Entergy Texas, Inc.// Office of Public Utility Counsel and Public Utility Commission of Texas v. Public Utility Commission of Texas and Texas Industrial Energy Consumers// Office of Public Utility Counsel and Entergy Texas, Inc.

ACCEPTED
03-14-00735-CV
4703327
THIRD COURT OF APPEALS
AUSTIN, TEXAS
3/31/2015 9:04:27 AM
JEFFREY D. KYLE
CLERK
No. 03-14-00735-CV

IN THE FILED IN
3rd COURT OF APPEALS
THIRD COURT OF APPEALS AUSTIN, TEXAS
AT AUSTIN, TEXAS 3/31/2015 9:04:27 AM
JEFFREY D. KYLE
Entergy Texas, Inc., et al., Clerk
Appellants

v.

Public Utility Commission of Texas, et al.,
Appellees

Appeal from the 353rd Judicial District Court, Travis County, Texas
The Honorable John K. Dietz, Judge Presiding
________________________________________________________________

APPELLANT’S BRIEF
OF ENTERGY TEXAS, INC.
_________________________________________________________________

John F. Williams
State Bar No. 21554100
jwilliams@dwmrlaw.com
Marnie A. McCormick
State Bar No. 00794264
mmccormick@dwmrlaw.com
DUGGINS WREN MANN & ROMERO, LLP
600 Congress Ave., Ste. 1900 (78701)
P. O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300
(512) 744-9399 fax

ATTORNEYS FOR APPELLANT
ENTERGY TEXAS, INC.

March 2015

ORAL ARGUMENT REQUESTED
 IDENTITY OF PARTIES AND COUNSEL

The following is a list of all parties to the order appealed from and the names

and addresses of all trial and appellate counsel:

Parties: Attorneys:

Entergy Texas, Inc. John F. Williams
Plaintiff in District Court Marnie A. McCormick
Duggins Wren Mann & Romero, LLP
600 Congress Ave., Ste. 1900 (78701)
P. O. Box 1149
Austin, Texas 78767-1149
Counsel in District Court and on Appeal

Public Utility Commission of Texas Elizabeth R. B. Sterling
Defendant in District Court Assistant Attorney General
Environmental Protection Division
Office of the Attorney General
P.O. Box 12548
Austin TX 78711-2548
Counsel in District Court and on Appeal

Office of Public Utility Counsel Sara J. Ferris
Plaintiff/Intervenor in District Court Office of Public Utility Counsel
1701 N. Congress Ave., Ste. 9-180
Austin TX 78711-2397
Counsel in District Court and on Appeal

Cities of Bridge City, et al. Daniel J. Lawton
Plaintiff/Intervenor in District Court Lawton Law Firm PC
12600 Hill Country Blvd., Ste. R275
Austin TX 78738
Counsel in District Court

i
State Agencies Susan M. Kelley (retired)
Plaintiff/Intervenor in District Court Office of the Attorney General
P. O. Box 12548
Austin TX 78711-2548
Counsel in District Court

Texas Industrial Energy Consumers Meghan Griffiths
Intervenor in District Court Andrews Kurth LLP
111 Congress Ave., Ste. 1700
Austin TX 78701
Counsel in District Court

Rex VanMiddlesworth
Benjamin Hallmark
Thompson Knight LLP
98 San Jacinto Blvd., Ste. 1900
Austin, Texas 78701
Counsel in District Court

ii
 TABLE OF CONTENTS

IDENTITY OF PARTIES AND COUNSEL ............................................................ i 

TABLE OF CONTENTS ......................................................................................... iii 

INDEX OF AUTHORITIES.................................................................................... vi 

STATEMENT OF THE CASE ................................................................................ ix 

STATEMENT REGARDING ORAL ARGUMENT ............................................. ix 

ADMINISTRATIVE RECORD .............................................................................. ix 

ISSUES PRESENTED...............................................................................................x 

STATEMENT OF FACTS ........................................................................................1 

I.  Regulatory Framework ....................................................................................1 

II.  Procedural History ...........................................................................................4 

SUMMARY OF THE ARGUMENT ........................................................................5 

ARGUMENT AND AUTHORITIES ........................................................................7 

I.  The Commission erred in disallowing over $11 million associated
with ETI’s unrecovered Hurricane Rita reconstruction costs. ........................7 

A.  Background ...........................................................................................7 

B.  The Commission erred as a matter of law in concluding that
PURA required the insurance proceeds to be trued-up in Docket
No. 37744. ...........................................................................................13 

C.  The Commission also erred in treating the issue as if it had in
fact been resolved in Docket No. 37744. ............................................15 

D.  The Commission’s order contravenes legislative intent. ....................18 

II.  The Commission erred in refusing to include any of ETI’s adjustments
to test-year purchased capacity costs in setting rates. ...................................19 

A.  Background .........................................................................................19 

iii
 B.  The Commission misapplied the standard for adjustments to
test-year expenses. ...............................................................................24 

1.  Adjustments to test-year data are not extraordinary relief........24 

2.  Adjustments to test-year data need not be proven with
absolute certainty. .....................................................................26 

C.  The Commission’s wholesale disallowance of any adjustment
to test-year levels of capacity costs is not supported by
substantial evidence.............................................................................27 

1.  ETI proved that it will incur an annual capacity cost
increase of $15.8 million under the Frontier contract...............28 

2.  ETI proved that it will incur an annual capacity cost
increase of $8.1 million under the SRMPA contract. ...............30 

3.  ETI proved that it will incur an annual capacity cost
increase of $14.1 million under the Calpine contract. ..............31 

4.  The record does not reasonably support the
Commission’s other reasons for disallowing 100 percent
of these known capacity costs. ..................................................32 

a.  Load Growth ...................................................................32 

b.  MSS-1 Costs ...................................................................34 

c.  MSS-4 Costs ...................................................................36 

D.  The consequences of the Commission’s decision are extreme
and unjust. ...........................................................................................38 

III.  The Commission erred in setting ETI’s transmission equalization
(MSS-2) expense at the test-year level. .........................................................39 

A.  The Commission erred as a matter of law in applying the
standard for adjustments to test-year expenses. ..................................41 

B.  Additionally, the Commission’s adherence to test-year expense
levels is unsupported by substantial evidence.....................................42 

CONCLUSION AND PRAYER .............................................................................43 
iv
CERTIFICATE OF COMPLIANCE .......................................................................44 

CERTIFICATE OF SERVICE ................................................................................45 

APPENDICES .........................................................................................................47 

v
 INDEX OF AUTHORITIES

Cases 
B.L.M. v. J.H.M., III,
No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17,
2014, pet. denied) .................................................................................................17
Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State
of W.Va.,
262 U.S. 679 (1923) ...............................................................................................2
Cameron v. Terrell & Garrett, Inc.,
618 S.W.2d 535 (Tex. 1981) ................................................................................33
Cities of Dickinson v. Public Util. Comm’n of Tex.,
284 S.W.3d 449 (Tex. App. – Austin 2009, no pet.) ...........................................11
City of Corpus Christi v. Public Util. Comm’n of Tex.,
51 S.W.3d 231 (Tex. 2001) ..................................................................................10
City of El Paso v. Public Util. Comm’n of Tex.,
344 S.W.3d 609 (Tex. App. – Austin 2011, no pet.) ................................ 3, 19, 20
City of El Paso v. Public Util. Comm’n of Tex.,
883 S.W.2d 179 (Tex. 1994) ............................................................... 3, 25, 26, 41
Commint Technical Services, Inc. v. Quickel,
314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ......................16
Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex.,
173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ......................................1
Federal Power Comm’n v. Hope Natural Gas Co.,
320 U.S. 591 (1944) ...............................................................................................2
Idaho Power Co. v. Idaho State Tax Comm'n,
109 P.3d 170 (Idaho 2005) ...................................................................................10
Office of Consumer Counsel v. Department of Public Util. Control,
742 A.2d 1257 (Conn. 2000) ................................................................................10
Office of Consumer Counsel v. Department of Public Util. Control,
905 A.2d 1 (Conn. 2006) .....................................................................................10
Office of Public Util. Counsel v. Public Util. Comm’n of Tex.,
104 S.W.3d 225 (Tex. App. – Austin 2003, no pet.) .............................................2

vi
Starr County v. Starr Industrial Servs., Inc.,
584 S.W.2d 352 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.) ......................27
State of Texas' Agencies & Institutions of Higher Learning v. Public Util.
Comm’n of Tex.,
450 S.W.3d 615 (Tex. App. -- Austin 2014, pet. requested) ........................ 10, 17
Suburban Util. Corp. v. Public Util. Comm’n of Tex.,
652 S.W.2d 358 (Tex. 1983) ........................................................................... 3, 26
TXU Elec. Co. v. Public Util. Comm’n of Tex.,
51 S.W. 3d 275 (Tex. 2001) (per curiam) ..............................................................8
Woods v. William M. Mercer, Inc.,
769 S.W.2d 515 (Tex. 1988) ................................................................................16
Statutes 
Tex. Gov’t Code Ann. § 2001.174 .............................................................. 19, 39, 43
Tex. Gov’t Code Ann. § 2001.190...........................................................................17
Tex. Util. Code Ann. §§ 11.001, et seq. ....................................................................1
Tex. Util. Code Ann. §§ 36.001, et seq. ..................................................................14
Tex. Util. Code Ann. § 36.003 ...................................................................................2
Tex. Util. Code Ann. § 36.051 .................................................................. 2, 7, 25, 41
Tex. Util. Code Ann. §§ 39.001-.359 ........................................................................2
Tex. Util. Code Ann. § 39.452 ...............................................................................2, 8
Tex. Util. Code Ann. § 39.455 .................................................................................33
Tex. Util. Code Ann. § 39.458 ........................................................................ 7, 8, 18
Tex. Util. Code Ann. §§ 39.458-463 .................................................................. 7, 18
Tex. Util. Code Ann. § 39.459 ............................................................................ 7, 13
Tex. Util. Code Ann. § 39.462 ......................................................................... passim
Rules 
16 Tex. Admin. Code § 22.222 ................................................................................17
16 Tex. Admin. Code § 25.181 ..................................................................................4
16 Tex. Admin. Code § 25.231 ..................................................................... 3, 24, 41
16 Tex. Admin. Code § 25.234 ..................................................................................3
16 Tex. Admin. Code §§ 25.235-.237 .......................................................................4
vii
16 Tex. Admin. Code § 25.236 ......................................................................... 19, 20
16 Tex. Admin. Code § 25.238 ................................................................................20
Tex. R. Civ. P. 94 .....................................................................................................15
Commission Proceedings 
Application of Entergy Gulf States, Inc. for Authority to Change Rates and
to Reconcile Fuel Costs, Docket No. 34800 ........................................................13
Application of Entergy Gulf States, Inc. for Determination of Hurricane
Reconstruction Costs, Docket No. 32907 .................................................... passim
Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 ............................................................17

viii
 STATEMENT OF THE CASE

This is a suit for judicial review of the final order of the Public Utility

Commission of Texas (the “Commission” or “PUCT”) in its Docket Number

39896, a proceeding initiated by Entergy Texas, Inc. (“ETI” or the “Company”) for

authority to change its retail electric rates and reconcile fuel costs. ETI and several

other parties to the contested case sought judicial review of the Commission’s

order.1 The cases were consolidated.2 The district court, Judge John K. Dietz

presiding, reversed the Commission’s order in one respect and summarily affirmed

it in all other respects.3

STATEMENT REGARDING ORAL ARGUMENT

Cases involving public utility regulation usually involve complex regulatory

principles, and this one is no exception. For that reason, the Court’s decisional

process would be aided by oral argument.

ADMINISTRATIVE RECORD

The Administrative Record (“AR”) comprises Joint Exhibits 4-13 of the

Reporter’s Record. Joint Exhibit 13 was sealed per the requirements of Texas Rule

of Civil Procedure 76a.4 Joint Exhibits 1-3 are indices to the record.

1
Clerk’s Record (“CR”) 5. The Clerk’s Record does not yet contain the petitions filed by parties
other than ETI.
2
CR 81.
3
CR 2118.
4
CR 2109.
ix
 ISSUES PRESENTED

1. The Commission disallowed over $11 million of costs that ETI incurred to
restore its system after Hurricane Rita and that no one disputes ETI is
entitled to recover. The Commission decided that ETI should have begun
recovering these costs at the end of a previous rate case, Docket No. 37744,
based upon a PURA provision and what the Commission characterizes as an
ambiguity in the resolution of Docket No. 37744.

a. Did the Commission erroneously interpret PURA as requiring
resolution of this issue in Docket No. 37744, when PURA section
39.462(a) says ETI may recover these costs in “any” proceeding
authorized by Chapter 36?

b. Did the Commission err by requiring ETI to disprove its opponents’
res judicata theory that the order in Docket No. 37744 bars ETI from
seeking recovery of the costs in this case?

c. Does the record reasonably support the Commission’s decision that
the order in Docket No. 37744 required ETI to begin recovering these
costs, when everyone agrees the Commission’s order said nothing
about the issue?

2. The Commission disallowed over $30 million of ETI’s expenses for
purchasing capacity from third parties because the amount was not incurred
in the test year and because the Commission found there was a possibility
that some of the costs might be avoided or offset.

a. Did the Commission err as a matter of law by treating adjustments to
test-year levels of expense as “exceptional” and by refusing to make
any adjustments for anticipated costs?

b. Is every one of the Commission’s multiple theories about how the
costs might be avoided or offset supported by substantial evidence?

x
3. The Commission refused to make any adjustment to ETI’s test-year level of
“transmission equalization” expense because the parties disagreed about
how big an adjustment was warranted.

a. Did the Commission err as a matter of law by requiring proof of
adjustments to test-year expenses with absolute certainty?

b. Is the Commission’s decision to set this expense at the test-year level
supported by substantial evidence, when every witness who testified
on this issue agreed the test-year level was too low?

xi
 STATEMENT OF FACTS

ETI is an investor-owned electric utility.5 ETI provides bundled generation,

transmission, distribution, and customer services to over 400,000 retail customers,

primarily in southeastern Texas.6 During the time periods at issue in this case, ETI

served both wholesale and retail customers.

I. Regulatory Framework

ETI is a subsidiary of Entergy Corporation, which also owns other

subsidiaries, or “operating companies,” including electric utilities in Louisiana,

Arkansas, and Mississippi.7 The utility subsidiaries each own facilities separately,

but they have historically coordinated and shared resources for providing and

transmitting energy.8 This coordination across state lines is governed by the

“Entergy System Agreement,” a tariff approved by the Federal Energy Regulatory

Commission (“FERC”).9 ETI’s wholesale rates are also regulated by the FERC.

See Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199, 207

(Tex. App. – Austin 2005, pet. denied).

The services ETI provides to Texas retail customers are subject to regulation

by the PUCT under the Public Utility Regulatory Act (“PURA”).10 The Texas

5
AR Binder 31, ETI Exh. 4 (Domino Direct at 1 of 38).
6
Id.
7
Id.
8
AR Binder 36, ETI Exh. 39 (Cicio Direct at 6-10 of 75).
9
Id.
10
See Tex. Util. Code Ann. §§ 11.001, et seq.
1
legislature in 1999 ordered electric utilities to “unbundle” their generation,

transmission, distribution, and customer service functions as part of an effort to

introduce competition into the Texas retail electric industry. See Tex. Util. Code

Ann. §§ 39.001-.359. However, in 2009, the legislature amended PURA to require

ETI to cease activities relating to the transition to retail competition. See id.

§ 39.452(i). Accordingly, ETI remains subject to traditional cost-of-service rate

regulation. Id. § 39.452(a).

Under traditional regulation, an electric utility provides service, from the

acquisition to delivery of power, to all requesting customers in a service area at a

Commission-approved “just and reasonable” rate. See Office of Public Util.

Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225, 227-28 (Tex. App. –

Austin 2003, no pet.); see also Tex. Util. Code Ann. § 36.003(a). Under PURA

and applicable constitutional principles, a utility is entitled to rates that afford it a

“reasonable opportunity to earn a reasonable return on the utility’s invested capital

used and useful in providing service to the public in excess of the utility’s

reasonable and necessary operating expenses.” Tex. Util. Code Ann. § 36.051;

Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944);

Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of

W.Va., 262 U.S. 679, 692 (1923). To set rates, the Commission determines each of

these components, which cumulatively are the utility’s “revenue requirement” or

2
“cost of service.” See, e.g., City of El Paso v. Public Util. Comm’n of Tex., 883

S.W.2d 179, 187 (Tex. 1994); 16 Tex. Admin. Code § 25.231.

The PUCT by rule has adopted a process by which rates are based on a

historical “test year,” adjusted for known and measurable changes. See 16 Tex.

Admin. Code § 25.231(a). The Commission evaluates the reasonableness of the

utility’s expenses, determines the appropriate level of capital investment (or rate

base) and a reasonable rate of return on that investment, and then allocates the total

revenue requirement among the utility’s various classes of customer. Id.

§§ 25.231(b), (c) & .234.

The central goal of this process is to arrive at cost recovery as representative

as reasonably possible of the utility’s “cost situation expected in the future.”

Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex.

1983). The utility generally bears the risk that its actual operating expenses will

exceed the expectations incorporated into the rate, while retail customers bear the

converse risk, during the regulatory “lag” between rate cases. City of El Paso v.

Public Util. Comm’n of Tex., 344 S.W.3d 609, 613 (Tex. App. – Austin 2011, no

pet.).

Exceptions to this general rule of risk exist for certain categories of costs,

such as fuel costs and energy efficiency costs. For these types of costs, the utility

has a separate rate or “rider” through which it collects its projected costs. The

3
utility later must reconcile those revenues to its actual, reasonable costs so that it

recovers no more or less than its actual, reasonable costs for the particular category

of expense covered by the rider. See, e.g., 16 Tex. Admin. Code §§ 25.235-.237 &

§ 25.181.

II. Procedural History

The Company initiated the underlying general rate case because the rates in

effect did not adequately compensate it for its cost of providing service.11 Among

other things, ETI’s third-party purchased power costs were doubling, a study

showed that its current depreciation rates were severely understated, and its actual

return on equity was some three percentage points lower than its then-authorized

return.12 ETI sought a total annual increase of $104.8 million.13 The “test year”

for the Company’s application was July 1, 2010 through June 30, 2011.14 Rates

were proposed to go into effect in June 2012.15

After an evidentiary hearing, four Administrative Law Judges (“ALJs”)

issued a proposal for decision recommending that ETI’s rates be increased by a

total of $28.3 million annually.16 The Commission, with a few exceptions, adopted

11
AR Binder 31, ETI Exh. 4 (Domino Direct at 7 of 38).
12
Id. at 7-8.
13
AR Binder 37, ETI Exh. 55 (LeBlanc Rebuttal at 7 of 14).
14
AR Binder 31, ETI Exh. 4 (Domino Direct at 8 of 38).
15
AR Binder 43, Vol. K (5/2/12 Tr. at 1540).
16
See AR Binder 7, Item 244 (Order on Rehearing at 1).
4
the proposal for decision and ordered that ETI’s rates be increased by a total of

$27.7 million annually.

ETI appealed several aspects of the final order to the district court.17 Several

parties that intervened in the Commission proceeding, including a group of cities

(“Cities”), the Office of Public Utility Counsel (“OPUC”), and State Agencies,

also appealed.18 The district court sustained one of ETI’s points, reversing the

Commission’s decision on that issue.19 The court summarily affirmed the

Commission’s order in other respects.20 More detailed facts are explained below in

the context of the specific errors ETI brings to this Court.

SUMMARY OF THE ARGUMENT

This case is about several multi-million-dollar outlays that ETI made to

serve its customers, but that the Commission refused to include in ETI’s rates.

First, ETI spent millions of dollars reconstructing its system after Hurricane

Rita. The Commission long ago determined these costs were reasonable and

necessary, and that ETI was entitled to recover them. Nevertheless, the

Commission has now disallowed over $11 million of these costs on the theory that

ETI should have started recovering them after its 2009 rate case. This decision is

17
CR 5.
18
Though the separate appeals were consolidated, CR 81, the Clerk’s Record does not yet
contain the petitions filed by parties other than ETI. In any event, after the cases were
consolidated, State Agencies nonsuited their appeal but remained in the case as an intervenor
defendant. CR 2084 & 2085.
19
CR 2118.
20
Id.
5
based upon an erroneous interpretation of a PURA provision. It is also based upon

a legally and factually unsupportable conclusion that ETI should have divined that

it was required to begin recovering these costs after the 2009 rate case, even

though the order in that case said no such thing.

Second, ETI spent millions of dollars purchasing third-party capacity to

serve its customers. Even though the Commission did not find that these purchases

were unreasonable or unnecessary, the Commission refused to include the costs in

ETI’s rates. The Commission’s decision is based upon an erroneous insistence that

test-year data is more important than evidence of what costs the Company expects

to bear when the rates go into effect. It is also based upon several fact-findings

that ETI might be able to avoid or offset some of these costs. These findings do

not support a total disallowance of the purchased capacity costs and are not

rationally based upon the record evidence.

Similarly, ETI spent millions of dollars to pay for its share of the multi-

jurisdictional transmission network that supports service to its customers, and those

costs dramatically increased after the test year. Even though every witness who

testified about this issue agreed that the test-year level of this expense was too low,

the Commission refused to make any adjustment because the witnesses did not

agree on how much of an increase was warranted. This decision is another

example of the Commission’s erroneous application of the standard for calculating

6
expenses that should be included in rates. It is also unsupported by substantial

evidence.

The effect of all these decisions was that ETI had to bear all these costs at

shareholder expense until its next rate case. ETI, therefore, did not have the

opportunity to earn the reasonable return on its investment to which it is entitled

under PURA. See Tex. Util. Code Ann. § 36.051. Because these decisions were

fraught with error, this Court should reverse them.

ARGUMENT AND AUTHORITIES

I. The Commission erred in disallowing over $11 million associated with
ETI’s unrecovered Hurricane Rita reconstruction costs.

A. Background

In 2005, Hurricane Rita struck the upper Texas coast, causing extensive

damage to southeastern Texas. The next year, the legislature enacted a set of

provisions in PURA that entitles electric utilities like ETI to timely recover

reconstruction costs they reasonably and necessarily incurred as a result of the

hurricane. See Tex. Util. Code Ann. §§ 39.458-463.

The enactment requires the Commission, upon application by a utility, to

determine whether particular hurricane reconstruction costs were reasonably and

necessarily incurred and thus eligible for recovery. Id. §§ 39.459(a)(1) &

39.462(b). This determination need not be made in the context of a base-rate

proceeding under PURA Chapter 36. Id. § 39.462(e).
7
 If, upon a utility’s application, the Commission determines it would benefit

ratepayers for the utility to recover eligible costs through “securitization”

financing,21 as opposed to “conventional financing methods,” the Commission

must adopt a financing order authorizing the utility to issue bonds. Id. § 39.458.

The bonds are repaid or secured by charges to ratepayers in the utility’s service

area. E.g., TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275, 277

(Tex. 2001) (per curiam). Alternatively, a utility is entitled to recover eligible

reconstruction costs in a base rate proceeding “or through any other proceeding

authorized by Subchapter C, Chapter 36” of PURA. Tex. Util. Code Ann.

§ 39.462(a).

In December 2006, ETI’s predecessor22 initiated a proceeding to determine

whether certain of its Hurricane Rita reconstruction costs were eligible for

recovery and securitization.23 The parties to that case reached a settlement and

21
Securitization is a specialized form of debt financing where repayment of bondholders
achieves a high degree of assurance, resulting in very low bond interest rates.
22
ETI’s predecessor was Entergy Gulf States, Inc. (“EGSI”). EGSI provided retail electric
service in both Texas and Louisiana. In 2005, the Texas Legislature enacted legislation
providing that EGSI could proceed with and complete jurisdictional separation of its Texas and
Louisiana operations to establish two separate, vertically integrated utilities. See Tex. Util. Code
Ann. § 39.452(e). By January 1, 2008, EGSI had separated into ETI, a Texas-only utility, and
Entergy Gulf States Louisiana, L.L.C., a Louisiana-only utility.
23
See Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction
Costs, Docket No. 32907 (Jul. 5, 2006 Application). Public filings in Docket No. 32907 and
other Commission dockets may be accessed at the Commission’s interchange:
http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp
by entering the docket number in the “Control Number” field.
8
agreed that $381,236,384 of the expenses at issue were eligible.24 Because ETI

expected to receive insurance proceeds of $65,700,000 in the future, the settlement

provided that ETI would deduct that amount from its eligible costs.25 The parties

agreed that ETI should be allowed to securitize $381,236,384, plus carrying costs,

minus the $65.7 million estimated insurance proceeds, plus other qualified costs.26

It was understood that the Company might not receive exactly $65,700,000 in

insurance proceeds, so the parties further agreed that after ETI received all of its

insurance payments, a true-up would occur to determine the difference between the

$65,700,000 estimate and the amount actually received.27 The parties agreed that

ETI would accrue interest on the anticipated payments until they were actually

paid, either by insurance companies or ratepayers.28

The Commission approved the parties’ agreement.29 The order provided that

if ETI received more insurance payments than estimated, the excess would be

passed through to ratepayers via a rider.30 But the agreed rider was only for over-

recovery. Neither the settlement nor the order specified a method for recovering

any insurance under-recovery from ratepayers.

24
See Docket No. 32907 (Nov. 17, 2006, Settlement Agreement at 2 of 10).
25
Id. at 3 of 10.
26
Id. at 5 of 10.
27
Id. at 3 of 10.
28
Id.
29
See id. (Dec. 1, 2006, Order at 1).
30
Id. at FOF 30.
9
 By 2009, ETI had received only $46,013,904 in insurance proceeds,

resulting in a $19,686,096 under-recovery of its actual, eligible hurricane

reconstruction costs.31 ETI carried this unrecovered balance on its books, with

interest, as a regulatory asset32 because the Commission’s order in Docket No.

32907 expressly contemplated that ETI would be authorized to recover these

amounts in the future.33

In 2009, ETI filed a base rate case, Docket No. 37744. By that time, ETI

had recovered most of the insurance proceeds it expected to recover, and it sought

permission to begin recovering the regulatory asset of $19,686,096, plus interest,

on a five-year amortization schedule.34

31
AR Binder 5, Item 185 (Proposal for Decision at 16).
32
A “regulatory asset” is a mechanism by which a utility carries a cost on its books as a balance
sheet asset based on the expectation that a regulator will allow the utility to recover the cost over
a period of years in the future instead of at the time the expenditure is made. E.g. Office of
Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1, 7 (Conn. 2006); Idaho
Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170, 173 (Idaho 2005); Office of Consumer
Counsel v. Department of Public Util. Control, 742 A.2d 1257, 1263 (Conn. 2000); City of
Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231, 238 (Tex. 2001); State of Texas'
Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615,
646 (Tex. App. -- Austin 2014, pet. requested). Public utility commissions often permit utilities
to recover large capital expenditures on this deferred basis to avoid the “rate shock” that could
result if the costs were passed on to ratepayers all at once. E.g., Office of Consumer Counsel,
905 A.2d at 7; Idaho Power Co., 109 P.3d at 173. A regulatory asset is, therefore, a future debt
of the ratepayers. Office of Consumer Counsel, 905 A.2d at 7. Regulatory assets are recovered
over time from ratepayers on an “amortized” schedule. See Idaho Power Co., 109 P.3d at 173;
Office of Consumer Counsel, 742 A.2d at 1263.
33
Docket 32907 (Dec. 1, 2006, Order at FOF 28) (authorizing ETI to accrue carrying costs on
estimated insurance proceeds until paid by insurance companies or until the trued-up amount “is
recovered in base rates”); AR Binder 5, Item 185 (Proposal for Decision at 19).
34
AR Binder 5, Item 185 (Proposal for Decision at 16). Again, as explained above in footnote
32, regulatory assets are traditionally “amortized.” That means they are recovered over a period
of time so they are not charged to ratepayers all at once.
10
 Docket No. 37744 was concluded by a “black box” settlement that did not

mention the Hurricane Rita regulatory asset.35 Neither the parties’ stipulation nor

the PUCT’s order in Docket No. 37744 directed ETI to begin amortizing the

regulatory asset or otherwise prescribed a method for recovering it. Neither

indicated an intent to alter ETI’s rights under PURA section 39.462 and the

Commission’s order in Docket No. 32907.36 ETI, therefore, continued to account

for and accrue interest on the unrecovered regulatory asset.

After Docket No. 37744, ETI received an additional $5.7 million in

insurance proceeds.37 In its next rate case, the one underlying this appeal, ETI

sought permission to begin recovering the updated balance of the reconstruction

costs eligible for recovery. With interest, that balance totaled $26,229,627.38 The

ALJs recommended ETI recover only $15,175,563.39

The ALJs determined that even though the order in Docket No. 37744 did

not say so, ETI should have begun amortizing the regulatory asset on August 15,

2010, the effective date of the rates approved in that docket.40 The ALJs expressed

two rationales for their decision. First, they concluded that PURA required any

35
In a “black box” settlement, the parties agree to a total amount that a utility can recover
through its rates without specifying any of the individual numbers used to calculate the amount.
See, e.g., Cities of Dickinson, et al. v. Public Util. Comm’n of Tex., 284 S.W.3d 449, 450 (Tex.
App. – Austin 2009, no pet.).
36
Docket No. 32907, supra (Nov. 17, 2006, Settlement Agreement; Dec. 1, 2006, Order).
37
AR Binder 37, ETI Exh. 46 (Considine Rebuttal at 18).
38
Id.; AR Binder 5, Item 185 (Proposal for Decision at 16).
39
AR Binder 5, Item 185 (Proposal for Decision at 23).
40
Id. at 21-22.
11
true-up of insurance proceeds to occur in the first base rate case after the

reconstruction costs were deemed eligible for recovery.41 The ALJs believed that

Docket No. 37744 was that case.42 Second, though they characterized the issue as

a “close call,”43 the ALJs concluded that the amortization of the unrecovered costs

“should be considered as having been approved in Docket No. 37744.”44 They

believed the proposed amortization was not disputed in Docket No. 37744, and that

ETI therefore had the burden of proving the issue was not resolved in the docket.45

Because they believed ETI did not meet that burden, they treated the issue as if it

had already been resolved.46 The ALJs determined that if ETI had begun

amortizing the regulatory asset upon the conclusion of Docket No. 37744, only

$15,175,563 would be left to deal with in this case.47

The Commission adopted the ALJs’ recommendation.48 This decision must

be reversed, because all the rationales for it are flawed.

41
Id. at 15 & 21-22.
42
Id. at 16 & 22.
43
Id. at 20.
44
Id. at 22.
45
Id.
46
Id.
47
Id. at 23.
48
AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 19-22).
12
 B. The Commission erred as a matter of law in concluding that
PURA required the insurance proceeds to be trued-up in
Docket No. 37744.

The ALJs relied upon PURA section 39.459(c) in concluding that the

insurance proceeds were required to be trued up in the first base rate case after the

reconstruction costs were deemed eligible for recovery.49 Section 39.459(c) reads:

To the extent a utility subject to this subchapter receives insurance
proceeds, governmental grants, or any other source of funding that
compensates it for hurricane reconstruction costs, those amounts shall
be used to reduce the utility’s hurricane reconstruction costs
recoverable from customers. If the timing of a utility’s receipt of
those amounts prevents their inclusion as a reduction to the hurricane
reconstruction costs that are securitized, the commission shall take
those amounts into account in:

(1) the utility’s next base rate proceeding; or

(2) any proceeding in which the commission considers hurricane
reconstruction costs.

Tex. Util. Code Ann. § 39.459 (c) (emphasis added). The Commission, in

adopting the ALJs’ construction of this provision, erred as a matter of law.50

PURA section 39.459(c) requires the Commission to remedy a double-

recovery if a utility receives insurance or grant money for hurricane reconstruction

costs after those same costs have already been securitized. That is the exact

49
AR Binder 5, Item 185 (Proposal for Decision at 15 & 21-22).
50
The Commission also erred as a matter of fact in assuming that Docket No. 37744 was ETI’s
first base rate case after the reconstruction costs were deemed eligible for recovery in Docket No.
32907. There was another base rate case filed and decided between Docket Nos. 32907 and
37744. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to
Reconcile Fuel Costs, Docket No. 34800.
13
opposite of what happened here. In Docket No. 32907, ETI agreed not to

securitize amounts it expected to recover from insurance. Therefore, in the

language of the statute, the timing of ETI’s receipt of those amounts did not

prevent their inclusion as a reduction to the amounts that were securitized. The

Attorney General conceded in the district court that the wording of section

39.459(c) “is not an exact match to the circumstances of this case.”51 Indeed,

section 39.459(c) is by its plain terms inapplicable.

Section 39.462(a), on the other hand, speaks directly to this situation. It

says:

An electric utility subject to this subchapter is entitled to recover
hurricane reconstruction costs consistent with the provisions of this
subchapter and is entitled to seek recovery of amounts not recovered
under this subchapter … in its next base rate proceeding or through
any other proceeding authorized by Subchapter C, Chapter 36.

Id. § 39.462(a) (emphasis added). There is no question that the proceeding

underlying this appeal was authorized by PURA Subchapter C, Chapter 36. See id.

§ 36.001, et seq. Therefore, the Commission was expressly authorized to address

the issue in this case. It certainly was not statutorily required to address the issue

in Docket No. 37744 or some other particular case.

51
CR 698 (PUCT Initial Brief at 14).
14
 C. The Commission also erred in treating the issue as if it had
in fact been resolved in Docket No. 37744.

Nothing in the settlement agreement or final order in Docket No. 37744 even

mentioned the regulatory asset, much less a method of recovering it. The ALJs

acknowledged that.52 They also recognized that utilities are typically not allowed

to recover regulatory assets without express approval of the Commission.53 The

ALJs nevertheless concluded that the proposed amortization of the regulatory asset

should be “considered to have been approved” in Docket No. 37744. They

believed that the proposed amortization was not disputed in Docket No. 37744 and

that ETI consequently should be required to prove the issue was not resolved in

Docket No. 37744.54 Both of these assumptions are incorrect.

First, as a matter of law, ETI did not bear the burden of proving what issues

Docket No. 37744 did or did not resolve. The issue of whether Docket No. 37744

bars ETI from seeking particular relief in a subsequent case was a defensive issue

raised by intervenors.55 The argument is really that the order in Docket No. 37744

is res judicata of the reconstruction cost recovery issue. Because that is an

affirmative defense, intervenors bore the burden of proof on the issue. See, e.g.,

Tex. R. Civ. P. 94; Woods v. William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex.

52
AR Binder 5, Item 185 (Proposal for Decision at 20-21).
53
Id. at 21.
54
Id. at 22.
55
See, e.g., AR Binder 8 (Cities Exh. 2, Garrett Direct at 11).
15
1988); Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex.

App. – Houston [14th Dist.] 2010, no pet.).

There is no reasonable basis in the record upon which to conclude that the

parties or the Commission intended ETI to begin amortizing the regulatory asset

years ago. The only reason the intervenors gave in support of their argument was

their allegation that the issue was “undisputed” in Docket No. 37744. It is true that

no party to Docket No. 37744 argued that ETI should not recover the money at

all.56 They could not, given that Docket No. 32907 and PURA clearly entitle ETI

to recover the full amount of its eligible restoration costs. Regardless, the parties’

litigation positions during the contested phase of a proceeding do not inform what

the parties intend when they settle the case, or what the Commission intends in

approving the settlement.

Even assuming for the sake of argument that the parties’ litigation positions

in Docket No. 37744 were relevant, their positions on whether ETI was entitled to

recover the money at all would not be the relevant issue. What would matter is

what the parties’ positions were on how and when ETI should recover the money,

because that is the issue the Commission says was resolved in Docket No. 37744.

Cities’ witness in Docket No. 37744, Jacob Pous, did dispute ETI’s request to

amortize the regulatory asset over a five-year period. He testified that ETI should

56
See id. at 11.
16
credit the amount to its storm reserve instead.57 The ALJs were mistaken in

concluding that this issue was uncontested in Docket No. 37744.58 There certainly

is no evidence in this docket that the parties or the Commission intended ETI to

begin amortizing the regulatory asset upon the conclusion of Docket No. 37744.

Given that neither the settlement agreement nor the Commission’s order said

anything about this issue, and especially since the issue was disputed, ETI would

have been unreasonable to “assume” it could begin amortizing the regulatory asset

when Docket No. 37744 was over. As this Court recently recognized, the recovery

of a regulatory asset is a two-step process. First, the Commission allows creation

of the asset, and later, the Commission decides how the utility may recover the

asset in rates. State of Texas' Agencies & Institutions of Higher Learning v. Public

Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet

requested). Here, the settlement and Commission order in Docket No. 32907

established that the hurricane reconstruction costs were reasonable and necessary

and authorized creation of the regulatory asset. But the Company’s proposed
57
See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel
Costs, Docket No. 37744 (Pous Direct at 113). Both the Commission and this Court may take
notice of the fact this testimony was filed in Docket No. 37744. Tex. Gov’t Code Ann.
§ 2001.190; 16 Tex. Admin. Code § 22.222(a); B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014
WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) (not designated for
publication).
58
In contrast, the ALJs correctly observed that another issue – regarding ETI’s storm reserve
balance -- was disputed in Docket No. 37744. AR Binder 5, Item 185 (Proposal for Decision at
48). They concluded that issue was not resolved by the black box settlement. Id. Using the
ALJs’ own logic, this fact leads to the conclusion that the Hurricane Rita issue was not
adjudicated in Docket No. 37744. Resolving two issues differently based on materially similar
facts is the essence of arbitrary and capricious action.
17
method of recovering that asset in Docket No. 37744 was a contested issue, and

neither the parties’ settlement nor the Commission’s order resolved the issue in

favor of one party or another. The only reasonable thing for the Company to do

was to maintain the status quo, carrying the balance on its books as a regulatory

asset until the Commission affirmatively addresses how the Company may recover

it.59

D. The Commission’s order contravenes legislative intent.

The Commission’s decision thwarts the legislature’s purpose in enacting the

hurricane reconstruction cost recovery provisions. See Tex. Util. Code Ann.

§§ 39.458-.463. The legislature clearly intended to ensure that utilities that

incurred reconstruction costs as a result of Hurricane Rita would be able to

expeditiously recover those costs in full, with interest. Indeed, the legislature

expressly articulated this purpose in PURA. Id. § 39.458. The effect of the

Commission’s order here is to disallow over $11 million in unrecovered hurricane

reconstruction costs and interest. The order penalizes the utility for, instead of

securitizing all of its hurricane reconstruction costs as authorized by the statute,

opting not to securitize amounts that it anticipated recovering through insurance.

No one has suggested that ETI was unreasonable in estimating its anticipated

59
Even Cities opined that the Docket No. 37744 settlement should not be interpreted as changing
the status quo unless expressly stated in the settlement agreement or the final order. See AR
Binder 5, Item 185 (Proposal for Decision at 17).
18
insurance proceeds when the securitization docket was taking place. The

Commission’s reasons for disallowing the amounts that were not ultimately

recovered through insurance are not legally or factually sound. The Court should

reverse the Commission’s disallowance. See Tex. Gov’t Code Ann.

§ 2001.174(b)(2).

II. The Commission erred in refusing to include any of ETI’s adjustments
to test-year purchased capacity costs in setting rates.

A. Background

“Capacity” is the amount of power a utility has available at any given time

to serve customers. Utilities are required to have a percentage surplus or “cushion”

of capacity available in reserve, in case demand exceeds expectations.

Traditionally regulated utilities supply their need for capacity either by owning

generating plants or by buying capacity from someone else.

A utility’s capital investment in building and maintaining its own plant

become a part of its invested capital (or “rate base”), and the utility earns a return

on that investment. The cost of fueling a power plant and other specified variable

“energy” charges incurred to generate power are recoverable dollar-for-dollar as

fuel expenses. 16 Tex. Admin. Code § 25.236(a); City of El Paso, 344 S.W.3d at

614.

Purchases of capacity from third parties are, however, treated differently.

They are simply expenses, and earn no return for the utility. Moreover, the fixed
19
costs associated with obtaining capacity from third parties may not, absent special

circumstances, be recovered as fuel expenses. 16 Tex. Admin. Code

§ 25.236(a)(4); City of El Paso, 344 S.W.3d at 614. Instead, they are recovered

through base rates. Id.60 Like other base rate expenses, “purchased capacity costs”

are quantified during a “test year,” are adjusted for known and measurable

changes, and become a component of the utility’s revenue requirement that forms

the basis for prospective rates. There is no true-up or reconciliation for the

purchased capacity costs recovered through base rates. Combined with the fact

that there is no opportunity to earn a return on this type of expense, the adverse

financial impact of “regulatory lag” is much more significant for this type of

expense than it is for reconcilable fuel costs.

Before 2009, ETI was under a regulatory directive to position itself for retail

competition, and that directive necessitated that the Company forego long-term

resource procurement. During that time, ETI relied on or “shared” the capacity

from Entergy System resources owned by other Entergy operating companies, and

relied on short- and limited-term resources to reliably serve its retail customers.61

ETI paid for this Entergy System capacity under Schedule MSS-1 of the Entergy

System Agreement. That FERC-approved tariff requires the various Entergy

60
In some circumstances, Commission rules allow utilities to recover purchased capacity costs
through a rider. See 16 Tex. Admin. Code § 25.238. ETI does not have such a rider.
61
See AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5-6 of 21); AR Binder 43, Vol. L (5/3/12
Tr. at 1939).
20
operating companies to make and receive payments according to their relative

share of total system capacity.62 Some Entergy operating companies own a greater

share of Entergy System capacity than they need to serve their own load.63 These

entities are considered “long” on capacity.64 Other companies own less than they

need, and are “short” on capacity.65 Under Schedule MSS-1, “short” companies

pay “long” companies a per-MW rate for the cost of owning these capacity

reserves.66 While it was in regulatory limbo, ETI controlled relatively less

resources compared to its load than other Entergy companies. It, therefore, made

“reserve equalization” payments under Schedule MSS-1.67

In addition to sharing Entergy System capacity under Schedule MSS-1, ETI

also purchased power from specific units owned by other Entergy operating

companies. Those unit-specific purchases were paid for under contracts with those

operating companies under Schedule MSS-4 of the Entergy System Agreement.

Schedule MSS-4 contains a formula that sets the price of power for these purchases

based on the actual cost of producing the power.68

After the legislature in 2009 delayed the onset of retail competition in ETI’s

service area, ETI found it cost effective to begin to substantially increase its

62
AR Binder 36, ETI Exh. 39 (Cicio Direct at 11-12 of 75).
63
Id. at 12.
64
Id.
65
Id.
66
Id. at 13-14.
67
AR Binder 35, ETI Exh. 34 (Cooper Direct at 22-23 of 25).
68
AR Binder 36, ETI Exh. 39 (Cicio Direct at 24-26 of 75).
21
reliance upon purchases of capacity from third parties.69 ETI did not buy more

third-party capacity simply to serve additional load. Rather, ETI employed the

strategy to serve existing load, reduce its reliance on Entergy capacity resources,

and render ETI less “short” compared to other Entergy entities.70 The strategy also

reduced fuel costs for customers because the third-party resources were by and

large more fuel-efficient than the combined Entergy resources and, as explained

above, there was no return component included in the cost.71

In this case, ETI asked the Commission to recognize the cost of ETI’s

increased reliance on three new third-party purchased capacity contracts. Those

contracts cost ETI some $38 million annually. ETI recognized that these contracts

would enable ETI annually to avoid about $8 million of the costs it paid to Entergy

affiliates for their capacity in the test year. ETI, therefore, asked the Commission

to increase its test-year expenses for purchased capacity by the net amount of about

$30 million for purposes of setting its annual rates.

No party challenged the wisdom of ETI’s entering into any of the new, third-

party contracts or the prices reflected in the contracts. The ALJs, however,

included in ETI’s base rates only purchased capacity costs that were incurred

69
E.g, AR Binder 35, ETI Exh. 34 (Cooper Direct at 23 of 25).
70
AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); see also id. at 10-11; AR Binder 37,
ETI Exh. 57 (May Rebuttal at 13-15 of 31).
71
AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 7-8 of 21).
22
during ETI’s test year.72 The ALJs disallowed 100 percent of the additional

expense associated with the third-party capacity contracts that would be incurred

during the first year rates would be in effect (the “rate year”) and thereafter.73 The

Commission adopted the ALJs’ proposal for decision on this issue.74

The ALJs concluded that ETI had not proven that the costs it would incur as

a result of entering into the third-party purchase capacity contracts were “known

and measurable” adjustments to the utility’s test-year expenses.75 The ALJs found

that there is “substantial uncertainty” about what ETI will be obligated to pay for

the third-party purchased capacity because the third parties might not fully perform

their obligations under the contracts.76 The ALJs suggested that the contract costs

should not be in rates because they may be offset by increased revenues from load

growth.77 The ALJs further found there is “substantial uncertainty” about how

much money the third-party purchased power capacity contracts will enable ETI to

avoid paying to other Entergy entities under Schedule MSS-1 of the Entergy

System Agreement.78 The source of this perceived uncertainty was apparently the

ALJs’ view that the net costs were difficult to quantify because the calculations

72
AR Binder 5, Item 185 (Proposal for Decision at FOF 86).
73
Id. at FOF 73 & 86.
74
AR Binder 7, Item 244 (Order on Rehearing at 1 & 7).
75
AR Binder 5, Item 185 (Proposal for Decision at 108).
76
Id. at FOFs 77-78.
77
Id. at 109 & FOFs 84.
78
Id. at FOFs 75, 76, & 79-82.
23
involve projections and “complex” formulae and “variables.”79 Rather than

accepting any of the calculations in evidence or adopting a result within the range

of these recommendations, the ALJs simply disallowed the entire adjustment.80

The Commission’s order adopting these recommendations constitutes error of law

and is not supported by substantial evidence.

B. The Commission misapplied the standard for adjustments
to test-year expenses.

The fundamental error in the Commission’s order is that it misapplies the

legal standard for determining what expenses should be included in rates. The

order adopts the ALJs’ erroneous view that an adjustment to test-year data is

somehow extraordinary or “exceptional” rate relief.81 The ALJs also took the view

that to the extent additional costs are based on anticipated changes, they cannot be

“known and measurable.”82 These assumptions are wrong as a matter of law.

1. Adjustments to test-year data are not extraordinary
relief.

To determine what a utility’s reasonable and necessary expenses are, the

Commission determines “the electric utility’s historical test year expenses as

adjusted for known and measurable changes.” 16 Tex. Admin. Code § 25.231(b).

Under the rule, known and measurable changes have equal weight with historical

79
Id. at 108.
80
Id. at 109.
81
Id. at 108; AR Binder 7, Item 244 (Order on Rehearing at 1).
82
AR Binder 5, Item 185 (Proposal for Decision at 102).
24
test-year levels. That makes sense, because PURA does not limit a utility’s

recoverable expenses to those incurred in a historical test year. Rather, PURA

guarantees a utility a reasonable opportunity to earn a reasonable return on its

investment over and above its “reasonable and necessary expenses.” Tex. Util.

Code Ann. § 36.051. The goal of ratemaking is to set utility rates that will meet

the utility’s and customers’ needs in the future, not the past, as rates are set on a

prospective basis.

The Texas Supreme Court has confirmed that making known and

measurable adjustments is a critical component of establishing the costs upon

which rates are set, and not a rare exception to the use of test-year cost levels. The

Court has explained that “changes occurring after the test period, if known, may be

taken into consideration by the regulatory agency to help mitigate the effects of

inflation and in order to make the test year data as representative as possible of

the cost situation that is apt to prevail in the future.” City of El Paso v. Public

Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994) (emphasis added).

The recognition of changes to test-year data is especially critical in a case

such as this one, where the inability to recover substantial post-test-year expenses

inevitably causes ETI to recover an inadequate return, contrary to the requirements

of PURA’s fundamental cost-recovery standards. See Tex. Util. Code Ann.

§ 36.051. The Commission’s conclusion that a utility is somehow less entitled to

25
expenses that occur beyond the test year is contrary to PURA and judicial

precedent, and its erroneous application of the known and measurable standard

tainted the entirety of its decision on this issue. This is reason enough to reverse

the Commission’s decision.

2. Adjustments to test-year data need not be proven
with absolute certainty.

The quantum of proof required to establish adjustments to test-year data is

not greater than the quantum required to establish the test-year data itself. The

Texas Supreme Court has held that known and measurable adjustments should be

made if they reflect costs that will be “actually realized,” can be “anticipated with

reasonable certainty,” and if they are representative of the costs “apt” to prevail in

the future. See City of El Paso, 883 S.W.2d at 188; Suburban Util. Corp., 652

S.W.2d at 362. The standard is not an impossible-to-meet requirement of absolute

or virtual certainty. Suburban Util. Corp., 652 S.W.2d at 362. Contrary to its

ruling regarding purchased capacity, the Commission in this and other cases has

routinely adopted known and measurable adjustments that involve estimates and

uncertainty.83 In rejecting ETI’s proposed adjustments to test-year purchased

capacity expense, the Commission did not acknowledge or discuss the statute, rule,

judicial precedent, or regulatory precedent that guide its inquiry. The decision is

83
E.g., AR Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-64
(payroll adjustments), & 182-86 (ad valorem tax rate update)).
26
contrary to and inconsistent with all those authorities. Under the Commission’s

analysis, known and measurable changes routinely adopted by the Commission

would never be allowed. The Commission’s ruling is, therefore, arbitrary and

capricious. See Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352, 355-

56 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.). This is another reason the

decision must be reversed.

C. The Commission’s wholesale disallowance of any
adjustment to test-year levels of capacity costs is not
supported by substantial evidence.

The proposed adjustments for third-party purchased capacity expenses are

attributable to three contracts the parties call the Frontier, Calpine, and Sam

Rayburn Municipal Power Agency (“SRMPA”) contracts. ETI established with

reasonable certainty what costs it would incur under each of these contracts while

the rates being set in this case would be in effect. The Commission did not discuss

the contracts separately, but ruled on them in the aggregate. The Commission said:

77. ETI’s projection of its rate-year third-party capacity contract
payments includes numerous assumptions, one of which is that
every single third-party supplier will perform at the maximum
level under the contract, even though that assumption is
inconsistent with ETI’s historical experience.

78. There is substantial uncertainty with regard to ETI’s projection
of its rate-year third-party capacity contract payments.84

84
AR Binder 7, Item 244 (Order on Rehearing at FOFs 77-78); see also AR Binder 5, Item 185
(Proposal for Decision at 108-109).
27
 These findings are not supported by substantial evidence. As discussed

below, the adjustments were based on contracts already in place before and during

the rate year. The contracts had clearly and specifically ascertainable prices and

quantities, which were in evidence. No one disputed that ETI will pay money

under these contracts. Rather, some parties speculated that ETI might not have to

pay the full amount of these contracts because suppliers might not perform

perfectly. Performance under each of the contracts is reasonably assured. There is

no reasonable uncertainty regarding the outcome under any of these contracts,

certainly none sufficient to support a finding that none of these contract costs are

“apt to prevail” in the near future.

1. ETI proved that it will incur an annual capacity cost
increase of $15.8 million under the Frontier contract.

There is no reasonable basis in the evidence for the Commission’s finding

that the costs of the Frontier contract are uncertain. ETI has had a contract with

Frontier for years, leading up to and including the first ten months of the test

year.85 In the second-to-last month of the test year, ETI increased the annual

amount of power it purchased under the Frontier contract from 150 MW to 300

MW.86 Applying the language of the Texas Supreme Court, the 150 MW increase

in capacity and capacity cost was “actually realized” in the test year. But because

85
AR Binder 43, Vol. L (5/3/12 Tr. at 1938 & 1941).
86
Id. at 1942 & 1959.
28
the step-up happened late in the test year, the test year does not reflect the full

amount of expense ETI will incur going forward under the Frontier contract.87 No

witness challenged ETI’s quantification of what this contract would cost ETI

during the rate year.

On cross-examination at the hearing, ETI’s witness Cooper acknowledged

that ETI’s purchased capacity contracts include provisions that authorize ETI to

reduce its payments if the counter-party does not perform.88 He explained that ETI

did not assume any reduction in future payments for poor performance because in

the past, any such adjustments have been “relatively minor.”89 ETI’s witness May,

who quantified the increase in annual Frontier costs at $15.8 million, confirmed

that ETI has “quite a bit of experiences” with the contract, and a “good

understanding of what the costs are today and what the costs will be in the future”

under the contract.90 The other parties did not produce evidence to the contrary.

It is simply not reasonable to conclude, based upon this record, that there is

“substantial uncertainty” about what ETI’s annual expenses will be in connection

with the Frontier increase. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

87
Id. at 1942.
88
AR Binder 43, Vol. F (4/26/12 Tr. at 705-06); see also id. at 682.
89
Id. at 705.
90
AR Binder 43, Vol. L (5/3/12 Tr. at 1942).
29
 2. ETI proved that it will incur an annual capacity cost
increase of $8.1 million under the SRMPA contract.

During the test year, ETI executed a 25-year agreement with SRMPA for

225 MW of capacity.91 Power started flowing under the contract on December 1,

2011, just five months after the end of the test year, well before intervenors filed

their testimony in March 2012, and well before the conclusion of the proceeding

under review.92 All of the capacity contracted for was allocated to ETI.93 The

price of this contract is a “very straightforward $3 per kW a month.”94 It is “very

easy to calculate what those known and measurable costs are.”95 $3.00 x 225,000

kW = $675,000 per month. At $675,000 per month, the contract will cost $8.1

million annually. No witness challenged ETI’s quantification of the annual costs

of the SRMPA contract. In addition, the SRMPA contract commits “System

Capacity,” meaning multiple network resources and substitute resources are

designated to supply the capacity. There is no evidence in the record that

SRMPA’s entire portfolio of network resources is likely to be simultaneously

unavailable.

There is, therefore, no evidence in the record that there is “substantial

uncertainty” about whether SRMPA will perform the contract, or what the annual

91
AR Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25).
92
See id.
93
Id. at 17 & 19 of 25.
94
AR Binder 43, Vol. L (5/3/12 Tr. at 1944).
95
Id.
30
costs of the contract will be. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

3. ETI proved that it will incur an annual capacity cost
increase of $14.1 million under the Calpine contract.

ETI purchased capacity from Calpine Energy Services under a one-year

contract in effect from June 1, 2008 through May 31, 2009.96 In 2009, ETI entered

into a ten-year purchased power agreement with Calpine to purchase 485 MW of

capacity from its Carville Energy Center.97 Purchases under this contract were set

to begin on June 1, 2012, the beginning of the rate year for this case.98 Fifty

percent of the contract was allocated to ETI.99

The resource had been under contract with the Entergy system for some

time, and the Entergy companies have significant experience with the pricing and

costs under the contract. The most recent contract simply allocated the resource

differently to reflect the fact that the “overhang of retail competition” had been

lifted for ETI.100 Because of ETI’s experience with Calpine, the capacity costs are

“well known.”101 The contract sets out specific capacity quantities and prices, and

includes default and other terms to ensure performance. ETI’s historical

experience with the Calpine resource establishes that any deviations from the
96
AR Binder 35, ETI Exh. 34 (Cooper Direct at 21-22 of 25).
97
Id. at 16.
98
Id.
99
Id. at 19 of 25.
100
See AR Binder 43, Vol. L (5/3/12 Tr. at 1938).
101
Id. at 1942.
31
negotiated contract payments will be “very, very small.”102 Both parties to the

contract intend and are incentivized to perform such that they will get the full

benefits of the capacity and price under the contract.103 ETI projected the annual

cost of the Calpine contract will be $14.1 million.104

No witness challenged ETI’s quantification of the costs associated with the

Calpine contract. There is no evidence in the record that there is “substantial

uncertainty” about whether Calpine will perform the contract, or what the annual

costs of the contract will be. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

4. The record does not reasonably support the
Commission’s other reasons for disallowing 100
percent of these known capacity costs.

a. Load Growth

Intervenors and Commission staff championed multiple theories they alleged

would offset ETI’s additional expense under these three contracts. One such

theory` was that the cost increase is not known and measurable because it may be

offset by load growth that occurs after the test year.105

If it were appropriate to consider future load growth in setting base rates,

PURA or the Commission’s rules would say so. Indeed, there are other instances
102
Id.
103
Id. at 1942-43.
104
AR Binder 8 (Cities Exh. 4B [Highly Sensitive], Goins Direct Exh. DWG-2).
105
AR Binder 5, Item 185 (Proposal for Decision at 109); AR Binder 7, Item 244 (Order on
Rehearing at FOF 84).
32
in which PURA does specify that the utility’s recovery of costs should be subject

to an offsetting load growth adjustment. See, e.g., Tex. Util. Code Ann. § 39.455

(utility entitled to recover specified incremental capacity costs “adjusted for load

growth”). For base rates, the legislature has left load growth out of the equation,

so that it may serve as a source of revenue to address other future cost increases

and avoid or defer additional rate increases. The legislature’s inclusion of “load

growth” language for specific circumstances but not base rates is evidence the

legislature did not intend it to apply generally. Cameron v. Terrell & Garrett, Inc.,

618 S.W.2d 535, 540 (Tex. 1981).

Even if load growth could properly be considered, however, it does not

support a wholesale disallowance of the increased purchased capacity costs. First,

the load growth that intervenors suggested would occur would not fully materialize

for at least two years.106 It could not logically offset the third-party capacity cost

increases ETI began to experience during or shortly after the test year.

Second, Cities witness Goins is the only intervenor witness who attempted

to quantify a load growth adjustment, and he quantified it at $15.8 million – a far

cry from the $38 million in increased purchased capacity expense that ETI proved

it would incur.107 Moreover, Mr. Goins’s proposal overstated retail load growth

106
AR Binder 43, Vol. J (5/1/12 Tr. at 1299-1300 [Confidential]).
107
AR Binder 8 (Cities Exhs. 4 & 4B [Highly Sensitive], Goins Direct at 9 & 16-19).
33
significantly and attempted to predict events beyond the rate year.108 It does not

provide a reasonable basis for a known and measurable change at all, much less

one that negates all $38 million of ETI’s third-party capacity contract costs.109

The large gap between Mr. Goins’s speculative adjustment and the known

costs ETI sought illustrates how far the Commission has strayed from setting rates

at a level that will enable ETI to recover the costs it reasonably expects to incur

when the rates are in effect. In any event, the Commission’s reliance on the load

growth theory to deny ETI any adjustment for its post-test-year increases in third-

party purchased capacity costs is not supported by substantial evidence.

b. MSS-1 Costs

Another “offset” theory that the Commission adopted concerned the amount

of money ETI might save under Schedule MSS-1 as a result of the new third-party

purchased capacity contracts. The Commission found that the impact the contracts

would have on ETI’s “reserve equalization” payments under Schedule MSS-1 was

substantially uncertain, because the calculation of MSS-1 costs depends on

“numerous assumptions.”110 The record does not support a wholesale disallowance

of ETI’s third-party capacity cost increases on this ground.

108
Id. at 17-19.
109
AR Binder 37, ETI Exh. 57 (May Rebuttal at 9-11 of 31); AR Binder 43, Vol. I (5/1/12 Tr. at
pp. 1296-1306, 1316-1324 [Confidential]).
110
AR Binder 5, Item 185 (Proposal for Decision at 108); AR Binder 7, Item 244 (Order on
Rehearing at 1 & FOFs 75-76).
34
 Company witness Cooper testified that the MSS-1 cost adjustment is a

straightforward calculation.111 While it is true that the MSS-1 amount is dependent

on the relative load responsibility of ETI, that relative change in load responsibility

was factored into the Company’s calculation.112

Evidence from other parties regarding the MSS-1 costs likewise does not

provide substantial evidence justifying a wholesale disallowance of the third-party

contract costs. Cities, in fact, adopted ETI’s calculation of MSS-1 impacts.113 And

though TIEC argued on one hand that ETI’s MSS-1 expense would increase over

test-year levels,114 the evidence, including TIEC’s, is undisputed that MSS-1 costs

go down as ETI adds new capacity contracts.115 In fact, the MSS-1 costs decreased

during the test year and reached test-year lows during the last two months (when

the new Frontier contract was first put in place).116 TIEC’s recommendations

regarding MSS-1 costs are contrary to reality and all the record evidence. They

certainly do not provide a reasoned basis to reject all of ETI’s proposed increase in

third-party purchased capacity costs.

111
AR Binder 43, Vol. L (5/3/12 Tr. at 1947).
112
See AR Binder 35, ETI Exh. 34 (Cooper Direct at 20 of 25 & ETI Exh. 34A RRC-1 [Highly
Sensitive]).
113
AR Binder 9, Cities Exh. 6 (Nalepa Direct at 17).
114
AR Binder 41, TIEC Exh. 1 (Pollock Direct at 26).
115
AR Binder 41, TIEC Exh. 1D (Pollock Direct at 22, Table 1); AR Binder 9, Cities Exh. 6
(Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).
116
See AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).
35
 c. MSS-4 Costs

The Commission also found that the impact the purchased capacity contracts

would have on MSS-4 costs (costs of unit-specific purchases from other Entergy

operating companies) was substantially uncertain because the calculation of MSS-4

costs depends on “complex mathematical formulae that utilize numerous

variables.”117 However, as shown in the proposal for decision adopted by the

Commission, the adjusted MSS-4 costs sought by the Company are lower than the

test-year level of MSS-4 costs awarded by the Commission. As the Commission

further acknowledged, “while the purchases pursuant to MSS-4 [from test year to

rate year] remain fairly stable, the third-party purchases will substantially increase,

with a somewhat corresponding decrease for purchases pursuant to MSS-1.”118

In other words, the Commission recognized that the known and measurable

adjustment to the test-year amount was driven by third-party purchases, not MSS-4

purchases. The small difference between the test-year and rate-year levels

associated with MSS-4 purchases, under the Commission’s own observations, is

not material to determining the merits of ETI’s proposed purchased power cost

adjustments. In short, alleged uncertainty regarding the rate-year level of MSS-4

117
AR Binder 7, Item 244 (Order on Rehearing at FOFs 79-82).
118
AR Binder 5, Item 185 (Proposal for Decision at 100); AR Binder 7, Item 244 (Order on
Rehearing at 1, adopting Proposal for Decision).
36
expense is not a reasonable basis for the Commission to reject ETI’s additional

third-party purchased power expense.

Even assuming arguendo that the Commission’s rejection of the Company’s

adjustment to MSS-4 expense is material to the resolution of this issue, the

evidence regarding MSS-4 expense does not support rejection of the entire increase

in third-party purchased capacity costs. Similar to ETI, Cities’ and TIEC’s

adjustments for MSS-4 costs in all but one respect varied only marginally from the

test year. They come nowhere near to offsetting the entire cost of the third-party

contracts.119 Cities and TIEC proposed MSS-4 reductions that were materially

larger than ETI’s120 only because one of ETI’s Arkansas affiliate contracts (the

“WBL” contract) was set to terminate after the test year. Intervenors’ argument

was based on the flawed assumption that ETI would take no action to replace the

WBL contract. To the contrary, the evidence was undisputed that ETI was short of

capacity and in fact extended the very contract in question.121 The dispute over

how much ETI might save in MSS-4 costs does not rationally support a

disallowance of the entire increase for the new purchased capacity contracts

119
AR Binder 41, TIEC Exh. 1 (Pollock Direct at Exh. JP-1) (Line 4 shows $1.4 million
reduction to test year amount of affiliate contracts)); AR Binder 8, Cities Exh. 4B (Goins Errata
3 Exh. DWG-2 [Highly Sensitive]) (less than $3 million reduction to test-year costs for affiliate
contracts excluding WBL).
120
$12.7 million and $11.1 million, respectively.
121
AR Binder 43, Vol. E (4/26/12 Tr. at 687-88 & 696); AR Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 5 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1946).
37
 D. The consequences of the Commission’s decision are extreme
and unjust.

The three new third-party purchased power contracts that drive ETI’s

requested adjustment to test-year capacity costs benefit customers tremendously.

They increase the capacity of ETI resources by 618 MW (150 by the Frontier

contract, 225 by the SRMPA contract, and 243 by the half of the Calpine contract

allocated to ETI). They result in substantial fuel savings for customers because of

their diverse fuel resources and efficient heat rates.122 Customers will benefit from

those savings on a dollar-for-dollar basis in fuel reconciliations. While the third-

party owners of the capacity resources profit from the capacity payments ETI must

make, and the retail customers of ETI benefit from the superior heat rates and

resulting fuel savings, the Commission’s order forces the middleman – ETI –to pay

for the capacity with shareholder funds.

The Commission’s draconian adherence to the test-year data and incorrect

application of the standard for making adjustments to that data are reasons alone to

reverse the decision, because they taint every one of the Commission’s findings

discussed above. Even disregarding those errors, none of the Commission’s

findings rationally justifies the disallowance of 100 percent of the cost increase

resulting from the three new contracts. Because the Commission did not quantify

122
AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 7-8 of 21).
38
how much of a disallowance it made upon each individual theory, if this Court

finds any of the findings are unsupported by substantial evidence, it must reverse

the whole disallowance and remand to the Commission for further consideration.

This Court may not decide fact issues the Commission did not. Tex. Gov’t Code

Ann. § 2001.174(1).

III. The Commission erred in setting ETI’s transmission equalization (MSS-
2) expense at the test-year level.

The Commission also erred in refusing to make any adjustment for another

known and measurable increase in ETI’s expenses after the test year. The Entergy

system transmission grid is a large network, the various pieces of which are owned

by individual Entergy operating companies. The network, however, is integrated

and operated for the mutual benefit of all of the Entergy operating companies.123

In any given month, some of the operating companies may be “long” on the

amount of transmission capacity they own. That is, they own a portion of the

transmission capacity that is greater than their share of the overall load placed on

the transmission system. Other operating companies may be “short” on capacity.

The Entergy System Agreement includes a FERC-approved Schedule MSS-2 that

equalizes the ownership costs of certain high-voltage transmission facilities among

the operating companies. The long operating companies receive MSS-2 payments

123
AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. C (4/25/12 Tr. at
450); AR Binder 43, Vol. F (4/27/12 Tr. at 793).
39
from the short operating companies for the use of their transmission facilities so

that each pays its fair share of the total ownership costs of the shared system on a

monthly basis.124

Over the course of the test year, ETI was short, so it paid a total of

$1,753,797 in MSS-2 payments to various other operating companies.125 But

ETI’s MSS-2 expenses increased at the end of the test year and continued to

increase after the test year.126 ETI anticipated these costs would increase even

more by the rate year because of transmission projects that were planned to go into

service by the rate year.127 ETI calculated that its MSS-2 expenses would be $10.7

million annually by the rate year.128 ETI sought to include that level of its expense

in its rates.

The ALJs recommended that the Commission disallow any increase in MSS-

2 expense over the test-year level. They found that the increased expenses were

not “known and measurable,” again because the MSS-2 calculation depends on

variables and projections, and because not all the projects ETI included in its

124
AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. F (4/27/12 Tr. at
731 & 735-36).
125
AR Binder 43, Vol. F (4/27/12 Tr. at 724 & 737); AR Binder 9, Cities Exh. 28.
126
AR Binder 9, Cities Exh. 29.
127
AR Binder 43, Vol. F (4/27/12 Tr. at 761); AR Binder 37, ETI Exh. 59 (McCulla Rebuttal at
2-3 of 12).
128
AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738 &
760).
40
calculation were in service during the test year.129 The Commission adopted the

ALJs’ recommendation that only the test-year level of MSS-2 expense should be

included in ETI’s rates.130

A. The Commission erred as a matter of law in applying the
standard for adjustments to test-year expenses.

The Commission’s decision is flawed as a matter of law for the same reason

its decision about purchased capacity costs is flawed. That is, the goal of

ratemaking is to give the utility a reasonable opportunity to earn a reasonable

return on its investment over and above its reasonable and necessary expenses.

Tex. Util. Code Ann. § 36.051. Commission Rule 25.231 mirrors this principle.

16 Tex. Admin. Code 25.231. This undertaking cannot lawfully turn on the

manner in which the calculation is made, or on the number of inputs to the

calculation. The Commission cannot arbitrarily rely upon test-year levels of

expense to the extent they are proven not to represent the level of expense the

utility is reasonably anticipated to bear in the rate year, or that is “apt to prevail in

the future.” City of El Paso, 883 S.W.2d at 188. If a change is known and can

reasonably be measured, the Commission must make it.

None of the opposing parties’ witnesses refuted that the projects underlying

ETI’s proposed MSS-2 adjustment were already approved and in process, or that

129
AR Binder 5, Item 185 (Proposal for Decision at 116 & FOFs 87-93).
130
AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 87-94).
41
they will be completed. No intervenor or Staff witness offered any testimony or

evidence casting doubt on the reasonableness of the construction cost estimates.

Their position was simply that if there is any possibility of uncertainty or

variability in the elements of an adjustment to test-year data, it must be denied.

The Commission erred as a matter of law in adopting that standard.

B. Additionally, the Commission’s adherence to test-year
expense levels is unsupported by substantial evidence.

It is undisputed that ETI’s test-year level of MSS-2 expense was too low.

Every witness testifying on the issue recognized that the test-year amount is too

small and should be updated based on more recent, actual payment information.

ETI proffered evidence that by the time of the hearing, its annualized MSS-2

expenses based upon actual, known, historical investment exceeded test-year

levels by about $6.7 million, and its rate-year MSS-2 expenses would exceed test-

year levels by almost $9 million.131 TIEC witness Pollock annualized the last six

months of the test-year expense, increasing it by a million dollars.132 Cities

witness Goins also rejected the test-year expense level and instead used a more

recent 12-month period of actual payments, including six months that occurred

after the test year. He recommended the Commission include an annual expense of

131
AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738, 760,
763, 780, & 783-84).
132
AR Binder 41, TIEC Exh. 1 (Pollock Direct at 32-33).
42
$4.1 million in ETI’s rates, exceeding the test year by almost $2.5 million.133

Indeed, Cities Exhibit 29 includes the MSS-2 payment for every month from

January 2010 to February 2012. It shows that MSS-2 costs have steadily increased

every month from the last month of the test year, and in fact have doubled since the

last month of the test year.134 No witness testified that the test year was

representative of the expense ETI would bear during the rate year. The

Commission’s decision that the test-year level of MSS-2 expense is sufficient is

simply not supported by any evidence in the record.

Viewing the evidence as a whole, there is no reasonable basis for a

conclusion that the test-year level of $1.7 million is representative of costs apt to

prevail in the future. The Commission’s ruling is, therefore, unsupported by

substantial evidence and must be reversed. Tex. Gov’t Code Ann.

§ 2001.174(b)(2).

CONCLUSION AND PRAYER

For all these reasons, Entergy Texas, Inc. respectfully requests this Court

reverse the district court’s judgment insofar as it affirms the Public Utility

Commission’s order in the respects discussed above. ETI requests the Court

remand the case to the Commission for further proceedings consistent with the

133
AR Binder 8, Cities Exh. 4 (Goins Direct at 21-22).
134
AR Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI 5-1).
43
Court’s decision. Entergy Texas, Inc. further requests its costs of court and any

other relief to which it may show itself justly entitled.

Respectfully submitted,

/s/ Marnie A. McCormick
John F. Williams
State Bar No. 21554100
Marnie A. McCormick
State Bar No. 00794264
mmccormick@dwmrlaw.com
DUGGINS WREN MANN & ROMERO, LLP
P. O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300
(512) 744-9399 fax

ATTORNEYS FOR APPELLANT
ENTERGY TEXAS, INC.

CERTIFICATE OF COMPLIANCE

I certify that this document contains 10,765 words in the portions of the
document that are subject to the word limits of Texas Rule of Appellate Procedure
9.4(i), as measured by the undersigned’s word-processing software.

/s/ Marnie A. McCormick
Marnie A. McCormick

44
 CERTIFICATE OF SERVICE

The undersigned counsel certifies that the foregoing document was
electronically filed with the Clerk of the Court using the electronic case filing
system of the Court, and that a true and correct copy was served on the following
lead counsel for all parties via electronic service on the 31st day of March, 2015:

Elizabeth R. B. Sterling
Environmental Protection Division
Office of the Attorney General
P. O. Box 12548 (MC 066)
Austin TX 78711-2548
Counsel for Appellee Public Utility Commission of Texas

Rex D. VanMiddlesworth
Benjamin Hallmark
Thompson Knight LLP
98 San Jacinto Blvd., Ste. 1900
Austin TX 78701
Counsel for Intervenor Texas Industrial Energy Consumers

Susan M. Kelley (retired)135
Administrative Law Division
Office of the Attorney General
P. O. Box 12548
Austin TX 78711-2548
Counsel for Intervenor State Agencies

Sara Ferris
Office of Public Utility Counsel
1701 N. Congress Ave., Ste. 9-180
P. O. Box 12397
Austin TX 78711-2397
Counsel for Intervenor Office of Public Utility Counsel

135
State Agencies have not yet appeared or designated a new lead counsel in this appeal.
45
Daniel J. Lawton
LAWTON LAW FIRM PC
12600 Hill Country Blvd., Ste. R-275
Austin TX 78738
Counsel for Cities of Anahuac, et al.

/s/ Marnie A. McCormick
Marnie A. McCormick

46
 APPENDICES

A. ALJs’ Proposal for Decision in Docket No. 39896

B. Commission's Order on Rehearing in Docket No. 39896

C. District Court's Final Judgment

D. Commission’s Final Order in Docket No. 37744

47
 APPENDIX A

ALJ's Proposal for Decision in Docket No. 39896
 SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, § OF
AND OBTAIN DEFERRED §
ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS

PROPOSAL FOR DECISION

TABLE OF CONTENTS

I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]........ 1
II. JURISDICTION AND NOTICE ......................................................................... 2
III. PROCEDURAL HISTORY ................................................................................. 2
IV. EXECUTIVE SUMMARY .................................................................................. 4
A. Rate Base................................................................................................................ 4
1. Capital Investment .................................................................................... 4
2. Hurricane Rita Regulatory Asset ............................................................ 4
3. Prepaid Pension Asset Balance ................................................................ 5
4. FIN 48 Tax Adjustment ............................................................................ 5
5. Cash Working Capital .............................................................................. 5
6. Self-Insurance Storm Reserve ................................................................. 5
7. Coal Inventory........................................................................................... 5
8. Spindletop Gas Storage Facility .............................................................. 5
9. Short Term Assets ..................................................................................... 6
10. Acquisition Adjustment ............................................................................ 6
11. Capitalized Incentive Compensation ...................................................... 6
B. Rate of Return and Capital Structure ................................................................ 6
C. Cost of Service ....................................................................................................... 7
1. Purchased Power Capacity Expense ....................................................... 7
2. Transmission Equalization (MSS-2) Expense ........................................ 7
3. Depreciation Expense ............................................................................... 7
4. Labor Costs................................................................................................ 7
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE II
PUC DOCKET NO. 39896

5. Interest on Customer Deposits................................................................. 8
6. Property (Ad Valorem) Tax Expense ...................................................... 9
7. Advertising, Dues, and Contributions..................................................... 9
8. Other Revenue Related Adjustments ...................................................... 9
9. Federal Income Tax .................................................................................. 9
10. River Bend Decommissioning Expense ................................................... 9
11. Self-Insurance Storm Reserve Expense .................................................. 9
12. Spindletop Gas Storage Facility ............................................................ 10
D. Affiliate Transactions ......................................................................................... 10
E. Jurisdictional Cost Allocation............................................................................ 10
F. Class Cost Allocation .......................................................................................... 11
1. Renewable Energy Credit Rider............................................................ 11
2. Class Cost Allocation .............................................................................. 11
3. Revenue Allocation ................................................................................. 12
4. Rate Design .............................................................................................. 12
G. MISO Transition ................................................................................................. 14
V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] ...... 14
A. Capital Investment [Germane to Preliminary Order Issue No. 17] ............... 14
B. Hurricane Rita Regulatory Asset ...................................................................... 15
C. Prepaid Pension Asset Balance .......................................................................... 23
D. FIN 48 Tax Adjustment ...................................................................................... 26
E. Cash Working Capital ........................................................................................ 30
1. The Revenue Lag Component of the Lead-Lag Study ........................ 31
2. The Expense Lead Component of the Lead-Lag Study ....................... 39
F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue
No. 5] .................................................................................................................... 45
1. The Effect of Prior Settled Cases........................................................... 46
2. OPC’s Proposed Adjustment ................................................................. 49
3. 1997 Ice Storm ......................................................................................... 54
4. Jurisdictional Separation Plan Allocation ............................................ 57
5. $50,000 Reserve Threshold .................................................................... 58
6. Hurricane Rita Regulatory Asset .......................................................... 60
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE III
PUC DOCKET NO. 39896

7. Conclusion ............................................................................................... 60
G. Coal Inventory..................................................................................................... 61
H. Spindletop Gas Storage Facility ........................................................................ 63
I. Short Term Assets ............................................................................................... 68
J. Acquisition Adjustment ...................................................................................... 69
K. Capitalized Incentive Compensation ................................................................ 71
VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and
11] ......................................................................................................................... 73
A. Capital Structure ................................................................................................ 73
B. Return on Equity................................................................................................. 73
1. Proxy Group ............................................................................................ 74
2. DCF Analysis ........................................................................................... 76
3. Risk Premium Analysis .......................................................................... 83
4. Comparable Earnings............................................................................. 88
5. CAPM Analysis ....................................................................................... 90
6. ALJs’ Analysis......................................................................................... 93
C. Cost of Debt ......................................................................................................... 95
D. Overall Rate of Return ....................................................................................... 95
VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2,
3, 4, and 16] .......................................................................................................... 95
A. Purchased Power Capacity Expense [Germane to Supplemental
Preliminary Order Issue No. 1] ......................................................................... 95
1. The Sources of ETI’s Purchased Power................................................ 95
2. ETI’s Request Regarding PPCCs .......................................................... 99
3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal .......... 101
4. The Intervenors’ Recommendations Regarding PPCCs ................... 106
5. The ALJs’ Analysis Regarding PPCCs ............................................... 108
B. Transmission Equalization (MSS-2) Expense ................................................ 110
C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ........ 117
1. Terminology and Methodology............................................................ 118
2. Production Plant ................................................................................... 125
3. Transmission Plant ............................................................................... 132
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE IV
PUC DOCKET NO. 39896

4. Distribution Plant ................................................................................. 140
5. General Plant......................................................................................... 154
6. Fully Accrued Depreciation ................................................................. 160
7. Other Depreciation Issues – Accumulated Provision for
Depreciation .......................................................................................... 161
D. Labor Costs........................................................................................................ 163
1. Payroll and Related Adjustments ........................................................ 163
2. Incentive Compensation ....................................................................... 165
3. Compensation and Benefits Levels ...................................................... 175
4. Non-Qualified Executive Retirement Benefits ................................... 177
5. Employee Relocation Costs .................................................................. 179
6. Executive Perquisites ............................................................................ 180
E. Interest on Customer Deposits......................................................................... 181
F. Property (Ad Valorem) Tax Expense .............................................................. 181
G. Advertising, Dues, and Contributions............................................................. 185
H. Other Revenue-Related Adjustments ............................................................. 185
I. Federal Income Tax .......................................................................................... 185
J. River Bend Decommissioning Expense ........................................................... 186
K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order
Issue No. 5]......................................................................................................... 188
L. Spindletop Gas Storage Facility ...................................................................... 193
VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue
No. 3] .................................................................................................................. 194
A. Large Industrial & Commercial Sales Reallocation ...................................... 199
B. Administration Costs ........................................................................................ 201
C. Customer Service Operations Class ................................................................ 202
1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095
(Headquarter’s Credit & Collect), F3PCR73380 (Credit
Systems), and F3PCR73458 (Credit Call Outsourcing) .................... 202
2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk),
F3PCR73390 (Customer Svs Ctl - Entergy Bus), and
F3PCR73403 (Customer Issue Resolution – ES) ............................... 203
D. Distribution Operations Class ......................................................................... 203
1. Project F5PCDW0200 (Lineman’s Rodeo Expenses) ........................ 204
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE V
PUC DOCKET NO. 39896

2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and
F3PCTJTUSE (Joint Use With Third Parties – A)............................ 204
E. Energy and Fuel Management Class .............................................................. 205
1. Project F3PCWE0140 (EMO Regulatory Affairs) ............................ 205
2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense),
F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004
(SPO Summer09RFP IM & Propslsubmt), and F3PPWET303
(SPO2008 Winter Westn RegionRFP-IM) ......................................... 206
3. Project F3PCCSPSYS (System Planning and Strategic) .................. 207
F. Environmental Service Class ........................................................................... 207
G. Federal PRG Affairs Class ............................................................................... 209
1. Project F5PPSPE044 (PMO Support Initiative-System) .................. 209
2. Project F3PPUTLDER (Utility Derivatives Compliance) ................. 210
3. Project F3PCSYSRAF (System Regulatory Affairs-Federal) .......... 211
H. Financial Services Class ................................................................................... 214
1. Projects F3PCF05700 (Corporate Planning & Analysis),
F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000
(Financial Forecasting), F3PPADSENT (Analytic/Decision
Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-
Entergy) ................................................................................................. 214
2. Projects F3PCF20990 (Operations Exec VP & CFO) and
F3PCFF1001 (OCE Support)............................................................... 215
3. Project F3PCR73345 (Quick Payment Center, Adm) ....................... 216
4. Project F3PCF23936 (Manage Cash) .................................................. 217
I. Human Resources Class ................................................................................... 218
1. Project F3PCHRCCSM (HR Competitive Compensation) .............. 218
2. Projects (Non-Qualified Post-Retirement) and F5PPZNQBDU
(Non-Qual Pension/Benf-Dom Utl)...................................................... 219
J. Information Technology Class ......................................................................... 219
1. (Evaluated Receipts Settlement) ......................................................... 220
2. Project F3PCFX3555 (BOD/Executive Support) ............................... 220
K. Internal and External Communications Class ............................................... 221
L. Legal Services Class .......................................................................................... 222
1. Project F3PPCASHCT (Contractual Alternative/Cashpo) .............. 223
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VI
PUC DOCKET NO. 39896

2. Project F5PCZLDEPT (Supervision & Support – Legal)................. 223
3. Project F3PCF99180 (Corp. Compliance Tracking Sys) .................. 223
4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and
F3PPTDHY19 (Dept. of Justice Investigation) .................................. 224
5. Project F3PCE01601 (Ferc - Access Transmission) ......................... 226
6. Project F3PCERAKTL (RAKTL Patent Matter) ............................. 227
7. Project F3PPEASTIN (Willard Eastin et al.) ..................................... 228
8. Project F3PPTCGS11 (TX Docket Competitive Generation) .......... 229
9. Project F5PCE13759 (Jenkins Class Action Suit) ............................. 230
10. Project F3PCSYSAGR (System Agreement-2001) ............................ 231
11. Project F3PCCDVDAT (Corporate Development Data Room) ....... 232
12. Project F3PPWET302 (SPO 2008 Winter Western Region) ............ 233
13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) ........... 234
M. Other Expenses Class ....................................................................................... 235
1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and
F5PPKATRPT (Storm Cost Processing & Review) .......................... 235
2. Project F3PCC08500 (Executive VP, Operations)............................. 236
3. Projects F3PPBFMESI (ESI Function Migration Relocation),
F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI
Disaster Recovery Plan Charge), F5PPBFMREL (Business
Function Migration Employee), F5PPBFRREL (Business
Function Relocation), F5PPBFRSEV (Business Function
Relocation Severance), F5PPDRPREL (Disaster Recovery Plan
Relocation), and F5PPETXRFI (2009 Texas Ike Recovery Filing) .. 236
N. Regulatory Services Class ................................................................................ 238
O. Retail Operations Class .................................................................................... 239
1. Project F5PPICCIMG (ICC – “Image” Message) ............................. 240
2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920
(Wholesale - All Jurisdictions) ............................................................. 240
P. Supply Chain Class ........................................................................................... 241
Q. Transmission and Distribution Support Class ............................................... 242
R. Tax Services Class ............................................................................................. 244
S. Transmission Operations Class ....................................................................... 245
T. Treasury Operations Class .............................................................................. 246
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VII
PUC DOCKET NO. 39896

U. Utility and Executive Management Class ....................................................... 249
IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary
Order Issue No. 13] ........................................................................................... 250
A. A&E 4CP ........................................................................................................... 251
B. 12CP ................................................................................................................... 252
X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to
Preliminary Order Issue No. 1] ....................................................................... 255
A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue
No. 19] ................................................................................................................ 255
1. ETI’s Proposed Cost Recovery ............................................................ 255
2. Opposition to ETI’s Proposal .............................................................. 256
3. ETI’s Response ...................................................................................... 260
4. ALJs’ Analysis....................................................................................... 261
B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ......... 262
1. Municipal Franchise Fees .................................................................... 262
2. Miscellaneous Gross Receipts Taxes ................................................... 267
3. Capacity-Related Production Costs .................................................... 268
4. Transmission Costs ............................................................................... 273
C. Revenue Allocation ........................................................................................... 274
1. Argument for Moving Rates to Cost ................................................... 275
2. Argument for Gradualism ................................................................... 278
3. ALJs’ Recommendation ....................................................................... 281
D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] .... 282
1. Lighting and Traffic Signal Schedules ................................................ 283
2. Demand Ratchet .................................................................................... 287
3. Large Industrial Power Service (LIPS) .............................................. 295
4. Schedulable Intermittent Pumping Service (SIPS)............................ 299
5. Standby Maintenance Service (SMS) .................................................. 303
6. Additional Facilities Charge (AFC) .................................................... 310
7. Large General Service (LGS) .............................................................. 313
8. General Service (GS) ............................................................................ 315
9. Residential Service (RS) ....................................................................... 315
SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VIII
PUC DOCKET NO. 39896

XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue
Nos. 21-31] ......................................................................................................... 319
A. Spindletop Gas Storage Facility ...................................................................... 324
B. Use of Current Line Losses for Fuel Cost Allocation .................................... 325
C. ETI’s Special Circumstances Request ............................................................ 326
XII. OTHER ISSUES ............................................................................................... 327
A. MISO Transition Expenses [Germane to Preliminary Order Issue
Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] ............. 327
1. Deferred Accounting............................................................................. 329
2. Base Rate Recovery............................................................................... 336
B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue
No. 2] .................................................................................................................. 338
C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue
No. 2] .................................................................................................................. 338
D. Purchased Power Capacity Cost Baseline [Germane to Supplemental
Preliminary Order Issue No. 1] ....................................................................... 339
XIII. CONCLUSION ................................................................................................. 341
XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
ORDERING PARAGRAPHS .......................................................................... 341
A. Findings of Fact ................................................................................................. 341
B. Conclusions of Law ........................................................................................... 364
C. Proposed Ordering Paragraphs ...................................................................... 366

List of Acronyms and Defined Terms

Attachment A
 List of Acronyms and Defined Terms

TERM DEFINITION
12CP 12 Coincident Peak
A&E 4CP Average and Excess, 4 Coincident Peak
A&P Average and Single Coincident Peak
ADFIT Accumulated Deferred Federal Income Tax
AFC Additional Facilities Charge
AFUDC Allowance for Funds Used During Construction
ALJs Administrative Law Judges
BCII/U3 Big Cajun II, Unit 3
Brazos Brazos Electric Cooperative, Inc.
Calpine Calpine Energy Services
Contract for the purchase of 485 MW of capacity from
Carville Contract Calpine’s Carville Energy Center
CAPM Capital Asset Pricing Model
CenterPoint CenterPoint Energy Houston Electric, LLC
CGS Competitive Generation Service
CI Conformance Index
Anahuac, Beaumont, Bridge City, Cleveland, Conroe,
Dayton, Groves, Houston, Huntsville, Montgomery,
Navasota, Nederland, Oak Ridge North, Orange, Pine
Forest, Rose City, Pinehurst, Port Arthur, Port Neches,
Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and
Cities West Orange, Texas
Commission Public Utility Commission of Texas
Company Entergy Texas, Inc.
CP Coincident Peak
CWIP Construction Work in Progress
DCF Discounted Cash Flow
DCRF Distribution Cost Recovery Factor
DOE United States Department of Energy
DOJ United States Department of Justice
EAI Entergy Arkansas, Inc.
EA WBL 2009 Contract between ETI and EAI for Wholesale Base
Contract Load Resources
EGSI Entergy Gulf States, Inc., predecessor to ETI
EGSL Entergy Gulf States Louisiana, LLC
ELL Entergy Louisiana, Inc.
EMI Entergy Mississippi, Inc.
Enbridge Long-term Gas Supply Contract between ETI and Enbridge
Contract Pipeline, L.P.
ENOI Entergy New Orleans, Inc.
Entergy Entergy Corporation
TERM DEFINITION
ESI Entergy Services, Inc.
ETEC East Texas Electric Cooperative, Inc.
ETI Entergy Texas, Inc.
FAS 106 FASB Statement No. 106
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FIN 48 Financial Interpretation Number 48
GAAP Generally Accepted Accounting Principles
GDP Gross Domestic Product
GS General Service
GSU Gulf States Utilities Company
Iowa Curves Various Known Patterns of Industrial Asset Mortality Rates
IRS Internal Revenue Service
ISB Intra-System Bill
Class action lawsuit filed in Texas district court in 2003 on
Jenkins Class behalf of all Texas retail customers served by ETI’s
Action predecessor-in-interest, EGSI
Kroger The Kroger Co.
kW Kilowatt
kWh Kilowatt-hour
LED Light Emitting Diode
LGS Large General Service
LIPS Large Industrial Power Service
MFF Municipal Franchise Fees
MGRT Miscellaneous Gross Receipts Tax
MISO Midwest Independent Transmission System Operator, Inc.
MSS-2 Schedule MSS-2 of the Entergy System Agreement
MW Megawatt
Moody’s Moody’s Investors Service
MWh Megawatt-hour
NARUC National Association of Regulatory Utility Commissioners
Nelson Nelson 6, a 550 MW Unit located in Westlake, Louisiana
O&M Operations and Maintenance
OATT Open Access Transmission Tariff
OPC Office of Public Utility Counsel
PFD Proposal for Decision
PPCCs Purchased Power Capacity Costs
PPR Purchased Power Rider
PUC Public Utility Commission of Texas
PURA Public Utility Regulatory Act
Rate Year June 1, 2012, through May 31, 2013
Reconciliation
Period July 1, 2009, through June 30, 2011
TERM DEFINITION
RECs Renewable Energy Credits
Reserve Strategic Petroleum Reserve
River Bend River Bend Nuclear Generating Station Unit No. 1
ROE Return on Equity
RRC Railroad Commission of Texas
RS Residential Service
RTO Regional Transmission Organization
S&P Standard & Poor’s
SFAS Statement of Financial Accounting Standards
SIPS Schedulable Intermittent Pumping Service
SMS Standby Maintenance Service
SOAH State Office of Administrative Hearings
Spindletop
Facility Spindletop Gas Storage Facility
SRMPA Sam Rayburn Municipal Power Agency
Staff Staff of the Public Utility Commission of Texas
State Agencies State of Texas State Agencies
T&D Transmission and Distribution
TCRF Transmission Cost Recovery Factor
Test Year July 1, 2010, through June 30, 2011
TIEC Texas Industrial Energy Consumers
Value Line Value Line Investment Survey
Wal-Mart Wal-Mart Stores, LLC, and Sam’s East, Inc.
Zacks Zacks Investment Service
 SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, § OF
AND OBTAIN DEFERRED §
ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS

PROPOSAL FOR DECISION

I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]

Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
service area located in southeastern Texas. ETI serves retail and wholesale electric customers in
Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal
Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations.

On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the
period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff
schedules presented in the Electric Utility Rate Filing Package for Generating Utilities
accompanying ETI’s application and including new riders for recovery of costs related to purchased
power capacity and renewable energy credit requirements; (3) a request for final reconciliation of
ETI’s fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30,
2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package
Schedule V accompanying ETI’s application. The rate year for ETI’s proposed changes is June 1,
2012, through May 31, 2013 (Rate Year).1 On April 13, 2012, adjusted its request for a proposed
increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year
revenues.

1
During the hearing the parties used the term “Rate Year” to refer to the period June 2012 through May
2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates
in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes
of this PFD, Rate Year will refer to the period June 2012 through May 2013.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 2
PUC DOCKET NO. 39896

II. JURISDICTION AND NOTICE

The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and
this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001,
33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the
contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to
PURA § 14.053 and Tex. Gov’t Code § 2003.049(b). Those municipalities in ETI’s service area that
have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction
over ETI’s rates, operations, and services in their respective municipalities pursuant to PURA
§ 33.001. When ETI filed its application with the Commission, it also filed the application with its
original jurisdiction cities. Pursuant to PURA §§ 32.001(b), 33.051, and 33.053, ETI appealed the
actions of the original jurisdiction cities to the Commission and had those appeals consolidated with
this docket.

ETI’s notice of its application and notice of the hearing were not contested and, therefore, do
not require further discussion but will be addressed in the proposed findings of fact and conclusions
of law.

III. PROCEDURAL HISTORY

As noted above, ETI filed its application and rate filing package on November 28, 2011. On
November 29, 2011, the Commission referred this proceeding to SOAH. On December 19, 2011,
the Commission issued its Preliminary Order setting forth 31 issues to be addressed in this
proceeding. On January 19, 2012, the Commission issued a Supplemental Preliminary Order listing
two additional issues to be considered and stating that ETI’s request for a purchased power cost
recovery rider should not be addressed in this docket.

On September 2, 2011, ETI filed an application requesting authority to defer accounting
related to its proposed transition to membership in the Midwest Independent Transmission System
Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22,
2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 3
PUC DOCKET NO. 39896

threshold legal/policy questions and setting forth nine issues to be addressed in the proceeding. On
December 20, 2011, Docket No. 39741 was consolidated into this docket for all purposes.

The following entities were granted intervenor status in this case: Texas Industrial Energy
Consumers (TIEC); State of Texas State Agencies (State Agencies); Office of Public Utility Counsel
(OPC); the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves,
Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest,
Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor,
and West Orange (Cities); The Kroger Co. (Kroger); Wal-Mart Stores, LLC, and Sam’s East, Inc.
(Wal-Mart); East Texas Electric Cooperative, Inc. (ETEC); and the United States Department of
Energy (DOE).

The hearing on the merits convened before SOAH Administrative Law Judges (ALJs)
Thomas H. Walston, Steven D. Arnold, and Hunter Burkhalter on April 24, 2012, and continued
through May 4, 2012. The record remained open for the filing of post-hearing briefs and proposed
finds of fact and conclusions of law. On June 8, 2012, the parties filed proposed finds of fact and
conclusions of law and the record closed. As permitted by P.U.C. PROC. R. 22.261(a), ALJ Lilo D.
Pomerleau read the record and joined in writing the PFD. Number running began on June 26, 2012,
and Staff returned the final numbers to the ALJs on July 3, 2012. The parties requested that the ALJs
submit their PFD so the Commission could consider the matter at its July 27, 2012, open meeting.

The following is a list of the parties who participated in the hearing and their counsel:

PARTIES REPRESENTATIVES
ETI Steven H. Neinast, Casey Wren, and John F. Williams2
Cities Daniel J. Lawton, Stephen Mack, and Molly Mayhall
TIEC Rex. D. VanMiddlesworth, Meghan Griffiths, and James
Nortey
State of Texas Susan Kelley
OPC Sara J. Ferris
DOE Steven A. Porter

2
Several other attorneys appeared on behalf of ETI. The ALJs listed only the three attorneys who appeared
throughout the hearing.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 4
PUC DOCKET NO. 39896

PARTIES REPRESENTATIVES
Kroger Kurt J. Boehm
Wal-Mart Rick D. Chamberlain
Staff Scott Smyth, Joseph Younger, Jacob J. Lawler, and Jason
Haas

IV. EXECUTIVE SUMMARY

ETI proposed an overall increase of approximately $104.8 million. The ALJs recommend an
overall rate increase for ETI of $16.4 million, as shown on the schedules attached to this PFD. With
respect to ETI’s request to reconcile fuel and purchased power costs during the Reconciliation
Period, the ALJs recommend approval without change. Attachment A contains the schedules
provided by Commission Staff reflecting the ALJs’ recommendations. On issues of particular
significance, the ALJs’ recommendations are set forth below.

A. Rate Base

1. Capital Investment

ETI’s capital additions closed to plant in service between July 1, 2009, and June 30, 2011,
were prudently incurred and are used and useful in providing service to ETI’s customers.

2. Hurricane Rita Regulatory Asset

The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744,3 less amortization accruals to the end of the Test Year
in the present case, and less the amount of additional insurance proceeds received by ETI after the
conclusion of Docket No. 37744. This produces a remaining balance of $15,175,563, which should
remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced
August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm
insurance reserve.

3
Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 5
PUC DOCKET NO. 39896

3. Prepaid Pension Asset Balance

The construction work in progress (CWIP)-related portion of ETI’s pension asset
($25,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for
funds used during construction.

4. FIN 48 Tax Adjustment

The Commission should find that $4,621,778 (representing ETI’s full FIN 48 Liability of
$5,916,461 less the $1,294,683 cash deposit ETI has made with the Internal Revenue Service (IRS)
for the FIN 48 Liability) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate
base.

5. Cash Working Capital

The ALJs recommend no changes to ETI’s cash working capital.

6. Self-Insurance Storm Reserve

The Commission should approve ETI’s Test Year-end storm reserve balance of negative
$59,799,744.

7. Coal Inventory

The full value of ETI’s coal inventory was reasonable and should be included in rate base.

8. Spindletop Gas Storage Facility

The Spindletop Gas Storage Facility (Spindletop Facility) is a used and useful facility
providing reliability and swing flexibility to ETI’s customers at a reasonable price and should be
included in rate base.

No. 37744 (Dec. 13, 2010).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 6
PUC DOCKET NO. 39896

9. Short Term Assets

The ALJs recommend Staff’s proposal to include the following amounts in rate base:
prepayments at $8,134,351 ($916,313 more than ETI’s request); materials and supplies at
$29,285,421 ($32,847 more than ETI’s request); and fuel inventory at $52,693,485 ($1,066,490 less
than ETI’s request).

10. Acquisition Adjustment

The $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of
the Spindletop Facility was reasonable, necessary, properly incurred, and should be included in rate
base.

11. Capitalized Incentive Compensation

The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009. The
reasonableness of ETI’s capital costs (including capitalized incentive compensation) was dealt with
by the Commission in that proceeding and is not at issue here. Thus, exclusion of capitalized
incentive compensation that is financially-based can only be made for incentive costs that ETI
capitalized during the period from July 1, 2009 (the end of the prior Test Year) through June 30,
2010 (the commencement of the current Test Year).

B. Rate of Return and Capital Structure

The ALJs recommend a return on equity (ROE) of 9.80 percent; a cost of debt of
6.74 percent; a capital structure comprised of 50.08 percent debt and 49.92 percent common equity;
and an overall rate of return of 8.27 percent. This is a downward adjustment to ETI’s request for a
10.60 percent ROE, and no change to ETI’s 6.74 percent cost of debt and 50.08/49.92 capital
structure. It compares to Staff’s proposed 9.60 percent ROE; OPC’s proposed 9.30 percent ROE;
TIEC’s proposed 9.50 percent ROE; Cities’ proposed 9.50 percent ROE; and State Agencies’
proposed 9.30 percent ROE. No party opposed ETI’s proposed 6.74 percent cost of debt or its
proposed 50.08/49.92 capital structure.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 7
PUC DOCKET NO. 39896

C. Cost of Service

1. Purchased Power Capacity Expense

ETI’s purchased power capacity costs should be set at the amount of the Company’s Test
Year level, which is $245,432,884.

2. Transmission Equalization (MSS-2) Expense

ETI should recover only the amount of expenses under Schedule MSS-2 of the Entergy
System Agreement it paid in the Test Year, $1,753,797.

3. Depreciation Expense

The interim retirements methodology should not be adopted. The values proposed by ETI
should be adopted except for the following:

Service Lives:
Account 364-40 R1.
Account 368-33 L0.5.

Net Salvage:
Production Plant- negative 5 percent.
Account 354-negative 5 percent
Account 361-negative 5 percent.
Account 362-negative 10 percent.
Account 368-negative 5 percent.
Account 369.1-negative 10 percent.
Account 369.2-negative 10 percent.

4. Labor Costs

¾ Payroll and Related Adjustments

The Commission should accept: (1) the payroll adjustments proposed in the ETI application;
and (2) the further payroll adjustments proposed by Staff as corrected by ETI.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 8
PUC DOCKET NO. 39896

¾ Incentive Compensation

ETI should not be entitled to recover its financially based incentive compensation costs.
Thus, the ALJs recommend removing $6,196,037 from ETI’s requested operation and maintenance
(O&M) expenses. Additionally, an additional reduction should be made to account for the FICA
taxes that ETI would have paid as a result of those costs.

¾ Compensation and Benefit Levels

ETI met its burden to prove the reasonableness of its base pay and incentive package costs.
It is reasonable to view market price for these categories of costs as lying within a range of +/-
10 percent of median, rather than being a single point along a spectrum. As to both base pay and the
incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly,
the ALJs recommend rejecting the adjustments sought by Cities.

¾ Nonqualified Executive Retirement Benefits

The ALJs recommend an adjustment to remove $2,114,931, representing the full costs
associated with ETI’s non-qualified executive retirement benefits.

¾ Employee Relocation Costs

The Commission should allow ETI’s relocation expenses.

¾ Executive Perquisites

The ALJs recommend an adjustment to remove $40,620, representing the full cost of ETI’s
executive perquisite costs.

5. Interest on Customer Deposits

The ALJs recommend using the active customer deposits amount of $35,872,476 and the
2012 interest rate, which produces a recommended interest expense of $43,047 ($35,872,476
multiplied by .12 percent).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 9
PUC DOCKET NO. 39896

6. Property (Ad Valorem) Tax Expense

ETI’s property tax burden should be adjusted upward by applying the effective tax rate of
0.007435784 for the calendar year 2011 to the final, adopted Test Year-end plant in service value for
ETI.

7. Advertising, Dues, and Contributions

The ALJs recommend an adjustment to remove $12,800 from ETI’s costs of advertising,
dues and contributions.

8. Other Revenue Related Adjustments

These amounts were determined through number running and are reflected in Attachment A.

9. Federal Income Tax

The Commission should adopt ETI’s proposal on federal income taxes.

10. River Bend Decommissioning Expense

ETI’s annual decommissioning revenue requirement should reflect the most current
calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro forma cost of service is
needed to reflect the difference between the requested level for decommissioning costs of
$2,019,000 and the recommended level of $1,126,000.

11. Self-Insurance Storm Reserve Expense

The Commission should approve a total annual accrual of $8,270,000, comprised of an
annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual
accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The ALJs
recommend approval of ETI’s proposed target reserve of $17,595,000. The Commission should
require ETI to continue recording its annual accrual until modified by future Commission orders.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 10
PUC DOCKET NO. 39896

12. Spindletop Gas Storage Facility

The ALJs recommend inclusion of the costs of operating the Spindletop Facility as requested
by ETI.

D. Affiliate Transactions

ETI agreed to remove the following affiliate transactions from its request, which the ALJs
recommend be approved: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the
amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of
$14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.
Except as noted below, all remaining affiliate transactions should be approved. The ALJs
recommend that the following affiliate transactions not be included:

¾ $356,151 (which figure includes the $112,531 agreed to by ETI) of costs
associated with Projects F5PCZUBENQ (Non-Qualified Post
Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl);

¾ $10,279 of costs associated with Project F3PPFXERSP (Evaluated
Receipts Settlement);

¾ $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et
al); and

¾ $171,032 of costs associated with Project F3PPE9981S (Integrated
Energy Management for ESI).

E. Jurisdictional Cost Allocation

The ALJs recommend the use of 12 Coincident Peak (12CP) to allocate capacity-related
production costs between the retail and wholesale jurisdictions.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 11
PUC DOCKET NO. 39896

F. Class Cost Allocation

1. Renewable Energy Credit Rider

The Commission should deny ETI’s request to institute a renewable energy credit rider, and
the Test Year expense of $623,303 should be used for setting rates in this case. Finally, the
Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an
adjustment to the credit rates to reflect the Test Year data used to set ETI’s base rates.

2. Class Cost Allocation

The parties generally agreed that ETI’s cost-of-service study comported with accepted
industry practices, but some parties had issues with specific items discussed below.

(a) Municipal Franchise Fees

Municipal franchise fees should be allocated on the basis of in-city kilowatt-hour (kWh)
sales, without an adjustment for the municipal franchise fee rate in the municipality in which a given
kWh sale occurred. The ALJs recommend adoption of ETI’s proposal to collect costs from all
customers taking service from the system.

(b) Miscellaneous Gross Receipts Tax

Similar to municipal franchise fees, miscellaneous gross receipts taxes should be allocated to
the rate classes according to ETI’s cost of service study.

(c) Capacity-Related Production Costs

The ALJs recommend the use of Average and Excess 4 Coincident Peak (A&E 4CP) to
allocate capacity-related production costs, as proposed by ETI. The ALJs do not find sufficient
support to allocate the reserve equalization payments differently than other capacity-related
production costs.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 12
PUC DOCKET NO. 39896

(d) Transmission Costs

ETI’s proposed methodology for allocation of transmission costs should be approved. A&E
4CP is a well-accepted method for allocating such costs.

3. Revenue Allocation

Revenue allocation in this case should be based on each class’s cost of service and consistent
with the ALJs’ recommendations in the PFD that impact revenue allocation.

4. Rate Design

(a) Lighting and Traffic Signal Schedules

ETI should be directed to perform a light emitting diode (LED) lighting cost study before
significant changes are made to its lighting rates. The ALJs further recommend that ETI conduct
this study before filing its next rate case and provide the results of any completed study to Cities and
interested parties. The study should include detailed information regarding differences in the cost of
serving LED and non-LED lighting customers, if ETI currently has LED lighting customers taking
service. ETI should modify the applicable tariffs to eliminate its fee for any replacement of a
functioning light with a lower-wattage bulb.

(b) Demand Ratchet

ETI’s proposed Large Industrial Power Service (LIPS) tariff should be amended to include
the language proposed by DOE witness Etheridge.

(c) Large Industrial Power Service

The ALJs recommend the adoption of a $630 customer charge for this customer class, a
slight decrease in the LIPS energy charges, and an increase in the demand charges from current rates
for this class, as proposed by Staff witness Abbott.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 13
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(d) Schedulable Intermittent Pumping Service

The Commission should adopt the Schedulable Intermittent Pumping Service rider proposed
by DOE witness Etheridge.

(e) Standby Maintenance Service

The Commission should adopt the changes to Schedule SMS recommended by TIEC, with
the exception of a $6,000 customer charge. Consistent with the ALJs’ recommendation that a new
LIPS charge of $630 is reasonable, the Standby Maintenance Service (SMS) charge should be
limited to $630 and not apply if a Schedule SMS customer also purchased supplementary power
under another applicable rate.

(f) Additional Facilities Charge

Schedule AFC should be changed in accordance with TIEC’s recommendations and those
recommended numbers should be reduced in proportion to any authorized reduction in ETI’s
proposed rate of return, O&M expense, and property tax expense.

(g) Large General Service

Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand
ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is
applicable to this class

(h) General Service

The Commission should adopt the decrease in the Schedule GS customer charge to $39.91
from the current (and Company proposed) rate of $41.09, as well as Staff’s recommended decrease
in energy charges. Schedule GS also has a demand ratchet, and the ALJs’ recommendation for the
elimination of ETI’s LIPS demand ratchet is applicable to this class.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 14
PUC DOCKET NO. 39896

(i) Residential Service

ETI’s declining block winter rates provide a disincentive to energy efficiency. The ALJs
recommend an initial 20 percent reduction, followed by 20 percent subsequent reductions of the
differential in the next three rate cases unless ETI provides sufficient evidence that such changes are
unjust and unreasonable.

G. MISO Transition

The Commission should deny ETI’s request for deferred accounting of its MISO transition
expenses to be incurred on or after January 1, 2011. However, the Commission should authorize
ETI to include $2.4 million of MISO transition expense in base rates set in the present case, based on
a five-year amortization of $12 million in total projected expenses. Further, the Commission should
authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of
the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of
$2,452,800.

V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16]

A. Capital Investment [Germane to Preliminary Order Issue No. 17]

ETI presented for review $408,078,600 in capital additions closed to plant in service between
July 1, 2009, and June 30, 2011; that is, from the end of the test year in the Company’s last base rate
case, which was Docket No. 37744, through the Test Year presented in this case. The capital
additions were detailed in the testimony and exhibits of the following Company witnesses: Garrison
(Generation), McCulla (Transmission), Corkran (Distribution), Stokes (Customer Service), Brown
(Information Technology), Plauche (Administrative), Cicio (System Planning and Operations),
Hunter (Supply Chain), May (Regulatory), and Sloan (Legal).4 The evidence shows that these

4
ETI Ex. 27 (Garrison Direct) at 20-28 and WWG-4; ETI Ex. 32 (McCulla Direct) at 64-92 and MFM-16;
ETI Ex. 25 (Corkran Direct) at 78-108 and SBC-3; ETI Ex. 37A (Roman Direct, adopted by Stokes) at 121-
125 and AFR-5; ETI Ex. 24 (Brown Direct) at 29-37 and JFB-3; ETI Ex. 20 (Plauche Direct) at 37-44 and
TCP-11; ETI Ex. 39 (Cicio Direct) at 71-75 and PJC-6; ETI Ex. 16 (Hunter Direct) at 34-38 and JMH-7; ETI
Ex. 7 (May Direct) at 53-54 and PRM-3; and ETI Ex. 38 (Sloan Direct) at 37-43 and RDS-4.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 15
PUC DOCKET NO. 39896

capital additions were prudently incurred and are used and useful in providing service to ETI’s
customers. No party challenged any of the capital additions or the costs thereof, and the ALJs find
no reason to do so either.

B. Hurricane Rita Regulatory Asset

Hurricane Rita struck the upper Texas coast in September 2005, causing extensive property
damage. In 2006, the Texas Legislature enacted PURA Chapter 39 to authorize electric utilities such
as ETI to securitize the recovery of their reconstruction costs incurred as a result of Hurricane Rita.
Under the statute, the amount of reconstruction costs to be securitized had to be reduced by the
insurance proceeds and government grants received by a utility. If additional insurance or grant
proceeds were received after the securitization order was approved, the Commission was required to
take those amounts into account in the utility’s next base rate case. This was provided in
Section 39.459(c) of PURA:

To the extent a utility subject to this subchapter receives insurance proceeds,
governmental grants, or any other source of funding that compensates it for hurricane
reconstruction costs, those amounts shall be used to reduce the utility’s hurricane
reconstruction costs recoverable from customers. If the timing of a utility’s receipt
of those amounts prevents their inclusion as a reduction to the hurricane
reconstruction costs that are securitized, the commission shall take those amounts
into account in:

(1) the utility’s next base rate proceeding; or
(2) any proceeding in which the commission considers hurricane
reconstruction costs.

Docket No. 32907 was the proceeding for ETI to determine the amount of Hurricane Rita
reconstruction costs that it could securitize, net of any proceeds received from insurance or
government grants.5 In that case, ETI asserted that it incurred $393,236,384 in Hurricane Rita
reconstruction costs for its Texas Retail jurisdiction. The parties reached a settlement in that case,
which set ETI’s hurricane reconstruction expenses eligible for securitization at $381,236,384. In

5
Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket
No. 32907 (Dec. 1, 2006).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 16
PUC DOCKET NO. 39896

addition, ETI estimated that it would receive $65,700,000 in future insurance proceeds that, pursuant
to the settlement, was deducted from the amount to be securitized. The parties also agreed that after
ETI received all of its insurance payments, a true-up would occur to reflect the difference between
the $65,700,000 credited and the amount actually received. The settlement agreement provided that
if ETI received more insurance payments than estimated, the excess payments would be passed
through to ratepayers in the form of a rider; however, the agreement did not address how an under-
recovery by ETI would be handled. It turned out that ETI received only $46,013,904 in insurance
proceeds,6 leaving a $19,686,096 under-recovery by ETI, which the parties refer to as Overestimated
Insurance Proceeds.7

Docket No. 37744 was ETI’s next base rate case after Docket No. 32907. In Docket
No. 37744, ETI requested recovery of the Overestimated Insurance Proceeds by establishing a
regulatory asset of $19,686,096, plus accrued carrying costs, to be amortized over five years.8
Docket No. 37744 also concluded by a black-box settlement, and neither the Stipulation and
Settlement Agreement nor the Order entered by the Commission specifically addressed the proposed
regulatory asset or any other recovery for Overestimated Insurance Proceeds.

In the present case, ETI has again sought approval of a regulatory asset to recover
$26,229,627, for the balance of Overestimated Insurance Proceeds, plus carrying costs through
June 30, 2011.9 Cities objected to the amount of ETI’s request. They argue that this issue was
resolved in Docket No. 37744 and that ETI should have been amortizing the asset since the
conclusion of that case. Staff also argues that the issue was resolved in Docket No. 37744 and
requested that ETI’s request be denied entirely; or, alternatively, that it should be considered
partially amortized and accordingly reduced. ETI argues that the issue was not resolved in Docket
No. 37744 and that it should be allowed a full recovery in the present case. Alternatively, ETI
argues that Cities’ proposed reduction was not calculated correctly.

6
See Docket No. 32907, Final Order at FoF 27. Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.
7
$19,686,096 = 65,700,000 - $46,013,904.
8
Cities Ex. 2 (Garrett Direct) at 11.
9
Schedule P Cost of Service Workpapers, Vol. 2, ETI Ex. 3 at AJ 15, page 15.3.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 17
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Cities’ expert accounting witness, Mark Garrett, testified that ETI should have been
amortizing the balance of Overestimated Insurance Proceeds since the effective date of rates set in
Docket No. 37744. In addition, he argues that ETI should not have continued to accrue interest on
the balance that was added into rate base in that docket, because it would have then earned a rate of
return. Therefore, Mr. Garrett’s adjustment started with the balance of $25,278,210 that ETI
requested in Docket No. 37744. He reduced that balance by $9,479,329 for amortization between
the date rates went into effect in Docket No. 37744 and the date that rates will go into effect in the
current case (22.5 months). Mr. Garrett further reduced the remaining balance by $5,678,960 to
account for additional insurance proceeds received by ETI after Docket No. 37744. By
Mr. Garrett’s calculations, this left a remaining balance of Overestimated Insurance Proceeds of
$11,071,338.10 Both Mr. Garrett and Cities witness Jacob Pous also recommended that this
remaining balance not be carried as a regulatory asset but, instead, be moved to the storm insurance
reserve for recovery.11 In their view, this would ensure that the remaining balance would be
properly recovered.

In response to ETI’s argument that the Hurricane Rita Regulatory Asset was not resolved in
Docket No. 37744, Cities stress that Docket No. 37744 settled as a “black box settlement.” In
Cities’ opinion, such a settlement should not be interpreted as changing the status quo unless
expressly stated in the settlement agreement or final order. Cities contend that the status quo in
Docket No. 37744 was that ETI was authorized to recover its Over Estimated Insurance Proceeds,
because recovery was authorized by PURA § 39.459(c); recovery had been previously approved in
Docket No. 32907; and no party objected to its recovery in Docket No. 37744. Therefore, Cities
state, the final order in Docket No. 37744 should be interpreted as authorizing ETI’s requested
recovery of the Hurricane Rita Regulatory asset in the rates set in that docket.12

Cities also disagree with ETI’s alternative argument that Mr. Garrett improperly calculated
the remaining balance of the asset by deducting an amount for insurance proceeds ETI received after

10
Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.
11
Id. (Garrett Direct) at 12; Cities Ex. 5 (Pous Direct) at 64.
12
Cities Reply Brief at 10-14.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 18
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Docket No. 37744 concluded. Cities state that Mr. Garrett’s adjustment was correct because it
began with the balance requested in Docket No. 37744, before the additional insurance proceeds
were received. In other words, Mr. Garret did not start with the balance claimed by ETI in the
present case,13 so he correctly applied the amount received after Docket No. 37744 to reduce the
balance claimed in that docket.14 According to Cities, Mr. Garrett began with the prior balance to
properly reflect that no carrying charges would accrue on the balance after it was included in rate
base and recovered a return through rates.15 Cities also dispute ETI’s argument that Mr. Garrett
should not have accounted for amortization occurring between the Test Year and the Rate Year as an
“invalid post-test year adjustment.”16 In Cities’ view, this was a valid known and measureable
change that should be taken into account.17

Staff recommends that the Hurricane Rita Regulatory Asset be removed from rate base
entirely. Staff witness Anna Givens stated that it is reasonable to assume that this asset was included
as part of the settlement in Docket No. 37744. Accordingly, she stated that it is not appropriate for
ETI to request recovery of the same asset in the present docket. Therefore, Ms. Givens
recommended removal of the entire requested $26,229,627 Hurricane Rita regulatory asset from
ETI’s rate base.18

Alternatively, Ms. Givens proposed that the Commission allow ETI a regulatory asset of
$17,486,418, to be amortized over 40 months. Ms. Givens noted that higher rates from Docket
No. 37744 first went into effect on August 15, 2010;19 therefore, at least one-third of the regulatory
asset should have been amortized by the conclusion of the present case. Using ETI’s updated
hurricane regulatory asset request of $26,229,627, Ms. Givens recommended a decrease of one-third

13
Cities Initial Brief at 8.
14
Cities Ex. 2B (Garrett Direct), Exhibit MG-2.3.
15
Docket No. 32907, Final Order at FoF 28.
16
ETI’s Initial Brief at 7.
17
Cities’ Reply Brief at 10-14.
18
Staff Ex. 1 (Givens Direct) at 32-34.
19
Docket No. 37744, Order, FoF 16 (Dec. 13, 2010).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 19
PUC DOCKET NO. 39896

to ETI’s request. This would equal an $8,743,209 reduction, resulting in her recommended
regulatory asset of $17,486,418 ($26,229,627 - $8,743,209). Ms. Givens also recommended that the
amortization period be decreased from 60 months to 40 months, which is the time remaining on
ETI’s original Docket No. 37744 request.20

ETI disagrees with Cities and Staff, and it argues that its total requested Hurricane Rita
regulatory asset should be included in rate base in this case. First, it notes that no instruction in the
Stipulation and Settlement Agreement filed in Docket No. 37744 required ETI to begin amortizing
the asset or otherwise directed the treatment of the asset. Likewise, no Finding of Fact or
Conclusion of Law in the agreed order entered in Docket No. 37744 authorized the proposed
treatment of the asset. In contrast, ETI notes, the settlement in Docket No. 32907 does specifically
address the treatment of this asset, and it argues that its request to include the full Hurricane Rita
regulatory asset in rate base in the present case is consistent with that settlement. In ETI’s opinion,
it has not previously been authorized to establish the regulatory asset, it has not amortized it, and the
full amount should be included in rate base in this case.21

Alternatively, if Cities’ proposed amortization is accepted, ETI argues that Mr. Garrett’s
calculations were wrong. First, ETI states, Mr. Garrett incorrectly assumed that the $26,229,627
Hurricane Rita regulatory asset requested in this case did not account for the $5,678,960 of
insurance proceeds that ETI received after Docket No. 37744. According to ETI, the $5,678,960
was accounted for, as shown on WP/P AJ 15.3. Therefore, ETI states, Mr. Garrett’s adjustment for
this $5.6 million would remove this amount from the asset a second time.22 Second, ETI argues that
Mr. Garrett erred by amortizing the asset by 22.5 months. Mr. Garrett calculated the amortization
period from the time rates went into effect after Docket No. 37744 (August 15, 2010) through the
time revised rates would go into effect in this docket (June 30, 2012). ETI states that Mr. Garrett

20
Staff Ex. 1 (Givens Direct) at 34. Ms. Givens noted that amount recommended in Docket No. 37744 was
$25,278,000, which is $951,627 less than the amount requested in the current proceeding. However, she
stated that this does not affect her recommendation, because by the time the hearing on the merits concluded,
at least another two months of amortization expense under the existing rates would be collected by the ETI
and should adequately compensate it for the difference. Staff Ex. 1 (Givens Direct) at 35.
21
ETI Ex. 46 (Considine Rebuttal) at 19-24; ETI Initial Brief at 5-6.
22
ETI Ex. 46 (Considine Rebuttal) at 21-22; ETI Initial Brief at 7.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 20
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made an invalid post-test year adjustment because post-test year adjustments for rate base items are
limited to plant additions recorded in FERC Accounts 101 or 102. In contrast, regulatory assets, like
the Hurricane Rita regulatory asset, are recorded in Account 182.3. Therefore, in ETI’s opinion, if it
was required to amortize this regulatory asset, it would be appropriate to amortize it for only
10.5 months, to the end of the Test Year (August 15, 2010, through June 30, 2011). These two
corrections would adjust Mr. Garrett’s proposed asset balance from $10,714,557 to $21,805,940.23

ETI also disagrees with Mr. Pous’ recommendation that the regulatory asset be removed
from rate base and placed in the storm reserve, to be amortized over 20 years. In ETI’s opinion, this
approach would defeat the purpose of securitization, which is to provide ETI with cost recovery in
an expedited manner.24

Finally, ETI argues that Ms. Givens’ analysis was flawed. It reiterated that no provision in
the Stipulation and Settlement Agreement or the final order filed in Docket No. 37744 directed the
treatment of the regulatory asset or stated that ETI would begin amortizing the asset. Further, ETI
stresses that it never sought recovery of the entire asset all at once in Docket No. 37744. Instead,
ETI requests recovery over a period of years through amortization. Thus, according to ETI, even if
Ms. Givens’ argument were accepted, the entire asset should not be disallowed.25

This issue is a close call because the black-box settlement agreement and final order in
Docket No. 37744 did not expressly state how the Hurricane Rita regulatory asset issue was
resolved. The following factors support finding that the Hurricane Rita regulatory asset issue was
resolved in Docket No. 37744:

x the settlement agreement and final order in Docket No. 32907 expressly provided that the
difference between the amount of ETI’s estimated insurance proceeds and the amount actually
received by ETI would be trued up after ETI received the proceeds;

23
ETI Ex. 46 (Considine Rebuttal) at 22; ETI Initial Brief at 7-8.
24
ETI Initial Brief at 8.
25
ETI Ex. 46 (Considine Rebuttal) at 21; Id. at 8-9.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 21
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x PURA § 39.459(c) provides that if the timing of a utility’s receipt of insurance proceeds
prevented their inclusion as a reduction to the securitized costs, the Commission “shall take
those amounts into account . . . in the utility’s next base rate proceeding;”

x Docket No. 37744 was ETI’s next base rate proceeding;

x in Docket No. 37744, ETI requested a true-up concerning the insurance proceeds, and it
requested that a regulatory asset be established for the deficit and amortized over five years;

x in Docket No. 37744, no party objected to ETI’s proposed regulatory asset or amortization;

x the stipulation and settlement agreement entered by the parties in Docket No. 37744 stated that
the parties resolved all issues, except for ETI’s Competitive Generation Service (CGS) proposal;
and

x neither the stipulation and settlement agreement nor the Order entered in Docket No. 37744
specifically disapproved, excluded, or deferred consideration ETI’s proposed regulatory asset,
although they did specifically exclude or disapprove other items, such as ETI’s CGS proposal
and various proposed riders.

On the other hand, some factors support a finding that the Hurricane Rita regulatory asset
issue was not resolved in Docket No. 37744. The stipulation and settlement agreement and the
Order entered in Docket No. 37744 did not expressly approve ETI’s proposed regulatory asset,
although certain other items were expressly approved, such as River Bend Nuclear Generating
Station Unit No. 1 (River Bend) decommissioning costs, depreciation rates, and other items. Also,
utilities are typically not allowed to create regulatory assets without express approval of the
Commission.

Thus, the difficulty with this issue is the nature of the black-box settlement of Docket
No. 37744. In the settlement, the parties agreed to an increase in base rate revenues of $59 million
effective August 15, 2010, with an additional increase in base rate revenues effective May 2, 2011.
However, there was no explanation on how this increase was determined, and there was no specific
agreement or finding on the amount of ETI’s rate base or its reasonable and necessary cost of
service. In that case, there was no objection to ETI’s proposed Hurricane Rita regulatory asset, it
was authorized by the prior settlement in Docket No. 32907, and the Commission was directed by
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 22
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PURA § 39.459(c) to take into account ETI’s insurance proceeds related to the Hurricane Rita
securitized costs in ETI’s next rate case, which was Docket No. 37744. Moreover, when there is
uncertainty whether an undisputed issue was deferred for future consideration or was included
within the rates set in a black-box settlement, the burden should be on the utility to establish that the
issue was deferred for future consideration. When all the evidence and factors are considered, the
ALJs find that that ETI’s proposed Hurricane Rita regulatory asset should be considered as having
been approved in Docket No. 37744, and ETI should have amortized the asset since August 15,
2010, the effective date of rates approved in that docket.

The ALJs also find that none of the amortization calculations proposed by the parties were
entirely correct. ETI’s proposal to start with its requested $26,229,627 was flawed because it
included carrying costs from August 15, 2010, when the asset should have been included in rate
base, to June 30, 2011, the end of the Test Year in the present case. During that period, the asset
would have earned a rate of return as part of rate base, and accrual of carrying costs should have
ceased. Therefore, it would be more accurate to begin amortizing the Hurricane Rita regulatory
asset by using the balance requested by ETI in Docket No. 37744. That amount, according to Mr.
Garrett, was $25,278,210. However, the amortization calculation should not extend beyond the end
of the Test Year in the present case (June 30, 2011), as proposed by Cities and Staff. P.U.C. SUBST.
R. 25.231(c)(2)(F)(ii) provides for post-test-year reductions to rate base, and the recommendation for
a post-test-year adjustment to the Hurricane Rita regulatory asset does not fall within the scope of
that rule. The balance remaining after amortization to the end of the Test Year should be further
reduced by $5,678,960 to account for additional insurance proceeds received by ETI after Docket
No. 37744 concluded but before the end of the Test Year in the present case. ETI argues that this
reduction was already included in its request. However, as discussed above, the appropriate
calculation should begin with the balance of the asset at the conclusion of Docket No. 37744, not the
balance requested by ETI in the present case. The balance of the asset at the conclusion of Docket
No. 37744 did not account for the additional insurance proceeds paid to ETI afterwards, so it should
be deducted now. In summary, the ALJs find that the appropriate amount of the Hurricane Rita
regulatory asset to be included in rate base in this case should be calculated as follows:
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 23
PUC DOCKET NO. 39896

Beginning balance at conclusion of Docket No. 37744 (original balance + carrying charges) $25,278,210

Less amortization for period 8/15/10 to 6/30/11 = 10.5 months / 60 months = 17.5% - $4,423,687

Less additional insurance proceeds received - $5,678,960

Remaining balance of Hurricane Rita regulatory asset $15,175,563

Finally, the ALJs recommend that the Commission not adopt the recommendation of Cities
to move the Hurricane Rita regulatory asset to the storm insurance reserve for recovery. As noted by
ETI, one purpose of enactment of PURA Chapter 39 was to allow expedited recovery of costs
resulting from Hurricane Rita storm damage. Moving the regulatory asset to the storm insurance
reserve would defeat that purpose and negate the five-year amortization plan the parties agreed to in
Docket No. 37744.

In summary, the ALJs find that ETI’s proposed Hurricane Rita regulatory asset was an issue
resolved by the black-box settlement in Docket No. 37744. Therefore, ETI should have included the
asset in rate base at the conclusion of that docket and should have begun amortizing it over a period
of five years. The accrual of carrying charges should have ceased when Docket No. 37744
concluded, because the asset would have then begun earning a rate of return as part of rate base. The
appropriate calculation of the asset should begin with the amount claimed by ETI in Docket
No. 37744, less amortization accruals to the end of the Test Year in the present case, and less the
amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.
This produces a remaining balance of $15,175,563, which should remain in rate base as a regulatory
asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the
Hurricane Rita regulatory asset should not be moved to the storm insurance reserve.

C. Prepaid Pension Asset Balance

ETI included in rate base an item titled Unfunded Pension in the amount of $55,973,545.26
The amount requested in this account represents the accumulated difference between the Statement
of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual

26
ETI Ex. 3, Sched. B-1, Line 10.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 24
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contributions made by the Company to the pension fund.27 It is a debit balance, meaning that the
Company has contributed roughly $56 million more to its pension fund than the minimum required
by SFAS 87.28 Other than Cities, no party opposes ETI’s request to include this item in rate base.

Cities argue that ETI ought not be entitled to include this amount in rate base because it
represents amounts the ETI overpaid to its pension, resulting in little to no benefit to ratepayers.
Cities witness Mark Garrett pointed out that ETI earned only 1.37 percent on its pension assets over
the past five years, while it is seeking a rate of return of more than 11 percent. Thus, he argues, if
the asset were included in rate base, ratepayers would pay a substantial premium for the slight
pension cost savings ETI’s excess contributions may have achieved.29

Cities argue that the entire prepaid pension asset should be removed from rate base because
ETI has not justified its inclusion. This would reduce pro forma rate base by $36,382,803, which is
the net amount of the prepaid balance less accumulated deferred income tax ($55,973,545 –
$19,590,740 = $36,382,803). At the same time, Cities would increase operating expense by
$498,284, to provide a 1.37 percent return on the net balance of ETI’s prepaid pension asset
balance.30

Alternatively, Cities contend that the Commission should treat the pension assets in the same
manner as the approach adopted by the Commission in Docket No. 33309.31 In that docket, the
Commission allowed a pension prepayment asset, less accrued deferred federal income taxes
(ADFIT) and less the portion of the asset that is capitalized to CWIP, to be included in rate base. As
to the excluded portion, the Commission allowed the accrual of an allowance for funds used during
construction (AFUDC). Thus, Cities contend, if the Commission opts for this approach, it should
allow ETI’s pension prepayment asset, less ADFIT, to be included in rate base, but excluding

27
Cities Ex. 2 (Garrett Direct) at 7.
28
ETI Initial Brief at 10; Cities Ex. 2 (Garrett Direct) at 8.
29
Cities Ex. 2 (Garrett Direct) at 8-9.
30
Id. at 10, MG-2.2; Cities Initial Brief at 10.
31
Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change Rates),
Docket No. 38772, Order on Remand at FoF 15A (Jan. 30, 2011).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 25
PUC DOCKET NO. 39896

$25,311,236 for the portion of the prepaid pension balance associated with CWIP, and allow
AFUDC to accrue on the excluded balance.32

ETI responds first by disputing Mr. Garrett’s contention that it has unreasonably overpaid
into its pension fund. It contends it has made contributions to the pension fund in accordance with
contribution guidelines established by the Employee Retirement Income Security Act of 1974 and
the Internal Revenue Code of 1986, and that the contributions were within the allowable range of
contributions deductible for tax purposes. ETI also was guided in its required pension contributions
by the Pension Protection Act of 2006 rules, effective beginning with the 2008 plan year.33

ETI next disputes Cities’ contention that the earnings associated with ETI’s pension
contributions provide insufficient benefits to justify inclusion of the asset in rate base. ETI points
out that ratepayer benefits are not just limited to the level provided by the actual pension fund
earnings on investment. Rather, under FAS 87, pension costs included in the cost of service for
ratemaking purposes are intended to include the expected rate of return on assets. Thus, ETI argues
that the expected long-term rate of return on ETI’s assets is 8.5 percent, not the actual earnings as
suggested by Mr. Garrett.34

On behalf of ETI, Mr. Considine testified that the pension balance is no different than any
other prepayments made by the Company, which are included in rate base and earn a full return on
rate base. Furthermore, the Company would be allowed to earn a full return on rate base had the
Company invested these same dollars in Plant in Service, but the Company in this case used funds to
contribute to a still under-funded pension plan and at the same time provided a timely reduction to
formerly FAS 87 annual pension cost, thereby immediately benefitting ratepayers.35 Therefore, ETI
argues it is clearly investor-supplied capital and accordingly should earn the Company’s requested
return on rate base.

32
Cities Initial Brief at 8-9; Cities Ex. 2 (Garret Direct) at 12.
33
ETI Ex. 46 (Considine Rebuttal) at 22.
34
Id.
35
Id. at 23-24.
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ETI acknowledged the approach to this issue taken by the Commission in Docket No. 33309,
but failed to explain why it is distinguishable from the present case.36

The ALJs conclude that the approach taken by the Commission in Docket No. 33309 was
sound and should be applied in the present case. Neither party adequately explained why the
circumstances of the present case are distinguishable. Thus, the ALJs recommend that the
CWIP-related portion of ETI’s pension asset ($25,311,236 out of the total asset) should be excluded
from the asset, but accrue allowance for funds used during construction.

D. FIN 48 Tax Adjustment

The Financial Accounting Standards Board (FASB) is the body that establishes the rules that
constitute generally accepted accounting principles (GAAP). FASB’s Interpretation No. 48
(FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential
consequences of tax positions that the company has taken which are legally “uncertain.” Pursuant to
FIN 48, ETI and its independent auditors are required to evaluate each of its uncertain tax positions
to determine, under the most objective, reasonable standards, which portion of each position will
most likely ultimately have to be paid to taxing authorities if challenged by the authorities. FIN 48
requires that this portion be excluded from ADFIT for financial reporting purposes and accrue
interest and, in some cases, penalties.37

ETI and its auditors periodically perform the FIN 48 analysis. In so doing, they have
concluded that the Company has taken a number of uncertain tax positions that the Company expects
to lose if challenged by the IRS. ETI concluded that these uncertain tax positions result in a total of
$5,916,461 in tax dollars that the Company expects it will ultimately have to pay, with interest, to
the IRS. As required by FIN 48, this amount is recorded on ETI’s balance sheet as a tax liability.38
In other words, ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (ETI’s FIN 48

36
ETI Initial Brief at 10-11.
37
ETI Ex. 70 (Warren Rebuttal) at 9-12.
38
ETI Ex. 64 (Roberts Rebuttal) at 4-7.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 27
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Liability) in reliance upon tax positions that the Company believes will not prevail in the event the
positions are challenged, via an audit, by the IRS.

In preparing its application in this proceeding, ETI made an accounting adjustment to its Test
Year numbers by not including the $5,916,461 in its ADFIT balance. This had the effect of reducing
the Company’s Test Year deferred tax balance and, therefore, increasing its rate base.39

Cities witness Mark Garrrett asserted that the deduction of $5,916,461 – representing ETI’s
FIN 48 Liability – should be added to ETI’s ADFIT balance and thus be used to reduce the
Company’s rate base. Mr. Garrett pointed out that the Commission first considered this issue in a
recent Oncor docket.40 In that docket, the Commission decided to include FIN 48 liabilities in
ADFIT because of the low likelihood that the IRS would actually audit and review the issue.41
Mr. Garrett testified that this is a fair result because: (1) a utility with FIN 48 liabilities might never
have its underlying uncertain tax positions audited by the IRS; and (2) even if the uncertain positions
are audited by the IRS, the utility might prevail on them. In either case, the utility would never have
to pay those tax amounts. Moreover, during the time when the uncertainty exists, the utility enjoys
the use of cost-free capital (from the deferred taxes associated with the deductions) at its disposal.42
Thus, Mr. Garrett recommends that ETI’s ADFIT balance be increased by $5,916,461 to reinstate
the FIN 48 Liability removed by the Company.43

ETI witnesses Rory Roberts and James Warren stated that the $5,916,461 should not be
included in the Company’s ADFIT balance. Mr. Roberts explained that, because the Company
expects to lose on its uncertain tax positions, it expects that it will ultimately have to pay $5,916,461
in taxes to the IRS, plus interest. Accordingly, Mr. Garrett testified that the amount does not

39
Id. at 4.
40
Cities Ex. 2 (Garrett Direct) at 5-7. See also Application of Oncor Electric Delivery Company LLC for
Authority to Change Rates, Docket No. 35717, Order on Reh’g (Nov. 30, 2009).
41
Id. at 18 FOF 59 (“The IRS may not audit or reverse Oncor’s position as to the tax deductions identified as
FIN 48 deductions and moved into the FIN 48 reserve.”).
42
Cities Ex. 2 (Garrett Direct) at 5-6.
43
Id. at 7.
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represent cost-free funds available to the Company and, as such, should not be included in the
Company’s ADFIT balance.44

Both the Cities and ETI agree that ETI’s rate base “should reflect the actual amount of cost
free capital in the ADFIT accounts at Test Year end.”45 However, ETI witness Mr. Warren testified
that the FIN 48 Liability is not cost-free capital to the Company because the best available expert
opinion in the record of this case is that ETI will “most likely” ultimately have to pay the money to
the IRS, with interest.46

Moreover, Mr. Warren pointed out that, beginning with 2010 tax returns, a corporate
taxpayer is required to complete and file a Schedule UTP, on which the taxpayer must specifically
identify and describe its FIN 48 positions. Mr. Warren contended that, because ETI must now
annually file a Schedule UTP, it is more likely that the IRS will audit the Company, thereby forcing
it to pay the FIN 48 Liabilities, with interest.47 This constitutes additional support for the notion that
the FIN 48 Liability is not cost-free capital for the Company. Mr. Warren correctly points out that,
in a recent CenterPoint Energy Houston Electric, LLC, (CenterPoint) rate case, the Commission
specifically acknowledged that filing of a Schedule UTP makes it more likely that a company will be
audited. In that case, the ALJs recommended that CenterPoint’s FIN 48 Liability, totaling some
$164 million, be added to CenterPoint’s ADFIT, thereby reducing its rate base. The Commission
adopted the recommendation. However, in light of its conclusion that the filing of a Schedule UTP
increases the likelihood of an audit, the Commission authorized CenterPoint to establish a deferred
tax account rider to enable it to recover any portion of its FIN 48 Liability that it might ultimately be
forced to pay to the IRS, plus interest.48 ETI does not necessarily oppose the use of a rider in this

44
ETI Ex. 64 (Roberts Rebuttal) at 7.
45
Cities Ex. 2 (Garrett Direct) at 6; see also ETI Ex. 70 (Warren Rebuttal) at 6-7.
46
ETI Ex. 70 (Warren Rebuttal) at 17.
47
Id. at 14, 20-21.
48
ETI Ex. 70 (Warren Rebuttal) at 19-20. See also Application of CenterPoint Electric Delivery Company,
LLC, for Authority to Change Rates, Docket No. 38339, Order on Reh’g at 3-4 (June 23, 2011).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 29
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case, but contends that it would be preferable to simply exclude ETI’s FIN 48 Liability from its
ADFIT balance, thereby increasing its rate base.49

In the alternative that the Commission rejects ETI’s request to exclude the full amount of the
FIN 48 Liability from the Company’s ADFIT balance, ETI contends that at least any amount of cash
deposit the Company has made with the IRS that is attributable to the FIN 48 Liability should be
removed from the Company’s ADFIT balance.50 The Cities’ witness, Mr. Garrett, agrees.51 Staff
also agrees, arguing that ETI should be required to increase its ADFIT balance by the amount of its
FIN 48 Liability less the amount of any cash deposit attributable to the liability that ETI has made
with the IRS.52 ETI has made a cash deposit with the IRS in the amount of $1,294,683. This
amount is associated with the Company’s FIN 48 Liability.53

Consistent with prior Commission precedent from the Oncor and CenterPoint proceedings,
the ALJs conclude that ETI’s FIN 48 Liability should be included in the Company’s ADFIT balance.
There is, however, one caveat to this conclusion. The amount of the cash deposit made by ETI to
the IRS which is attributable to the Company’s FIN 48 Liability should not be included in the
ADFIT balance. Therefore, the ALJs recommend that the Commission find that $4,621,778
(representing ETI’s full FIN 48 Liability of $5,916,461 less the $1,294,683 cash deposit ETI has
made with the IRS) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate base. No
party expressly advocated the addition of a deferred tax account rider,54 and the ALJs do not
recommend one in this case.

49
ETI Initial Brief at 13; ETI Ex. 70 (Warren Rebuttal) at 20.
50
ETI Ex. 64 (Roberts Rebuttal) at 8-9.
51
Cities Ex. 2 (Garrett Direct) at 7 n. 4.
52
Staff’s Initial Brief at 11-12.
53
ETI Ex. 64 (Roberts Rebuttal) at 8.
54
Cities and Staff both point out that there is much less need for a deferred tax account rider in the present
case than there was in the CenterPoint case, where CenterPoint had $164 million in FIN 48 liabilities. Cities
Reply Brief at 18; Staff Reply Brief at 10.
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E. Cash Working Capital

Rate base includes a reasonable allowance for cash working capital. Cash working capital
represents the average amount of investor capital used to bridge the gap in time between when
expenditures are made by ETI to provide services and when the corresponding revenues are received
by ETI.55 Generally, an increase in revenue lag days and/or a decrease in expense lead days will
result in an increase to the amount of cash working capital included in the rate base. Conversely, a
decrease in revenue lag days and/or an increase in expense lead days will reduce the cash working
capital included in rate base. A properly prepared lead-lag study can result in either a positive cash
working capital amount (and therefore an increase to the rate base) or a negative cash working
capital amount (and a corresponding decrease to the rate base).

Pursuant to P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), ETI calculated its cash working
capital allowance by performing a lead-lag study. ETI witness Jay Joyce prepared the lead-lag study
for the Company. Based upon the study, ETI requests a cash working capital addition to its rate base
of negative $2,013,921.56

Only Staff and Cities submitted evidence and argument relevant to the cash working capital
requirement. Staff does not challenge the accuracy of the lead and lag days determined in
Mr. Joyce’s study. Instead, Staff witness Anna Givens recommends that the cash working capital
calculation be updated to reflect the impacts of Staff’s recommended adjustments to ETI’s O&M
costs and taxes.57 ETI agrees that the final cash working capital amount should be updated to reflect
the actual revenue requirements approved by the Commission in this case.58

Cities witness Jacob Pous asserts that Mr. Joyce’s lead-lag study contains a number of errors
which understate the negative cash working capital requirements of the Company. Mr. Pous asserts
that the correct cash working capital amount for inclusion in ETI’s rate base is negative $24,000,000

55
ETI Ex. 17 (Joyce Direct) at 4.
56
Id. at 20 and JJJ-3.
57
Staff Ex. 1 (Givens Direct) at 30-31.
58
ETI Ex. 54 (Joyce Rebuttal) at 37; ETI Initial Brief at 14.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 31
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(more than an order of magnitude increase of the negative amount).59 Each of the major components
of the lead-lag study, and Cities’ criticisms of same, will be discussed in turn.

1. The Revenue Lag Component of the Lead-Lag Study

Mr. Pous raises a number of criticisms about the revenue lag component of Mr. Joyce’s lead
lag study. There are four parts to the revenue lag component: (1) the “service period lag,” which
consists of the roughly 15 days from the mid-point of the month in which service is provided to the
end of that month; (2) the “billing lag,” which represents the time between the date a customer’s
meter is read and the date a bill is issued to the customer; (3) the “collection lag,” which represents
the time between the issuance of the bill and the date the customer’s payment is received; and
(4) ”receipt of funds lag,” which measures the delay between ETI’s receipt of payment and the
bank’s clearance of the payment.60 When the four parts were combined together, Mr. Joyce
identified ETI’s revenue lag as 43.86 days.61

(a) Billing Lag

Mr. Joyce identified the billing lags (i.e., the delay between when meters are read and bills
are sent to customers) as ranging from 5.4 to 5.65 days, depending upon the customer class.62 On
behalf of the Cities, Mr. Pous asserted that this duration is too long. Mr. Pous complained that the
billing lag in ETI’s lead-lag study is longer than in studies from previous ratemaking proceedings
involving ETI’s predecessor, despite the fact that, in the interim between studies, ETI has invested
substantially in electronic meter reading devices and computer systems that ought to shorten the lag
time. According to Mr. Pous, in a previous proceeding, ETI’s predecessor identified its billing lag
as only 3.61 days.63 Mr. Pous also pointed out that the Railroad Commission of Texas (RRC),
recently adopted a 1-day billing lag for a large gas utility, Atmos Mid-Tex, due to the utility’s use of

59
Cities Ex. 5 (Pous Direct) at 72.
60
ETI Ex. 17 (Joyce Direct) at 8-10.
61
Id. at JJJ-3.
62
Cities Ex. 5 (Pous Direct) at 74.
63
Id.
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modern electronic meter reading devices (the Atmos Mid-Tex RRC proceeding). Mr. Pous stated
that the billing lag identified by ETI would unjustly reward the Company for being inefficient in
sending out its bills because customers should not be punished if the utility decides to manage its
billing processing and payment system less efficiently. Thus, Mr. Pous recommended a schedule of
different billing lags for different customer classes. For residential and commercial customers,
Mr. Pous recommended a 1.46 day billing lag, based since ETI’s predecessor claimed such a lag in a
prior PUC docket (Docket No. 12852). For large industrial, public authority, and street lighting
customers, Mr. Pous recommends a billing lag of 3.72 days. He calculated that the combined impact
of these adjustments would result in a 41.10-day total revenue lag (as compared to Mr. Joyce’s
figure of 43.86 days). Mr. Pous then calculates that this shorter lag period results in an additional
negative cash working capital of $11.4 million.64

ETI responds by pointing out that the 1.46-day billing lag suggested by Mr. Pous for
residential and commercial customers was derived from a rate case by ETI’s predecessor from 1993,
whereas Mr. Joyce more properly relied on actual Test Year data. Mr. Joyce asserted that Mr. Pous,
in effect, “cherry picked” the 1.46-day figure from one page of a 47-page study associated with the
1993 rate case, and that the remaining pages of the study have not been located and, therefore,
cannot be evaluated. Thus, Mr. Joyce testified, “[i]t is unfair and unreasonable to use such an old
document to attempt to support a position when reasonable, contemporaneous evidence exists.”65

ETI argues that it is more appropriate in this case to rely upon ETI’s actual residential and
commercial billing practices, rather than to substitute artificial and arbitrary 1.46-day and 3.72-day
periods derived from other sources. According to Mr. Joyce, it is unavoidably necessary, when
conducting a lead-lag study, to take into account the actual amount of time employed by ETI in
performing all of the activities in its billing-cycle-based meter reading and billing processes.
Mr. Joyce complains that Mr. Pous’ approach would jettison this actual data and analysis derived

64
Id. at 75-77.
65
ETI Ex. 54 (Joyce Rebuttal) at 11.
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from the Test Year and improperly substitute arbitrary numbers based upon a prior, dated, rate
proceeding.66

Mr. Joyce acknowledged that the RRC recently adopted a 1-day billing lag in the Atmos
Mid-Tex RRC proceeding. He pointed out, however, that the RRC did so simply because Atmos
Mid-Tex failed to present evidence supporting a longer billing lag. Additionally, Mr. Joyce pointed
out that the RRC promptly reversed itself in Atmos Mid-Tex’s next rate case, adopting a longer
billing lag after the company provided sufficient evidence to support the longer period.67

ETI also provided extensive evidence regarding the details of its meter reading and billing
process.68 ETI witness Dolores Stokes explained that the meter reading and billing cycle includes
time for extensive quality assurance activities to ensure accurate billing, thereby preventing
unnecessary frustration for the customer and additional costs to the Company that would be required
for customer service, rebilling, and account corrections.69

Cities questioned Mr. Joyce at the hearing about the billing lag period in this case compared
to ETI’s last rate case. Mr. Joyce explained that the total period from meter reading to collection of
billing revenues had not changed appreciably between the two cases, but due to a difference in lead-
lag methodology, the date that divides the two components of that lag – metering to billing and
billing to collection – had changed.70 As a result, the first period – billing lag – was longer than in
the previous case but the second period – collection lag – was shorter.71 ETI introduced into
evidence a response to a Cities RFI that discussed this difference in more detail.72 After explaining

66
Id. at 5-7.
67
Id.at 8-9.
68
ETI Ex. 54 (Joyce Rebuttal); ETI Ex. 66 (Stokes Rebuttal).
69
ETI Ex. 66 (Stokes Rebuttal) at 18.
70
Tr. at 499-500, 502.
71
Tr. at 499-502.
72
ETI Ex. 73.
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the change in lead-lag methodology, the RFI response concluded that “the combined billing and
collection lags are substantially similar from the prior case to this current case.”73

The ALJs conclude that ETI has met its burden to show that the billing lag it utilized in the
lead-lag study is reasonable and appropriate. Absent his own opinion, Mr. Pous does not offer
meaningful evidence to support his assertion that the Company’s billing lag is too long or that the
Company’s billing practices are inefficient. For example, he offered no criticism of any specific
billing practice of the Company. The only support for his charge of inefficiency is that the billing
lag in a previous ETI rate case was shorter. Mr. Joyce convincingly explained that this was merely
an artifact of changes in the methodology of the lead-lag study – the billing lag became longer, but
the collection lag became shorter.

Mr. Pous’ reliance upon an example from the RRC is unconvincing. Similarly, his reliance
upon data from a previous rate case is unpersuasive, especially because only a very limited snippet
of data from that case is available, the case occurred roughly 20 years ago, and it involved a different
company. It is not possible, from the evidence in the record, to know how different or similar ETI’s
current billing practices are to those used in the previous case.

In this case, ETI has thoroughly explained its metering and billing processes and established
that those processes are reasonable. The Company is therefore entitled to establish rates based on
the actual cash working capital necessary to facilitate those policies. The ALJs recommend rejecting
Cities’ request to shorten the billing lag time identified in ETI’s lead-lag study

(b) Collection Lag

In his lead-lag study, Mr. Joyce identified various collection lags (i.e., the delay between the
issuance of an electric bill and the date the customer’s payment is received) for different classes of
customers. As to third-party customers, the collection lag was determined using a random sample of
invoices from residential, commercial, industrial, public authority, and street light customer billings
during the Test Year, measuring the time between when the bills were mailed and the payment

73
ETI Ex. 73 at 2.
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receipt date. The collection lag for MSS-4 and Intra-System Bill (ISB) revenues was based on the
actual payment dates for each of the affiliate revenue types.74

¾ Collection Lag for Residential Customers

As to the residential class, Mr. Joyce determined that the collection lag was 23.73 days. On
behalf of the Cities, Mr. Pous disputed the accuracy of that estimate, complaining that it is
substantially longer than the lag identified for commercial customers. Mr. Pous contended that
Mr. Joyce determined the collection lag for residential customers by relying on a sample size that
was too small. Mr. Pous examined the month-end accounts receivable data for ETI’s entire
residential class for the entire Test Year, and concluded that the collection lag for the class is
actually 22.07 days (as compared to Mr. Joyce’s figure of 23.73 days). Mr. Pous then calculated that
this shorter lag period results in an additional negative cash working capital of $2.4 million.75

Mr. Joyce made several points in response. First, he noted that, although Mr. Pous is
advocating reliance upon month-end accounts receivable data to calculate the collection lag in this
case, he has testified in another proceeding that such data is unusable and unreliable. For example,
in the Atmos Mid-Tex RRC proceeding, Mr. Pous argued in favor of measuring actual bill payment
practices of actual customers (i.e., the approach taken by Mr. Joyce in the present case) and against
analyzing the monthly accounts receivable balances for each month of the Test Year (i.e., the
approach now being advocated for by Mr. Pous).76 Next, Mr. Joyce disputed Mr. Pous’ assertion
that the sample size used by Mr. Joyce was too limited. According to Mr. Joyce, his sample of 100
residential customers is comparable to all of the residential collection lag calculations he has
performed during his 15 years of performing lead-lag studies.77 Mr. Joyce also accused Mr. Pous of

74
ETI Ex. 17 (Joyce Direct) at 10.
75
Cities Ex. 5 (Pous Direct) at 77-79.
76
ETI Ex. 54 (Joyce Rebuttal) at 13-15.
77
Id. at 15-17.
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inexplicably picking out a few data points, rather than relying upon the entirety of the sampling data,
in order to derive his collection lag estimate.78

The ALJs are unpersuaded by Mr. Pous’ criticisms and conclude that ETI has met its burden
to show that the collection lag it utilized in the lead-lag study for residential customers is reasonable
and appropriate.

¾ Collection Lag for MSS-4 and ISB Affiliate Rate Classes

As to MSS-4 and ISB rate classes, Mr. Joyce determined that the collection lags were 46.19
and 15.61 days, respectively.79 Mr. Pous again disputed the accuracy of these estimates. Mr. Pous
pointed out that the underlying data reveals that the majority of the MSS-4 revenue lag days range
from 43 to 46 days, with only two values equaling or exceeding 50 days. Mr. Pous testified that the
two values equaling or exceeding 50 days should be deemed unrepresentative and, therefore,
excluded from the calculations for determining the average lag. Similarly, the majority of ISB
revenue lag days range from 15 to 16 days, with only a few lags running as long as 22 days. Again,
Mr. Pous contended that the longer revenue lag days should be deemed unrepresentative and
excluded from the calculations for the average. Mr. Pous also complained that the payment
deadlines for these affiliate transactions are stipulated in the Entergy System Agreement. Thus, it is
Mr. Pous’ opinion that ETI unreasonably contractually agreed to “excessively long” revenue lag
days associated with the MSS-4 and ISB rate classes. Mr. Pous concluded that if what he considers
to be the unrepresentative lag days are excluded from the calculations, then the collection lag would
change for the MSS-4 class from 46.19 days to 45.14 days, and for the ISB class from 15.61 days to
14.77 days. Collectively, the lag for the two classes would be .77 days shorter, resulting in an
additional negative cash working capital of $3.2 million.80

Mr. Joyce first responded by disputing Mr. Pous’ contention that there are unusual outliers in
the MSS-4 and ISB payment data. He noted that the lag days for MSS-4 payments ranged from 43

78
Id. at 17.
79
Id. at 18.
80
Cities Ex. 5 (Pous Direct) at 79-81; ETI Ex. 54 (Joyce Rebuttal) at 18.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 37
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to 54 days. He described this as a “relatively tight payment range and certainly within the expected
range of reasonableness.”81 Next, Mr. Joyce described Mr. Pous’ assertion that outlier numbers
should not be considered in the data as nonsensical. Mr. Joyce agreed that, in cases where sampling
is used (such as was done for the residential customer class), it is appropriate to exclude data points
that are unrepresentative of the population as a whole. In the case of the MSS-4 and ISB classes,
however, Mr. Joyce determined the collection lag by reviewing the entire class populations.
According to Mr. Joyce, it is inappropriate to eliminate data points when reviewing an entire
population, unless it is necessary to make a known and measurable change.82

The ALJs are again unpersuaded by Mr. Pous’ criticisms. The ALJs conclude that ETI has
met its burden as to show that the collection lag it utilized in the lead-lag study is reasonable and
appropriate.

(c) Receipt of Funds Lag

In the lead-lag study, Mr. Joyce identified the receipt of funds lag (i.e., the delay between the
date the funds are received from the customers and the date the funds clear the bank and are
available to ETI). As required by P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-), Mr. Joyce
assumed that one business day is needed to clear any payments by methods other than electronic
transfer, while electronic payments are available to ETI on the date received. Because 53.39 percent
of customer payments were made by methods other than electronic transfer, Mr. Joyce calculated the
receipt of funds lag to be .77 days.83

Mr. Pous again contended that this duration is too long. He acknowledges that P.U.C.
SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-) mandates the assumption that funds paid by check will be
available “no later than” the following business day. However, he stated that this is merely the
maximum possible duration, and ETI should take into account that fact that many checks are cleared

81
ETI Ex. 54 (Joyce Rebuttal) at 19.
82
Id. at 19.
83
ETI Ex. 17 (Joyce Direct) at 10. The receipt of funds lag is also sometimes referred to by the witnesses as
the “cash receipts float.”
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PUC DOCKET NO. 39896

(and therefore the funds are available) sooner than one day later. Therefore, the funds from all
checks received on any day other than Saturday should be assumed to be available on the date of
receipt, while the funds from checks received on Saturday should be assumed to be available two
days later. Mr. Pous was also critical of the fact that Mr. Joyce treated the funds from all “walk-in”
payments made by customers to be available the next day. Funds from walk-in payments ought to
be deemed available on the date they are received. If these two changes are adopted, Mr. Pous
contended that receipt of funds lag would be shortened from .77 days to .15 days, resulting in an
additional negative cash working capital of $2.1 million.84

Mr. Joyce first responded by pointing out that Mr. Pous’ contention that all funds are
immediately available except for checks received on Saturdays is simply not accurate. Mr. Joyce
cited from a 2007 Report to Congress made by the Board of Governors of the Federal Reserve
System which supports the conclusion that most funds paid by check in this country are not available
on the day they are received (and a significant portion are still not available the next business day).85
Mr. Joyce also disagreed with Mr. Pous’ contention that all walk-in payments should be considered
immediately available. According to Mr. Joyce, walk-in payments are made at third-party vendor
locations, such as grocery stores and check-cashing stores. Based upon his own investigation,
Mr. Joyce determined that walk-in payments are actually available to ETI two days after receipt.
Thus, his one-day assumption for walk-in payments is conservative.86

The ALJs conclude that ETI has met its burden as to show that the receipt of funds lag it
utilized in the lead-lag study is reasonable and appropriate. The positions taken by Mr. Pous on this
issue were unreasonable and counter to the requirements of P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii)(IV)(-d-).

84
Cities Ex. 5 (Pous Direct) at 81-82; Cities Ex. 5A (Errata No. 1).
85
ETI Ex. 54 (Joyce Rebuttal) at 21-23.
86
ETI Ex. 54 (Joyce Rebuttal) at 23-24.
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2. The Expense Lead Component of the Lead-Lag Study

For the expense lead portion of his lead-lag study, Mr. Joyce calculated different expense
lead days for numerous different categories of expenses. Each category will be discussed in turn.

(a) Expense Lead – Operations and Maintenance Expense

Mr. Joyce separated O&M expenses into two groups – energy costs and “other O&M”
expenses. Each of those two groups was further divided into subgroups.87

¾ Energy Costs

Fuel. Mr. Joyce explains that, during the Test Year, ETI purchased two kinds of fuel: (1)
coal and oil; and (2) natural gas. He concluded that there were 44.27 expense lead days for coal and
oil, based upon the time between the service periods and payment dates or payment due dates for all
coal and oil invoices from the Test Year. As to natural gas, he determined that there were 40.63
expense lead days, based upon a comparison of the service period and payment due dates and the
payment dates from a random sample of gas invoices.88 No party challenged this approach, and the
ALJs find no reason to do so either.

Purchased Power. Mr. Joyce explained that there were two components to ETI’s purchased
power energy costs in the Test Year: (1) MSS-4 Purchases; and (2) Other Purchased Power
(consisting of Joint Account Purchases, MSS-3 Purchases, Reserve Equalization, Cogeneration
Purchases, Renewable Energy Credits, and Toledo Bend Purchases). Relying upon either the entire
population or a sample from the Test Year (depending upon the category), Mr. Joyce concluded that
there were 58.76 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased
Power.89

87
ETI Ex. 17 (Joyce Direct) at 11.
88
Id. at 11 and JJJ-3.
89
ETI Ex. 17 (Joyce Direct) at 12 and JJJ-3.
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PUC DOCKET NO. 39896

No party challenged the 35.79 day estimate for Other Purchased Power. However, on behalf
of the Cities, Mr. Pous testified that the expense lead days for MSS-4 should be lengthened from
58.76 days to 60.65 days. According to Mr. Pous, Mr. Joyce made several errors in calculating the
expense lead days for MSS-4 expenses. First, Mr. Joyce inadvertently placed the service period
month after the billing month for two MSS-4 invoices. Mr. Pous based this conclusion on the fact
that the expense leads for these two invoices are roughly 30 days shorter than the “vast majority” of
the other invoices.90 In response, Mr. Joyce denied that he erroneously placed the service period
month after the billing month, and pointed out that Mr. Pous lacks any evidence to support his
assertion. Instead, Mr. Joyce considered the entire population of MSS-4 invoices for the Test Year.
Those invoices show payment lead days ranging from 30 to 120 days, with most points being near
30, 60, or 70 payment lead days. According to Mr. Joyce, this is reasonable and well within the
range he has experienced in other rate cases.91

Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4
expenses by considering only the payment due dates specified in the Entergy System Agreement,
rather than also considering the actual payment dates. According to Mr. Pous, in four instances
during the Test Year, extensions were granted to ETI to allow it to make MSS-4 payments after the
deadline specified in the Entergy System Agreement. Therefore, Mr. Pous stated that the expense
lead days for MSS-4 payments should have been calculated using the later of the actual payment
date or the allowable payment period.92 Mr. Joyce largely agreed with Mr. Pous on this point. That
is, he agreed that the payment lead days should be based on the later of the paid date or the due date.
However, he disagreed with some of Mr. Pous’ calculations on this issue because Mr. Pous wrongly
designated several due dates of Saturday or Sunday, when he should have selected Fridays as the due
date.93

90
Cities Ex. 5 (Pous Direct) at 83-84.
91
ETI Ex. 54 (Joyce Rebuttal) at 26-28.
92
Cities Ex. 5 (Pous Direct) at 84.
93
ETI Ex. 54 (Joyce Rebuttal) at 28-29.
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Next, Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4
expenses by erroneously concluding that one invoice had been paid on the first of the month when,
in fact, it had been paid on the 18th of the month.94 Mr. Joyce agreed with the change.95 Mr. Joyce
then recalculated the expense lead days for MSS-4 and revised the number of lead days from 58.76
to 59.81.96

The ALJs conclude that ETI has met its burden as to show that there were 59.81 expense lead
days for MSS-4, and 35.79 expense lead days for Other Purchased Power.

¾ Other O&M Expenses

This category of expenses was broken down in the lead-lag study into four groups – regular
payroll costs, incentive payroll costs, affiliate service company costs, and all other O&M costs (such
as materials, services, and so on).

Regular Payroll Costs. The lead days for regular payroll costs were computed by
determining the average days of service being reimbursed and adding the days between the end of
each service period and the payments to employees. This amount was then adjusted to incorporate
the effects of vacation pay based upon actual ETI data. By this method, Mr. Joyce determined the
expense lead for regular payroll costs to be 20.68 days.97 No party challenged this approach, and
the ALJs agree.

Incentive Pay Costs. ETI has an annual employee incentive program in place. Incentive
payments for the year 2010 were made in the first quarter of 2011. The lead days for incentive pay
costs were based on the weighted days between the midpoint of the service period (i.e., July 1, 2010)
and the date the incentives were paid (March 10, 2011). By this method, Mr. Joyce determined the

94
Cities Ex. 5 (Pous Direct) at 84.
95
ETI Ex. 54 (Joyce Rebuttal) at 29.
96
ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.
97
ETI Ex. 17 (Joyce Direct) at 13 and JJJ-3.
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expense lead for incentive pay costs to be 251.77 days.98 No party challenged this approach, and
the ALJs agree.

Affiliate Service Company Costs and Other O&M Costs. Charges from Entergy Services,
Inc. (ESI) are paid in the month following the month in which the charges were incurred. The lead
days for affiliate service company costs were based on the number of days from the mid-month to
the later of the contractual due date or the actual settlement date in the following month. By this
method, Mr. Joyce determined the expense lead for affiliate service company costs to be 39.64
days.99

The lead days for other O&M costs were based on a random sampling from the Test Year.
Mr. Joyce originally determined the expense lead for other O&M costs to be 47.46 days.100
However, to correct an error on his part, Mr. Joyce subsequently revised the expense lead time for
other O&M costs down to 43.89 days.101

Mr. Pous testified that ETI’s “FAS 106-related expenses” were wrongly included in either
the affiliate service company costs or the other O&M costs. FASB is the body that establishes the
rules that constitute GAAP. FASB’s Statement Number 106 (FAS 106) establishes the standards for
an employer’s treatment of the non-cash retirement benefits it gives its employees. Based on the
action taken by the Commission in Docket No. 16705,102 Mr. Pous believes that ETI’s FAS 106
costs should have been separately identified and accounted for in the lead-lag study. He contended

98
Id. at 14 and JJJ-3.
99
ETI Ex. 17 (Joyce Direct) at 15, and JJJ-3.
100
Id. at 15-17, and JJJ-3.
101
ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.
102
Application of Entergy Gulf States, Inc. for Approval of Its Transition to Competition Plan and the Tariffs
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to
Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, (Oct. 13, 1998).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 43
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that, when those costs are properly accounted for, it results in an additional negative cash working
capital of $3.8 million.103

Mr. Joyce contended that the prior Commission decision upon which Mr. Pous relies, Docket
No. 16705, dates from 1996, is inapplicable to the facts in the present case, is outdated, and has been
superseded by subsequent Commission decisions. Mr. Pous advocated a 312.55-day expense lead
for FAS 106 expenses. However, Mr. Joyce pointed out that, during the Test Year, ETI made its
FAS 106 payments to a trust at the end of each month, resulting in a one-half month payment lead
(15.25 days). Mr. Joyce testified that his treatment of FAS 106 expenses in his lead-lag study is
consistent with the approach that was approved by the Commission in a recent Oncor ratemaking
case, Docket No. 35717.104

The ALJs conclude that ETI met its burden to show that there were 39.64 expense lead days
for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.

(b) Expense Lead – Current Federal Income Tax Expense

As required by P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-), Mr. Joyce calculated the lead
days for federal income taxes by measuring the days between the midpoints of the annual calendar
year service periods and the actual dates on which ETI made its estimated quarterly tax payments.
By this method, Mr. Joyce determined the expense lead for current federal income tax costs to be
38 days. He then determined that this resulted in a $1.6 million cash working capital requirement
associated with the Company’s Federal Income Tax Expenses.105

Mr. Pous testified that the Company’s cash working capital requirement for Federal Income
Tax Expenses ought to be a negative number or, at most, zero. He bases this argument on his
assertion that, during the past five years, the Company “has received in excess of a net $90 million
of refunds” on its federal income taxes. In other words, because “refunds produce cash” for the

103
Cities Ex. 5 (Pous Direct) at 85-88.
104
ETI Ex. 54 (Joyce Rebuttal) at 29-32.
105
ETI Ex. 17 (Joyce Direct) at 17, and JJJ-3.
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Company, Mr. Pous contends that the Company is seeking a positive cash working capital
requirement for cash transactions “that have not been made and are not being made.”106

Mr. Joyce responds by disputing Mr. Pous’ contention that “refunds produce cash.”
Mr. Joyce points out that any refund from the IRS merely represents a return of the Company’s own
cash for payments previously made. Moreover, Mr. Joyce stresses that his approach for calculating
the expense lead for current federal income taxes is perfectly consistent with: (1) the requirements of
P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-); (2) current IRS guidelines found at IRS
Publication 542; and (3) Commission precedent. Mr. Joyce further points out that, by contrast,
Mr. Pous’ approach has been consistently rejected by the RRC.107 The ALJs find Mr. Joyce’s
arguments to be more persuasive on this point and conclude that ETI has met its burden as to show
that the expense lead for current federal income tax costs it utilized in the lead-lag study is
reasonable and appropriate.

The ALJs conclude that ETI met its burden to show that there were 39.64 expense lead days
for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.

(c) Expense Lead and Lag – Taxes Other than Income Taxes

This group of taxes consists of: (1) payroll-related taxes; (2) ad valorem taxes; (3) Texas
state gross receipts taxes; (4) the PUC assessment tax; and (5) Texas state franchise taxes.
Calculating from the midpoints of the work periods to the respective payment dates of the taxes,
Mr. Joyce determined that the payroll taxes had an expense lead time of 16.45 days. As to the
franchise taxes, Mr. Joyce concluded that the Company had a collection lag of 46.42 days because
the Company was required to pay the taxes in May 2010. As to the other non-payroll-related taxes,
Mr. Joyce calculated from the midpoint of the period for which the tax was assessed to the payment
date, resulting in the following expense lead days: 213.51 days for ad valorem taxes; 74.28 days for

106
Cities Ex. 5 (Pous Direct) at 88-89.
107
ETI Ex. 54 (Joyce Rebuttal) at 33-36, JJJ-R-1.
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Texas state gross receipts taxes; and 225.50 days for the PUC tax.108 No party challenged this
approach, and the ALJs agree.

F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. 5]

In Docket Nos. 16705 and 37744, the Commission authorized ETI to maintain a reasonable
and necessary storm damage reserve account of $15,572,000.109 As of June 30, 1996, ETI had a
positive reserve balance of $12,074,581, constituting a reduction to rate base. Over the next
15 years, ETI charged $101,670,803 to the reserve related to more than 200 storms (excluding
securitized events), but it accrued only $29,796,478 through base rates. Thus, ETI’s end-of-test-year
balance for its storm damage reserve in the present case was a negative $59,799,744.110 This
negative balance is an addition to rate base.111

OPC and Cities argue that ETI’s current storm damage reserve negative balance should be
adjusted. OPC contends that ETI failed to prove that its storm damage expenses booked since 1996
were reasonable and prudently incurred, so it recommends disallowing all of those charges and
refunding to customers the resulting positive balance that exceeds the authorized balance.
Alternatively, OPC suggests that ETI’s negative balance be reset to its currently authorized balance,
with no refund to customers. Cities contend that ETI’s current negative storm damage reserve
balance should be reduced because it includes: unreasonable expenditures associated with a 1997
ice storm; expenses associated with former assets in Louisiana; and amounts that Cities claim should
have been treated as insurance deductibles. Cities also recommend transferring ETI’s Hurricane
Rita Regulatory Asset to the storm damage reserve. The parties’ recommendations are summarized
as follows:

108
ETI Ex. 17 (Joyce Direct) at 18-19, and JJJ-3.
109
Staff Ex. 4 (Roelse Direct) at 8.
110
$12,074,581 + $29,796,478 – $101,670,803 = ($59,799,744).
111
P.U.C. SUBST. R. 25.231(c)(2)(E).
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Party Reserve Balance
ETI ($59,800,000)
Cities ($34,051,597)
OPC-1 $41,871,059
OPC-2 $15,572,000

1. The Effect of Prior Settled Cases

As with the Hurricane Rita Regulatory Asset (Section V.B.), the effect of the black-box
settlements in Docket Nos. 34800 and 37744 is a significant issue concerning the storm damage
reserve. However, the parties’ positions are generally reversed from the positions taken on the
Hurricane Rita Regulatory Asset. That is, ETI now argues that its storm reserve negative balance
was resolved and approved in those settled dockets, while Cities and OPC argue that it was not.

ETI notes that the final orders in Docket Nos. 34800 and 37744 contained “stipulated and
agreed upon” conclusions of law stating that overall total invested capital through the end of the test
year in those cases met the requirements of PURA § 36.053(a) that electric utility rates be based on
the original cost, less depreciation, of property used by and useful to the utility in providing
service.112 Then ETI cites language in P.U.C. SUBST. R. 25.231(c)(2)(E), which provides that any
deficit in a self-insurance plan will be considered an increase to rate base, or invested capital. As a
result, ETI argues, the Commission could not make a determination that a rate base expense item
was included in rate base as used and useful without also determining that the rate base expense was
prudently and reasonably incurred.113 Thus, ETI asserts, a Commission conclusion of law that
approved invested capital as meeting the requirements of PURA § 36.053(a) necessarily also
determined that an expense included in rate base was prudently and reasonably incurred. In other
words, ETI states, the “prudent and reasonable” standard is incorporated into the “used and useful”

112
PURA § 36.053(a) provides: “Electric utility rates shall be based on the original cost, less depreciation, of
property used by and useful to the utility in providing service.”
113
ETI cited: City of Alvin v. Public Util. Comm’n of Texas, 876 S.W.2d 346, 353-354 (Tex. App.—Austin,
1993, no pet.); see also Application of Gulf States Utilities Company for Authority to Change Rates, Docket
Nos. 7195 and 6755, 14 P.U.C. BULL. 1943 at 1969 (May 16, 1998) (“dishonest or obviously wasteful or
imprudent expenditures constitutionally can be excluded from a utility’s rate base. Such costs clearly are not
used and useful in providing serviced to the public.”).
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standard in PURA § 36.053(a).114 Therefore, ETI argues that by issuing a final orders in Docket
Nos. 34800 and 37744 with conclusions of law that ETI’s overall total invested capital met the
requirements of PURA § 36.053(a), the Commission implicitly approved the negative balances of its
insurance reserve in both prior dockets; consequently, those orders preclude litigation in the present
case of whether those expenses were prudently and reasonably incurred.115

Cities reject ETI’s contention that the storm damage reserve balance was approved in Docket
Nos. 34800 and 37744. Cities point out that in order to comply with PURA, all final orders in rate
cases must include a conclusion of law stating that the overall total invested capital through the end
of the test year meets the requirements of PURA § 36.053(a). However, Cities contend, pursuant to
the parties’ agreements in Docket Nos. 37744 and 34800, no determination was made as to what was
included in ETI’s total invested capital in those cases. Cities explain that in Docket Nos. 37744 and
34800 Cities claimed that certain expenses were not properly included in the storm reserve balance,
while ETI argues that they were. However, neither Cities nor ETI’s recommendation was
specifically approved as part of the base rate settlement and neither of their recommended balances
may be considered as the basis for setting rates in those dockets.116 Thus, Cities argues, in such
“black box” settlements no specific storm reserve balance is approved unless expressly stated.
Cities also argues that the final orders in Docket Nos. 37744 and 34800 could just as logically be
interpreted as denying ETI’s request to include objectionable expenses in the storm damage reserve,
because both orders specified that the revenue requirement approved in those cases did not include
any prohibited expenses. Finally, Cities states that adoption of ETI’s arguments would make black-
box settlements impossible in the future.117

114
ETI cited Docket No. 7195, 14 P.U.C. BULL. at 1969 (“the prudent investment test is embodied in
traditional ratemaking principles as expressed through PURA Sections … 41.”). PURA Section 41(a) is the
predecessor to current Section 36.053.
115
ETI Initial Brief at 20-22; ETI Reply Brief at 17.
116
Docket No. 37744, Final Order at Ordering Paragraph 14; Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 at Ordering Paragraph 12.
117
Cities Reply Brief at 22-26.
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OPC makes arguments similar to Cities, and notes that no storm damage reserve amount was
either agreed to by the parties or approved by the orders in either Docket No. 34800 or Docket
No. 37744.118

The ALJs find that the Commission did not implicitly approved all of ETI’s storm damage
expenses and its storm damage reserve balances in the final orders in Docket Nos. 34800 and 37744.
Although the orders in those settled cases contained conclusions of law the that overall total invested
capital through the end of the test year met the requirements of PURA § 36.053(a), the orders made
no findings of what the total invested capital included, and specifically there were no findings or
conclusions approving the amount of the storm damage reserve. As pointed out by Cities, in those
dockets the intervenors disputed various items in ETI’s requested storm damage reserve, but the
“black box” settlement did not specifically address those issues; consequently, it is as logical to
conclude that objectionable expenses were excluded from the storm damage reserve and from the
total invested capital as it is to conclude that the objectionable expenses were included. In
Section V.B., the ALJs conclude that ETI’s Hurricane Rita regulatory asset should be considered as
being included in the black-box settlement and final order in Docket No. 37744, even though the
settlement and order did not expressly state how the Hurricane Rita regulatory asset issue was
resolved. However, that issue involved unique circumstances and is distinguishable because PURA
§ 39.459(c) required the Commission to consider the insurance payments for the Hurricane Rita
restoration expenses in ETI’s next rate case, which was Docket No. 37744; ETI requested a true-up
in that docket of the insurance proceeds it received concerning the regulatory asset; and no party
objected to ETI’s proposed regulatory asset or its proposed amortization. In contrast, intervenors in
Docket Nos. 34800 and 37744 did object to ETI’s proposed storm damage reserve and, under those
circumstances, it is not possible to determine how the issues concerning the storm damage reserve
were resolved by the black-box settlement. Therefore, the ALJs find that the black-box settlements
and final orders in Docket Nos. 34800 and 37744 neither approved nor disapproved the
reasonableness and necessity of ETI’s storm damage expenses incurred since 1996 or ETI’s current
storm damage reserve negative balance.

118
OPC Reply Brief at 7-8.
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2. OPC’s Proposed Adjustment

OPC witness Nathan Benedict testified that ETI failed to prove that any of its $101,670,803
in storm damage expense booked since 1996 was prudently incurred, so he recommended
disallowing all of those charges and refunding to customers the resulting positive balance that
exceeds the authorized balance. Removing those charges would leave ETI with a current positive
storm reserve balance of $41,871,059 (beginning balance of $12,074,581 + accruals of
$29,796,478). This balance exceeds the currently approved storm reserve balance of $15,572,000 by
$26,299,059, and Mr. Benedict proposed that this surplus be refunded to rate payers at a rate of
$1,314,953 per year for 20 years. Mr. Benedict acknowledged that some storm damage expenses
incurred by ETI since 1996 likely were reasonable and necessary. Therefore, as an alternative
proposal, Mr. Benedict suggested that ETI’s current storm balance reserve be set at the last approved
amount of $15,572,000 (i.e., without any surplus or deficit). This proposal would result in a
$75,363,744 reduction to ETI’s current storm damage reserve negative balance and rate base.119

As discussed above, OPC disagrees with ETI’s argument that the Commission implicitly
approved these expenses in the final orders in Docket Nos. 34800 and 37744.120 Therefore, OPC
argues that ETI had to prove in the present case that the expenses were prudently incurred.
Concerning ETI’s burden of proof, OPC acknowledges that, although a utility has the ultimate
burden to prove that its proposed rates are just and reasonable, once the utility establishes a prima
facie case of prudence of a rate change, the burden shifts to the other parties to produce evidence to
rebut that presumption. Then, if the other parties rebut the presumption, the burden shifts back to
the utility to prove by a preponderance of the evidence that the challenged expenditures were
prudent. However, OPC notes, if the utility fails to establish a prima facie case, the burden of going
forward with evidence never shifts to the other parties.121 In OPC’s opinion, ETI never established a
prima facie case because ETI’s spreadsheet of storm damage expenses was excluded from evidence

119
OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 19.
120
OPC Reply Brief at 7-8.
OPC Reply Brief at 2-3, citing, Entergy Gulf States, Inc. v. Public Utility Comm’n, 112 S.W.3d 208 (Tex.
121

App. – 2003, pet. denied).
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and ETI witness Greg Wilson acknowledged on cross examination that he made no analysis of
whether ETI’s storm damage costs were reasonable and necessary.122

ETI complains that Mr. Benedict simply sought a global rejection of more than $100 million
of expenses without any evidence to support his position, and it stressed that even Mr. Benedict
acknowledged that some of ETI’s expenses were prudently incurred. ETI also states that, in any
event, it met its burden of proof with regard to expenses booked to the storm damage reserve.

Concerning its proof, ETI states that its burden was to make a prima facie case supporting
the prudence of its invested capital,123 and once it made that showing, the burden shifted to the
opposing parties to overcome the presumption of prudence by presenting evidence that reasonably
challenged the expenditures.124 This is the same position as OPC. ETI argues that it met its burden
to prove a prima facie case.125 ETI notes that it provided storm cost data accompanied by narrative
testimony that supported the reasonableness of ETI’s self-insurance plan; storm preparedness and
response; service quality; and cost of labor, materials, and services used to carry out distribution
activities (including system restoration). For instance, ETI states, it presented its proposed storm
reserve balance through the direct testimony of Mr. Greg Wilson126 and in the Commission’s rate
filing package.127 Mr. Wilson also explained the function of ETI’s self-insurance program,
described the $50,000 threshold to exclude minor weather events, and provided work papers
detailing the nominal and trended losses for each storm booked to the reserve since 1986, as well as
annual and total loss levels.128

122
OPC Reply Brief at 1-5.
123
ETI Initial Brief at 22, citing, Application of Texas Utilities Electric Company for Authority to Change
Rates, Docket No. 9300, 17 P.U.C. BULL. 2057, 2148, Order on Rehearing (Sept. 27, 1991).
124
Docket No. 9300, 17 P.U.C. BULL. at 2148.
125
Although ETI contended that the storm damage reserve has been approved in prior dockets, it argued that
its evidence also supported storm damage charges going back to July 1, 1996. ETI Initial Brief at 23, n. 147.
126
ETI Ex. 14 (Wilson Direct) at 11.
127
ETI Ex. 3 (Schedules) at Schedule B-1, line 7; Schedule WP_B-1, page 7.
128
ETI Ex. 14 (Wilson Direct) at 5-7; WP GSW-3_1.
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Further, ETI witness Shawn Corkran presented testimony regarding subject matters that
directly support the ability of the system to withstand storms, and ETI’s ability to reasonably and
efficiently respond to storm events, thereby supporting the conclusion that reasonable and necessary
costs are booked to the storm reserve balance. This evidence included ETI’s distribution operations,
industry-recognized comprehensive storm plans, annual storm drills, storm response and restoration
processes, distribution maintenance and asset improvement processes, service quality and
continuous improvement programs, and vegetation management practices. ETI points out that
Mr. Corkran also described how it prepares for emergency situations,129 and Mr. Corkran explained
how charges to the storm reserve are captured and recorded.130 Mr. Corkran also noted that ETI has
received either the Edison Electric Institute’s Emergency Assistance Award or Emergency Response
Award every year since 1998, which recognize ETI’s exemplary storm restoration response.131
Likewise, Mr. Corkran discussed ETI’s reliability statistics since 2000, which demonstrated a high
quality of service,132 and he provided four exhibits demonstrating that, on both per-kilowatt-hour
(kWh) and per-customer bases, ETI’s distribution O&M costs compared favorably to the costs of
other utilities.133 In ETI’s opinion, because it carried out its distribution activities in the same
efficient and cost-effective manner while performing routine activities as during storm restoration,
those metrics and reliability statistics support the reasonableness of costs booked to the reserve.134

ETI also argues that it supported the reasonableness of the costs booked to its storm reserve
through the direct testimony of its supply chain witness, Mr. Joseph Hunter. Mr. Hunter explained
that ETI’s procurement policies and procedures are designed to streamline the acquisition of
materials and services through the use of strategic supply networks in order to achieve the lowest
reasonable cost.135 Mr. Hunter also described how the centralization of the supply chain function on

129
Id. at 28.
130
Id. at 93.
131
Id. at 29.
132
Id. at 12-29.
133
Id., Exhibits SBC-2A, SBC-2B, SBC-2C, and SBC-2D.
134
ETI Initial Brief at 22-24.
ETI Ex. 16 (Hunter Direct) at 5, 9-10, and Exhibits JMH-1(Entergy Companies’ Procurement Policy) and
135

JMH-3 (Entergy Companies’ Approval Authority Policy).
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a system-wide basis provides greater leverage and buying power in the procurement of materials
and, thus, lower costs than could be achieved by ETI alone.136 Furthermore, Mr. Hunter specifically
noted that the standardization of supply chain activities “makes possible a smoother day-to-day
operation as well as rapid response to major storms or emergencies.”137

Finally, ETI stated that it provided an extensive amount of storm reserve data through the
discovery process, which provided a basis for any interested party to investigate the reasonableness
of any particular storm response or expenditure booked to the reserve. It stressed that OPC witness
Benedict acknowledged that ETI provided 420 pages and over 22,220 lines of detail reflecting every
charge to the storm reserve over the last 15 years,138 which specified the month, year, state, project
code, work order type, function, storm name, account number, resource code, resource code
description, and amount.139 Therefore, ETI argues that it made a prima facie case regarding its
storm reserve through the presentation of narrative testimony, schedules, work papers, and expense
detail and, accordingly, the burden shifted to parties seeking to disallow the expenses allocated to
the storm damage reserve to present evidence that reasonably challenges their prudence.140 Yet, ETI
contends, OPC did not challenge any specific expenditure booked to the reserve other than the 1997
ice storm expenses discussed later. Therefore, ETI argues that it met its prima facie burden and
OPC’s proposed disallowance of either $101,670,803 or $75,363,744 should be denied.141

Although it is a close call, the ALJs find that ETI established a prima facie case that its storm
damage expenses incurred since June 30, 1996, were prudently incurred. A prima facie case is a low
burden. It is not the same as a preponderance of the evidence. Rather, as stated in Town of Fairveiw
v. City of McKinney, prima facie evidence “is merely that which suffices for the proof of a particular

136
ETI Ex. 16 (Hunter Direct) at 17.
137
Id. at 18 (emphasis added).
138
Tr. at 1703.
139
Tr. at 1704.
140
Docket No. 9300, 17 P.U.C. BULL. at 2147.
141
ETI Initial Brief at 22-26; ETI Reply Brief at 16-19.
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fact until contradicted and overcome by other evidence.”142 Similarly, Black’s Law Dictionary
defines a prima facie case as sufficient evidence “to allow the fact-trier to infer the fact at issue and
rule in the party’s favor.”143

Except for expenses incurred with the 1997 ice storm, ETI did not present any testimony that
explicitly stated that the expenses included in its storm damage reserve were prudently incurred.
However, ETI did present sufficient other evidence that at least allows the ALJs to infer that the
expenses were prudently incurred. As noted above, a reasonable inference from the evidence
presented is sufficient to establish a prima facie case. ETI witness Gregory Wilson presented
testimony about the background of the storm damage reserve and about ETI’s yearly major storm
damage losses, although OPC is correct that he did not explicitly evaluate or determine whether
ETI’s expenses were reasonable and necessary.144 In addition, OPC witness Benedict provided
testimony that ETI has booked $101,670,908 to the storm damage reserve since 1996,145 and that
ETI’s $50,000 threshold is a means of excluding from the reserve small storm-related expenses that
ETI could anticipate as routine O&M expense and which should be excluded from the storm damage
reserve.146 ETI presented testimony that it had not recorded storm damage expense to both the storm
damage reserve and to O&M expense,147 and Mr. Benedict agreed that he had no information to
contradict this148 or that any securitized costs were charged to the storm damage reserve.149
Although the document itself was excluded from evidence, Mr. Benedict testified that ETI provided
him with a 420-page spreadsheet covering all of ETI’s storm damage expenses back to 1996,
including the month, year, state, project code, project name, work order type, function, storm name,
account number, resource code, resource code description, and amount.150 In addition, ETI provided

142
271 S.W.3d 461, 467 (Tex. App. – Dallas 2008 pet. denied).
143
Black’s Law Dictionary, 8th Ed. (2004).
144
ETI Ex. 14 (Wilson Direct) at Ex. GSW-3.
145
OPC Ex. 6 (Benedict Direct) at 7-8.
146
Tr. at 1694.
147
ETI Ex. 72 (Wilson Rebuttal) at 2-3.
148
Tr. at 1695-1696.
149
Tr. at 1698.
150
Tr. at 1704.
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other testimony described previously concerning its distribution operations, storm plans, storm
response operations, purchasing procedures, and the like.

ETI did not present a witness who specifically testified that all of its storm damage expenses
booked to the storm damage reserve were prudently incurred, except for expenses related to the 1997
ice storm. Such testimony would have been more helpful than the evidence ETI relied upon.
Nevertheless, the burden of establishing a prima facie case does not require such direct testimony, if
a fact can be reasonably inferred from other evidence presented. The ALJs reiterate that it is a close
call, but they find that ETI did present sufficient evidence to infer that the expenses charged to the
storm damage reserve were prudently incurred. At that point, the burden shifted to OPC to produce
evidence to challenge specific expense items included in the storm damage reserve, but OPC did not
present any such evidence except for the items discussed below. Therefore, the ALJs recommend
that the Commission not adopt either of OPC’s recommended denials of expenses contained in ETI’s
storm damage reserve.

3. 1997 Ice Storm

ETI’s proposed negative storm reserve balance includes $13,014,379 in expenditures
associated with a 1997 ice storm. Cities and OPC contend that this expense should be excluded
from the storm balance reserve.

Cities witness Pous explained that ETI first requested to include the 1997 ice storm expense
in the storm damage reserve as a post test year adjustment in its 1995-1996 test-year rate case,
Docket No. 16705. The Commission denied the requested post test year adjustment and stated that
the expense should be considered in ETI’s next rate case. Thereafter, ETI had a series of rate cases
(Docket No. 20150 – 1998 rate case; Docket No. 30123 – 2004 rate case; Docket No. 34800 – 2007
rate case; Docket No. 37744 – 2009 rate case) in which intervenors challenged the 1997 ice storm
expenses, but those cases all settled or were otherwise concluded without any express decision
concerning the prudence of ETI’s 1997 ice storm expenses.151 Mr. Pous testified that these expenses

151
Cities Ex. 5 (Pous Direct) at 49-55.
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are now appropriately at issue in the present case, and he recommended that the entire balance be
excluded from the storm damage reserve. He pointed out that in Docket No. 18249, the Commission
found that ETI’s poor quality of service exacerbated the extent of damage caused by the storm, and
it found that the response efforts were uneven and delayed and could have been more effective if
ETI had a better communication and management program in place.152 Mr. Pous also contended that
in the present case ETI failed to prove that any portion of the 1997 Ice Storm expenses were
reasonable.153

Thus, Cities argue that the Commission has already determined that ETI’s negligence was a
major factor in the extent and duration of the outages,154 so no expenses associated with the 1997 ice
storm should be eligible for recovery from customers through the storm damage reserve. In response
to ETI’s argument that it was already penalized for these issues in Docket No. 18249 through a
reduction to the allowed ROE, Cities argue that the Commission did not absolve ETI from
responsibility for damage caused by ETI’s poor service quality, and ETI’s customers should not be
ordered to pay for expenses that were caused by ETI’s negligence.155

OPC makes the same arguments as Cities concerning the 1997 ice storm expenses.156

ETI argues that, due to quality of service issues related to the 1997 ice storm, the
Commission reduced Entergy Gulf States, Inc.’s (EGSI) ROE by 60 basis points in Docket
No. 18249 and subjected EGSI to significant spending requirements and quantified performance
guarantees. In ETI’s opinion, it would be inequitable to now penalize ETI a second time for the
same issues. Moreover, ETI argues that it established that its expenses were reasonable and
necessary. ETI witness Shawn Corkran testified that the 1997 ice storm was the most destructive

152
Entergy Gulf States, Inc. Service Quality Issues Severed From Docket No. 16705, Docket No. 18249,
Final Order at FoF 97, 98, & 102 (Apr. 21, 1998).
153
Cities Ex. 5 (Pous Direct) at 56-59; see Cities Initial Brief at 18-19.
154
Cities Initial Brief at 18 (“The Company’s failure to clear the limbs before the storm was a major factor in
the number and duration of outages experienced by customers.”).
155
Cities Reply Brief at 28-30.
156
OPC Ex. 6 (Benedict Direct) at 12; OPC Initial Brief at 16; OPC Reply Brief at 7-10.
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winter storm ever to hit the EGSI/ETI system, with about 3,400 miles of distribution lines and
560 miles of transmission lines de-energized during the storm’s peak. A large part of the restoration
effort involved clearing broken and fallen trees and tree limbs from lines. Mr. Corkran reviewed all
of the costs incurred in response to the 1997 ice storm and stated that they were reasonable and
necessary to reliably restore service to customers as quickly as possible after the storm. He provided
an exhibit with a detailed breakdown of labor, materials, transportation, lodging, and other expenses
incurred. In his opinion, all of these costs charged to the storm damage reserve, totaling
$13,014,379, were reasonable, necessary, and prudently incurred.157

The ALJs recommend that the Commission authorize ETI to include in the storm damage
reserve its $13,014,379 in expenditures associated with the 1997 ice storm. ETI established that
those expenses were reasonable and necessary to repair the damage and restore power to its
customers. ETI witness Mr. Corkran provided detailed testimony concerning the seriousness of the
storm and the resulting expenses incurred for repair work and restoration of power to customers.158

In contrast, Cities and OPC did not challenge any specific item in these restoration expenses.
Instead, they relied upon the Commission’s findings in Docket No. 18249 that ETI’s deficient
maintenance exacerbated the amount of damage caused by the storm. However, in that docket the
Commission also reduced ETI’s ROE by 60 basis points due to poor service issues, including
deficient preventative maintenance. The Commission made the reduction in ROE retroactive and
required ETI to make refunds to customers. Likewise, in that docket the Commission found that the
ice storm was severe and that significant damage would have occurred even with exemplary
vegetation management and other preventative measures. It is not feasible to accurately determine
now what portion of ice storm damage that occurred 15 years ago was caused by preventative
maintenance issues.

The ALJs conclude, however, that the Commission’s retroactive reduction of ETI’s ROE in
Docket No. 18249 in part compensated ratepayers for the poor service issues that exacerbated the

157
ETI Ex. 48 (Corkran Rebuttal) at 2-12.
158
ETI Ex. 48 (Corkran Rebuttal) at 2-12 and Ex. SBC-R-1.
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storm damage. Nevertheless, once the ice storm occurred, ETI had to take appropriate action to
repair the damage and restore service. ETI has established the expenses incurred in those efforts
were reasonable and necessary, and the ALJs find that they should be included in the storm damage
reserve. Therefore, the ALJs recommend that the Commission deny Cities and OPC’s proposed
adjustment.

4. Jurisdictional Separation Plan Allocation

Cities complained that ETI’s storm damage reserve deficit includes $12,498,325 in costs that
belong to Louisiana jurisdiction customers but were incorrectly transferred to Texas customers
during implementation of the Jurisdiction Separation Plan. Cities explain that before the
jurisdictional separation of EGSI into ETI and Entergy Gulf States Louisiana, LLC (EGSL), the
transmission investment and expense associated with maintaining the transmission system, including
storm restoration costs, was allocated between the Texas and Louisiana retail jurisdictions. In the
jurisdictional separation of EGSI into ETI and EGSL, the transmission system investment was split
between each company based upon a situs basis. The transmission facilities in Texas were
transferred to ETI and the transmission facilities in Louisiana were transferred to EGSL. After the
jurisdictional separation, ETI and EGSL were each responsible for future O&M expense, including
storm restoration expense, associated with their respective transmission investments.

Cities claim that in the present case ETI has attempted to reverse the allocation of expenses
incurred on behalf of Louisiana customers before the jurisdictional separation and to charge those
expenses to Texas customers through the storm damage reserve. In Cities’ opinion, any expense that
was allocated to Louisiana customers prior to the jurisdictional separation was properly charged to
Louisiana customers. Cities argue that ETI may not now reverse expenses allocated to Louisiana
customers and charge them to Texas customers solely on the basis that ETI acquired the
transmission investment located in Texas.159

159
Cities Ex. 5 (Pous Direct) at 59-60; Cities Initial Brief at 19-20.
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In response, ETI witness Considine explained that an analysis of storm reserve charges was
preformed prior to the jurisdictional separation to determine if storm charges were incurred for
Texas or Louisiana property. The reclassification of certain charges was made as a result of that
analysis, which is in evidence, to properly reflect the state in which the storm charges were incurred.
The largest charge assigned to ETI through this analysis was a $10,652,130 charge related to project
“E2PPSJ8291 Trans EGSI-TX Hurricane Rita 9-24-05,” which expressly related to damages to the
Texas portion of the former EGSI transmission system. Similarly, costs were assigned from ETI to
EGSL for projects such as “E2PPSJ8296 Trans. Hurricane Katrina - EGSI-La” and “E2PPSJ8302
Trans EGSI-LA Hurricane Rita 9-24-05,” that clearly related to assets located in Louisiana. In other
words, prior to the separation, the Texas portion of the storm damage reserve could include charges
for restoration work performed on assets located in Louisiana, and vice versa. The analysis
conducted pursuant to the separation re-aligned the charges to the jurisdiction where the assets are
located. In that way, ETI argues, neither jurisdiction has charges in its storm reserve balance for
assets located in the other jurisdiction. In short, ETI argues that the assets and liabilities following
the separation have been properly assigned and no improper cost shifting occurred.160

The ALJs recommend that the Commission deny Cities’ proposed adjustment. ETI offered
evidence to explain how its reclassification study reassigned various costs from the Texas
jurisdiction to Louisiana, as well as from the Louisiana jurisdiction to Texas. This study resulted in
more expenses from Louisiana being reassigned to the Texas jurisdiction than from Texas to
Louisiana, but Cities offered no evidence to explain why the study was flawed or why the
reassignments were in error. The ALJs found ETI’s evidence to be credible and that it supported the
jurisdictional allocation of these expenses as proposed by ETI.

5. $50,000 Reserve Threshold

Cities witness Pous also proposed a $10,950,000 reduction to ETI’s negative storm damage
reserve balance due to ETI including in the reserve the first $50,000 of expense for each separate
storm event. Mr. Pous asserted that this amount is equivalent to a deductible for insurance purposes

160
ETI Ex. 46 (Considine Rebuttal) at 25 and Ex. MPC-R-3 at 25; ETI Initial Brief at 19-36; ETI Reply Brief
at 20-21.
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and should have not been charged to the reserve. Cities note that P.U.C. SUBST. R. 25.231(b)(1)(G)
requires that a storm reserve only collect for “property and liability losses which occur, and which
could not have been reasonably anticipated and included in operating and maintenance expenses.”
Because of ETI’s low $50,000 threshold, Cities contend, ETI has recorded to the storm reserve
expenses associated with 219 different weather events in the past 15 years. This equates to
approximately 14.6 weather events per year, or 1.2 weather events per month, on average. In Cities’
view, ETI’s booking to the storm damage reserve of all expenses associated with a weather event
exceeding $50,000 – including the first $50,000 – is inconsistent with P.U.C. SUBST.
R. 25.231(b)(1)(G). Cities argue that ETI may not reasonably claim that such a recurring expense is
“not reasonably anticipated” to qualify it for the storm reserve. Cities proposed adjustment is based
on $50,000 for each of the 219 storm events, for a total of $10,950,000. In addition, based on the
nature of ETI’s recurring storm expense, Cities also recommend that the deductible amount be
increased to $500,000, which Cities stated is consistent with the storm reserve treatment afforded to
other utilities in Texas.161

ETI witness Gregory Wilson testified that Mr. Pous misconstrued the $50,000 trigger when
he treated it as a deductible. Mr. Wilson explained that if a storm causes $50,000 or less in damage,
the expenses are not charged to the storm damage reserve. However, if a storm causes more than
$50,000 in damage, all of the expenses are charged to the reserve. He noted that if the $50,000 were
treated as a deductible, then that amount would still be charged to O&M whenever storm damage
exceeded the $50,000 threshold. But, under the current arrangement, when storm damage exceeds
$50,000 all of the expenses are charged to the storm damage reserve, and the first $50,000 is not
charged to O&M. Therefore, no double recovery occurs. Moreover, ETI argues that Cities’
proposed retroactive removal of these amounts from the reserve would constitute a disallowance of
costs without any finding of imprudence, as well as impermissible retroactive ratemaking. ETI also
contends that even if the Commission were to implement Mr. Pous’s recommendation prospectively,
it would require a corresponding increase in ETI’s O&M costs. Therefore, ETI disagreed with

161
Cities Ex. 5 (Pous Direct) at 61-63; Cities Initial Brief at 20-21.
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Cities’ recommendation to reduce the current balance of the storm damage reserve by $10,950,000
or to change the current level of the threshold.162

The ALJs find that Cities’ proposed adjustment to ETI’s storm damage reserve is not
warranted. ETI explained that the $50,000 threshold amount was included in the storm damage
reserve whenever storm restoration expenses exceeded the threshold, but that amount was not
included in O&M expense. Accordingly, no double recovery has occurred, and Cities presented no
other valid reason to disallow the allocation of these expenses to the storm damage reserve.
Therefore, the ALJs recommend that the Commission deny Cities’ proposed $10,950,000 adjustment
to ETI’s current storm damage reserve balance. As a policy matter, the Commission may choose to
increase ETI’s threshold on a prospective basis to some higher amount, as recommended by Cities,
but the evidence presented by the Cities on this issue was not sufficient for the ALJs to make such a
recommendation.

6. Hurricane Rita Regulatory Asset

As discussed in Section V.B., Cities recommend an adjustment to the Hurricane Rita
regulatory asset, and they recommended the adjusted balance be moved to the storm damage reserve.
For the reasons stated in Section V.B., the ALJs recommend that the Commission not adopt Cities’
proposal to move the Hurricane Rita regulatory asset to the storm damage reserve.

7. Conclusion

In conclusion, the ALJs find that ETI’s storm damage expenses since 1996 and its storm
damage reserve balance were not approved by the Commission as a result of the black-box
settlements in Docket Nos. 34800 and 37744. The ALJs also find that ETI established a prima facie
case concerning the prudence of its storm damage expenses incurred since 1996 and that
intervenors’ proposed adjustments should be denied. Therefore, the ALJs recommend that the
Commission approve ETI’s test-year-end storm reserve balance of negative $59,799,744.

162
ETI Ex. 72 (Wilson Rebuttal) at 2-3; EIT’s Initial Brief at 27-28; ETI Reply Brief at 21-22.
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G. Coal Inventory

ETI is the partial owner of two coal-fired power generating facilities. It owns a 29.75
percent interest in Nelson 6, a 550 megawatt (MW) unit located in Westlake, Louisiana (Nelson),
and a 17.85 percent interest in Big Cajun II, Unit 3, a 588 MW unit located in New Roads, Louisiana
(BCII/U3). EGSL is the majority owner and operator of Nelson and is responsible for the supply
and delivery of coal to that facility. A third party, LaGen, is a co-owner of BCII/U3, and is the
operator of the plant. Pursuant to a joint operating agreement between the co-owners, LaGen is
responsible for the acquisition and delivery of coal to BCII/U3. The coal for both units comes, via
train, from minefields in Wyoming.163

Entergy has adopted a “Coal Inventory Policy” at Nelson to ensure that a sufficient coal
inventory is always maintained on-site to help mitigate transportation and unit operating risks. The
policy calls for, among other things, a 12-month average inventory target of a 43-day supply of coal.
Because Entergy is not the operator of BCII/U3, it does not have ultimate control over the coal
inventories at that unit. Pursuant to the joint operating agreement for that unit, however, each year
ETI nominates for the next calendar year the level of coal to be delivered for its account at BCII/U3.
ETI’s nomination process is targeted to ensure an end-of-year inventory target of a 43-day supply of
coal.164

In its application, ETI includes a coal inventory amount in its rate base that is based upon the
average inventories at Nelson and BCII/U3 for the 13 months ending in June 2011.165 The average
coal inventory at Nelson was 384,860 tons, representing approximately 48 days of inventory,
assuming an average daily burn rate of 8,000 tons. The total proposed dollar amount for the coal
inventories at both facilities is $9,846,037. Of that total, the Nelson portion is $6,040,926, and the

163
ETI Ex. 33 (Trushenski Direct) at 3-4.
164
ETI Ex. 33 (Trushenski Direct) at 30-31.
165
ETI Ex. 68 (Trushenski Rebuttal) at 2. Notably, the amount ETI is seeking in its Rate Base is calculated
upon a 13-month average ending June 2011 (the last month of the Test Year), even though that amount is
slightly less than the 12-month average for the Test Year.
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BCII/U3 portion is $3,805,111.166 ETI witness Ryan Trushenski, the Manager of the Solid Fuel
Supply Group for ESI, testified that the coal inventory levels that were maintained at Nelson and
BCII/U3 during the test year were reasonable and the costs incurred to maintain those levels were
reasonable.167

Cities do not challenge the reasonableness of the Company’s 43-day inventory targets.
Rather, Cities point out that the size of the actual inventory that was maintained on-site at Nelson
during the Test Year exceeded the Company’s inventory target level. Therefore, Cities contend that
customers should not be forced to pay for inventory levels exceeding a 43-day supply (the amount
that the Company determined, through its Coal Inventory Policy, to be a reasonable and necessary
inventory to maintain on-site). According to Cities’ witness, Karl Nalepa, a 43-day inventory of
coal at Nelson would equate to 340,000 tons. He recommends that the value of a 43-day supply of
coal be included in the rate base, but that $1,451,415 be excluded from the rate base to account for
inventory at Nelson that was in excess of the 43-day supply.168

The evidence shows that the Company’s inventory “target” was a 43-day supply, while
actual inventories during the Test Year averaged around a 48-day supply. Mr. Trushenski pointed
out, and the ALJs concur, that the 43-day “target” was never intended to represent a hard and fast
figure from which no deviations could be allowed. Rather, the target merely represents an
operational planning tool. Moreover, there are many real-world factors – such as train cycle times,
coal burn rates, and so on – that can cause the actual coal inventory to fluctuate over time.169 The
ALJs conclude that the 48-day coal inventory was acceptably close to the 43-day target and was not
unreasonable. The total proposed dollar amount for this coal inventory is $9,846,037. The ALJs
conclude that the full value of the coal inventory was reasonable and should be included in rate base.

166
ETI Ex. 68 (Trushenski Rebuttal) at 2, and 3 at WP/P RB 4.2.
167
ETI Ex. 33 (Trushenski Direct) at 30-31.
168
Cities Ex. 6 (Nalepa Direct) at 28-29, 6C and 6E.
169
ETI Ex. 68 (Trushenski Rebuttal) at 4.
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H. Spindletop Gas Storage Facility

ETI relies upon a variety of fuel types to generate electricity. A major fuel component is
natural gas. However, energy generated from natural gas typically has the highest marginal cost
and, therefore, it is most often the last resource deployed to generate electricity. The fluctuation of
natural gas demand resulting from the changes in instantaneous demand is known as “swing.”
Although a portion of the system’s base load requirement is met with natural gas, the primary role of
natural gas is as a swing fuel on the system.170

Since 2004, ETI has owned and used the Spindletop Facility. ETI, through a third-party
operator, uses the Spindletop Facility to maintain a natural gas inventory that can be used to supply
ETI’s Sabine Station and Lewis Creek power generating facilities. Spindletop consists of two
salt-dome storage caverns (and associated equipment) located near Sabine Station.171 The
Spindletop Facility serves a function similar to that of a city water tower – it enables ETI to buy
natural gas at one point in time, store it, and use it at some future point when supplies are not
available elsewhere or when peak needs cannot otherwise be met. ETI maintains that the primary
benefit of the Spindletop Facility is that it provides: (1) supply reliability; and (2) swing flexibility.
“Supply reliability” means that the facility can provide a reliable supply of gas for Sabine Station
and Lewis Creek during potential gas supply curtailments, such as can occur during hurricanes,
freezes, or other unusual events. In a worst-case scenario, the Spindletop Facility is capable of
providing 100 percent of the fuel requirements for all five units at Sabine Station and one Lewis
Creek unit for four days at 70 percent of capacity. The Spindletop Facility also allows the Company
to avoid almost all intra-day gas purchases for Sabine Station. This is important because intra-day
purchases tend to be more expensive than longer-term purchases.172

Because major supply disruptions are more likely to occur during hurricane season and
during the winter, ETI manages its gas inventories conservatively during the period from June
through March in order to ensure that it can provide a reliable supply of fuel to meet peak generation

170
ETI Ex. 28 (McIlvoy Direct) at 7.
171
Id. at 31.
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loads for four consecutive days. During the remainder of the year, ETI will consider withdrawing
gas from the Spindletop Facility when the current day spot market price is higher than the
replacement cost for the gas, as determined by future market indicators. Conversely, ETI injects gas
into the Spindletop Facility when the cost of gas in the current market is less than the price of gas in
the futures market.173 For these various reasons, ETI witness Karen McIlvoy, who is employed as
the manager of ESI’s Gas & Oil Supply Group, testified that that Spindletop Facility is used and
useful for providing reliable, economical service to ETI’s customers.174 ETI witness Devon Jaycox,
who is employed as the manager of ESI’s Operations and Planning Group, testified that the
Company is always evaluating how much reliability the Spindletop Facility can provide as compared
to other options. He explained that, at Sabine Station, there is no other option that can provide ETI
with the same level of reliability and flexible swing service that the Spindletop Facility provides.175

Cities are critical of the Spindletop Facility, contending that the costs of operating it
outweigh the benefits gained from it. No other party challenged ETI’s use of the Spindletop
Facility. Cities’ witness Karl Nalepa testified that it costs ETI $13,219,097 per year to operate the
gas storage facility, whereas the Company could achieve the same supply reliability and swing
flexibility benefits it gets from the Spindletop Facility through other gas supply options at a cost of
only $1,724,659, thereby saving its customers $11,494,438. Thus, Mr. Nalepa stated that it is
imprudent for ETI to continue operating the Spindletop Facility.176

Mr. Nalepa testified that no other Entergy operating company owns or leases its own gas
storage facility, yet those other companies are able to satisfy their needs for supply reliability and
swing flexibility through other methods, such as existing gas supply and transportation contracts, at
much lower costs. According to Mr. Nalepa, those other companies obtain supply reliability and
swing flexibility through the use of monthly, daily, and intra-day natural gas supply contracts. In

172
ETI Ex. 28 (McIlvoy Direct) at 32-33; ETI Initial Brief at 39, n. 264.
173
ETI Ex. 28 (McIlvoy Direct) at 33-34.
174
Id. at 37.
175
Tr. at 966.
176
Cities Ex. 6 (Nalepa Direct) at 18-20; Cities Ex. 6B (Errata No. 2).
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support of this claim, he pointed to one of the operating companies, EGSL, as an example. He
pointed out that EGSL has no firm transportation contracts, no firm supply contracts, and no fuel oil
back-up at its generating plants. Thus, Mr. Nalepa stated that the only cost incurred by EGSL for
reliability and flexibility is the commodity cost of the natural gas it purchases. Mr. Nalepa testified
that EGSL achieves the same level of service as ETI without incurring the large cost of the
Spindletop Facility.177

Mr. Nalepa asserted that the long-term gas supply contract that ETI recently entered into
with Enbridge Pipeline, L.P. (the Enbridge Contract) will help provide the Company with increased
supply reliability because the gas supplied by Enbridge will come from production areas that are less
susceptible to hurricane-related disruptions. Mr. Nalepa also noted that ETI could meet its swing
flexibility requirements through use of spot gas purchases, its operational balancing agreement with
the TETCO pipeline, and other pipeline companies, such as the Copano Pipeline that serves Lewis
Creek.178

Mr. Nalepa also disputed ETI’s contention that the Spindletop Facility serves as a valuable
protection against extreme events such as hurricanes, by noting that the Spindletop Facility was out
of service for almost two weeks in 2005 following Hurricane Rita.179

As noted above, Mr. Nalepa testified that it cost ETI $13,219,097 to operate the Spindletop
Facility in the Test Year. Mr. Nalepa estimated that the sum of the Test Year withdrawals of gas
from the Spindletop Facility equaled 8,560,604 MMBtu. He then divided his total estimated cost of
the facility ($13,219,097) by his total estimated withdrawals of gas (8,560,604 MMBtu) to calculate
an “all-in per unit rate” of $1.54 per MMBtu. He asserted that, by contrast, transportation costs on
various gas pipelines connected to Sabine and Lewis Creek ranged from $0.025 to $0.22 per
MMBtu. Mr. Nalepa estimated $0.18 per MMBtu as the average replacement cost that ETI would
incur in transportation contracts if it were to stop using the Spindletop Facility and achieve the same

177
Cities Ex. 6 (Nalepa Direct) at 22-23.
178
Cities Ex. 6 (Nalepa Direct) at 25.
179
Id. at 23-24.
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level of supply reliability and swing flexibility through the use of gas supply contracts. By
multiplying $0.18 times 8,560,604 MMBtu, he estimated that the benefits of the Spindletop Facility
could have been achieved through other means at a cost of only $1,724,659. Thus, Mr. Nalepa
recommended that $7,794,202 should be removed from ETI’s base rate, and $5,424,895 should be
excluded as an eligible fuel expense.180

ETI disagrees with essentially all of Mr. Nalepa’s points and responds to his testimony on a
number of fronts. Perhaps foremost, ETI points out that Mr. Nalepa’s main premise – that ETI’s
customers pay all the costs of the Spindletop Facility while the other Entergy operating customers
avoid those costs – is simply incorrect. According to ETI witnesses, 57.50 percent of the costs
associated with the Spindletop Facility are billed to EGSL as part of the MSS-4 billing process
between ETI and EGSL for its “legacy plants,”181 and another 2.4 percent of the costs are passed on
to other Entergy operating companies through the MSS-3 agreement. Only 40.1 percent of the
Spindletop Facility costs are borne by ETI customers.182 Thus, Mr. Nalepa’s calculations greatly
overstate the costs of the Spindletop Facility that are borne by ETI customers and greatly understate
the costs that are borne by EGSL customers. ETI witness Considine also pointed out that the
Commission has consistently and repeatedly concluded that the Spindletop Facility is used and
useful and, therefore, has allowed ETI and its predecessors to recover the costs associated with the
Spindletop Facility.183

Ms. McIlvoy also testified that, contrary to Mr. Nalepa’s testimony, the conditions under
which the other Entergy operating companies operate are so different from the conditions under
which ETI operates that it makes no sense to assume they have similar supply reliability and swing
flexibility needs. For example, EGSL and ETI both own roughly the same generating capacity from

180
Id. at 24-27; Cities Ex. 6B (Errata No. 2).
181
The legacy plants are the four power generating plants that were owned by Entergy Gulf States, Inc. –
Lewis Creek, Sabine Station, Nelson, and Willow Glen. When EGSI was broken into ETI and EGSL in 2007,
ETI became the owner of Lewis Creek and Sabine Station, while EGSL became the owner of Nelson and
Willow Glen. ETI Ex. 60 (McIlvoy Rebuttal) at 5-6; ETI Ex. 46 (Considine Rebuttal) at 3.
182
ETI Ex. 46 (Considine Rebuttal) at 3-4; ETI Ex. 60 (McIlvoy Rebuttal) at 18-19.
183
ETI Ex. 46 (Considine Rebuttal) at 3-4.
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gas-powered plants – 2,378 MW for EGSL versus 2,295 MW for ETI. However, the ETI plants are
operated at a much higher capacity than the EGSL plants. During the Reconciliation Period, EGSL
burned much less natural gas than did ETI – 63,420,554 MMBtu burned at the EGSL plants versus
144,538,535 MMBtu burned at the ETI plants. Moreover, EGSL has four gas-powered plants while
ETI has only two. Of EGSL’s four plants, two (Calcasieu and Ouachita) use combined cycle gas
turbine technology. This gives them a quick-start and shut-down capability, allowing them to be
operated primarily only at peak demand times. Thus, according to Ms. McIlvoy, Mr. Nalepa’s
premise – that because EGSL is able to reliably operate its gas-fired facilities without gas storage,
ETI should be able to do so as well – makes no sense. Because ETI burns a vastly larger amount of
natural gas than EGSL, its need for supply reliability and swing flexibility is much greater.184

Ms. McIlvoy also disputed Mr. Nalepa’s assertion that ETI could use the Enbridge Contract
and call options to provide the Company with sufficient supply reliability. She noted that the
maximum amount of gas deliverable under the Enbridge Contract is insufficient to run the ETI
plants even at minimum load. By contrast, the Spindletop Facility is capable of supplying all Sabine
Station units and one unit at Lewis Creek for four days at 70 percent capacity. Moreover, the
Enbridge Contract will expire, whereas the Spindletop Facility can be operated indefinitely.
Ms. McIlvoy explains that the use of call options is not viable because a call option must be
delivered “ratably,” meaning the gas must be delivered at a constant, even rate throughout the
delivery period. In order to have gas available to meet peak needs in the absence of the Spindletop
Facility, ETI would have to exercise call options for a maximum delivery, but it would not need all
of the gas delivered at off-peak times of the day.185

ETI witness Jaycox disputed Mr. Nalepa’s premise that ETI could use call options to ensure
reliability. According to Mr. Jaycox, “call options are cheaper than storage, but there’s no
comparison” between the amount of reliability that they provide as compared to the Spindletop
Facility.186 Mr. Jaycox also explained that, due to their geographic location and the limited import

184
ETI Ex. 60 (McIlvoy Rebuttal) at 3-8.
185
ETI Ex. 60 (McIlvoy Rebuttal) at 8-12.
186
Tr. at 969.
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capability to the ETI service area, Sabine Station and Lewis Creek are considered particularly
critical, thereby increasing the need for reliability at those plants.187

When Mr. Nalepa calculated ETI’s cost of achieving supply reliability and swing flexibility
without the use of the Spindletop Facility, he estimated it would cost only $1,724,659. He did so, in
part, by assuming that a five-day 35,000 MMBtu/day call option would cost ETI $26,250.
Ms. McIlvoy asserted that it is not reasonable to assume that all options would cost as little as
$26,250. Based upon her calculations, ETI would have to purchase 14 five-day 35,000 MMBtu/day
call options per month to achieve supply reliability. She posited that, based upon the laws of supply
and demand, the more call options ETI has to purchase, the higher the cost of those options would
be. She also pointed out that Mr. Nalepa’s proposed use of call options would require ETI to spend
hundreds of thousands of dollars each month to purchase call options that it would never exercise.
According to Ms. McIlvoy, it is unclear from Commission precedents whether ETI would be entitled
to recover the costs of these un-exercised options.188

The evidence establishes that the Spindletop Facility is critical to providing reliability and
swing flexibility to ETI’s Texas plants. The ALJs conclude that the Spindletop Facility is a used and
useful facility providing reliability and swing flexibility to ETI’s customers at a reasonable price,
and Cities’ arguments to the contrary lack merit.

I. Short Term Assets

In its application ETI requested that, as short term assets, the following amounts be included
in the rate base: prepayments in the amount of $7,218,037; materials and supplies in the amount of
$29,252,574; and fuel inventory in the amount of $53,759,975. These amounts were derived using
13-month averages ending June 2011.189 Staff witness Anna Givens agrees with the approach of
using 13-month averages to determine the appropriate amounts for short term assets. However, she
recommends using the 13-month period ending December 2011, because it is the most recent

187
Tr. at 975, 986-87.
188
ETI Ex. 60 (McIlvoy Rebuttal) at 12-15.
189
ETI Ex. 3 at Sched. B-1.
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information available. Using this approach, Ms. Givens recommends that, as short term assets, the
following amounts be included in the rate base: prepayments at $8,134,351 ($916,313 more than
ETI’s request); materials and supplies at $29,285,421 ($32,847 more than ETI’s request); and fuel
inventory at $52,693,485 ($1,066,490 less than ETI’s request).190 ETI does not oppose Staff’s
recommendation on this issue. No party has a criticism of Staff’s estimates as to prepayment,
materials and supplies, and fuel inventory, nor do the ALJs. Accordingly, the ALJs recommend
adopting the numbers proposed by Staff.

J. Acquisition Adjustment

In its application, ETI included an adjustment of $1,127,778 for an “electric plant
acquisition.”191 The proposed adjustment, which relates to costs incurred by ETI when it acquired
the Spindletop Facility, consists of closing costs of $211,209 and legal and internal costs of
$916,568.192 ETI witness Considine explained that, prior to December 2009, the same amounts were
included in the Electric Plant in Service (FERC Account 101). On January 11, 2010, FERC issued
Opinion No. 505 in FERC Docket No. ER07-956-00 and ordered the Company to transfer the
amounts above from Account 101 to FERC Account 114, Electric Plant Acquisition Adjustments.
He also pointed out that the costs were included in ETI’s filed rate base amounts in Docket Nos.
34800 and 37744.193 Mr. Considine contended that these amounts should remain in rate base
because they represent costs incurred by ETI for the purchase of a viable asset that benefits its retail
customers. He pointed out that the amounts have previously been included in the Company’s rate
base, but the only thing that has changed is that the amounts were previously allocated to a different
account. ETI argues that the fact that the costs were approved as part of rate base in two previous
ETI dockets verifies that they were “reasonable, prudently incurred, and properly capitalized.”194

190
Staff Ex. 1 (Givens Direct) at 31-32.
191
ETI Ex. 3 at Sched. C-1.
192
ETI Ex. 46 (Considine Rebuttal) at 4.
193
Id. at 4-5.
194
ETI Initial Brief at 43.
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Thus, ETI contends it would be inappropriate to penalize it because of an accounting technicality
imposed upon it by FERC.195

Staff advocates the removal of the entire electric plant acquisition adjustment from rate base,
contending that, “[a]s a rule, the rate base component for plant in service includes only the original
cost, net of accumulated depreciation.”196 Cities similarly contend, without citing to any legal
authority, that acquisition adjustments are not legally permitted as an addition to rate base for
ratemaking purposes or as a depreciable asset for regulatory ratemaking purposes.197 Staff disputes
ETI’s contention that the fact that the costs were approved as part of rate base in two previous ETI
dockets proves that they were reasonable, prudently incurred, and properly capitalized. Staff points
out that those two prior dockets were settled rate cases and, therefore, “provide no illumination on
this issue.”198 Finally, Staff argues that ETI failed to prove either element of the Commission’s two-
part Hooks test for the determination of whether the acquisition adjustment should be included in
rate base. Pursuant to the Hooks test, in determining whether an acquisition adjustment should be
included in rate base, “the Commission should consider whether or not the purchase price was
excessive and whether or not specific and offsetting benefits have accrued to ratepayers.”199
According to Staff, ETI’s acquisition adjustment should be disallowed because the Company failed
to meet it burden of proof on these two issues.200

The ALJs are unpersuaded by the arguments of Staff and Cities. Their primary argument
(i.e., that acquisition adjustments are simply not allowed as an addition to rate base for ratemaking
purposes) is incorrect. Indeed, the Hooks decision, the precedent on which Staff relies for its
fallback argument, suggests that, more often than not, acquisition adjustments should be included in

195
ETI Ex. 46 (Considine Rebuttal) at 5.
196
Staff Ex. 1 (Givens Direct) at 35.
197
Cities Initial Brief at 26.
198
Staff Initial Brief at 11.
199
Application of Hooks Telephone Company for a Rate Increase within Bowie County, Docket No. 2150,
Examiner’s Report at 2 (Mar. 28, 1980)(Hooks).
200
Staff Reply Brief at 12.
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rate base: “Amortization of an acquisition adjustment need not be allowed as an expense in all
cases.”201

Moreover, the evidence demonstrates that ETI met is burden under the Hooks test. As
discussed more fully in Section V.H. of this PFD, above, there is ample evidence in the record to
demonstrate that the Spindletop Facility is used and useful and provides specific and offsetting
benefits to ratepayers in a cost-effective manner. The evidence further shows that the acquisition
adjustment represents costs that were actually incurred by ETI in the furtherance of acquiring the
Spindletop Facility, and not a mere mark-up in original cost. For these reasons, the ALJs conclude
that the $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of the
Spindletop Facility was reasonable, necessary, and properly incurred. Accordingly, the ALJs agree
that it should be included in ETI’s rate base.

K. Capitalized Incentive Compensation

In the application, some of the incentive payments ETI made to its employees were
capitalized into plant in service accounts and ETI asks to include those amounts in rate base.202 A
portion of those capitalized accounts represents payments made by ETI for incentive compensation
tied to financial goals (financially-based incentive compensation). Cities contend that, consistent
with Commission precedent, ETI ought not be allowed to include in rate base the portion of its
capitalized incentive compensation that is attributable to financially-based incentive
compensation.203 The issue of whether financially-based incentive compensation is recoverable as a
portion of Operating Expenses is discussed at length in Section VII.D.2. of this PFD. ETI makes the
same arguments in favor of recoverability in that section that it makes here as to the inclusion of
financially-based incentive compensation in rate base. The discussion of that issue need not be
repeated here, but the analysis is the same. In summary, the ALJs conclude that ETI should not be
entitled to recover its financially-based incentive compensation costs. Thus, for the same reasons
discussed in Section VII.D.2, the ALJs agree with Cities’ contention that the portion of ETI’s

201
Hooks (emphasis added).
202
Cities Ex. 2 (Garrett Direct) at 52.
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incentive payments that are capitalized and that are financially-based should be excluded from ETI’s
rate base.

On the other hand, the ALJs disagree with Cities as to the amount of that exclusion. Cities
argue that $9,835,111 (Cities’ estimate of ETI’s financially-based incentive payments that are
capitalized each year into plant in service) should be removed from rate base.204 Broadly speaking,
ETI has two categories of incentive compensation programs – annual incentive programs, and long-
term incentive programs. To arrive at the figure of $9,835,111, Cities’ witness Garrett assumed that:
(1) 100 percent of the costs of the long-term incentive programs were financially-based and,
therefore, should be excluded from rate base; and (2) his calculated percentage of the annual
incentive programs were financially-based and, therefore, should be excluded from rate base. He
then applied those percentages to the incentive costs that ETI capitalized in 2008, 2009, and the
portion of 2010 prior to the Test Year.205

As explained in Section VII.D.2., the ALJs agree that Mr. Garrett was correct to recommend
removing 100 percent of the cost of ETI’s long-term incentive programs. However, as to the annual
incentive programs, he defined what qualifies as “financially based” much too broadly, and therefore
wrongly assumed that his calculated percentage of the costs of those programs should be excluded.
Instead, the ALJs conclude that the actual percentages should be used to determine the amount that
is financially based.206

Finally, ETI challenges Mr. Garrett’s attempt to disallow capitalized incentive costs from
2008 through June 30, 2009.

Much of the rate base that Mr. Garrett seeks to disallow (namely, costs from 2007
through June 30, 2009) is not presented for review in this rate case. Rather those
costs were presented for review in the Company’s last rate case, Docket No. 37744,

203
Id. at 52-53.
204
Id. at 52-53; Cities Initial Brief at 27.
205
Cities Ex. 2 (Garrett Direct) at 53 and MG-2.10.
206
See discussion in Section VII.D.2.
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in which the Company presented capital additions for the period of April 1, 2007,
through June 30, 2009. . . . Even though Docket No. 37744 was a settled case, the
final order concluded that ‘[b]ased on the evidence in this docket, the overall total
invested capital through the end of the test year meets the requirements in PURA §
36.053(a) that electric utility rates be based on original cost, less depreciation of
property used and useful to the utility in providing service.’ This conclusion goes
beyond merely settling issues without deciding anything and should be construed as
to be conclusive as to the reasonableness of capital costs at issue in that prior case.207

The ALJs agree. The Test Year for ETI’s prior ratemaking proceeding ended on June 30,
2009. The reasonableness of ETI’s capital costs (including capitalized incentive compensation) was
dealt with by the Commission in that proceeding and is not at issue here. Thus, the ALJs conclude
that exclusion of capitalized incentive compensation that is financially-based can only be made for
incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior Test
Year) through June 30, 2010 (the commencement of the current Test Year). The amount of the
exclusion is not specifically known at this time.

VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and 11]

A. Capital Structure

ETI’s capital structure is 50.08 percent debt and 49.92 percent equity. No party has taken
issue with ETI’s capital structure. Therefore, the ALJs recommend that the Commission enter an
order finding that the appropriate capital structure for ETI is 50.08 percent debt and 49.92 percent
equity.

B. Return on Equity

The United States Supreme Court has set forth a minimum constitutional standard governing
equity returns for utility investors:

From the investor or company point of view it is important that there be enough
revenue not only for operating expenses but also for the capital costs of the business.
These include service on the debt and dividends on the stock. By that standard the

207
ETI Initial Brief at 44, quoting Docket No. 37744, Order at CoL 10 (Dec. 13, 2010).
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return to the equity owner should be commensurate with returns on investments in
other enterprises having comparable risks. That return, moreover, should be
sufficient to assure confidence in the financial integrity of the enterprise, so as to
maintain its credit and to attract capital.208

Thus, a utility must have a reasonable opportunity to earn a return that is: (1) commensurate with
returns on equity investments in enterprises having comparable risks; (2) sufficient to ensure the
financial soundness of the utility’s operations; and (3) adequate to attract capital at reasonable rates,
thereby enabling it to provide safe, reliable service. The allowed ROE should enable the utility to
finance capital expenditures at reasonable rates and to maintain its financial flexibility during the
period in which the rates are expected to remain in effect.

1. Proxy Group

Because ETI is not a publicly traded company, it is necessary to establish a group of
companies that are publicly traded and that are comparable to ETI in certain fundamental business
and financial respects to serve as its “proxy” in the ROE estimation process. Both financial theory
and legal precedent support the use of comparable companies within a proxy group to determine a
utility’s ROE, and all of the ROE witnesses in this case have relied on proxy groups to estimate a
required ROE for ETI.

ETI witness Hadaway started with all the vertically integrated electric utilities that are
included in the Value Line Investment Survey (Value Line). To improve the group’s comparability
with ETI, which has a senior secured bond ratings of BBB+ (Outlook Negative) from Standard &

208
Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603, 64 S. Ct. 281, 288 (1944); see also
Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of W. Va., 262 U.S. 679, 692-93, 43 S. Ct.
675, 679 (1923) (“A public utility is entitled to such rates as will permit it to earn a return on the value of the
property which it employs for the convenience of the public equal to that generally being made at the same
time and in the same general part of the country on investments in other business undertakings which are
attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are
realized or anticipated in highly profitable enterprises or speculative ventures. The return should be
reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate,
under efficient and economical management, to maintain and support its credit and enable it to raise the
money necessary for the proper discharge of its public duties.”).
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Poor’s (S&P) and Baa2 (stable) rating from Moody’s Investors Service (Moody’s), Dr. Hadaway
imposed the following restrictions:

x comparable companies had to have senior secured bond ratings of at least BBB by S&P or Baa
by Moody’s;

x comparable companies had to derive at least 70 percent of revenues from regulated utility sales;

x comparable companies had to have consistent financial records not affected by recent mergers or
restructuring; and

x comparable companies had to have a consistent dividend record with no dividend cuts or
resumptions during the past two years.

Those selection criteria resulted in a 23-utility proxy group.

State Agencies witness Miravete excluded Entergy from his proxy group, but otherwise his
proxy group was identical to ETI’s. Cities witness Parcell ran his calculations using both
Dr. Hadaway’s 23-utility proxy group and another 8-utility proxy group, but they produced similar
ROE results. TIEC witness Gorman used the same 23 utility proxy group as ETI witness Hadaway
used.

Staff witness Cutter was the only witness to use a different proxy group. He used a 13 utility
proxy group for his discounted cash-flow (DCF) analysis. To arrive at this proxy group, Mr. Cutter
started with all of the domestic electric-utility companies tracked by Value Line because Value Line
is the most widely used, independent investment service in the world. Then he eliminated the
utilities that did not meet the following criteria:

x Value Line Financial Strength ratings of A+, A or B++;

x A capital structure including less than 45 percent, or more than 55 percent, debt;

x Total capitalization in excess of five billion dollars;

x No recent dividend cuts or omissions;
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x No recent or potential merger activities or other major capital expansion; and

x No Value Line appraisal of being outside the norm.

On his final analysis, Mr. Cutter eliminated three of his 13 utility proxy group, referring to those he
eliminated as “outliers.” ETI points out, however, that one of the remaining ten companies, Con
Ed, is not comparable to ETI because it is a delivery company as opposed to a vertically integrated
utility. ETI’s essential criticism of Mr. Cutter’s proxy group analysis is that he should have used a
larger proxy group and that he admitted a better comparison to ETI could be obtained from using a
larger proxy group.

2. DCF Analysis

To analyze ETI’s cost of equity capital, all of the testifying experts first performed a DCF
analysis. The DCF approach is based on the theory that a stock’s current price represents the present
value of all expected future cash flows. In its most general form, the DCF model is expressed as
follows:

Where P0 represents the current stock price, D1 . . . . D∞ are all expected future dividends, and k is
the expected discount rate, or required ROE. That equation can be simplified and rearranged to
ascertain the required ROE:

Where P0 represents the current stock price, D is expected future dividends, g is the growth rate, and
k is the expected discount rate, or required ROE.

This is commonly referred to as the “Constant Growth DCF” model in which the first term is
the expected dividend yield and the second term is the expected long-term growth rate. The
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Constant Growth DCF model requires assumptions of: (1) a constant growth rate for earnings and
dividends; (2) a stable dividend payout ratio; (3) a constant price-to-earnings multiple; and (4) a
discount rate greater than the expected growth rate.

ETI witness Hadaway’s DCF analysis was based on three versions of the DCF model. In the
first version of the DCF model, he used the constant growth format with long-term expected growth
based on analysts’ estimates of five-year utility earnings growth. In the second version of the DCF
model, for the estimated growth rate, Dr. Hadaway used only the long-term estimated gross domestic
product (GDP) growth rate. In the third version of the DCF model, Dr. Hadaway used a two-stage
growth approach, with stage one based on Value Line’s three-to-five-year dividend projections and
stage two based on long-term projected growth in GDP. The dividend yields in all three of the
annual models are from Value Line’s projections of dividends for the coming year and stock prices
are from the three-month average for the months that correspond to the Value Line editions from
which the underlying financial data are taken.209

The DCF results for Dr. Hadaway’s comparable company group using the traditional
constant growth model indicated an ROE of 9.90 percent to 10.00 percent. Dr. Hadaway then
recalculated the constant growth results with the growth rate based on long-term forecasted growth
in GDP. With the GDP growth rate, the constant growth model indicates an ROE range of
10.40 percent to 10.70 percent. Although the GDP growth rate is higher than the average of
analysts’ growth rates, Dr. Hadaway testified that his GDP estimate is within the analysts’ range and
slightly below the 6.00 percent 3-to-5 year average growth rate projection from Value Line. Finally,
Dr. Hadaway’s multistage DCF model indicated an ROE range of 10.20 percent to 10.30 percent.
The results from the DCF model, therefore, indicate an ROE range of 9.90 percent to
10.70 percent.210 In his rebuttal, Dr. Hadaway updated his ROE analysis using current market
conditions but employing the same methodologies that he used in his previous analysis. After

209
ETI Ex. 6 (Hadaway Direct) at 33-44.
210
Id. at 44, Exhibit SCH-4.
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making adjustments to the proxy group to stay consistent with his selection criteria, Dr. Hadaway’s
indicated DCF range was 10.00 percent to 10.20 percent.211

The principal argument against Dr. Hadaway’s analyses is that he used unsupported and
excessive growth rates. According to the intervenors, these excessive growth rates exaggerate future
cash flows, which results in an inflated ROE.

Intervenors argue that Dr. Hadaway’s Analysts’ Constant Growth DCF model produces
excessive return estimates.212 In rebuttal, Dr. Hadaway’s analysts’ growth model produced a
10.1 percent group average ROE and a 10.0 percent group median ROE.213 The intervenors contend
that the group average long-term growth rate on which his DCF study was based was 5.62 percent,
which is far too high to be sustainable in the long-term (as required as an input in the Constant
Growth DCF model).214 According to intervenors, the excessive level of his growth rate is apparent
by comparison to current analysts’ projected growth for U.S. GDP, which range from 4.5 percent to
5.0 percent.215 Dr. Hadaway’s growth rate is more than 60 basis points above the most generous
expected growth of the U.S. economy. Intervenors contend that that nominal GDP should be the
ceiling of a reliable proxy for a utility dividend growth rate. Because the evidence shows that
nominal GDP as projected by consensus analysts, the Executive Branch, and the Congressional
Budget Office is 5 percent, Dr. Hadaway’s 5.62 percent growth rate is excessive and undermines the
reasonableness of his models.

Intervenors criticize Dr. Hadaway’s decision on rebuttal to exclude Edison International in
his proxy group.216 Dr. Hadaway did so because Edison International’s ROE of 5.2 percent was
below a 5.07 percent cost of debt based on an average of Triple B utility rates for the time period

211
Id. at 44.
212
TIEC Ex. 2 (Gorman Direct) at 39.
213
ETI Ex. 52 (Hadaway Rebuttal) at Ex. SCH-R-6.
214
Id. at Ex. SCH-R-6; TIEC Ex. 2 (Gorman Direct) at 39; Cities Ex. 3 (Parcell Direct) at 36-37; OPC Ex. 1
(Szerszen Direct) at 23-24.
215
TIEC Ex. 2 (Gorman Direct) at 19; Cities Ex. 3 (Parcell Direct) at 37.
216
ETI Ex. 51 (Hadaway Rebuttal) at Ex. SCH-R-6.
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January 12-March 12, plus 100 basis points.217 Intervenors contend that this rationale is tenuous,
and that had Dr. Hadaway included Edison International (or even excluded Hawaiian Electric, the
utility in his proxy group that had the highest ROE) his own analysis (even with its excessive growth
rates) would have resulted in a 9.85 percent average ROE.

Finally, Dr. Hadaway conceded that he used the same methodology for calculating GDP in
this case as he did in the Oncor rate case.218 Intervenors contend that Dr. Hadaway’s GDP
projections are not credible proxies for investor’s expected dividend growth rates because they are
not based on published analysts’ or government GDP forecasts. Rather, Dr. Hadaway forecasts
future GDP growth using his own personal calculation that forecasts GDP by examining historic
GDP growth over the last 10, 20, 30, 40, 50, and 60-year periods and weighting those averages.219
Intervenors note that this approach was rejected by the Commission in the Oncor rate case.220

Staff witness Cutter used the DCF model to project ETI’s cost of equity. Under Mr. Cutter’s
view, the theory underlying the DCF model is that the price of a share is equal to the present value
of all future earnings. Unless the stock is sold for a profit (or loss) from the price it was originally
purchased, the only way to determine earnings on a share is to determine its future dividends. This
requires, in Mr. Cutter’s opinion, an understanding of investors’ current expectations of growth of
those dividends. The issue is the growth expectation that investors have embodied in the current
price of the stock. According to Mr. Cutter, the best way to arrive at a reliable growth estimate of
those dividends is to use the growth estimates of investment advisory firms rather than the estimates
of a single, independent analyst.221

Mr. Cutter used both Value Line and Zacks Investment Service (Zacks) in ascertaining
long-term earnings growth rates. He used Value Line because it is the most widely used

217
Id.
218
Tr. at 227-228.
219
ETI Ex. 6 (Hadaway Direct) at Ex. SCH-3; Tr. at 218.
220
Application of Oncor Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 35717,
PFD at 72-73.
221
Staff Ex. 6 (Cutter Direct) at 10-15.
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independent investment service in the world and Zacks because it compiles consensus earnings
forecasts from groups of professional security analysts.222

Mr. Cutter’s DCF analysis resulted in range from 7.46 percent to 10.71 percent, with a point
estimate for cost of equity being 9.3 percent.

TIEC witness Gorman’s first DCF model was a constant growth model using consensus
analysts’ growth rates that resulted in an average constant growth DCF of 9.32 percent and a median
constant growth DCF of 9.84 percent. The average analysts’ growth rate was 4.94 percent.223
According to TIEC, ETI does not claim that a constant growth model using analysts’ growth rates is
inappropriate and argues that Dr. Hadaway failed to offer any rebuttal testimony criticizing
Mr. Gorman’s Analysts’ Growth DCF model.

Mr. Gorman also performed a constant growth DCF model using sustainable growth rates.
His average sustainable growth rate for the proxy group was 4.54 percent and produced a proxy
group average and median DCF result of 8.91 percent and 8.9 percent, respectively.224 According to
TIEC, a sustainable growth rate is based on the percentage of a utility’s earnings that are retained
and reinvested in utility plant and equipment.225

Mr. Gorman also performed a multi-stage DCF model to reflect changing growth
expectations that would reflect the possibility of non-constant growth for a company over time.
Mr. Gorman’s multi-stage model reflected three growth periods: (1) a short-term growth period of
five years; (2) a transition period for years six through ten; and (3) a long-term growth period,
starting in year 11 through perpetuity. For the short-term period, Mr. Gorman relied on the
consensus analysts’ growth projections from his constant growth DCF model (i.e., 4.94 percent).
For the second stage (i.e., the transition period), growth rates are reduced or increased by an equal

222
Staff Ex. 6 (Cutter Direct) at 13.
223
TIEC Ex. 2 (Gorman Direct) at Ex. MPG-4.
224
TIEC Ex. 2 (Gorman Direct) at 18.
225
TIEC Ex. 2 (Gorman Direct) at 17.
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factor, which reflect the difference between the analysts’ growth rates and the GDP growth rate. For
the long-term period, he assumed the maximum sustainable growth rate for a utility company as
proxied by the consensus analysts’ projected growth rate for the U.S. GDP (i.e., 5.0 percent). The
result of his multi-stage growth DCF model was an average ROE of 9.37 percent and a median of
9.48 percent.226

Cities witness Parcell calculated the DCF results for each company in his proxy group by
using and considering five indicators of growth expectations consisting of: (i) 2007 – 2011 earnings
retention; (ii) five-year historical average earnings per share, dividends per share, and book value per
share; (iii) projected earnings retention; (iv) projected EPS, DPS, BVPS; and (v) projected EPS as
reported by Yahoo Finance. Using this in his DCF model resulted in an ROE of 9.0 percent to
9.5 percent.227

OPC witness Szerszen’s DCF analysis used the same group of 23 comparable companies
included in Dr. Hadaway’s DCF analysis. Dr. Szerszen’s DCF analysis was framed with
consideration of ETI’s financial integrity as discussed by the major bond rating agencies, the current
and projected interest rate environment, and investment analyst views of the regulated utility
sector.228 Interest rates are currently very low, as reflected in the yields to maturity and interest rates
on various fixed income investments. OPC contends, in contrast to Dr. Hadaway, that utility stocks
have been less volatile than the stock market in general.229 This is confirmed by Value Line’s
December 23, 2011, observation that “electric utility stocks have long been viewed as a safe haven
in volatile markets, due in large part to their generous dividend yields.”230 Dr. Szerszen also took
exception to Moody’s characterization of ETI as having above average business and regulatory risk.
Moody’s assessment is primarily based on the lack of pass-through regulatory lag-reducing cost
recovery mechanisms in Texas compared to Entergy’s Louisiana and Mississippi jurisdictions. Dr.

226
TIEC Ex. 2 (Gorman Direct) at 19, Ex. MPG-9.
227
Cities Ex. 3 (Parcell Direct) at 24, 33.
228
OPC Ex. 1 (Szerszen Direct) at 8-17.
229
Id. at 15.
230
Id.
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Szerszen testified that ETI may not have a formula rate plan similar to the Louisiana and Mississippi
Entergy operating companies, but it does have a Distribution Cost Recovery Factor (DCRF) and
Transmission Cost Recovery Factor (TCRF) available that “will allow ETI to charge ratepayers for
additional distribution and transmission investments outside of a traditional rate request filing.”231
None of Entergy’s other operating companies have TCRF and DCRF riders. OPC notes that Cities
witness Parcell agrees that the availability of such recovery mechanisms affects ETI’s level of risk;
he testified that a combination of ETI’s fuel factor rider, TTC rider, energy efficiency rider,
hurricane cost recovery rider, rate case expense rider, proposed increased customer service charge,
and DCRF and TCRF riders results in about 30 percent of ETI’s total overall requested revenue
requirement being subject to revenue risk and regulatory lag.232

Dr. Szerszen incorporated two different dividend yield calculations in her DCF model. The
first calculation estimated a dividend yield using 2011 average stock prices and 2012 projected
dividend rates for each company, and the second calculation incorporated more recent March 5,
2012, closing prices for the comparables. The average dividend yield using 2011 average stock
prices was 4.66 percent and, using March 5, 2012, closing prices, was 4.32 percent.233

Dr. Szerszen provided some practical examples of how blind reliance on analyst earnings
growth projections can lead to questionable DCF growth rates. At least five of the comparable
utility companies had five-year earnings growth rate projections that ranged from 8.5 percent to
11 percent. Dr. Szerszen stated that she was unaware of any regulated utility company that has
consistently achieved such high earnings growth rate over the past 28 years, and that it is reasonable
to assume such performance is unlikely in the longer term future. Dr. Szerszen’s review of the
comparable company past and projected growth rates resulted in a reasonable dividend growth rate
expectation of 3.9 percent to 5 percent. Depending on whether 2011 average stock prices are used or

231
Id at 11-13.
232
Cities Ex. 3 (Parcell Direct) at 16-18.
233
OPC Ex. 1 (Szerszen Direct) at 17.
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the updated 2012 stock prices are used, Dr. Szerszen’s DCF analysis resulted in an ROE ranging
from 8.32 percent to 9.32 percent.234

State Agencies’ witness Miravete’s DCF analysis used calculations for three averaging
periods, 30, 90 (the reference period), and 180 days ending on March 2, 2012, respectively. For the
commonly used 90 day averaging period, the capitalization-weighted average ROE is 9.23 percent.
Evaluating the averaging period at either 30 or 180 days produces ROE estimates of 9.24 percent
and 9.34 percent, respectively. Dr. Miravete weighed the computations by the capitalization of each
firm to correct the effect of each variable according to the relative market value of the corresponding
utility. According to Dr. Miravete, this approach avoids the distortion caused by adding numerous,
but possibly irrelevant, firms that may produce biased estimates. Dr. Miravete conceded that the
effect of ignoring differences in scale of utilities in the determination of the ROE is substantial. He
acknowledged that if he had ignored the differences in size of these electric utilities, his DCF ROE
estimate would have been 9.68 percent.235

3. Risk Premium Analysis

Dr. Hadaway’s risk premium studies are divided into two parts. First, he compared electric
utility authorized ROEs for the period 1980-2010 to contemporaneous long-term utility interest
rates. The differences between the average authorized ROEs and the average interest rate for the
year is the indicated equity risk premium. He then added the indicated equity risk premium to the
forecasted and current triple-B utility bond interest rate to estimate ROE.236

In calculating the equity risk premium, Dr. Hadaway adjusted for the inverse relationship
between equity risk premiums and interest rates (when interest rates are high, risk premiums are low
and vice versa). Dr. Hadaway provided regression analyses of the allowed annual equity risk
premiums relative to interest rate levels. The negative regression coefficients confirm the inverse
relationship between equity risk premiums and interest rates according to ETI. Dr. Hadaway used

234
Id. at 22.
235
State Agencies Ex. 1 (Miravete Direct) at 12-13.
236
ETI Ex. 6 (Hadaway Direct) at 36-38, 45.
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that negative interest rate change coefficient in conjunction with current and forecasted interest rates
to establish the appropriate ROE.237 Staff witness Cutter agreed that the risk premium analysis
needs to reflect this adjustment.238

The results of Dr. Hadaway’s initial equity risk premium studies indicate an ROE range of
10.00 percent to 10.01 percent. ETI states that these results reflect the sharp drop in interest rates
that have occurred for high quality borrowers. The Federal Reserve System’s continuing “easy
money” policies have provided renewed liquidity in the credit markets that is reflected in these
lower yields. These models, however, cannot capture the current equity volatility or the increased
level of risk aversion for equity investors. These circumstances indicate that the cost of equity has
not declined to the extent that interest rates on utility debt have dropped. Thus, Dr. Hadaway
testified that the results of the risk premium analysis must be discounted and more emphasis placed
on the DCF analysis.239

In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but
employing the same methodologies that he used in his previous analysis.240 His updated risk
premium analysis was an ROE of 10.38 percent using projected triple-B utility interest rates and
9.96 percent using current triple-B utility interest rates.241

TIEC contends that Dr. Hadaway’s utility risk premium analysis is flawed for two primary
reasons. First, Dr. Hadaway developed a forward-looking risk premium model that relied on
forecasted interest rates and volatile utility spreads that are uncertain and produce inaccurate results.
As Mr. Gorman testified, it is more reasonable at this time to rely on current observable interest
rates rather than forecasted projections. Over the last several years, forecasted yield projections
have proven to be overstated because, even though interest rates have been projected to increase,

237
ETI Ex. 6 (Hadaway Direct) at 45-46, Ex. SCH-5; ETI Ex. 52 (Hadaway Rebuttal) at 32.
238
Staff Ex. 6 (Cutter Direct) at 20.
239
ETI Ex. 6 (Hadaway Direct) at 10-23, 45; Tr. at 233-235.
240
ETI Ex. 52 (Hadaway Rebuttal) at 44.
241
Id. at 45.
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those projections have consistently been proven wrong.242 Accordingly, Dr. Hadaway’s forecasted
utility bond yield of 5.17 percent is overstated.

Second, TIEC argues that Dr. Hadaway’s risk premium model is flawed because he
improperly inflates his actual risk premium of 3.28 percent with an adjustment of 1.56 percent that
he asserts reflects the inverse relationship between interest rates and utility risk premiums.243 TIEC
argues that Dr. Hadaway’s use of this adjustment is improper and not supported by academic
research. Mr. Gorman testified that “a relative investment risk differential cannot be measured
simply by observing nominal interest rates.”244 He noted:

While academic studies have shown that, in the past, there has been an inverse
relationship with these variables, researchers have found that the relationship
changes over time and is influenced by changes in perception of the risk of bond
investments relative to equity investments, and not simply changes to interest
rates.245

As described in Mr. Gorman’s testimony, correcting Dr. Hadaway’s models for the
elimination of this inverse relationship adjustment puts Dr. Hadaway’s risk premium in the range of
8.5 percent to 10 percent, with a midpoint of 9.3 percent.246

Staff witness Cutter’s “conventional risk premium estimate” estimated the cost of ETI’s
equity by comparing the costs of equity authorized for utilities across the United States to the yields
of large-company corporate bonds that are rated Baa by Moody’s within the timeframe of 1980
through 2011. This risk premium approach relies on the historical relationship between two indices

242
TIEC Ex. 2 (Gorman Direct) at 42-43; OPC Ex. 1(Szerszen Direct) at 27-28.
243
TIEC Ex. 2 (Gorman Direct) at 42-43; see also ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5 at 1.
244
TIEC Ex. 2 (Gorman Direct) at 44.
245
TIEC Ex. 2 (Gorman Direct) at 44 (citing “The Market Risk Premium: Expectational Estimates Using
Analysts’ Forecasts,” Robert S. Harris and Felicia C. Marston, Journal of Applied Finance, Volume 11, No.
1, 2001 and “The Risk Premium Approach to Measuring a Utility’s Cost of Equity,” Eugene F. Brigham,
Dilip K. Shome, and Steve R. Vinson, Financial Management, Spring 1985).
246
TIEC Ex. 2 (Gorman Direct) at 45.
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to forecast a value for one of the indices in a period for which it is unknown by using the known
value of the other one during that same period.247

To account for the relationship between the authorized costs of equity and the bond yields
required to quantify ETI’s cost of equity, Mr. Cutter subtracted the bond yields from the authorized
costs of equity to determine a risk premium for the riskier equity. He tested the data by performing a
regression analysis, which showed with high confidence that there is a trend in the relationship. It is
an inverse trend, in which the risk premiums increase as bond yields decrease. On average, from
1980 to 2011, risk premiums increased 0.4207 percent for every 1.00 percent that bond yields
decreased.248

The calculation of the adjustment to the risk premium that the regression analysis indicated
was incorporated in Staff’s analysis. The results of this risk premium analysis produced a cost of
equity of 9.81 percent.249

Mr. Gorman’s risk premium analysis produced an ROE estimate in the range of 9.2 percent
to 9.4 percent, with a midpoint estimate of approximately 9.3 percent. His risk premium model was
based on two estimates of an equity risk premium. First, he estimated the difference between the
required return on utility common equity investments and U.S. Treasury bonds for the period 1986
through 2011, which produced an equity risk premium of 5.23 percent. The second equity risk
premium estimate was based on the difference between regulatory commission-authorized returns on
common equity and contemporary “A” rated utility bond yields for the period 1986 through 2011,
which produced an equity risk premium of 3.8 percent. Mr. Gorman testified that “[t]he equity risk
premium should reflect the relative market perception of risk in the utility industry today.”250

247
Staff Ex. 6 (Cutter Direct) at 10, 19.
248
Staff Ex. 6 (Cutter Direct) at 20.
249
Id. at 20, Attachment SC-6.
250
TIEC Ex. 2 Gorman Direct) at 26.
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Accordingly, to gauge investor expectations he examined the yield spread between utility bonds and
Treasury bonds over the last 32 years.251

According to TIEC, this analysis showed that the current utility bond yield spreads over
Treasury bond yields are lower than the 32-year average spreads, which is evidence that “the market
considers the utility industry to be a relatively low risk investment and demonstrates that utilities
continue to have strong access to capital.”252 Mr. Gorman then added a projected long-term
Treasury bond yield to his estimated equity risk premium over Treasury yields, which produced a
common equity in the range of 8.2 percent to 9.95 percent. Due to unusually large yield spreads
between Treasury bond and “Baa” utility bond yields, Mr. Gorman gave two-thirds weight to his
high end risk premium of 9.95 percent and one-third weight to his low-end risk premium of
8.2 percent, which produced an equity risk premium of 9.4 percent. He also added his equity risk
premium over utility bond yields to the current 13-week average yield on “Baa” rated utility bonds
for the period ending March 2, 2012, of 5.05 percent. Adding his equity risk premium of
3.03 percent to 4.62 percent to the bond yield of 5.05 percent, produced an ROE in the range of
8.08 percent to 9.67 percent, which he then weighted more heavily on the high end estimate to
produce a recommendation of 9.2 percent.253

The primary criticism that Dr. Hadaway lodged against Mr. Gorman’s risk premium analysis
was that Mr. Gorman did not adjust his analysis upward to reflect a purported inverse relationship
between equity risk premiums and interest rates.254 For example, Dr. Hadaway’s risk premium
analysis adjusted his risk premium results by 1.56 percent to account for this relationship.255

OPC witness Szerszen also performed a risk premium analysis, using Dr. Hadaway’s study
of historical authorized electric company allowed returns on equity and average bond yields. The

251
Id. at 25-28.
252
Id. at 27.
253
TIEC Ex. 2 (Gorman Direct) at 26-28.
254
ETI Ex. 52 (Hadaway Rebuttal) at 32.
255
ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5.
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average risk premium from Dr. Hadaway’s 1980-2010 study was 328 basis points.256 Adding this
historical risk premium to current triple B bond yield (4.67 percent) results in a 7.95 percent
risk-premium derived DCF rate, and using Dr. Hadaway’s 5.17 percent projected bond yield results
in a risk premium derived rate of 8.45 percent. Giving more weight to the 2001-2010 risk premiums
shown in Dr. Hadaway’s exhibit results in an average risk premium of 4.21 percent. This yields an
8.88 percent to 9.38 percent risk premium derived cost of equity based on the current 4.67 percent
and projected 5.17 percent bond yields, according to Dr. Szerszen’s analysis.257

4. Comparable Earnings

Cities witness Parcell also performed a Comparable Earnings analysis. According to
Mr. Parcell, the Comparable Earnings method is derived from the “corresponding risk” standard of
the Bluefield and Hope cases. This method is thus based upon the economic concept of opportunity
cost. The cost of capital is an opportunity cost: the prospective return available to investors from
alternative investments of similar risk.258

The Comparable Earnings method is designed to measure the returns expected to be earned
on the original cost book value of similar risk enterprises. Thus, according to Mr. Parcell, this
method provides a direct measure of the fair return, because the Comparable Earnings method
translates into practice the competitive principle upon which regulation is based.259

The Comparable Earnings method normally examines the experienced and/or projected
returns on book common equity. The logic for examining returns on book equity follows from the
use of original-cost, rate-base regulation for public utilities, which uses a utility’s book common
equity to determine the cost of capital. This cost of capital is, in turn, used as the fair rate of return
which is then applied (multiplied) to the book value of rate base to establish the dollar level of

256
ETI Ex. No. 6 (Hadaway Direct) at Ex. SCH-5.
257
OPC Ex. 1 (Szerszen Direct) at 29-30.
258
Cities Ex. 3 (Parcell Direct) at 28.
259
Id. at 29.
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capital costs to be recovered by the utility. Mr. Parcell stated that this technique is thus consistent
with the rate base methodology used to set utility rates.260

Mr. Parcell conducted the Comparable Earnings methodology by examining realized returns
on equity for several groups of companies and evaluating the investor acceptance of these returns by
reference to the resulting market-to-book ratios. He testified that in this manner it is possible to
assess the degree to which a given level of return equates to the cost of capital.

Mr. Parcell’s Comparable Earnings analysis is based on market data (through the use of
market-to-book ratios) and is thus essentially a market test. As a result, he testified that his analysis
is not subject to the criticisms occasionally made by some who maintain that past earned returns do
not represent the cost of capital. In addition, he stated that his analysis uses prospective returns and
thus is not confined to historical data.261

Mr. Parcell’s Comparable Earnings analysis considered the experienced equity returns of the
proxy groups of utilities for the period 1992-2011 (i.e., the last twenty years). His Comparable
Earnings analysis required an examination of a relatively long period of time to determine trends in
earnings over at least a full business cycle. Further, in estimating a fair level of return for a future
period, it is important to examine earnings over a diverse period of time to avoid any undue
influence from unusual conditions that may occur in a single year or shorter period. Therefore, in
forming his judgment of the current cost of equity he focused on two periods: 2002-2011 (the recent
business cycle) and 1992-2001 (the prior business cycle).262

Based on the recent earnings and market-to-book ratios, Mr. Parcell’s Comparable Earnings
analysis indicated that the cost of equity for the proxy utilities is no more than 9.5 percent to
10.0 percent (9.75 percent mid-point). Recent returns of 10.0 percent to 12.1 percent have resulted
in market-to-book ratios of 143 and greater. Prospective returns of 9.5 percent to 10.3 percent result

260
Id.
261
Cities Ex. 3 (Parcell Direct) at 29.
262
Id. at 30.
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in anticipated market-to-book ratios of over 125. As a result, it is apparent that returns below this
level would result in market-to-book ratios of well above 100. According to Mr. Parcell, an ROE of
9.5 percent to 10.0 percent should thus result in a market-to-book ratio of well over 100 .263

5. CAPM Analysis

The Capital Asset Pricing Model (CAPM) is a risk premium approach that estimates the
ROE for a given security as a function of a risk-free return plus a risk premium to compensate
investors for the non-diversifiable, or systematic, risk of that security. The CAPM formula is as
follows:

Ke = rf + β(rm – rf)

Where Ke equals the required market ROE; β equals the Beta of an individual security; rf equals the
risk free rate of return; and rm equals the required return on the market as a whole. In this equation,
(rm – rf) represents the market risk premium. According to the theory underlying the CAPM,
because diversifiable risk can be diversified away, investors should be concerned only with
non-diversifiable risk, which is measured by Beta. In effect, Beta represents the risk of the particular
security relative to the market as a whole.

Only Staff witness Cutter, Cities witness Parcell, and State Agencies witness Miravete used
the CAPM methodology to estimate ETI’s ROE.

Mr. Cutter used CAPM in the qualitative analysis of ETI’s cost of equity. He did not directly
use the CAPM in the determination of ETI’s cost of equity because it yielded a cost of equity that
was over 200 basis points lower than the lower of the other two estimates, while those other two
estimates were less than half a percent apart from each other.264 The CAPM provides an additional
indication that a significant drop to the estimated costs of equity that Staff made in prior dockets is

263
Cities Ex. 3 (Parcell Direct) at 31-32.
264
Staff Ex. 6 (Cutter Direct) at 21.
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appropriate because the CAPM estimate is lower than either of the two other approaches even when
adjusted for the current low yield on Treasury Bonds.265

Mr. Cutter testified that the CAPM is one of the cornerstones of financial theory.266 In its
simplest sense, the model describes the relationship between the risk of an asset and its expected
return, and assumes that investors will not hold a risky asset unless they are adequately compensated
for the risk.267

In this case, without any adjustment to the way it has been used in recent rate cases at the
Commission, the CAPM yielded a cost of equity for ETI of 6.93 percent. Mr. Cutter testified that
aspects of the capital markets today were likely causing the CAPM’s cost of equity estimate to be
low. Specifically, the Federal Reserve System is following an aggressive policy designed to keep
the yields of both short-term and long-term Treasury bonds low. This policy influences two of the
three variables used in the CAPM formula to be lower, which, in turn, makes the CAPM’s final
estimate of ETI’s cost of equity lower.268

To account for the impact of this aggressive Federal Reserve System policy, Mr. Cutter made
two adjustments to his CAPM analysis. First, Mr. Cutter adjusted the risk-free rate variable in the
CAPM because it is most influenced by current Federal Reserve System policy. By changing this
variable to 3.7 percent (which is the average yield from 1926 through 2010 of the risk-free rate’s
proxy security, U.S. Treasury Bills), the CAPM’s estimate of ETI’s cost of equity increased from
6.93 percent to 7.92 percent, or by 99 basis points.269

The second adjustment to the CAPM result that Mr. Cutter made to account for the current
aggressive Federal Reserve System policy was to the risk premium, which is also particularly
sensitive to Federal Reserve System policy. By using the difference between the averages of the

265
Id.
266
Id.
267
Id.
268
Staff Ex. 6 (Cutter Direct) at 21-24.
269
Id. at 24.
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yield of long-term government bonds and the yield of large company stocks between 1926 and 2010,
the effect of Federal Reserve System policy on the risk premium was significantly diluted.
Mr. Cutter found that because the CAPM estimate of ETI’s cost of equity was excessively low, even
with adjustments for Federal Reserve System policy, it would be appropriate to further adjust it by
multiplying the unadjusted estimate plus two times the effect of adjusting the risk-free rate, or:
6.93 percent + (2 * 0.99 percent) = 8.91 percent.270 It is important to note, however, that Mr. Cutter
used the CAPM analysis only as a qualitative check on its DCF and risk premium analyses, not as an
independent source of analysis.

Although Cities witness Parcell did perform a CAPM analysis, he does not employ the
CAPM results in arriving at his 9.0 percent to 10.0 percent range of results.271

State Agencies witness Miravete used the daily average of the yield of the ten-year Treasury
bond between December 1, 2011, and March 2, 2012, as reported by the Board of Governors of the
Federal Reserve System, as his risk-free return in his CAPM model. He used Value Line’s most
recent betas for the regulated utilities included in the proxy group. Dr. Miravete corrected the betas
by substituting an average between their value and 1.0 to recognize that markets trend towards
long-term equilibrium because these regulated utilities were able to attract investors during the most
troubled times, which indicates that the perceived market risk of these utilities is lower than for other
firms. Dr. Miravete’s capitalization-weighted average CAPM ROE is 7.64 percent on a 90 days
averaging period, with a range between 7.64 percent (30 days) and 8.28 percent (180 days).
Dr. Miravete characterizes these estimates as low relative to those of the DCF model because of the
low yields of Treasury bonds after the implementation of the quantitative easing monetary policy
over the past two years.272

270
Id. at 21, 24-25.
271
Cities Ex. 3 (Parcell Direct) at 3, 25-28.
272
State Agencies Ex. 1 (Miravete Direct) at 19-21.
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6. ALJs’ Analysis

Given the detail, time, and effort that went into the various experts’ testimony on this issue,
one might easily conclude that the development of an estimated ROE is a precise science. But, as
acknowledged by virtually all experts on the subject, estimating the cost of equity is not an exact
science but rather a result of informed judgment.

The first question that must be addressed is the appropriate proxy group. There were
essentially only two competing views on this issue – one presented by Dr. Hadaway and the other by
Mr. Cutter. The ALJs have reviewed the evidence and the arguments of both sides with respect to
the composition of the proxy group. Although Staff’s proxy group could, in some respects, be
considered more comparable to ETI than Dr. Hadaway’s larger group, the ALJs do not believe that
this overcomes the flaws inherent in such a small group. In the end, a group of nine companies,
while comparable, simply does not provide a robust enough sample to create a valid group for
comparison. The ALJs therefore find that the 23 utility group selected by ETI witness Hadaway is
the appropriate proxy group.

The next issue is the core issue to be decided: the appropriate ROE for ETI. The experts in
this case testified to the following ROE ranges or estimates, depending on the calculation
methodology employed:

Witness/Analysis Range Ultimate Recommendation
Hadaway - DCF 9.9 – 10.7 10.6
Hadaway – Risk Premium 9.96 – 10.38

Cutter – DCF 7.46 – 10.71 9.6
Cutter – Risk Premium 9.81
Cutter – CAPM 8.91

Gorman –DCF 9.3 – 9.7 9.5
Gorman – Risk Premium 9.2 – 9.4

Parcell – DCF 9.0 – 9.5 9.5
Parcell – Comparable Earnings 9.5 – 10.0
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Witness/Analysis Range Ultimate Recommendation
Szerszen – DCF 8.32 – 9.32 9.3
Szerszen – Risk Premium 9.3

Miravete – DCF 9.23 – 9.34 9.3
Miravete – CAPM 7.64 – 8.28

Just focusing on the ultimate ROE recommendations, it is clear that there is a fairly tightly grouped
range when considering Staff and the intervenors. This ranges from a low of 9.3 percent to a high of
9.6 percent. The range expands when it is considered that Staff witness Cutter did not contest ETI’s
assertion that Staff’s DCF recommended ROE would be 10.0 percent if he had used the same proxy
group as the other witnesses.273 The ALJs believe that the criticisms leveled at Dr. Hadaway’s ROE
recommendation are generally correct, certainly to the point that the ultimate recommendation is so
high as to be an outlier. The ALJs conclude that the proper range of acceptable ROEs would be
from 9.3 percent to 10.0 percent. This is actually confirmed by ETI’s own witness, Mr. Barrileaux,
who testified that, from a cash flow metric standpoint, an ROE of 9.99 percent would provide “a
reasonable outcome that balances debt and equity financing.”274

The mid-point of the range discussed above is 9.65 percent. There has been a tremendous
amount of testimony about the unsettled economic conditions facing utilities and the effect of those
conditions on the appropriate ROE. The ALJs believe that this is an effect that must be taken into
account, and that the effect would be to move the ultimate ROE towards the upper limits of the range
determined to be reasonable. In this case, the ALJs find that the reasonable adjustment would be
15 basis points, moving the reasonable ROE to 9.80 percent. Accordingly, the ALJs recommend
that the Commission find that 9.80 percent is the appropriate ROE for ETI.

273
Tr. at 1795.
274
ETI Ex. 44 (Barrileaux Rebuttal) at 5, Ex. CEB-R-1.
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C. Cost of Debt

ETI’s weighted average cost of debt at the end of the test year was 6.74 percent.275 No party
has taken issue with that cost of debt. Therefore, the ALJs recommend that the Commission enter an
order finding that the appropriate cost of debt for ETI is 6.74 percent.

D. Overall Rate of Return

The overall rate of return is a product of the capital structure, ROE, and cost of debt. Based
on the discussions set forth above, the ALJs recommend that the Commission adopt the following
overall rate of return for ETI:

Weighted
Component Cost Weighting Cost
Debt 6.74 50.08% 3.38
Equity 9.80 49.92% 4.89
Overall 8.27

VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4,
and 16]

A. Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order
Issue No. 1]

One of the most hotly contested issues in this case concerned the appropriate size of ETI’s
purchased power capacity costs (PPCCs). In order to understand this issue, it is necessary to
understand some background relative to how ETI obtains and uses power generation capacity.

1. The Sources of ETI’s Purchased Power

The Entergy System Agreement is a FERC-approved tariff that mandates that the Operating
Companies operate as a single, integrated system.276 The System Agreement’s essential function is
to provide the contractual basis for the planning, construction, and operation of generation and

275
ETI Ex. 5 (Barrilleaux Direct) at 37.
276
ETI Ex. 30 (Jaycox Direct) at 5-6; ETI Ex. 39 (Cicio Direct) at 6-10.
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transmission resources in an economic and reliable manner. By jointly planning and operating their
electric systems, the Operating Companies believe they are able to aggregate their loads and jointly
dispatch their resources to serve that load using the lowest cost resources available from all of the
Operating Companies, resulting in lower total costs than the total cost of each Operating Company
planning and operating separately. Another function of the Entergy System Agreement is to provide
a basis for the equalization among the Operating Companies of any imbalances of costs arising from
the construction, ownership, or operation of facilities that are used for the collective benefit of all
Entergy Operating Companies.277

To provide reliable service, ETI must have sufficient generation capacity to meet the
maximum demands imposed on its system. Some of this generation capacity (approximately
1,200 MW) is generating plants owned and operated by ETI.278 The remainder of ETI’s capacity
comes from four types of purchased capacity: (1) capacity purchases from third parties; (2) capacity
purchases from other Entergy affiliates through “legacy affiliate contracts” under MSS-4;
(3) capacity purchases from other Entergy affiliates through “other affiliate contracts” under MSS-4;
and (4) capacity purchases from the Entergy system through reserve equalization payments under
MSS-1.279 MSS-1 and MSS-4 are schedules included in the Entergy System Agreement which set
out complex mathematical formulas whereby the various Operating Companies can equalize and
share the costs of power capacity among themselves.280 These four sources of purchased capacity
are inversely related to one another: the more ETI purchases from one source, the less it needs to
purchase from the others.281

¾ Capacity Purchases from Third Parties

Third-party capacity contracts are contracts that the system has allocated in whole or part to
ETI. ETI has contracted to purchase capacity from a number of third parties, including

277
ETI Ex. 39 (Cicio Direct) at 6, 8-10, 11-30.
278
Tr. at 1539-40.
279
ETI Ex. 34 (Cooper Direct) at 20-21; Tr. at 1901; ETI Initial Brief at 71.
280
ETI Ex. 39 (Cicio Direct) at PJC-1, pp. 30 and 62.
281
Tr. at 1946-47.
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ConocoPhillips-SRW, Dow Pipeline, Frontier, Calpine-Carville, and Sam Rayburn Municipal Power
Agency (SRMPA). Since 2009, ETI has been in the process of substantially increasing its reliance
upon third party purchases of capacity. During the Rate Year, it plans to more than double the
amount of capacity it purchases from third parties as compared to the amount it purchased during the
Test Year.282

Since the Test Year, Entergy has been engaged in an effort to increase ETI’s long-term
power capacity through dealing with third parties. It has entered into a number of agreements in that
regard:

x In 2009, it entered into a ten-year purchased power agreement with Calpine Energy Services
(Calpine) to purchase 485 MW of capacity from Calpine’s Carville Energy Center (Carville
Contract). Purchases pursuant to the Carville Contract will commence during the Rate Year, on
June 1, 2012, and 50 percent of this contract is allocated to ETI.283

x During the Period from July 2009 through June 2011, the Company executed an agreement with
NRG for a 75 MW one-year call option, with a delivery period that began on March 1, 2011, and
100 percent of this contract is allocated to ETI.284

x During the Period from July 2009 through June 2011, the Company executed a three-year
agreement with Dow Pipeline for 100 MW capacity, with a delivery period that began on April
1, 2011, and 100 percent of this contract is allocated to ETI.285

x During the Period from July 2009 through June 2011, the Company executed a 25-year
agreement with SRMPA for 225 MW, with a delivery period beginning on December 1, 2011,
and 100 percent of this contract is allocated to ETI. ETI contends that the SRMPA contract will
be beneficial because it provides “much-needed long-term base load capacity at an economically
attractive price.”286

282
ETI Ex. 34 (Cooper Direct) at 23; see also ETI Init. Br. at 75-76.
283
ETI Ex. 34 (Cooper Direct) at 16, 19.
284
ETI Ex. 34 (Cooper Direct) at 16, 19.
285
Id. at 17, 19.
286
Id.
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x An additional contract, the Frontier contract, was in place during the Test Year, and saw a
150 MW increase in contract capacity during the Test Year.287

ETI argues that its growing reliance on third-party purchases will diversify its energy
portfolio and help the Company meet its reliability needs at a lower cost.288 The new purchased
power contracts will also reduce ETI’s fuel costs and dependence upon aging, higher heat rate
generation units within the Entergy system.289

¾ Capacity Purchases from Other Entergy Affiliates Through “Legacy” Affiliate
Contracts Under MSS-4

The term “legacy affiliate contracts” refers to those contracts resulting from the
December 31, 2007, jurisdictional separation of EGSI into ETI and EGSL, pursuant to which ETI
purchases its allocated share of power from plants such as the River Bend nuclear plant, located in
Louisiana and owned by EGSL as a result of the separation. The legacy affiliate purchases are made
under MSS-4.290

¾ Capacity Purchases from Other Entergy Affiliates Through “Other” Affiliate
Contracts Under MSS-4

“Other affiliate contracts” refers to all affiliate contracts other than legacy contracts whereby
ETI purchases capacity and associated energy from other Operating Companies.291 The other
affiliate purchases are also made under MSS-4.292 Among others, in 2009 ETI entered into a new
affiliate contract with Entergy Arkansas, Inc. (EAI) for wholesale base load resources (the EA WBL
Contract), whereby ETI was allocated 31.7 percent of 336 MW capacity.293

287
Tr. 1937-38.
288
ETI Ex. 34 (Cooper Direct) at 24.
289
Tr. at 1112-13, 1940-41.
290
ETI Ex. 39 (Cicio Direct) at 24-26.
291
ETI Ex. 34 (Cooper Direct) at 21.
292
ETI Ex. 39 (Cicio Direct) at 24-26.
293
Cities Ex. 6 (Nalepa Direct) at 13-14.
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¾ Capacity Purchases from the Entergy System Through Reserve Equalization
Payments Under MSS-1

Reserve Equalization payments are made under MSS-1. In any given month, some of the
Operating Companies might be “long” on the amount of generating capacity they own (meaning that
they own more capacity than they need) while others might be “short” on capacity (meaning they
own less capacity than they need). In such a month, the long Operating Companies would receive
MSS-1 payments from the short Operating Companies for use of their capacity.294

2. ETI’s Request Regarding PPCCs

During the Test Year, ETI had total PPCCs of $245,432,884.295 In the application, however,
ETI is not seeking to recover its Test Year expenses. Rather, it is asking to recover roughly
$276 million, which represents the Company’s anticipated PPCCs in the Rate Year.296 In other
words, ETI is seeking roughly $31 million more than its actual Test Year expenses. ETI derived this
estimate based largely upon what it believes will the purchased power agreements in place during
the Rate Year.297

As the following tables illustrate, ETI projects that, during the Rate Year, the total quantity,
and the relative quantities purchased from each source, will differ substantially from its Test Year
purchases.

Test Year vs. Rate Year Power Capacity Quantities
(MW-Months)298
Purchase Test Year Rate Year
Third Party Purchases 5,884 12,834

294
ETI Ex. 39 (Cicio Direct) at 11-13; Cities Ex. 4 (Goins Direct) at 13.
295
TIEC Ex. 1 (Pollack Direct) at Ex. JP-1; Tr. at 652-53.
296
TIEC Ex. 1 (Pollack Direct) at JP-1; ETI Ex. 34 (Cooper Direct) at 20; ETI Ex. 34A (Errata to Cooper
Direct).
297
TIEC Ex. 1 (Pollack Direct) at 22.
298
TIEC Ex. 1 (Pollack Direct) at 22, Table 1 (Errata).
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Test Year vs. Rate Year Power Capacity Quantities
(MW-Months)298
Purchase Test Year Rate Year
Affiliate Purchases (both 21,670 21,711
Legacy and Other) Under
MSS-4
Reserve Equalization 8,309 5,262
Under MSS-1
Total 35,863 39,807

Test Year vs. Rate Year Power Capacity Costs299
Purchase Test Year Rate Year
Third Party Purchases $32,094,893 $69,061,200
Affiliate Purchases (both $189,032,442 $188,430,917
Legacy and Other) Under
MSS-4
Reserve Equalization $25,461,353 $18,317,367
Under MSS-1
Total $246,588,688300 $275,809,484

This indicates ETI will purchase roughly 11 percent more power in the Rate Year than it did
in the Test Year. Moreover, while the purchases pursuant to MSS-4 will remain fairly stable, the
third-party purchases will substantially increase, with a somewhat corresponding decrease for
purchases pursuant to MSS-1. In other word, ETI’s plan is to become “less short” (on capacity)
relative to the other Operating Companies in the Rate Year than it was in the Test Year.

ETI contends that the shift toward more third party purchases is part of its effort to develop a
more diverse, modern, and efficient portfolio of generation supply resources, both to serve current
customer needs and to serve anticipated load growth. This, in turn, will lower energy costs and
result in savings for customers.301

ETI’s initial request in this case was for a Purchased Power Rider (PPR) that would allow the
Company to recover $276 million, but would be subject to future reconciliation based on actual

299
Cities Ex. 12.
300
Cities now agree that the correct amount for the Test Year is $245,432,884. See TIEC Reply Brief at 18.
301
ETI Ex. 47 (Cooper Rebuttal) at 7-8.
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expenses and revenues, much like a fuel factor.302 The intervenors point out that the PPR proposal,
while unprecedented, would have at least matched any post-Test Year increases in total purchased
capacity costs with corresponding increases in sales, and would also have allowed for a prudence
review of any post-Test Year purchased power capacity expenses in a future reconciliation
proceeding.303 The Commission, however, rejected the PPR proposal in its Supplemental
Preliminary Order.304 In lieu of the PPR proposal, ETI now proposes to simply recover the
$276 million as part of its base rates.

3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal

Staff and all of the actively-engaged intervenors oppose ETI’s proposed adjustment to its
Test Year PPCCs. They make a number of arguments against ETI’s proposal.

(a) The PPCCs Requested by ETI Are Not Known and Measurable

First, they contend that ETI’s Rate Year forecast cannot be considered known or measurable.
Staff points out that the four305 components from which ETI purchases power are interrelated, such
that, “when ETI adds capacity under one element, such as through third party contracts, the other
components, such as ETI’s MSS-1 payments, will decrease.”306 Staff describes each of the
components comprising ETI’s PPCC Rate Year forecast as being “infected” with numerous
assumptions.307 For example, ETI necessarily made projections, rather than relying upon actual
payments, when it estimated what it will pay for third-party contracts in the Rate Year.308 Many of
the third party contracts that will be in effect in the Rate Year do not contain fixed price terms.
Rather, the amounts ETI will pay will fluctuate based upon factors such as required availability and

302
Tr. at 1954; Cities Ex. 4 (Goins Direct) at 14.
303
TIEC Init. Br. at 25-26; Tr. at 1954; Cities Init. Br. at 37; Cities Ex. 6 (Nalepa Direct) at 8.
304
Supplemental Preliminary Order at 2 (Jan. 9, 2012).
305
Staff (and some of the intervenors) describe them as three components, by combining affiliate purchases
under legacy contracts and affiliate purchases under other contracts into one component.
306
Staff Initial Brief at 25 (citing Tr. at 1946).
307
Staff Initial Brief at 26.
308
Tr. at 704.
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performance. Nevertheless, ETI simply assumed it would pay the maximum amount possible under
each of its third party contracts, and disregarded any of the contractual factors that might reduce its
Rate Year payments.309 Thus, the intervenors contend that ETI’s cost estimates for third party
purchased power are merely projections, as opposed to known and measurable changes.310

Similarly, ETI’s contractual agreements with its affiliate Operating Companies require ETI
to make assumptions about their future costs. The contracts do not definitively fix prices or
quantities. Rather, prices and quantities under the contracts will fluctuate based on the specific
operational conditions actually experienced by the various Operating Companies during the Rate
Year.311 The ultimate determination of payments made in the Rate Year will be calculated based
upon the complex mathematical formula set out in schedule MSS-4. That formula contains a great
number of variables. ETI had to make assumptions about each one of those variables in order to
estimate its Rate Year costs.312 The intervenors point to ETI’s new contract with EAI (the EA WBL
Contract) as evidence of the “inherently speculative nature” of ETI’s PPCCs request. According to
the intervenors:

x the EA WBL Contract was signed on April 11, 2012 (only days before the hearing in this matter
commenced); purchases will not commence under the contract until January 1, 2013;

x pricing under the contract will be determined in 2013 pursuant to the complex formula contained
in MSS-4;

x the quantity of capacity ETI ultimately purchases under the contract will be based on a yet-to-be-
determined allocation percentage between ETI and the other Operating Companies;

x the contract itself may never go into effect because it is contingent upon ETI receiving all
necessary “regulatory approvals” before August 1, 2012; and

x if it does go into effect, it will still be subject to at least two further revisions before any power is
received by ETI under the contract.313

309
Tr. at 704-05.
310
TIEC Initial Brief at 29-30; Staff Initial Brief at 26.
311
Tr. at 606.
312
See Staff Initial Brief at 27; Tr. 606.
313
ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, and Tr. at 628-9.
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The EA WBL Contract accounts for more than one-third of ETI’s upward adjustment to its Test
Year PPCCs. The intervenors contend that, in order for ETI to arrive at its forecasted PPCCs for the
Rate Year, it had to make myriad assumptions as to the future values of the many variables in the EA
WBL Contract (and the other affiliate contracts).314 Therefore, the intervenors argue that ETI’s cost
estimates for its contractual agreements with its affiliate Operating Companies are merely
projections, as opposed to known and measurable changes.315

ETI’s estimated costs for its MSS-1 payments also require assumptions about the future. In
order to calculate its future reserve equalization responsibilities using the complex formula set out in
MSS-1, ETI had to forecast its own future loads, along with the future loads of all the other
Operating Companies. If those assumptions prove to be wrong, then ETI’s actual MSS-1 costs will
be different than as projected in the application.316 It is noteworthy, according to the intervenors,
that ETI projected the future load growths of all the Operating Companies when it calculated its
projected Rate Year MSS-1 costs because, elsewhere in ETI’s evidence, the Company has taken the
position that future projected loads should not be considered known and measurable.317 Staff argues:

ETI cannot have it both ways. It cannot claim load growth to be speculative in one
context, and then claim that it can forecast with absolute certainty the respective load
growths for each EOC on the Entergy System.318

TIEC points out that ETI’s estimated MSS-1 payments “were still changing on the eve of the
hearing.”319 In the following exchange, even ETI witness Phillip May, one of the Company’s

314
Staff Initial Brief at 27-28. Staff makes the further point that, because the EA WBL Contract was
executed only days before the hearing, Staff has been unable to determine whether the contract is even a
prudent one.
315
TIEC Initial Brief at 30-32; Staff Initial Brief at 27-28.
316
Tr. at 651-52.
317
Tr. at 1907; see also Staff Initial Brief at 28; TIEC Initial Brief at 27-28.
318
Staff Initial Brief at 29; see also TIEC Initial Brief at 37.
319
TIEC Initial Brief at 28.
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primary witnesses regarding its PPCCs, seems to have conceded that the Company’s MSS-1
projections are not known and measurable:

Q: Do you think that the projection . . . of rate year sales that is implicit in the
calculation of MSS-1 costs . . . is a known and measurable change?
A: I think that there is some uncertainty with regard to that projection, yes,
sir.320

In sum, the intervenors contend that ETI’s cost estimates for all components of purchased power in
the Rate Year are merely projections, as opposed to known and measurable changes.321

(b) The PPCCs Requested by ETI Violate the Matching Principle

Second, the intervenors acknowledge the principle that Test Year expenses may be adjusted
for known and measurable changes. However, they contend that such adjustments can only be made
where the attendant impacts on all aspects of a utility’s operations (including revenue, expenses, and
invested capital) can with reasonable certainty be identified, quantified, and matched.322 They assert
that ETI’s proposed adjustment does not satisfy this matching principle. The intervenors complain
that ETI is improperly attempting to “compare apples to oranges” by mixing a forecast of future Rate
Year PPCCs with actual Test Year billing determinants. As explained by Cities witness Nalepa,
“[u]nder the company’s approach of mixing estimated rate year costs with test year billing units,
there is a failure to recognize customer growth and increased sales revenue – thus overstating the
revenue requirement.”323 The argument, essentially, is that the various new or expanded contracts
that ETI has entered into were executed so that, in whole or in part, ETI would be able to meet future
demand, but that ETI is seeking to recover the costs of those new contracts from its existing
customers.324

320
Tr. at 1918-19.
321
TIEC Initial Brief at 27-28; Staff Initial Brief at 29.
322
Cities Ex. 6 (Nalepa Direct) at 12, citing P.U.C. SUBST. R. 25.231(c)(2)(F).
323
Cities Ex. 6 (Nalepa Direct) at 8; Cities Ex. 4 (Goins Direct) at 14-15.
324
Cities Ex. 6 (Nalepa Direct) at 11; see also Cities Initial Brief at 38, Staff’s Initial Brief at 30, TIEC Initial
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The intervenors offer various examples, of which the following is typical, to illustrate why it
was inappropriate for ETI to fail to take load growth into account when it calculated its Rate Year
PPCCs. Assume that, during the Test Year, Utility X had 100 billing units and $500 of PPCCs. Also
assume that, during the Rate Year, Utility X had 200 billing units and $1,000 of PPCCs. If Utility X
were limited to setting its rates based solely on its Test Year numbers, then it would recover
precisely the right amount to cover its PPCCs in both the Test Year (100 billing units x $5 per unit =
$500 of PPCCs) and in the Rate Year (200 billing units x $5 per unit = $1,000 of PPCCs). If, on the
other hand, Utility X were allowed to set its rates based upon it billing units from the Test Year
(100) and its PPCCs from the Rate Year ($1,000), then Utility X would unfairly recover twice the
amount needed to cover its actual PPCCs in the Rate Year (200 billing units x $10 per unit =
$2,000).325 Thus, intervenors contend that ETI’s load growth must be taken into account if PPCCs
are to be based on Rate Year projections.326 They point out that ETI itself expects steady load
growth in the next few years,327 and experienced “good” growth over the two years preceding the
Test Year.328

For its part, ETI denies that its increased capacity has been obtained in order to meet load
growth. Rather, it contends that it has added capacity in order to be “less short” in comparison to the
other Operating Companies.329 Moreover, ETI contends that the load growth adjustments proposed
by intervenors are “uncertain and unnecessary.”330

(c) ETI’s Proposal Would Preclude Prudence Review

Third, TIEC contends that ETI’s future Rate Year proposal would set rates based on
projections without any effective Commission review of: (1) what the actual expenditures under

Brief at 35-39.
325
Cities Ex. 4 (Goins Direct) at 16-17.
326
Cities Ex. 4 (Goins Direct) at 17; see also TIEC Ex. 23.
327
Cities Ex. 4 (Goins Direct) at 17; Tr. at 706.
328
Tr. at 130.
329
ETI Initial Brief at 68-69.
330
Id. at 69.
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purchased capacity contracts turn out to be; (2) whether those expenditures turn out to be reasonable;
and (3) whether the future contracts were prudent.331

4. The Intervenors’ Recommendations Regarding PPCCs

The intervenors agree that the amount requested by ETI is unreasonable, excessive, and
should be rejected. They do not universally agree, however, about what the proper number for
PPCCs should be. Staff, TIEC, and State Agencies argue that ETI’s PPCCs should be set at the
amount of the Company’s Test Year PPCCs: $245.4 million. This position is best summarized by
Staff:

Staff recommends that the Commission adhere to traditional ratemaking principles
and set the amount of ETI’s purchased power expenses based on what the Company
actually experienced during its test year. During its test year, ETI had total
purchased power capacity expenses of $245.4 million. This amount is not in dispute.
This amount is known. This amount is measurable. The Commission should utilize
this amount to set just and reasonable rates for ETI and its ratepayers.332

Rather than recommending Test Year PPCCs, Cities offer two alternatives – one
recommended by its witness Dr. Dennis Goins, and another recommended by its witness
Mr. Nalepa.333 Dr. Goins recommends that ETI be allowed to recover PPCCs of roughly
$242.9 million.334 This amount is roughly $33 million less than ETI’s requested amount and
$3 million less than ETI’s actual Test Year costs. To arrive at this amount, Dr. Goins made several
calculations. First, he adjusted the average per kW cost of ETI’s legacy and other affiliate purchases
using cost data from November 2010 through October 2011, which is slightly more current data than
that relied upon by ETI.335 Second, as to MSS-4 costs, because the EA WBL contract is set to expire
sooner than the three years he assumed ETI’s new rates will be in effect, Dr. Goins “normalized” the

331
TIEC Initial Brief at 33-35.
332
Staff Initial Brief at 29.
333
Cities Initial Brief at 40.
334
Cities Ex. 6 (Nalepa Direct) at 17, and Errata No. 3.
335
Cities Ex. 4 (Goins Direct) at 17-18.
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costs of the EA WBL contract over the three year period.336 Finally, he adjusted the Rate Year total
PPCCs estimate to reflect the effects of load growth, based upon ETI forecasts.337

Mr. Nalepa took a slightly different approach. He recommended that ETI be allowed to
recover PPCCs of $236,838,634, or roughly $39 million less than ETI’s requested amount and
$8 million less than ETI’s Test Year costs.338 To arrive at this amount, Mr. Nalepa first calculated
the per kW cost of ETI’s third party Rate Year capacity and applied it to ETI’s Test Year-end
capacity. In this way, “the increased cost of the new resources is recognized, but current demand is
better matched to current resources.”339 Second, he made the same adjustment as Dr. Goins as to
MSS-4 costs due to the EA WBL contract.340

TIEC explains it is reluctant to “descend into the rabbit hole and engage in ratemaking based
on prognostications, estimates, projections, and assumptions about what may happen in the
future.”341 If the Commission were to do so, however, TIEC argues that the final result would be
lower than the Test Year PPCCs, not higher. TIEC’s witness Jeffry Pollock calculated the impact of
projected unit prices based upon ETI’s projections, and he eliminated the expiring EA WBL
Contract. His result, which TIEC is not advocating, would allow ETI to recover PPCCs of $238.8
million, roughly $7 million less than its Test Year costs.342

ETI describes the proposals made by TIEC and Cities as “extreme” and contrary to common
sense.343 For example, Mr. Pollock’s calculations indicate that ETI’s MSS-1 costs would increase
by roughly $5 million, while its third-party and affiliate contracts would slightly decrease. ETI
argues that this is the opposite of reality. By adding capacity through third party contracts, its

336
Cities Ex. 4 (Goins Direct) at 18; Cities Ex. 6 (Nalepa Direct) at 15-16.
337
Cities Ex. 4 (Goins Direct) at 18-19.
338
Cities Ex. 6 (Nalepa Direct) at 17.
339
Cities Ex. 6 (Nalepa Direct) at 12-13.
340
Id. at 15-16.
341
TIEC Initial Brief at 41.
342
TIEC Ex. 1 (Pollack Direct) at 25-27; TIEC Initial Brief at 41-42.
343
ETI Initial Brief at 83.
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reliance upon the other purchased power components, especially MSS-1, will necessarily decline,
not increase.344 ETI also argues that load growth is inherently uncertain and should not be taken into
account.345

5. The ALJs’ Analysis Regarding PPCCs

The ALJs conclude that ETI failed to meet its burden to prove that the adjustment it seeks to
its Test Year PPCCs is known and measurable. The known and measurable standard is an exception
to the actual data contained in the Test Year. The point of a historical Test Year is to review actual
costs, which include the ups and downs of what actually occurred. As to a forecast of the Rate Year,
by contrast, the evidence demonstrates that the costs attributable to a particular contract to purchase
capacity cannot currently be known because there are so many variables that will play into the
amount ETI ultimately pays. As stated above, ETI’s third party contracts lack fixed prices and the
amounts ETI will pay could fluctuate based upon factors such as required availability and
performance. ETI simply assumed it would pay the maximum amounts under those contracts, and
disregarded the contractual factors that could lower the payment amounts. Yet this assumption runs
counter to ETI’s historical experience with its contracts.346 Similarly, ETI’s affiliate contracts do not
fix prices or quantities, and the amount ETI ultimately pays will fluctuate based upon operational
conditions experienced by all of the Operating Companies during the Rate Year. Those operational
conditions obviously cannot be known at this time. Both the affiliate contracts under MSS-4 and the
equalization payments under MSS-1 are based upon highly complex mathematical formulae that
utilize numerous variables. Any of the variables could change during the Rate Year, thereby altering
the amounts paid by ETI under affiliate contracts or MSS-1. As a result, the evidence demonstrates
that there could be a substantial difference between ETI’s projected Rate Year costs and what
actually ends up occurring. ETI asks the Commission to trust it that these differences would be
“small,”347 but provides no evidence as to what small means.

344
Id. 83.
345
Id. 84.
346
Tr. at 705.
347
ETI Initial Brief at 81.
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The efforts made by ETI, Cities, and TIEC to forecast Rate Year PPCCs further illustrate the
difficulty of deviating from actual Test Year data in an area that involves so many future
contingencies and unknowns. Those forecasts swung wildly – ETI estimated Rate Year PPCCs that
were $31 million more than the Test Year, while the Cities’ and TIEC’s estimates came in at $3
million, $8 million, and $7 million less than the Test Year, respectively. Indeed, even Cities’ own
witnesses disagreed substantially among themselves as to what the proper amount should be.
Moreover, arguably ETI could not even agree with itself regarding the proper amount because, in its
Initial Brief, it suggested that a reduction of roughly $4.5 million might be warranted to account for
its latest projection of its MSS-1 costs in the Rate Year.348

The ALJs are similarly convinced that ETI’s request violated the matching principle by
mixing its forecast of future Rate Year PPCCs with Test Year billing determinants. It is logically
inconsistent for ETI to have, on the one hand, based its estimate of Rate Year MSS-1 costs on its
projections of the load growths of ETI and all the other Operating Companies and, on the other hand,
argue that load growth cannot be considered known and measurable when calculating its overall
PPCCs. This argument does not withstand scrutiny, especially in light of the fact that ETI clearly
believes its load will be larger in the Rate Year than it was in the Test Year and it has, in fact,
contracted for six percent more load in the Rate Year.349

Simply put, the intervenors presented substantial evidence that all of the components of
ETI’s purchased power capacity contain significant variability and uncertainty in costs, thereby
leading to the conclusion that estimates of Rate Year PPCCs cannot be considered known and
measurable. For this reason, the ALJs recommend that ETI’s PPCCs request be rejected. In its
place, the ALJs recommend that ETI be allowed to recover its Test Year PPCCs of $245,432,884.

348
ETI Initial Brief at 77 (citing Tr. at 684, 1945).
349
ETI Ex. 47 (Cooper Rebuttal) at 4; Tr. at 667-68.
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B. Transmission Equalization (MSS-2) Expense

The Entergy system transmission grid is a large, integrated transmission network that is
operated for the mutual benefit of all of the Entergy Operating Companies.350 Service
Schedule MSS-2 is a FERC jurisdictional tariff that equalizes the ownership costs of certain high
voltage transmission facilities among ETI and the other Operating Companies, so that each
Operating Company pays its just and reasonable share of those costs. Accordingly, those costs are
referred to as “transmission equalization” payments.351 MSS-2 generally applies to equalization of
transmission costs for transmission assets of 230 kV and larger.352

In any given month, some of the Operating Companies might be “long” on the amount of
transmission capacity they own (meaning that they own more capacity than they need) while others
might be “short” on capacity (meaning they own less capacity than they need). In such a month, the
long Operating Companies would receive MSS-2 payments from the short Operating Companies for
use of their transmission facilities.353 Over the course of the Test Year, ETI was short, meaning that
it paid a total of $1,753,797 in MSS-2 payments to various other Operating Companies.354

In the application, rather than seeking to recover only the $1.7 million in Test Year MSS-2
costs, ETI is seeking to recover roughly $10.7 million, which represents its anticipated MSS-2
expenses in the Rate Year.355 The additional $9 million that ETI seeks is based on the Company’s
estimates of transmission construction projects that are expected to have been completed by or
during the Rate Year which will result in changes to the relative transmission line ownership ratios
between the Operating Companies. In other words, ETI expects that, by or during the Rate Year, its
ownership share under the MSS-2 will decrease relative to the other Operating Companies (as the

350
Tr. at 450, 793.
351
Tr. at 724; ETI Ex. 39 (Cicio Direct) at 15-17 and PJC-1 at 38.
352
Tr. at 450-51, 731.
353
Tr. at 731, 735.
354
Tr. at 723-24, 737; Cities Ex. 28.
355
Tr. at 452-53, 738, 760.
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transmission capacity owned by the other Operating Companies increases), thereby driving the
amount of ETI’s MSS-2 payments upward.356

The increase is driven by ETI’s prediction that $184.9 million in additional transmission
capacity will be built by other Operating Companies by the end of the Rate Year. ETI identified six
construction projects that are either underway or approved for construction and which, collectively,
will account for roughly $141 million of the predicted $184.9 million in additional transmission
capacity. Of those six projects, one was completed and went into service on December 16, 2011,
after the end of the Test Year. The other five are either under construction or still in the planning
phase and are currently scheduled to go into service on dates ranging from June 29, 2012, to
December 31, 2012.357 According to ETI, the remaining $43.9 million of the $184.9 million in
additional transmission capacity is derived from “an estimate of the capital investment necessary to
maintain equalizable [i.e. MSS-2 qualifying] transmission investments across the Entergy
Transmission System.”358 The estimate is based upon the Operating Company’s projected budgets
and historical spending patterns for maintenance of transmission facilities.359

Staff, State Agencies, TIEC, and Cities all oppose ETI’s effort to recover $10.7 million in
MSS-2 expenses. The parties make a number of arguments. First, they point out that MSS-2 utilizes
a complex mathematical formula to calculate each Operating Company’s liability (or credit) under
the equalization process. There are a great number of variables that are used in the formula, such as
the amount of investments made by each Operating Company in transmission facilities, the costs of
capital for each Operating Company, the size of the load demanded by each Operating Company,
and the amount of state and federal taxes paid by each Operating Company. Changes to any of these
variables can change the amount ETI owes (or is due) pursuant to MSS-2.360 Moreover, these
variables relate not only to ETI, but to all of the Operating Companies. Indeed, Cities calculate that,

356
Tr. at 775-77.
357
ETI Ex. 59 (McCulla Rebuttal) at 2 and MFM-R-1; Tr. at 456-58.
358
ETI Ex. 59 (McCulla Rebuttal) at 3.
359
Id.
360
ETI Ex. 39 (Cicio Direct) at PJC-1 at 38-43; Tr. at 454-55.
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to perform the MSS-2 calculation, at least 360 “mini-forecasts” must be made, only 60 of which
relate to ETI.361 As explained by TIEC witness Pollock, any effort to estimate future amounts of
these many variables “is susceptible to a host of uncertainties.”362 The intervenors argue that for
ETI to arrive at its estimate of $10.7 in MSS-2 costs during the Rate Year, the Company had to
speculate as to what the many MSS-2 variables would be in the Rate Year. In other words, they
contend that ETI’s estimate of its future MSS-2 costs cannot possibly be considered “known and
measurable” and, therefore, is not recoverable.363 State Agencies and Staff liken ETI’s attempt to
obtain an MSS-2 adjustment for not-yet-complete construction projects to an impermissible request
to recover the costs of CWIP without having to meet PURA’s burden of proving that recovery is
necessary to protect the utilities financial integrity.364

Second, the parties oppose ETI’s effort to recover its predicted MSS-2 expense in the Rate
Year point out that the primary driver of the increased costs over the Test Year comes from a
number of transmission projects that have not yet come into service, and are still in the planning or
construction phase. ETI concedes that if the projects do not actually come into service at the
currently estimated times, then the Company’s estimates of its MSS-2 costs during the Rate Year
will be inaccurate.365 Thus, Staff contends that ETI’s projections about future MSS-2 costs cannot
be considered known and measurable.366 Moreover, TIEC and Staff contend that ETI is effectively
seeking higher rates based upon expenses associated with projects that are not yet completed and,
therefore, the projects cannot be considered “used and useful.”367 As explained by TIEC:

It would be bad public policy for the Commission to rely on speculative construction
end dates to form the basis of a known and measurable change to test year costs.

361
Cities Reply Br. at 68-69.
362
TIEC Ex. 1 (Pollock Direct) at 29.
363
Staff Initial Brief at 31; State Agencies Initial Brief at 11-13; TIEC Initial Brief at 44-45; Cities Initial
Brief at 44.
364
State Agencies Initial Brief at 12 (citing PURA § 36.054; P.U.C. SUBST. R. 25.231(c)(2)(D)); Staff Reply
Brief at 20.
365
Tr. at 800-801
366
Staff Initial Brief at 32.
367
TIEC Initial Brief at 47; Staff Initial Brief at 19-20.
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ETI’s own witness Mr. Cicio admitted that in-service dates can be uncertain. . . .
Similarly, costs can change upward or downward. For this reason, the Commission
has typically followed the policy that proper ratemaking requires that a utility
actually build the transmission infrastructure suggested by its projections, and then
seek to account for that investment on a historical basis in a future rate case. In
Docket No. 28906, for example, the Commission held that LCRA’s projections of
future transmission investment did not support a finding that its projected capital
needs satisfied the known and measurable test. It is similarly unreasonable for ETI
to make a post-test year adjustment associated with transmission projects that are not
serving any of its customers and that may or may not impact ETI’s transmission
equalization expense, depending on when the projects are finally completed.368

Third, in addition to the six transmission projects that are under development, another driver
of the increased costs over the Test Year comes from ETI’s estimate that $43.9 million will be spent
to maintain transmission investments across the Entergy Transmission System. The intervenors
contend that ETI has provided little to no evidentiary support for this estimate. State Agencies and
Cities also point out the unfairness of allowing ETI to begin recovering $10.7 million per year in its
rates immediately based upon new transmission facilities, even though many of those new facilities
will not come into service (and ETI will therefore not incur higher MSS-2 payments for those
facilities) for many months.369

Fourth, Cities points out that Entergy and the various Operating Companies have announced
a plan to sell all of their transmission assets to a third party. That process is currently underway.
The evidence suggests that, if and when that transaction is complete, ETI’s MSS-2 expenses will
disappear.370

Finally, TIEC argues that there is no need to grant ETI’s request for a pro forma adjustment
to its test year MSS-2 expenses because the Company can avail itself of a TCRF if its Rate Year
costs deviate substantially from its Test Year costs. Thus, if it turns out that ETI experiences an

368
TIEC Initial Brief at 47 (citing Docket No. 28906, Order at 6).
369
State Agencies Initial Brief at 12; Cities Initial Brief at 45.
370
Cities Reply Brief at 67-68; Tr. at 113-14; Cities Ex. 4 (Goins Direct) at 20-21. Admittedly, if these
expenses disappear, ETI will still have to bear transmission expenses. However, it is impossible to know, at
this time, what those expenses would be.
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increase in its MSS-2 expenses during the Rate Year, the utility has cost recovery mechanisms at its
disposal that could make it whole in a timely manner.

Staff and State Agencies argue that only $1.7 million (representing ETI’s actual Test Year
expenses) should be approved in this proceeding. TIEC witness Pollock recommends approving a
slight upward adjustment to account for the fact that ETI’s MSS-2 expenses were substantially
higher in the second six months of the Test Year than they were in the first six months. Mr. Pollock
and TIEC recommend a pro forma adjustment equal to twice the amount of MSS-2 payments
incurred by ETI in the second six months of the Test Year, or $2.7 million.371

Cities’ witness Goins presented yet another alternative. Dr. Goins proposes to adjust the
projected Rate Year costs for known expenses incurred after the Test Year. He proposed reducing
the adjusted Rate Year MSS-2 expense to a Test Year level by applying a load growth adjustment
using ETI’s own projected load growth as a benchmark indicator of the reasonable anticipated level
of growth. (Cities invoke essentially the same “matching principle” argument regarding load growth
that they raised with respect to PPCCs). The result of Dr. Goins’ adjustment would be to would
allow ETI to recover $4,103,850 in MSS-2 expenses.372

ETI responds to these arguments on a number of fronts. It contends that the main driver of
changes in MSS-2 expenses is the relative amount of equalizable transmission investment in the
transmission system by ETI and the other Operating Companies, compared to their proportionate
responsibility for that investment, based on each company’s responsibility ratio.373 ETI argues that
the other elements of the formula are relatively stable, and do not vary significantly from year to
year.374 ETI contends its requested level of MSS-2 expense is based on a known and measurable

371
TIEC Ex. 1 (Pollack Direct) at 32-33.
372
Cities Ex. 4 (Goins Direct) at 20-21.
373
ETI Ex. 45 (Cicio Rebuttal) at 3-4. Responsibility Ratio is an allocator that reflects the relative
contribution of each Operating Company to the System’s coincident peak load – in other words, an Operating
Company’s coincident peak load divided by the System peak load, calculated on a rolling twelve-month
average. ETI Ex. 39 (Cicio Direct) at 12.
374
Tr. at 763 and 780.
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change because it is based on the $184.9 million in additional transmission investment for all of the
Operating Companies that ETI knows will occur and can reasonably measure. ETI points out that
“the vast majority” of the planned transmission projects have received full funding approval and
have been constructed or are on schedule to be completed before the end of the Rate Year, while the
remaining amount is reasonably quantified and measured based on the budget and historical
spending for maintenance of equalizable transmission facilities.375

ETI also argues that its actual MSS-2 expenses have steadily trended upward since the Test
Year. ETI explains as follows:

[I]n the last month of the test year (June 2011), ETI’s payments began to increase
significantly, as the balance of relative equalizable investment levels shifted among
the Operating Companies. ETI’s actual monthly payments have climbed steadily ever
since, reaching $698,289 in the most recent actual month’s bill (February 2012).
Annualization of this most recent actual data yields an annual MSS-2 amount of
$8.4 million, almost five times the test year level. In light of this trend in actual
historical data, the notion of basing the MSS-2 expense in rates on the test year level
is unreasonable on its face.376

Thus, ETI contends its requested expense level is “consistent” with actual recent historical levels of
MSS-2 expense.377

ETI describes Cities’ concern regarding load growth as a “red herring.” ETI contends that
load growth is not the cause of changes in MSS-2 costs. Instead, its MSS-2 increases are driven by
the other Operating Companies’ transmission investments, “separate and apart from, and unaffected
by,” any increase in ETI’s load.378 Moreover, ETI contends that load growth adjustments are not

375
ETI Ex. 59 (McCulla Rebuttal) at 2-3; ETI Initial Brief at 88-89.
376
ETI Initial Brief at 90-91; Tr. at 784.
377
ETI Initial Brief at 91.
378
ETI Ex. 45 (Cicio Rebuttal) at 4-5; ETI Initial Brief at 93.
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known and measurable and are not the proper subject of a post-test year adjustment for ordinary
expenses such as MSS-2 costs.379

Finally, if the Commission rejects its request for $10.7 million in MSS-2 costs, ETI suggests
annualizing the most recent period of its actual MSS-2 costs, by multiplying its February 2012 MSS-
2 bill times 12, resulting in an amount of $8,379,480. ETI contends this would be more
representative of expected Rate Year MSS-2 costs than the amounts proposed by the intervenors.380

For largely the same reasons as were discussed relative to PPCCs, the ALJs conclude that
ETI failed to meet its burden to prove that its proposed Rate Year MSS-2 costs are known and
measurable. The MSS-2 formula requires assumptions about a great number of variables. Changes
to any of the variables could occur during the Rate Year, thereby altering the amount paid by (or
received by) ETI during the Rate Year. The projects that underlie ETI’s Rate Year request are
largely not yet built, and might never be built. Additionally, much like with the PPCCs estimates,
there is a wide gulf between the competing estimates by ETI, Cities, and TIEC of forecast Rate Year
MSS-2 costs, illustrating the problem of deviating from actual Test Year data in an area that involves
so many future contingencies and unknowns.

The ALJs are equally unconvinced by ETI’s alternative proposal to multiply its February
2012 MSS-2 bill times 12, resulting in an amount of $8,379,480. ETI offered no evidence to
establish that a single month’s costs can serve as a reasonable representation of what ETI’s future
Rate Year MSS-2 costs will be. Moreover, February 2012 is outside of the Test Year.

The intervenors presented substantial evidence to demonstrate that ETI’s estimate of its Rate
Year MSS-2 costs cannot be considered known and measurable. For this reason, the ALJs
recommend that ETI’s MSS-2 request be rejected. In its place, the ALJs recommend that ETI be
allowed to recover its Test Year MSS-2 costs of $1,753,797.

379
ETI Ex. 57 (May Rebuttal) at 12; ETI Initial Brief at 93.
380
ETI Ex. 46 (Considine Rebuttal) at 37; ETI Initial Brief at 32.
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C. Depreciation Expense [Germane to Preliminary Order Issue No. 12]

ETI currently has an annual depreciation expense of approximately $72.1 million. This
expense is based on the previously approved depreciation rates.381 ETI now requests depreciation
rates that would result in an annual depreciation expense of approximately $86 million. This
requested amount represents an increase in the annual depreciation expense of approximately
$13.9 million - almost 20 percent - from the current annual depreciation expense.382 The
depreciation expense ultimately included in retail rates, however, will be derived by applying the
Commission approved rates to the test year end plant balances as of June 30, 2011.

The other parties have accepted the vast majority of ETI’s recommendations, but take issue
with the Company on a few issues related to generation, transmission, distribution, and general plant
accounts. Staff recommends an annual depreciation expense of approximately $78.2 million, an
increase of approximately $6.1 million from the current annual depreciation expense.383 Cities
recommend an annual depreciation expense of approximately $67.6 million.384

The identical positions of ETI, Staff, and Cities on depreciation issues are set forth in the
following table:385

Plant Group Approved ETI Proposal Staff Proposal Cities Proposal
Hydro $7,137 $245 $245 n/a
Production
Regional Trans. $685,351 $685,351 $685,351 n/a
& Market
Operations
General $4,175,311 $5,946,949 $5,946,949 n/a
Amortized Plant

381
ETI Ex. 13 (Watson Direct) Attachment DAW-1. Appendix B at 3.
382
ETI Ex. 13 (Watson Direct) at 7.
383
Staff Ex. 2 (Mathis Direct) at 8.
384
Cities Ex. 5C (Pous Depreciation Study) at 2.
385
ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation
Study) at 7, 8, and 34.
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The differing positions of ETI, Staff, and Cities on depreciation issues are set forth in the
following table:386

Plant Group Approved ETI Proposal Staff Proposal Cities Proposal
Steam $17,497,781 $18,660,946 $14,709,942 n/a
Production
Transmission $13,679,827 $16,493,761 $16,417,727 $13,451,479
Plant
Distribution $32,110,774 $40,493,392 $38,806,863 $33,186,546
Plant
General Plant $3,943,450 $1,604,644 $1,604,644 $973,519
General Plant $0 $2,134,924 $0 n/a
Reserve
Deficiency
TOTAL $72,099,631 $86,020,212 $78,171,721 n/a387

The competing positions of ETI, Staff, and Cities reflected in the table above are primarily
the result of different: (1) net salvage rates for certain accounts; (2) remaining life parameters for
certain accounts; and (3) treatment of a potential general plant reserve deficiency. Cities witness
Pous also questions the reliability of the data employed by ETI witness Watson in the performance
of his study.

An analysis of the competing net salvage rates and life parameters for each account is
presented in detail below, organized by plant and account group.

1. Terminology and Methodology

Depreciation is a method of allocating the loss of the service value, not restored by current
maintenance, over the useful life of an asset. This loss may be caused by wear and tear, decay,
obsolescence, or changes in demand.388

386
ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation
Study) at 7, 8, and 34.
387
A total value of Cities’ adjustments in this format would be out of context and is therefore not provided in
this table.
388
Staff Ex. 2 (Mathis Direct) at 8.
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Within the context of a rate case, the purpose of depreciation is to allow a company to
recover the cost of an asset over the asset’s useful life. Ideally, the cost of the asset is spread out
evenly across the years the asset is in service, thus recovering the cost of the asset from the
customers who receive the benefit of the asset.389

Both ETI and Staff use the remaining-life technique, average life group procedure, and
straight-line method to calculate the depreciation rate.390 The basic formula for the remaining life
technique is presented below.

For example, if an asset has a book reserve ratio of 0.5 (i.e., 50 percent of the asset’s value
has already been recovered through prior depreciation expense), a net salvage ratio of zero (i.e., the
asset will cost nothing to retire, or all retiring costs will be recovered through its subsequent sale),
and the composite remaining life is ten years (i.e., the asset is expected to remain in service for
another ten years), then the depreciation rate will be 5 percent (i.e., {[(1 - 0.5 - 0) / 10 ] *100}).

By operation of the remaining-life formula, a greater net salvage value will reduce the
numerator and result in a lower depreciation rate and a lower depreciation expense. Likewise, a
lower net salvage value will increase the numerator and result in a higher depreciation rate and a
higher depreciation expense. Similarly, a longer remaining-life will result in a lower depreciation
rate and lower depreciation expense, and a shorter remaining-life will result in a higher depreciation
rate and a higher depreciation expense.

Because net salvage and remaining-life values are the two contested variables in the
remaining-life formula, a clear explanation of net salvage and remaining-life will be helpful.

389
Staff Ex. 1 (Mathis Direct) at 8-9.
390
ETI Ex. 13 (Watson Direct) at 15; Staff Ex. 2 (Mathis Direct) at 10-11.
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Net Salvage Value. Net salvage is calculated by taking the amount received for an asset as a
result of its sale, reuse, or reimbursement, and subtracting that amount from the cost associated with
retiring the asset. This figure is then divided by the original cost of the asset to determine the net
salvage ratio. For example, if an asset with an original cost of $200 is resold for $20, but it costs the
owner $10 to ship the asset to the purchaser, then the net salvage value of that asset would be $10
($20 - $10), and the net salvage ratio of that asset would be 5 percent ($10/$200).

ETI witness Watson and Staff witness Mathis used different methods of calculating a net
salvage rate.391 Mr. Watson took the average (mean) of recorded net salvage values for groups of
successive years (rolling bands), and then selected the net salvage rate from among these
averages.392 Ms. Mathis also used rolling band averages (means), but then took the median from a
representative group of rolling bands when the historical salvage data would have otherwise
produced what Mr. Watson considers skewed results.393

Ms. Mathis’ method of calculating net salvage rates follows recent Commission precedent.394
As Mr. Watson explained at the hearing, it is appropriate to infer acceptance of a methodology by
looking at whether the Commission adopted the conclusions that the methodology produced.395 In
other words, if the Commission adopts the conclusions, then by inference the Commission has
adopted the methodology used to derive those conclusions. Thus, it is necessary to examine recent
litigated rate cases to ascertain Commission precedent.

In the most recent fully-litigated rate case, Docket No. 38339,396 Staff disagreed with
CenterPoint’s depreciation witness, Mr. Watson, concerning the net salvage rates for five

391
Tr. at 415-416.
392
ETI Ex. 13 (Watson Direct) at 20-21.
393
Id. at 22-23, 32-33.
394
Tr. at 1766; Staff Ex. 9 (Docket No. 38339 Final Order) at FoF 126, 128, 130, and 131.
395
Tr. at 397.
396
Application of CenterPoint Energy Houston Electric, LLC, for Authority to Change Rates, Docket
No. 38339 (June 23, 2011).
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accounts.397 In its order, the Commission adopted Staff’s recommended net salvage rates for four
out of those five accounts for which Staff disagreed with Mr. Watson.398 Staff’s method for
calculating net salvage rates is the same in the present case as it was in the CenterPoint rate case.399

ETI argues that the use of a median, as employed by Ms. Mathis, is not a sufficiently
rigorous or expansive approach to depreciation analysis. According to ETI, depreciation training
and texts, as well as authoritative statistical texts, favor the average, or mean, not the median, as the
best indicator of the central tendency of a data set. ETI argues that this is particularly the case
because depreciation analysis requires careful consideration of trends over time.400 ETI then offers
the following comments:

[Ms. Mathis] agreed in response to a hypothetical that the median value of an initial
period of ten years of +5% net salvage, followed by one year of 0% salvage,
followed by the most recent period of ten years of -5% salvage, would be 0%. This
hypothetical plainly illustrates how reliance on the median can overlook data trends.
In the hypothetical, if the depreciation analyst would otherwise wish to give more
weight to the most recent historical period as indicative of conditions going forward,
the use of the median would obscure that important trend information.401

A close examination of the hypothetical shows that in the case posited by ETI, however, the median
and the mean are identical: both are zero. While the use of the median would produce a result that
ignores the trend that ETI says should be taken into account, the mean produces the same result.
Changing the hypothetical produces no more clarity. If the examination was of a period that had ten
years of positive five percent salvage value, followed by one year of zero percent net salvage value,
followed by the most recent 10-year period, which had negative 10 percent net salvage value, the
median would still be zero but the mean would be negative 2.38 percent. This appears to support the
trending argument advanced by ETI. If the analysis then focuses on a different hypothetical, one
with ten years of positive 10 percent net salvage value followed by one year of zero percent net

397
Tr. at 401-402.
398
See Staff Ex. 9 (Docket No. 38339 Final Order); Tr. at 402.
399
Tr. at 415-416.
400
ETI Initial Brief at 105.
401
Id.
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salvage value, with the most recent ten-year period having negative five percent net salvage value,
the results are more perplexing. The median is still zero, but the mean, which ETI contends will
recognize the trending, is 2.38. Although this does in some respects recognize the trend to a
negative salvage value, it does not recognize it as well as the median.

Principles and Procedures of Statistics, by Steel and Torrie, states: “Certain types of data
show a tendency to have a pronounced tail to the right or the left. Such distributions are said to be
skewed, and the arithmetic mean may not be the most informative central value.” Where the average
of the incomes of a group of individuals is required, and most of those incomes are low, the mean
income could be considerably larger than the median. In Docket No. 38339, Staff posed the
following example, which the ALJs found both informative and persuasive: Suppose a sample of
50 incomes from professional baseball players was taken that happened to include the salary of two
of the most highly compensated players in the league today. As a result, the mean of the salaries
would likely be far greater than the median salary, because the use of the median would be skewed
by the very high salaries. The median would likely provide a more accurate measure of the central
tendency of the salaries. Such circumstances are found where using the median to find the central
tendency prevents outliers in data that “skews” or shows extreme variations rather than showing
more symmetrical variations. The ALJs believe this is as accurate today as it was during the Docket
No. 38339 timeframe. They therefore find that the use of the median is the more appropriate
methodology for determining net salvage value.

Remaining Life. Composite remaining life is the weighted average remaining life of the
property account for a group of all vintages. The average remaining life represents the future years
of service expected for the surviving property.

There are numerous ways to calculate the remaining life (life parameter) of a group of assets
in a depreciation study. Examples include the interim retirement rate method and the retirement
(actuarial) rate method. The interim retirement rate method uses interim retirement curves to model
(predict) the retirement of individual assets within plant accounts. Alternatively, the retirement
(actuarial) rate method uses historical mortality data for a group of assets and compares that data to
various known patterns of industrial asset mortality rates (Iowa Curves). If the historical data
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creates a pattern of mortality that closely follows one of the Iowa Curves, then that Iowa Curve may
be used to approximate the remaining lives of that given group of assets in the future. Whether the
historical mortality data creates a pattern that closely follows a given Iowa Curve is determined
through plotting both sets of data (the historical mortality data and the Iowa Curve) on a graph and
quantifying the closeness of fit through statistical analysis and visual examination.

Mr. Watson used multiple methods to calculate the remaining lives of assets, depending on
the asset. Generally, he used the retirement rate (actuarial) method.402 However, to calculate the
remaining life of production plant accounts, he used the interim retirement rate method.403 Ms.
Mathis disagreed with the use of the interim retirement rate method because the Commission has
rejected the application of interim retirement rates of production plant, as they are based on future
projection of retirements, for ETI and Central Power and Light Company in Docket Nos. 16705404
and 14965,405 respectively.

ETI argues that the life span procedure, without the use of interim retirement curves, is
unrealistic in its assumption that all production plant assets are “depreciated (straight-line) for the
same number of periods and retire at the same time (the terminal retirement date).” Use of interim
retirements is an important refinement that adds accuracy to the determination of the depreciation
rates according to ETI. Mr. Watson offered the following explanation:

Adding interim retirement curves to the procedure reflects the fact that some of the
assets at a power plant will not survive to the end of the life of the facility and should
be depreciated (straight-line) more quickly and retired earlier than the terminal life of
the facility.406

402
ETI Ex. 13 (Watson Direct) at 16.
403
Staff Ex. 2 (Mathis Direct) at 14.
404
Application of Entergy Gulf States, Inc., for Approval of its Transition to Competition to Competition Plan
and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel
Factors, and to Recover a Surcharge for Under-recovered Fuel Costs, Docket No. 16705 (Oct. 14, 1998).
405
Application of Central Power & Light Company for Authority to Change Rates, Docket No. 14965
(Oct. 16, 1997).
406
ETI Ex. 13 (Watson Direct) at Ex. DAW-1, at 7-8.
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ETI contends that this issue presents a unique situation where all the experts agree with the
theoretical soundness of Mr. Watson’s approach, but Mr. Pous and Ms. Mathis recommend its
rejection due to the existence of contrary Commission precedent. The impact of their position is a
$1,558,081 reduction to depreciation expense, based on December 31, 2010, plant balances.
Mr. Pous generally supports the use of interim retirements because “I think it’s right,”407 and he uses
the method in other jurisdictions, where it is a prevalent practice. Ms. Mathis “also appears to
recognize the theoretical soundness of utilizing interim retirements.”408 Even in Docket No. 16705,
the precedent cited by Mr. Pous and Ms. Mathis, the Staff depreciation witness agreed that the use of
interim retirements was appropriate, though not blessed by the Commission. ETI argues that use of
interim retirements reflects the undisputable fact that “generating units will have retirements of
depreciable property before the end of their lives.”409

ETI is correct that neither Ms. Mathis nor Mr. Pous provide any reasoning behind the prior
Commission precedent. Moreover, it is also true that the Commission precedent is relatively old at
this point (dating back to the mid-1990s) and apparently has not been revisited in any recent cases.
ETI argues that the Commission has in at least one other case used interim retirements (Docket
No. 15195410), but provides little more than that comment to support the concept. It is true that in
concept, interim retirements are determined in much the same fashion as other elements of
depreciation analysis. Primarily based on historical accounting data, the analyst identifies
characteristics in the history of the data upon which to base a reasoned assessment of retirements
going forward, which is similar to what occurs in determining asset lives or net salvage. Interim
retirement determinations are supported by their own Iowa Curves, just as is the analysis of plant
lives.

Although the ALJs are persuaded by ETI’s arguments that the use of interim retirements may
be the more theoretically correct methodology to employ, Commission precedent clearly disfavors

407
ETI Ex. 71 (Watson Rebuttal) at 71, citing Pous Deposition at 49, 51.
408
Staff Ex. 2 (Mathis Direct) at 12-13.
409
ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 8.
410
Application of Texas Utilities Electric Company for the Reconciliation of Fuel Costs, Docket No. 15195
(Aug. 26, 1997).
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the use of interim retirements and the ALJs are reluctant to rule contrary to Commission precedent.
Accordingly, the ALJs find that the retirement (actuarial) rate method, rather than the interim
retirement method, should be used.

2. Production Plant

(a) Lives

Mr. Watson primarily used the life span method to calculate remaining lives of the
production plant accounts.411 The life span method estimates a production plant’s life based on
consultation with utility management, financial, and engineering staff.412 However, he used interim
retirement methodology to reduce the remaining lives determined by the life span method. Staff
does not dispute the remaining lives determined by the life span methodology, but does dispute the
use of interim retirements. For the reasons discussed in Section VII.C.1, ETI should not be allowed
to use the interim retirement methodology to adjust downward the remaining lives of its production
plant accounts.

Cities witness Pous disputed only the remaining life determination for ETI’s Sabine Power
Plant Units 4 and 5, ETI’s largest and newest gas fired generating units. Mr. Pous recommended a
life span for Sabine Units 4 and 5 of 64 years based on assessment of the units, comparison to the
estimated life span of similar units owned by ETI as well as other gas fired generating units across
the country. ETI proposes a 60-year life for the two units. Mr. Pous noted that a “64-year life span
recommended for Sabine Units 4 and 5 is consistent with the life span proposed by the Company for
its Lewis Creek 1 generating unit. Lewis Creek Unit 1 is an older, smaller, and generally less
efficient generating unit than Sabine Units 4 and 5. Cities contend that there is no basis or logic for
assigning a shorter life span for a more capital-intensive asset that is newer, larger, and generally
more efficient.”413

411
ETI Ex. 13 (Watson Direct) at 16.
412
Staff Ex. 2 (Mathis Direct) at 14.
413
Cities Ex. 5C (Pous Depreciation Study) at 9.
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ETI witness Watson explained that he primarily relied on the determination of Company
personnel to arrive at the 60-year life for the Sabine Units. Although Cities attempted to cast doubt
on Mr. Watson’s determinations regarding the life of these units, it is clear that his determinations
are based on conversations with ETI various generation personnel and that those conversations
confirmed that based on evaluation of a variety of considerations, including age, operational role,
level of funding, unit condition, and operational risk, 60 years constitutes a reasonable threshold for
the expected life of Sabine Units 4 and 5. It is also clear that comparisons to Lewis Creek Unit 1 are
not appropriate. Lewis Creek Unit 1 has significant differences, which explain its longer life-span.
Unlike the Sabine Units, ETI is planning to spend in excess of $100 million to refurbish the Lewis
Creek critical equipment over the next three years to sustain operating reliability. ETI is not
performing similar refurbishment activities at Sabine.414

The Sabine Units are projected to be “must-run” units. This means that these units are, for
the most part, deployed to operate whenever they are available for service. Mr. Pous compared these
units to EAI’s Lake Catherine Units 1 & 2,415 but ETI contends this is not a reasonable comparison.
EAI’s Lake Catherine Units 1 & 2 are not “must-run” units. They experience very infrequent
operation and are not projected to run much in the future. Other things being equal, according to
ETI, this would justify the longer 67-year life span assigned to these Arkansas units, because they
would not be experiencing the wear and tear of daily operation.416

The explanations offered by ETI for the 60-year life of the Sabine Units 4 and 5 generating
facilities are convincing. It appears that Mr. Watson engaged knowledgeable people within ETI to
gather pertinent information and applied that information appropriately. The comparison to Lake
Creek units is not appropriate given the planned refurbishment of those units. Similarly, the
comparison to the Lake Catherine units also fails. A unit that does not carry the “must-run”
designation can easily be expected to perform longer than a unit, such as the Sabine Units, that

414
ETI Ex. 51 (Garrison Rebuttal) at 3.
415
Cities Ex. 5 (Pous Direct) at 7-8.
416
ETI Ex. 51 (Garrison Rebuttal) at 3.
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carries the “must-run” designation. Accordingly, the ALJs find that ETI’s choice of a 60-year life
for the Sabine Units 4 and 5 is reasonable.

(b) Net Salvage Value

In determining the net salvage attributable to production plant, ETI witness Watson started
with the negative 5 percent net salvage factor approved most recently for ETI in PUC Docket
No. 16705. This is a net salvage value that the Commission has adopted in a number of cases for
production plant.417 Mr. Watson testified that the net salvage calculation must reflect known
changes in the cost of retiring production plant since the net salvage factor was last set.
Accordingly, Mr. Watson’s study used the Handy-Whitman labor index to calculate the change in
labor costs applicable to removal activity for the years 1997 to 2010. Consideration of the increases
in labor costs over this 13-year period resulted in an increase in the cost of removal, and a
corresponding increase in the level of negative net salvage, from negative five percent to
negative 8.5 percent.418

Both Staff witness Mathis and Cities witness Pous disagreed with ETI’s proposal for
production plant net salvage. Ms. Mathis proposed that the existing negative 5 percent net salvage
factor be retained. Ms. Mathis stated that Mr. Watson’s analysis is flawed for three reasons:

x First, Mr. Watson did not calculate a gross salvage value for each plant. This is a
necessary element of the fundamental net salvage rate calculation.419

x Second, Mr. Watson unreasonably assumed that all steam production plants would be
demolished at the end of their estimated remaining lives without any consideration of
reuse of the unit after refurbishment, or mothballing the unit or selling the unit in the
event of deregulation of the generating function of the utility.420

417
Staff Ex. 2 (Mathis Direct) at 17.
418
ETI Ex. 13 (Watson Direct) at Ex. DAW-1, at 64.
419
Staff Ex. 2 (Mathis Direct) at 16-17.
420
Id. at 17.
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x Third, Mr. Watson did not provide detailed plans for the actual demolition of each of its
power plants. The Commission has consistently approved negative five percent net
salvage rates for production plants if detailed plant-specific and reasonable demolition
cost studies were not filed by the utility.421

ETI responds that Staff’s recommendation fails to account for the fact that the
negative 5 percent benchmark is stale, having been established in a Commission proceeding 35 years
ago. Since that time, “labor costs have escalated by 267 percent with the rational expectation that
they will continue to increase at least with inflation.”422

Cities witness Pous recommended moving from the current negative five percent net salvage
to a positive 5 percent net salvage; i.e., that it should be determined that the gross salvage from the
power plants will exceed the removal cost. Mr. Pous stated that he bases this claim on the ETI’s
actual experience over the past 45 years as well as current trends within the industry in the last
14 years. According to Mr. Pous, ETI has retired many units since 1965 and demolished or sold the
units and achieved a range of net salvage values from zero percent net salvage to
positive 180 percent.423 Other utilities in Texas and elsewhere have also experienced positive net
salvage levels.424 Mr. Pous testified that since 1998 over 1,000 generating units have been sold, and
in all instances resulted in positive net salvage.425 He also claims that his positive five percent
production net salvage is consistent with the Commission’s decision in the most recent SPS case,
Docket No. 32766, where Mr. Watson was hired by SPS as a depreciation witness and the
Commission ultimately approved a positive five percent net salvage.426 As ETI notes, however, the
SPS rate case was the result of settlement427 and is of little precedential value.

421
Id.
422
ETI Ex. 71 (Watson Rebuttal) at 17, 19.
423
Cities Ex. 5 (Pous Direct) at 15.
424
Cities Ex. 5C (Pous Depreciation Study) at 11; Cities Ex. 5 (Pous Direct) at 15-16.
425
Cities Ex. 5C (Pous Depreciation Study) at 11.
426
Cities Ex. 5 (Pous Direct) at 17.
427
See ETI Ex. 71 (Watson Rebuttal) at 6.
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ETI argues that Cities witness Pous appears to primarily base this claim on the fact that the
sale of utility plants in circumstances bearing no relationship to depreciation analysis has yielded
gains that Mr. Pous characterizes as “positive net salvage.” He uses as examples sales that form a
part of the restructuring of the Texas utility business to introduce retail competition. Ms. Mathis
also concluded, without elaboration, that ETI’s production plant net salvage analysis is flawed
because it does not consider the possibility that the unit could be sold as a consequence of
deregulation. Neither Ms. Mathis nor Mr. Pous, however, pointed to any instance in which the
Commission has adopted such an approach to determining net salvage.

ETI contends that this argument should be rejected for a number of reasons. It argues that
although there is no precedent supporting Ms. Mathis’ and Mr. Pous’ approach, there is clear recent
precedent rejecting the inclusion of sales in depreciation analysis.428 The sales referenced by these
witnesses are unique and unpredictable events, as should be evident from the use of the restructuring
of the utility industry as an example of this type of activity. Indeed, at this time the Texas
Legislature has halted for the foreseeable future any ETI move to competition. For purposes of
depreciation analysis, net salvage is aimed at determining the salvage received at the end of the
plants’ useful lives. Mr. Pous’ analysis necessarily assumed that, due to the sale, the life of the
plants will be truncated. Yet he made no adjustment to production plant lives to account for the
effect of theoretical sales.429

ETI also contends that Mr. Pous’ other examples of positive net salvage are equally
unavailing. Mr. Pous points to ETI’s retirement of Neches Station as an example of positive
salvage,430 but fails to mention that: (1) this outcome was uniquely the result of insurance proceeds
received by ETI after a boiler explosion; and (2) the proceeds flowed back to customers via means
other than depreciation rates.431 ETI contends that Mr. Pous’ claim that a contractor paid $1 million

428
See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, FoF 107,
108, 112 (Mar. 4, 2008) (proceeds from sale of building properly removed from depreciation analysis as
non-recurring item).
429
ETI Ex. 71 (Watson Rebuttal) at 5-7.
430
Cities Ex. 5 (Pous Direct) at 14.
431
ETI Ex. 46 (Considine Rebuttal) at 49-50.
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for the right to demolish a power plant, apparently based on unrecorded hearsay conversations, and
without any information from Mr. Pous regarding the facts and circumstances surrounding the
transaction, proves nothing.

Finally, Mr. Pous stated that Mr. Watson’s adjustment to the net salvage rates is flawed
because it does not adequately reflect the increase in scrap metal prices in recent years. ETI
responds that although scrap metal prices have gone up recently, it is unknown what the prices will
be in the future, and these commodity prices have proven to be quite volatile and unpredictable.432
According to ETI, it is not reasonable to assume, as does Mr. Pous, that prices will stay indefinitely
at what is their historically highest level. ETI argues that Mr. Pous’ method is based on speculation
and broad, conclusory opinions regarding economic trends, as to which he makes no attempt to
actually arrive at a quantifiable analysis that yields his unprecedented positive net salvage
recommendation.433

Mr. Pous’ testimony that net salvage value should be revised to reflect a value of
positive 5 percent is seriously flawed. First, pointing to a settled case as precedent carries no weight.
Second, attempting to draw conclusions from sales that were forced to comply with the regulatory
framework and apply those conclusions to an entity that is not subject to the same regulatory
framework is equally flawed. Finally, Mr. Pous attempted to use ETI’s own experience to support
his position ignores the fact that ETI’s experiences were driven by factors that were unique to ETI at
the time and circumstances involved; they do not support the more universal application urged by
Mr. Pous.

Ms. Mathis’ analysis, in some respects, suffers from the same flaws as Mr. Pous’.
Nevertheless, some of her points carry more weight. The ALJs believe that Mr. Watson is correct
that labor costs have increased since the negative five percent net salvage value was first established
by the Commission. However, that is not the end of the story. Are there other factors that also have
changed in the corresponding time period? There is no evidence on this point, and that is the crux of

432
ETI Ex. 71 (Watson Rebuttal) at 17-18.
433
ETI Initial Brief at 103.
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the matter. As Ms. Mathis argues, there is only one way that all the changing values can be
evaluated; through the introduction of plant-specific demolition cost studies. Had studies of that
nature been provided, the parties would have been able to evaluate them and provide a supportable,
fully-vetted recommendation. The ALJs recommend that the Commission find that a
negative 5 percent net salvage value for production plant is appropriate.

(c) Depreciation Reserve

TIEC argues that $1.1 million of ETI’s requested $13 million increase in depreciation
expenses is related to ETI’s production plant assets.434 ETI has a $92,537,000 surplus in production
plant assets. A surplus depreciation reserve occurs when the theoretical reserve (the reserve that
would exist if the current proposed rates had been in place in the past) exceeds the per book
depreciation reserve. According to TIEC, this indicates that ETI customers have overpaid the value
of production plant assets.435 Since ETI has already over-recovered the value of the production plant
assets, there is no valid reason to seek any additional recovery. TIEC contends that ETI has not
shown why it needs to increase production depreciation rates at this time given that the production
depreciation reserve has a considerable surplus. Therefore, it argues, $1.1 million of the proposed
increase should be rejected.

ETI rejects TIEC’s recommendation because it is clearly contrary to Commission policy and
precedent. According to ETI, the Commission has consistently adopted the remaining life, straight-
line method for determining depreciation rates.436 This method requires that the remaining life of
the asset be determined, and depreciation rates established to recover the asset’s remaining cost in
equal installments over that life. In this way, by the end of the life, the costs will be recovered.
Mr. Pollock’s approach ignores these principles, and seeks to look back in time to compare how the

434
ETI Ex. 13A (Watson Workpapers) at Appendix B. This figure is derived by subtracting the expenses
from the existing production plant account from the proposed production plant account.
435
TIEC Ex. 1 (Pollock Direct) at 36-37, Ex. JP-5.
436
See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, PFD at
127-128 (Mar. 4, 2008); Application of CenterPoint Electric Delivery Company for Authority to Change
Rates; Docket No. 39339, PFD at 86 (Dec. 3, 2010); Application of Oncor Electric Delivery Company, LLC,
for Authority to Change Rates, Docket No. 35717, PFD at 153-154 (June 2, 2009).
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depreciation rates now proposed would have affected the recovery in the past. Those past
depreciation rates, however, were authorized for use by the Commission. ETI argues that
depreciation rates are at all times estimates, subject to adjustment using updated studies, and there is
no reason for adoption of Mr. Pollock’s alternative. Finally, the Commission expressly rejected
adjustment to the outcome of remaining life depreciation determinations based on differences
between theoretical and book depreciation reserves in CenterPoint Docket No. 38339.437

The ALJs agree with TIEC that the Commission’s decision in Docket No. 38339 is not
four-square on point with this case. That is not sufficient, however, to overcome the arguments
advanced by ETI in favor of its position in the current case. The Commission has consistently used
the remaining life, straight-line methodology for determining depreciation rates, and that
methodology requires that the remaining life of the asset be determined, and depreciation rates
established to recover the asset’s remaining cost in equal installments over that life. Mr. Pollock’s
proposal ignores that consistently applied methodology. The ALJs recommend that the Commission
approve ETI’s recommended treatment of the production plant depreciation reserve.

3. Transmission Plant

(a) Lives

Mr. Watson’s study presents ETI’s life proposal for transmission Accounts 350.2 to 359, a
total of eight accounts.438 Neither Staff witness Mathis nor Cities witness Pous took issue with any
of the recommended lives for transmission plant accounts.439 Accordingly, the ALJs recommend
that the Commission adopt ETI’s proposed lives for these accounts.

437
ETI Ex. 71 (Watson Rebuttal) at 75-77 (citing CenterPoint Docket No. 38839 PFD).
438
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 30-36.
439
Staff Ex. 2A (Mathis Direct) at 21; Cities Ex. 5 (Pous Direct) at 28.
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(b) Net Salvage Value

Staff disagrees with Mr. Watson’s recommendations for two of the eight transmission
accounts, and Mr. Pous disagrees regarding three of the accounts. The parties’ positions on
transmission net salvage values in dispute are set out below:

Transmission Account Net Salvage
Account Current ETI Staff Cities
Net Salvage Proposal Proposal Proposal
Value
352-Structures & Improvements -5% -10% -5% -10%
353-Station Equipment +5% -20% -20% 0%
354-Towers & Fixtures -5% -20% -5% -20%
355-Poles and Fixtures -25% -30% -30% -15%
356-Overhead Conductors & -20% -30% -30% -10%
Devices

(i) Account 352-Structures & Improvements

Mr. Watson’s analysis of this account, and for all the accounts in his study, included the
examination of trends and bands for numerous years. For Account 352, he found the five-year and
ten-year moving averages for the years 2008-2010 particularly telling.440 A moving average is a
rolling average that updates each year to include the additional year as part of the average for the
longer period under study. Mr. Watson testified that his recommendation of negative 10 percent net
salvage is consistent (albeit less negative) with the five-year and ten-year moving averages for 2008,
which range from negative 16.31 percent to negative 16.80 percent. Although the moving averages
for 2009 and 2010 appear more positive, this was the result of a large, atypical gross salvage in
2009.441 Cities propose no change to Mr. Watson’s recommendation.

Staff witness Mathis recommended a net salvage rate of negative five percent for
Account 352. This recommendation is based on analysis of historical salvage data for the period of

440
ETI Ex. 71 (Watson Rebuttal) at 56.
441
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65. The atypical gross salvage resulted from the sale of a
spare transformer, an asset whose cost is booked to an entirely different account. ETI Ex. 71 (Watson
Rebuttal) at 57. The atypical amount is shown at Appendix E-2 at 1 of Mr. Watson’s depreciation study.
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1984 through 2010. Specifically, the three-year moving average for the same period produces a net
salvage rate of negative 5.53 percent, which is very close to the currently approved net salvage rate
for this account. Moreover, an examination of the mean and median rolling band averages for
Account 352 shows a range of net salvage rates between positive 0.08 percent and
negative 6.83 percent.442 Thus, according to Ms. Mathis, the net salvage rate of negative 5 percent is
a reasonable estimate based on the available historical data.

In response to Mr. Watson’s contention that the 2008 moving average is the most important,
Ms. Mathis pointed out that the 2009 five-year and ten-year moving averages feature
positive 16.66 percent and positive 4.45 percent net salvage rates, respectively. Moreover, the 2010
five-year and ten-year moving averages feature positive 25.13 percent and positive 6.75 percent net
salvage rates, respectively.443 Ms. Mathis stated that if it is a sound depreciation methodology to
select a net salvage rate based on recent five-year and ten-year moving averages, then the rate for
this account should be significantly greater than either Ms. Mathis’ or Mr. Watson’s
recommendation.444

Although the moving averages cited by Ms. Mathis for 2009 and 2010 appear to belie the
arguments raised by Ms. Watson, the ALJs are persuaded that those are significantly influenced by
the atypical gross salvage resulting from the 2009 sale of a spare transformer, an asset whose cost is
booked to an entirely different account. If, as claimed by Mr. Watson, the sale was sufficiently
atypical, it would influence both 2009 and 2010 moving averages, making them unreliable.
Accordingly, the ALJs recommend that the Commission adopt ETI’s negative 10 percent net salvage
value for Account 352.

442
Staff Ex. 2 (Mathis Direct) at 22, Appendix C at 1.
443
Id.
444
According to Ms. Mathis, if 2009’s moving averages are adopted, the net salvage ratio should be around
positive 4.45 percent or positive 16.66 percent. If 2010’s moving averages are adopted, the net salvage ratio
should be around positive 6.75 percent or positive 25.13 percent.
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(ii) Account 353-Station Equipment

Similar to Account 352, a large atypical positive salvage amount in this account makes the
most recent moving average appear more positive than the history would otherwise suggest.445
Mr. Watson recommended setting net salvage at negative 20 percent, which he contended is a
reasonable middle ground between the values suggested by the five-year and ten-year moving
averages for transaction year 2010 (which show net salvage of negative 14.42 percent and
negative 20 percent, respectively).446 Ms. Mathis agreed with the Company’s proposal on this
account.

Although Mr. Pous acknowledged that retention of the current Commission-approved
positive five percent net salvage is supported by ETI’s experience, he ultimately opted for a
recommendation that the net salvage value be reduced to zero percent. Mr. Pous noted that the
actual per book data for a five-year band and a ten-year band are a positive 117.04 percent and a
positive 31.95 percent, respectively.447 Mr. Pous stated that his analysis does not ignore the positive
net salvage recorded by ETI because of the sale of transmission investment, rather he testified that:

the Company has reported five separate sales during the past 22 years, or about once
every four years. Such activity cannot be considered an ‘unusual circumstance’ or an
outlier, and should be taken into consideration as an event that may continue to occur
in the future. In a proper evaluation phase of a depreciation study, recognition of
some level of future sales is appropriate.448

Mr. Pous’ analysis also reflected that transformers, which contain large quantities of copper and
produce gross salvage when retired, comprise a significant level of investment in this account, but
were underreported in the five-year and ten-year band analyses.449 Mr. Pous stated that, given the
significant increase in the value of copper, the future proportionate retirement of transformers will
result in future net salvage values being less negative or more positive than the historical data.

445
The atypical amount is shown at Appendix E-2, p. 1 of 10 of Mr. Watson’s depreciation study.
446
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65.
447
Cities Ex. 5C (Pous Depreciation Study) at 21, 23.
448
Id.
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ETI responds that Cities’ criticism that the per book data in Mr. Watson’s workpapers show
a large positive net salvage value for the five-year and ten-year bands is unfounded. According to
ETI, Mr. Watson’s workpapers clearly indicate that adjustments were required and made to the per
book data for unique transactions involving sales and storm activity. As to sales, the workpapers450
show that in the 26 years of data for Account 353, there were three occasions with very large sales
proceeds for the sale of substations. As to storm activities, the same workpapers show only one
occasion in 26 years where gross salvage amounts were recorded. ETI contends that these unique
events are properly excluded from net salvage analysis and Mr. Pous’ reliance on the per book data
to establish positive net salvage is erroneous. With respect to Mr. Pous’ concern’s relating to the
price of copper, ETI responds that Mr. Pous’ reliance on copper’s scrap value is pure speculation,
unsupported by any ETI-specific data regarding the amount of copper at issue, or any consideration
of the offsetting significant and increasing labor costs involved in the removal of large station
transformers.

As explained by Mr. Watson, it appears to the ALJs that the adjustments made were, indeed,
required because of the unique nature of the events they reflected. The ALJs also find that
Mr. Pous’ concerns relating to the price of copper are speculative. Coupled with the fact that Staff
supports ETI’s proposed net salvage value, the ALJs recommend that the Commission approve
ETI’s recommended negative 20 percent net salvage value.

(iii) Account 354-Towers and Fixtures

Although there is limited experience available for this account, the five-year and ten-year
moving averages for transaction year 2010 show a substantial level of negative net salvage
(negative 299 percent and negative 233 percent, respectively). Taking into account the low level of

449
Id. at 22.
450
ETI Ex. 13A (Watson Direct) Workpaper on CD, “Entergy Net Salvage Transmission Distribution
General” Spreadsheet, “Data Adjustments” Tab, Account 353.
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retirement experience, Mr. Watson stated that he moderated the outcome by recommending moving
to negative 20 percent net salvage.451 Mr. Pous concurred in this recommendation.

Ms. Mathis recommended a net salvage rate of negative 5 percent for Account 354.452 This
recommendation is based on Commission precedent due to the absence of reliable historical salvage
data.453 Although historical salvage data is available for the period of 1984 through 2010, this
account had a low level of retirement during this period.454 Because of the limited retirement
activity, Ms. Mathis stated that a reasonable net salvage rate cannot be calculated from the historical
salvage data.455 For example, annual net salvage rates range from approximately
negative 6,000 percent to approximately positive 31,253,400 percent.456 According to Ms. Mathis,
such divergent numbers are indicative of the low retirement activity within this account.

The negative five percent net salvage value recommended by Ms. Mathis is the current
Commission-approved number. The ALJs find it difficult to draw any conclusions from the paucity
of historical data. Had there been additional historical data, it might have been possible to reach the
conclusion urged by Mr. Watson; however, there was not. The ALJs recommend that the
Commission adopt the negative five percent net salvage value recommended by Staff.

(iv) Account 355-Poles and Fixtures

The Commission approved net salvage value for this account is a negative 25 percent.457
This account has shown negative salvage since the 1990s, and the most recent ten-year moving
averages show negative 33.84 percent net salvage. Although years 2009-2010 reflect positive
salvage values, Mr. Watson determined that these values were the product of differences in the

451
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66.
452
Staff Ex. 2 (Mathis Direct) at 23.
453
Id. at 23.
454
ETI Ex. 13 (Watson Direct) at DAW-1 at 66.
455
Staff Ex. 2 (Mathis Direct) at 23.
456
Id. at Appendix C at 2.
457
Cities Ex. 5C (Pous Depreciation Study) at 23.
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timing of the recording of the various transactions associated with the asset retirement, rather than
reflecting an actual positive salvage amount.458 For example, Mr. Watson’s net salvage workpapers
show a significant level of positive salvage only for the years 2009-2010 in Account 355.459 This is
at odds with the remainder of the net salvage data shown in the workpapers, which is almost
exclusively negative net salvage.460 Accordingly, Mr. Watson gave less weight to the 2009 and
2010 values, but moderated his recommendation compared to the ten-year moving averages,
resulting in a recommended net salvage of negative 30 percent. Ms. Mathis concurred.

Cities witness Pous disagreed with Mr. Watson’s analysis, claiming: (1) per book data from
the five-year and ten-year moving averages show positive net salvage amounts; (2) authoritative
depreciation treatises do not support Mr. Watson’s decision to adjust relocation-related transactions
out of the analysis;461 (3) no portion of relocation-related costs can be treated as removal unless that
treatment is prescribed by contract with the third-party; and (4) after the correction to his analysis,
Mr. Watson changed his methodology to arrive at a negative net salvage recommendation. Mr. Pous
recommended an increase in the net salvage values to a negative 15 percent based on the actual
historical data of ETI. Cities contend that Mr. Pous was conservative in his recommendation given
the trend in the data. The most recent five-year band of actual data yields a positive two percent net
salvage.462

The ALJs agree that the debate regarding this account essentially boils down to whether
Mr. Watson’s adjustment to remove relocation expense associated with third-party reimbursement
from the analysis is appropriate. Although Mr. Pous claims that Mr. Watson’s approach is contrary

458
ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 66.
459
ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, lines 130-131,
columns I – S.
460
ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, at lines 105 – 129,
columns I – AC. The 2005-2006 data in this workpaper show an obvious example of an accounting
adjustment timing difference, wherein the year 2005 shows a $1,867,532 removal cost (row 126, column G),
while the immediately following year 2006 shows a large negative removal adjustment of ($1,059,096),
(row 127, column G).
461
Relocations involve the situation where the Company is reimbursed by a third party who desires the
relocation or replacement of the facilities in question.
462
Cities Ex. 5C (Pous Depreciation Study) at 22-25.
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to authoritative guidance, ETI contends that he arrives at that conclusion only by disregarding the
guidance in question, as well as Commission precedent. ETI argues that the depreciation text in
question squarely supports Mr. Watson’s approach:

A reimbursed retirement is one for which the company is fully compensated at the
time of retirement …. Usually reimbursed retirements should not be included in
analysis of property whose investment is recovered through depreciation accruals.463

Mr. Watson explained at hearing that, in his experience, adjustments to remove relocation
expense are standard in depreciation analysis, and to do otherwise would result in a disproportionate
impact on reasonably expected ongoing net salvage, caused by a transaction (the relocation) that
constitutes a very small portion of the overall assets in question.464

Mr. Pous stated that all third-party reimbursements for facility relocation performed by the
Company have to be deemed as salvage (thereby inflating the salvage portion of the net between
removal costs and salvage proceeds) unless a contract between ETI and a third-party explicitly says
otherwise. Mr. Watson’s approach, however, is squarely supported the Commission’s decision in
the recent Oncor case, Docket No. 35717, where it was held that these third-party “reimbursements
are prepayments for new property being installed.”465 The ALJs find that Mr. Pous’ argument is not
credible in light of Mr. Watson’s treatment of relocations in general. Since Mr. Watson properly
removed such relocation expense from the depreciation analysis altogether, those amounts correctly
have no impact on depreciation rates, regardless of how they are allocated between gross salvage
proceeds and the cost of installing new facilities.

ETI’s evidence and argument support its request. Accordingly, the ALJs recommend that the
Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson.

463
ETI Ex. 71 (Watson Rebuttal) at 63 (quoting Depreciation Systems, Iowa State Press, 1994, at 16-17).
464
Tr. at 405.
465
ETI Ex. 71 (Watson Rebuttal) at 63.
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(v) 356-Overhead Conductors and Devices

The Commission approved net salvage value for this account is a negative 20 percent.466
Much as was the case with Account 355, ETI argues that timing differences in reflecting accounting
adjustments made the more recent shorter data bands less representative of reasonably expected
future net salvage. Mr. Watson’s study determined that the longer ten-year moving average for
transaction year 2010 showed salvage of negative 33 percent, so Mr. Watson recommended moving
to negative 30 percent net salvage for this account.467 Staff witness Mathis adopted the same
negative net salvage value.

Cities’ witness Pous recommended an increase to the net salvage value to a
negative 10 percent based on a review of the actual historical data. The actual five-year and ten-year
bands yield a positive one percent and a negative 31 percent. Mr. Pous argues that the trend in the
data could justify even a less negative value.

As with Account 355, the ALJs find that ETI’s evidence and arguments support its request.
Accordingly, the ALJs recommend that the Commission approve a net salvage of
negative 30 percent as proposed by Mr. Watson.

4. Distribution Plant

(a) Lives

An asset’s useful life is used to determine the remaining life over which the cost will be
spread for recovery through depreciation expense.468 The Company’s depreciation study addresses
14 distribution accounts included between Accounts 360.2 and 373.2. According to ETI, the life
parameters in Mr. Watson’s study reflect standard depreciation analysis procedures, including
comparison to standard Iowa curves and actuarial analysis, along with the exercise of informed

466
Cities Ex. 5C (Pous Depreciation Study) at 25.
467
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66-67.
468
Id. at 16.
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judgment.469 Multiple bands and trends were reviewed and, in general, Mr. Watson’s study
explained that the dispersion curve chosen for each account is based on examination of the various
“placement and experience bands”470 and the characteristics of the underlying asset in each account.
The dispersion curve is then chosen that best matches the actual data.471 Staff disagrees with
Mr. Watson’s life parameters for three accounts; Cities with five accounts. The parties’ various
recommendations on the accounts in dispute are shown below:

Depreciation Plant Lives
Account Approved Life ETI Proposal Staff Proposal Cities Proposal
361 45 yrs. S2 65 yrs. R3 70 yrs. R3 65 yrs. R3
364 44 yrs. S1 38 yrs. R1.5 40 yrs. R1 44 yrs. L1
365 44 yrs. S1 39 yrs. R0.5 40 yrs. R0.5 42 yrs. S-0.5
367 40 yrs. S1 35 yrs. R1.5 35 yrs. R1.5 45 yrs. S-0.5
368 39 yrs. S0 29 yrs. L1 29 yrs. L1 33 yrs. L0.5
369.1 36 yrs. S4 26 yrs. L4 26 yrs. L4 33 yrs. R4

(i) Account 361 – Structures and Improvements

Mr. Watson’s study depicts the fit between the actual data in the account and the 65 R3 life
parameter that he proposed for this account.472 Mr. Pous agreed with this recommendation.
Ms. Mathis stated, however, that a life parameter of 70 R3 is a better visual fit for the 1960-2010
experience band.473

Considering all the historical mortality data available for this account (the overall experience
band), the selected Iowa Curve produces a conformance index (CI) of 37.53.474 The CI is a measure

469
Id. at Ex. DAW-1 at 37-54.
470
Placement bands look at assets installed in various years and reveal the types of assets in the account over
time. Experience bands show accounting transactions associated with the assets over time and reveal trends
associated with operational changes and other events.
471
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 37-54.
472
Id. at Ex. DAW-1 at 37.
473
Staff Ex. 2 (Mathis Direct) at 25-26.
474
Id. at 26, Table-5.
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of closeness of fit, and a higher CI value indicates a closer fit between the two sets of data that are
being compared.475

Mr. Watson recommended a life parameter of 65 years based on comparing various slices
(bands) of this account’s mortality data to the 65 R3 Iowa Curve.476 However, Staff argues that
Mr. Watson’s recommended life parameter and Iowa Curve of 65-R3 produces a CI of only 23.61
when measured against the overall (1960 – 2010) experience band.477

ETI responds that the flaw in Ms. Mathis’ position is that she only looks at one band. As the
average age of the investment is only 19.22 years, it is inadequate to look at only one band that
examines a 50-year period. When shorter bands are also factored in (1970-2010 and 1990-2010), the
Company’s proposal shows a significantly higher CI, which is indicative of a better fit to the actual
data.478

The ALJs are persuaded that, in this instance, Ms. Mathis erred by limiting her review to a
single band, especially when that band is significantly longer than the average age of the investment
at issue. In this case, looking at multiple, shorter bands will give a clearer picture of the average life
of the investment at issue. Therefore, the ALJs recommend the Commission approve the 65 R3 life
parameter Mr. Watson proposes for this account.

(ii) Account 364 – Poles, Towers, and Fixtures

Mr. Watson’s study results in his proposing a life parameter of 38 R1.5.479 He stated that the
current plant in service reflects a life (13.97 years on average) that is substantially shorter than his
recommendation, and all the bands examined reflect a shorter life than the currently approved
44 years. Mr. Watson testified that his recommendation balances these facts with the additional fact

475
ETI Ex. 71 (Watson Rebuttal) at 24.
476
ETI Ex. 13 (Watson Direct) at 18, Figure 1.
477
Staff Ex. 2 (Mathis Direct) at 26, Table-5.
478
ETI Ex. 71 (Watson Rebuttal) at 24.
479
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 41.
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that ETI is currently using Penta and CCA-treated poles (as opposed to creosote treated poles), for
which a longer life is expected.

Ms. Mathis (40 R1) and Mr. Pous (44 L1) both proposed different life parameters than
Mr. Watson. Ms. Mathis stated that her proposed life parameter is a better visual and mathematical
fit for the single experience band (1959-2010) she considered.480 Mr. Watson responded to this
argument, stating that the mathematical computer fitting emphasized by Ms. Mathis is too limited an
approach, because there is too little information provided at the tail of the curve to rely on computer
fitting in this instance. Mr. Watson indicated that his proposed life parameter shows a better fit over
the full range of placement and experience bands applicable to this account.481

Mr. Pous recommended that the expected service life remain at 44 years based on actuarial
analysis and advances made by the industry and ETI in treating and preserving poles.482 Mr. Pous
also noted that “absent identifiable and supportable specific problems, the industry is not
experiencing shorter lives for poles and neither should ETI.”483 He stated that selection of different
types of poles and different treatments by other utilities have their engineers expecting lives between
50 and 70 years.484 According to Mr. Pous, it is simply not realistic to believe or assume that ETI
would operate now or in the future in a manner that its poles would only last two-thirds the life
expectance being achieved by others.485 Mr. Watson responded that the increased life span urged by
Mr. Pous based on his general discussion of varieties of poles with longer lives is not verifiable, not
consistent with the Company-specific data or the specific experience of its distribution personnel,
and is plainly exaggerated.486

480
Staff Ex. 2 (Mathis Direct) at 28-29.
481
ETI Ex. 71 (Watson Rebuttal) at 29-31.
482
Cities Ex. 5C (Pous Depreciation Study) at 35-36.
483
Id. at 37.
484
Id.
485
Id. at 36.
486
ETI Ex. 71 (Watson Rebuttal) at 28-29.
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The ALJs reviewed the evidence and arguments of the parties with respect to this issue and
were most persuaded by the CIs that resulted from the recommendations of Staff and ETI.
Considering all the historical mortality data available for this account (the overall experience band),
Staff’s selected Iowa Curve produces a CI of 41.44, while ETI’s produces a CI of only 20.66 when
measured against the overall (1958 – 2010) experience band.487 The ALJs recommend that the
Commission adopt Staff’s proposal of 40 R1.

(iii) Account 365 – Overhead Conductors and Devices

The Commission approved average service life is 44 years.488 All parties propose a change
to this life parameter. Mr. Watson proposed a life parameter of 39 R0.5, Ms. Mathis proposes a life
parameter of 40 R0.5, and Mr. Pous proposed a life parameter of 42 S.-5.

Mr. Watson noted that his analysis took into account the fact that the currently authorized life
is longer than the history would support, and that the young average age of the current plant in
service (12.15) points toward placing more weight on recent bands for life selection. He also noted
that ETI’s movement toward re-conductoring lines supports the conclusion that lives in this account
will be shorter.

Ms. Mathis indicated that her recommendation is based on comparing the account’s historical
mortality data for the period of 1958 through 2010 to the 40 R0.5 Iowa Curve.489 Considering all the
historical mortality data available for this account (the overall experience band), the selected Iowa
Curve produces a CI of 29.63.490 Mr. Watson countered that Ms. Mathis used the wrong curve to
represent the Company’s proposal in her calculations. He stated that when her analysis is corrected

487
Staff Ex. 2 (Mathis Direct) at 29, Table-6.
488
Cities Ex. 5C (Pous Depreciation Study) at 38.
489
Staff Ex. 2 (Mathis Direct) at 30.
490
Id. at 31, Table-7.
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to make the proper comparison, ETI’s proposal has a higher CI (and thus a better fit) across all
experience bands save one.491

Mr. Pous testified that his life parameter best matches the actuarial analysis taking into
account the unusually high level of retirement activity recorded in the first 0.5 year of age. As
Mr. Pous noted, “the highest retirement ratio for this investment in the first 23 years occurred at age
0.5 years, for brand new assets. While such events can and have occurred associated with utility
plant, it is not the type of event that is reasonably expected to repeat itself in future periods as
different equipment it purchases if it was an equipment problem, or different installation processes
are employed if the early retirement were due to installation issues.”492 Mr. Pous criticized
Mr. Watson’s recommendation on several grounds: (1) it is not consistent with expected lives
reported by ETI personnel; (2) it did not account for anomalies and/or unusual activity in the
retirement data; (3) the major re-conductoring activity shown in the account should not be expected
to continue; and (4) the life-curve combination chosen by Mr. Watson is not long enough to match
the actual data.493

Mr. Watson took issue with Mr. Pous. He stated that Mr. Pous simply misread the data
Mr. Watson argued that Exhibit DAW-R-1 to his rebuttal testimony shows that retirements are
decreasing.494 Mr. Watson believes that his proposed life parameter is a better fit to the actual data.
The very small amount of plant that may not last until the tail of the curve used by Mr. Watson does
not alter this conclusion.495 Finally, ETI argues that Mr. Pous provides no persuasive basis for
second guessing the opinion of Company personnel regarding re-conductoring.

The ALJs are persuaded by ETI’s evidence and argument. It does appear that Ms. Mathis
used the wrong curve in her calculations. If corrected, Mr. Watson’s proposal renders the higher CI.

491
ETI Ex. 71 (Watson Rebuttal) at 36.
492
Cities Ex. 5C (Pous Depreciation Study) at 38-39.
493
Id. at 38-41.
494
ETI Ex.71 (Watson Rebuttal) at 32-33.
495
Id. at 32, 33-35.
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Mr. Pous’ arguments fair no better. To the ALJs’ eye, Mr. Pous did misread the data, and the
conclusions drawn by Mr. Pous are simply inaccurate. The ALJs recommend that the Commission
adopt ETI’s proposed life parameter of 39 R0.5.

(iv) Account 367 – Underground Conductors and Devices

The Commission approved average service life is 40 years.496 Mr. Watson’s life parameter
for this account (35 R1.5) is based on his review of the various placement and experience bands, as
well as the characteristics and longevity of the conductors in place in the ETI system and the
retirement patterns that are unique to underground conductor performance and the locations where it
is buried.497 Ms. Mathis agreed with Mr. Watson on this account. Cities propose a significantly
longer life (45 S-0.5). Mr. Pous stated that Mr. Watson’s and Ms. Mathis’ recommendations do not
account for the increased durability of newer types of conductor, and that the actuarial analysis
should focus on more recent data that he believes is more consistent with the newer conductors.498

Mr. Watson testified that Mr. Pous’ recommendation should be rejected for a variety of
reasons. The Southern California Edison-based opinions regarding longer life for the conductor,
relied on by Mr. Pous, relate to plant installed less than ten years ago. Therefore, based on his own
theory, much of the investment in question in this account is still the older, shorter-lived variety, and
his recommendations are premature. Moreover, Mr. Watson’s plotting of the dispersion curves
show that his is a better fit than that of Mr. Pous. In this instance, Mr. Pous’ analysis, relying only
on the shortest band, failed to pick up the older investment that constitutes almost 80 percent of the
surviving investment.499

It appears that Mr. Pous, in relying on the shortest band, did fail to take into account
investment that comprises almost 80 percent of the surviving investment in this account. That is a
significant flaw in his analysis. Similarly, his reliance on the Southern California Edison-based

496
Cities Ex. 5C (Pous Depreciation Study) at 41.
497
ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 45.
498
Cities Ex. 5C (Pous Depreciation Study) at 41-44.
499
ETI Ex. 71 (Watson Rebuttal) at 40.
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opinions relate to newer plant, which again calls his analysis into question in the present
circumstances. The ALJs recommend that the Commission approve ETI’s recommended service life
of 35 R1.5.

(v) Account 368 – Line Transformers

The Commission approved anticipated service life is 39 years.500 Mr. Watson proposed a
service life of 29 L1,501 with which Ms. Mathis agreed. Mr. Watson stated that this is consistent
with the data showing decreasing lives for these assets, the expected lives per Company personnel,
and the fact that transformers are junked or sold rather than repaired.502

Mr. Pous recommended that the expected service life be decreased to 33 years, representing a
15 percent reduction in the anticipated service life. Mr. Pous stated that his analysis is based on
actuarial analyses and the Company’s addition of approximately $80 million of pad mounted
transformers since the last case, when the Commission approved a 39-year anticipated average
service life. According to Mr. Pous, ETI personnel have stated that pole mounted transformers have
a life of between 25 and 35 years. However, pad mounted transformers are expected to last up to
40 years by the same Company personnel. Given the sizable investment since the last case in the
pad mounted transformers with a longer expected service life, a decrease in the anticipated service
life of greater than 15 percent is not warranted, according to Mr. Pous. Moreover, Mr. Pous stated
his analysis uncovered abnormally high retirement ratios in the 21.5 to 22.5 year age brackets
indicative of one-time events such as the ice storm or changes in accounting systems. As such,
Mr. Pous performed his curve fitting analysis recognizing the unusually high retirement activity
between years 21.5 and 22.5 rather than emphasizing such unusual activity as Mr. Watson did for his
proposal to reduce service life by 26 percent.503

500
Cities Ex. 5C (Pous Depreciation Study) at 44.
501
ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.
502
Id. at 47.
503
Cities Ex. 5C (Pous Depreciation Study) at 45.
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Mr. Watson recommended a decline in average service life from a 39-year anticipated service
life to a 29-year anticipated service life citing the high occurrence of lightning in the ETI service
area.504 However, Mr. Pous noted that the effects of lightning in ETI’s service area would have been
present in ETI’s last base rate case when a 39-year anticipated service life was approved by the
Commission. Both Mr. Watson and Mr. Pous recognized that the pad mounted transformers are not
subject to the same forces of retirement like weather, lightning, and animal disturbances.505
However, Mr. Watson did not realistically factor ETI’s relative increased investment in pad mounted
transformers into his analysis. Moreover, when performing his curve fitting analysis, Mr. Watson
neither analyzed nor adjusted for the abnormal unusual retirement ratios between years 21.5 and
22.5.506 Instead, Mr. Watson attempted to select a life analysis that anticipates a high level of
retirement within that time period in the future.507 Cities argue that, by failing to recognize the
sizable new investment in pad mounted transformers and failing to consider the unusual retirement
ratios, Mr. Watson proposed an average service life that is lower than the bottom end of the range of
life estimates of Company personnel for pad mounted transformers. Moreover, Mr. Watson’s
proposal does not even reach the midpoint of life estimates expected by Company personnel for pole
mounted transformers.

The arguments and evidence advanced by Cities witness Pous are persuasive to the ALJs.
Mr. Watson’s contention regarding the occurrences of lightening in the ETI service area was equally
applicable at the time the existing approved rate was set, and is, therefore, of little value in this
proceeding. Further, Mr. Watson’s failure to analyze the abnormal retirement ratios between years
21.5 and 22.5 also argues against his analysis. The ALJs recommend that the Commission adopt
Mr. Pous’ proposed life of 33 L0.5.

504
ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.
505
Id.
506
Cities Ex. 5C (Pous Depreciation Study) at 47.
507
ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50-51.
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(vi) Account 369.1 – Overhead Services

The Commission previously approved anticipated service life for this account is 36 years.508
Mr. Watson’s analysis of this account shows that overhead assets have retired earlier and have been
replaced more frequently than is consistent with the existing 36 S4 life. The average age of current
investment is 10.12 years. Consistent with this data and his review of various curves and placement
and experience bands, he recommended shortening the life to 26 L4. Ms. Mathis agrees with this
proposal.509

Mr. Pous recommended that the expected service life be shortened to 33 years based on the
lack of Company historical data and based on comparative utility experience including recent studies
by Mr. Watson, where he proposed significantly longer average service lives. Mr. Pous testified that
an evaluation of the actual data casts serious doubt about the reliability of the data for depreciation
purposes. ETI does not have any records of services in this subaccount surviving past 1978.
Mr. Pous stated that his recommended 33-year life expectancy for this sub-account is still far shorter
than industry expectations, but is consistent with the depreciation study recently conducted for
EGSL where the depreciation expert hired by EGSL recommended a 33-year life.510

ETI argues that Mr. Pous apparently made no attempt to perform any curve fitting regarding
this account, as none appears in his study; in the absence of performing this essential analysis, he
settles for again casting doubt on the reliability of Company accounting data. ETI contends that, in
reality, Mr. Pous appears to present no recommendation for this account based on evaluation of any
of the accounting data that actually depicts the past and current characteristics of the assets.511

508
Cities Ex. 5C (Pous Depreciation Study) at 48.
509
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 49.
510
Cities Ex. 5C (Pous Depreciation Study) at 48-49.
511
Id. at 48-50.
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ETI argues that its recommended life is clearly supported by the Company-specific data,
graphically depicted in Mr. Watson’s rebuttal testimony, while Mr. Pous’ suggested life parameter is
not even close, and is based on unsupported speculation.512

Although the evidence on this issue is sparse, the ALJs ultimately are persuaded that ETI’s
(and Staff’s) position is more reasonable. Accordingly, the ALJs recommend the Commission adopt
ETI’s proposed 26 L4 life span.

(b) Net Salvage Value

Staff disagrees with Mr. Watson’s recommendations for five of the distribution accounts, and
Mr. Pous disagrees regarding two of the accounts. The parties’ positions on distribution net salvage
values in dispute are set out immediately below:

Distribution Plant Net Salvage
Account Approved Rate ETI Proposal Staff Proposal Cities Proposal
361 -5% -10% -5% -10%
362 +15% -20% -10% 0%
365 +10% -7% -7% 0%
368 0% 0% -5% 0%
369.1 -10% -5% -10% -5%
369.2 -10% -5% -10% -5%

(i) Account 361 – Structures and Improvements

The existing net salvage value for this account is negative five percent, which is the value
proposed by Staff. Mr. Watson and Mr. Pous, on the other hand, proposed a salvage value of
negative 10 percent.

Mr. Watson’s recommendation is based on the most recent five-year and ten-year net salvage
ratios, which are negative 9.70 percent and negative 36.70 percent, respectively. Ms. Mathis’
recommendation is based on analysis of historical salvage data for the period of 1984 through 2010.
Specifically, the two-year moving average median for the same period produces a net salvage rate of

512
ETI Ex. 71 (Watson Rebuttal) at 46-48.
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negative 5.87 percent, which is very close to the currently approved net salvage rate for this
account.513 Moreover, the one-year, three-year, four-year, five-year, six-year, and seven-year
moving average medians of negative 6.95 percent, negative 5.11 percent, negative 3.64 percent,
negative 1.90 percent, negative 4.57 percent, and negative 7.24 percent, respectively, support this
recommendation. Additionally, this account contains a few significant outliers, such as
negative 655.91 percent in 2002 and negative 322.55 percent in 2005.514 Ms. Mathis’ use of the
median average eliminates the skewing effect of these outlying values.

As discussed in Section VII.C.1, the use of the median is the most appropriate methodology.
For this reason, the ALJs recommend the Commission approve Staff’s proposed negative 5 percent
net salvage value.

(ii) Account 362 – Station Equipment

The existing net salvage value of this account is positive 15 percent. Mr. Watson proposed
that it be changed to negative 20 percent, Staff proposes it be changed to negative 10 percent, and
Cities propose it be changed to zero.

Mr. Watson’s study shows that the most recent five-year and ten-year net salvage ratios are
negative 22.10 percent and negative 43.55 percent, respectively. He recommended negative
20 percent net salvage based on the Company’s experience.515

Ms. Mathis’ recommendation is based on analysis of historical salvage data for the period of
1984 through 2010. Specifically, the recommendation is supported by the two-year moving average
median for the same period of negative 12.23 percent.516 Moreover, the one-year, three-year,
five-year, six-year, seven-year, and eight-year moving average medians of negative 11.07 percent,

513
Staff Ex. 2 (Mathis Direct) at 27.
514
Id. at Appendix C at 4.
515
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 68.
516
Staff Ex. 2 (Mathis Direct) at 27.
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negative 14.16 percent, negative 7.62 percent, negative 8.19 percent, negative 11.75 percent, and
negative 14.15 percent, respectively, support her recommendation.517

Mr. Pous’ recommendation is based on what he characterizes as the Company’s actual,
unadjusted, experience; recognition of the type of investment in the account; recognition of
significant value of scrap copper; investigation of retirement mix compared to investment mix over
the past ten years; and recognition of industry values.518 According to Mr. Pous, given the
significant increase in the value of copper, the retirement of a transformer could be expected to
significantly influence the net salvage value for this account.

Mr. Pous’ recommendation is the outlier among the three before the ALJs, and the ALJs are
not convinced that the reasons put forth by Mr. Pous in support of his position are sufficient to carry
the day. The real argument here is between ETI and Staff, which centers on the use of the median
(Staff) and the mean (ETI). As discussed in Section VII.C.1, the use of the median is the most
appropriate methodology. For this reason, the ALJs recommend the Commission approve Staff’s
proposed negative 10 percent net salvage value.

(iii) Account 365 – Overhead Conductors and Devices

The current net salvage value for this account is positive 10 percent.519 ETI and Staff
recommend changing it to negative seven percent, and Cities recommend changing it to zero.

Mr. Pous recommended a reduction in the current net salvage values to zero based on review
of the actual historical data and the relative mix of the investment recorded in this account.
Mr. Pous noted that $40 million of investment recorded in this account is associated with clearing
rights of way, which will not likely be retired or incur cost of removal or gross salvage. Another $40

517
Id. at Appendix C at 4-5.
518
Cities Ex. 5C (Pous Depreciation Study) at 26.
519
Id. at 28.
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million is associated with investment in copper conductors, which has escalated in demand in recent
years and should result in positive net salvage.520

Mr. Watson corrected his analysis and recognized that timing differences between the
recording of accounting adjustments related to net salvage (i.e., salvage and removal costs for a
particular transaction were not recorded at the same time) made one of the recent years less
representative of reasonably expected ongoing net salvage levels. He focused, therefore, on longer
period averages and recommends negative seven percent net salvage consistent with the most recent
ten-year ratios.521 Mr. Watson explained that his adjustments removed relocation activity altogether
from this account because it is not characteristic of the vast majority of retirements and because, if
the adjustment is not made, it will shorten and skew the life analysis. Further, Mr. Watson stated
that Mr. Pous’ claims regarding the impact of copper prices ignore those prices’ future volatility and
are not supported by any analysis or quantification specific to these accounts. Mr. Watson indicated
that his recommendations are based on the most clear and reliable source – Company-specific
accounting data – not “selective comparisons of industry norms,” as alleged by Mr. Pous.522

The ALJs find Mr. Watson’s explanations of the rationale behind his analysis to be both
credible and convincing. Accordingly, the ALJs recommend the Commission adopt ETI’s requested
negative 7 percent net salvage value.

(iv) Account 368 – Line Transformers

The existing net salvage value for this account is zero, which both Mr. Watson and Mr. Pous
recommended be retained. Ms. Mathis, on the other hand, argued that the net salvage value should
be changed to negative five percent.

The argument here is whether the median or the mean best represents the appropriate net
salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in

520
Id. at 28-29.
521
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 69.
522
ETI Ex. 71 (Watson Rebuttal) at 68-69.
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Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the
ALJs recommend the Commission approve Staff’s proposed negative five percent net salvage value.

(v) Account 369.1 – Overhead Services

The existing net salvage value for this account is negative 10 percent, which Staff
recommends be retained. Mr. Watson and Mr. Pous argue in favor of a change to negative 5 percent
net salvage value.

The argument here is whether the median or the mean best represents the appropriate net
salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in
Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the
ALJs recommend the Commission approve Staff’s proposed negative 10 percent net salvage value.

(vi) Account 369.2 – Underground Services

ETI began specifically charging salvage and removal cost to this account just in the last two
years, producing a five-year net salvage ratio of negative 15.75 percent. Mr. Watson recommended
moving from the current negative 10 percent to negative five percent net salvage.523 Mr. Pous
agreed. Because of the limited available data, Ms. Mathis recommended retaining the existing
negative 10 percent net salvage.524

The ALJs agree with Staff that because of the limited retirement activity, a reasonable net
salvage rate cannot be calculated from the historical salvage data. Accordingly, the ALJs
recommend the Commission adopt the negative 10 percent net salvage value proposed by Staff.

5. General Plant

General plant includes some accounts that are subject to depreciation, and some that are
subject to amortization. ETI proposes to adopt “Vintage Group Amortization,” consistent with

523
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 70.
524
Staff Ex. 2 (Mathis Direct) at 34.
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FERC Rule AR-15 for Accounts 391-397.1 and Account 398. This approach, approved by both the
FERC and the Commission (Docket No. 38339), does not affect the annual level of expense, but
provides for timely retirement of assets and simplifies accounting for general property.525
Ms. Mathis concurred in the Company’s proposal to adopt Vintage Group Amortization and with its
recommendations for lives, amortization periods, and net salvage.526

The increase in expense for general plant proposed by ETI is due to the need to reduce the
deficit in the general plant reserve caused by inadequate account level rates in the past.527 This is a
matter of debate among the parties, as discussed in more detail below.

(a) Account 390 – Structures and Improvements (Life Parameter)

Based on his analysis of the data in comparison to various potential dispersion curves,
Mr. Watson recommended an increase in the life of this account to 45 R2.528 Ms. Mathis agreed
with this life. Mr. Pous proposed a significantly longer life (54 S0.5) and claimed that Mr. Watson
did not adequately investigate the data and investments in this account. Mr. Pous concluded that
“superstructures and roadways” are a significant element in the account which can be expected to
have a long life.529

ETI contends that Mr. Pous’ analysis is incorrect. First, as confirmed by his workpapers,
Mr. Watson conducted an analysis of five bands, not a single band as alleged by Mr. Pous.
Furthermore, Mr. Pous’ argument regarding long lives, based on the idea that the investment dates
back to 1927, is contrary to the actual data showing a minute amount of old investment (0.02 percent
of the account) dating back only to 1939. The average age of investment in the account, however, is

525
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.
526
Staff Ex. 2 (Mathis Direct) at 35-37.
527
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.
528
Id. at Ex. DAW-1 at 56.
529
Cities Ex. 5C (Pous Depreciation Study) at 51.
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only 15.87 years. Mr. Watson explained that the actual data shows no investment has achieved a life
of 85 years, as alleged by Cities.530

The ALJs believe that the actuarial analysis and curve fitting shown in Mr. Watson’s direct
and rebuttal testimony demonstrate a more reasonable approach, as recognized by Staff witness
Mathis. Therefore, the ALJs recommend the Commission adopt the 45 R2 life parameter
recommended by ETI.

(b) Account 390 – Structures and Improvements (Net Salvage Value)

Account 390 is a depreciable account for structures and improvements. Though the current
authorized net salvage is zero, Mr. Watson recommended a negative five percent net salvage value,
and Staff agrees with this recommendation. Mr. Pous recommended a positive 15 percent net
salvage value.

Mr. Watson based his recommendation on the most recent five-year and ten-year ratios,
which are negative 1.51 percent and negative 34.27 percent.531 Mr. Pous disagreed, arguing that:
(1) Mr. Watson’s data adjustments present an incorrect picture of the salvage history; and
(2) Mr. Watson failed to account for the difference in net salvage values between the retirements of
leaseholds, versus Company-owned facilities, which should not produce negative salvage.532

According to ETI, Mr. Pous’ argument that retirement and sales of buildings will result in
positive net salvage is not backed up by the Company-specific data for this account. Such data
shows that negative net salvage has occurred in every period of the most recent ten-year moving
average. Averages of six years or longer range from negative 4.56 percent to negative
34.27 percent.533 ETI also argues that Mr. Pous’ attempt to use sales of facilities as an element of
depreciation analysis is contrary to Commission precedent regarding building sales ’and that his

530
ETI Ex. 71 (Watson Rebuttal) at 49.
531
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 73.
532
Cities Ex. 5C (Pous Depreciation Study) at 31.
533
ETI Ex. 71 (Watson Rebuttal) at 73-74.
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opinion is contrary to the facts that such sales are unique circumstances that do not reasonably
represent the ongoing year-to-year retirement activity that should form the basis of depreciation
analysis.

The ALJs find that Mr. Pous’ arguments are not supported by the facts and that Mr. Watson’s
explanations are the more credible. Accordingly, the ALJs recommend the Commission adopt ETI’s
proposed negative five percent net salvage value for this account.

(c) General Plant Reserve Deficiency

A $21.3 million deficit has developed over time in the reserve for the accounts that ETI
proposes should be converted to General Plant Amortization. This deficit, or under-recovery, has
occurred because assets have been retired more quickly than can be addressed by the existing
amortization rate. ETI, therefore, proposes a $2.1 million annual expense level to recover the deficit
over ten years.534 Ms. Mathis recommended that the amortization of the reserve deficiency be
rejected and that the deficit be recovered through application of the remaining life method to the
individual accounts where the deficit occurred.535

ETI argues that although Ms. Mathis’ recommendation could theoretically allow recovery,
her calculation of the amortization for the accounts that created the deficit is erroneous and
insufficient to carry out her proposed concept for recovery. During her cross examination,
Ms. Mathis agreed that she had intended to take the elements of the remaining life calculation
method exclusively from Mr. Watson’s depreciation study. 536 ETI contends that she failed to pull
the correct values from Mr. Watson’s study and her numbers did not match the corresponding entries
from Mr. Watson’s study.537 For example, Ms. Mathis affirmed that her remaining life calculations
were intended to allow recovery of the remaining investment in general plant account 391.2. The

534
ETI Ex. 13 (Watson Direct) at Ex. DAW-2 at 2, App. A-2 at 1-2.
535
Staff Ex. 2 (Mathis Direct) at 38.
536
Tr. at 1752-1753.
537
Tr. at 1746-1759.
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remaining investment she provided for was $10.9 million of an original cost of $21.7 million.538 The
actual remaining investment in the account, however, as shown in the data she purported to rely on,
was a credit balance of negative $4.4 million, meaning that not only the original cost, but
$4.4 million additional investment remained unrecovered.539 Ms. Mathis had no explanation for the
difference. In fact, it appears that she erroneously substituted the theoretical reserve for the account
in Mr. Watson’s study ($10.789 million) as the actual book reserve, resulting in an erroneous
calculation of the amount yet to be recovered.540 Mr. Watson’s rebuttal points out the errors in the
calculation and provides an exhibit to properly reflect the remaining life approach that Ms. Mathis
intended.541

However, Mr. Watson’s rebuttal also explained the reasons that the Company’s approach is
better. By using a ten-year amortization period for the deficit, ETI lowers the annual amount of the
expense in rates to $2.1 million. Once Ms. Mathis’ calculation is corrected, because the remaining
lives through which the asset value is recovered are so short, ’her remaining life approach increases
the annual expense of amortization to $5.8 million. Given the significant level of expense involved,
ETI personnel had asked Mr. Watson to moderate the remaining life approach in this instance by
using a ten-year amortization period that was consistent with the approach used by another affiliate
within the Entergy system. Moreover, although Ms. Mathis purports to rely on the Commission’s
decision in Docket No. 38339 in support of her proposal, that case includes no discussion of
rejecting the proposal on general plant that Mr. Watson makes here.542

The ALJs have reviewed the evidence cited by both parties and the testimony offered in
support of their respective positions. It is clear to the ALJs that Ms. Mathis inadvertently did exactly
what ETI alleges – she got numbers confused and, in so doing, confused her analysis. The ALJs find

538
Tr. at 1754; Staff Ex. 2 (Mathis Direct) at Ex. JLM-2 at 4.
539
Tr. at 1755.
540
Tr. at 1759-1761.
541
ETI Ex. 71 (Watson Rebuttal) at 84, Ex. DAW-R-5.
542
Id. at 80-81.
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that ETI’s proposed $2.1 million annual expense level to recover the deficit over ten years be
approved by the Commission.

(d) Amortization Period for Account 391.2 – Computer Equipment

Mr. Pous challenged the amortization period for this account, contending, contrary to Staff
and Mr. Watson, that the Company’s proposal to amortize general plant using “Vintage Group
Amortization” is not consistent with FERC pronouncement AR-15. ETI argues that Mr. Pous’
critique is wrong because the five-year life of which Mr. Pous complains is based on standard life
analysis. The life has nothing to do with AR-15, which does not determine such matters.
Mr. Watson’s study clearly explains that he based the life parameter on standard actuarial
analysis.543

According to ETI, Mr. Pous’ own recommendation points out the fallacy of his arguments
about AR-15. He recommended a one-year increase in the amortization, which does not match the
previous period of depreciation for this account, or the previous depreciation rate, despite that being
the supposed flaw in Mr. Watson’s approach.544 Mr. Watson explained that the use of AR-15 does
not involve any independent tinkering with the life of the asset account because the AR-15 process
“provides for the amortization of general plant over the same life as recommended,” based on
standard life analysis, which Mr. Watson’s study recognized.545

The ALJs are persuaded by ETI’s arguments on this point. FERC pronouncement AR-15
requires amortization over the same life as recommended based on standard life analysis.
Mr. Watson’s study employed standard life analysis to ascertain the recommended five-year life.
The ALJs therefore recommend the Commission adopt the five-year life proposed by ETI.

543
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 58.
544
Cities Ex. 5 (Pous Direct) at 36.
545
ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2.
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6. Fully Accrued Depreciation

Mr. Pous claimed that the Company has failed to conform its Commission-authorized
depreciation rates when it stops accruing depreciation on accounts and sub-accounts that are fully
accrued. He testified that the Company must continue to depreciate such accounts, despite the fact
that this policy would mandate that the Company intentionally create negative depreciation amounts
that do not relate to the existence of any depreciable asset still in existence. Mr. Pous testified that
neither standard depreciation definitions nor GAAP or National Association of Regulatory Utility
Commissioners (NARUC) depreciation guidance support the Company’s action.546 The impact of
Mr. Pous’ recommendation is to impute an additional $6,447,731 depreciation amount to reduce rate
base and amortize that credit over four years, with an associated revenue requirement reduction of
$1,611,933.547

ETI argues that Mr. Pous pointed to no instance in which his theory has been adopted by the
Commission, or any other regulatory body. Other regulators within the Entergy system have
rejected his position.548 The RRC, which sets gas utility rates under essentially the same regulatory
framework as PURA, has rejected Mr. Pous’ position on three separate occasions.549 ETI contends
that Mr. Pous’ suggestion violates GAAP, which requires that once an asset’s service value (original
cost less net salvage) has been fully amortized through the application of the most recently approved
depreciation rates, there is no further service value to be recognized. This has been ETI’s practice as
long as ETI regulatory accounting witness Considine has been aware. Furthermore, ETI suspends
depreciation only so long as the account is fully amortized. Once additional activity hits the
account, depreciation will begin again under the Company’s automated systems.550

ETI also argues that Mr. Pous’ retroactive approach is unreasonably selective. He would
reach back into recoveries under existing rates to reclaim revenues associated with the depreciation

546
Cities Ex. 5 (Pous Direct) at 39-45.
547
Id. at 45.
548
ETI Ex. 46 (Considine Rebuttal) at 45-46.
549
ETI Ex. 71 (Watson Rebuttal) at 81, n. 61; ETI Ex. 46 (Considine Rebuttal) at Ex. MPC-R-11.
550
ETI Ex. 46 (Considine Rebuttal) at 44-45, 47.
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expense that relates to the fully accrued accounts. According to ETI, Mr. Pous takes no notice of the
depreciation taken on new assets that are not included in rate base or recovered through depreciation
expense under existing rates. ETI witness Considine notes that Mr. Pous has essentially formulated
a one-sided exact recovery mechanism for depreciation expense that is completely unique in the
annals of base rates.551

According to ETI, Mr. Pous also ignores that the remaining life depreciation method already
addresses any over- or under-accrual of depreciation expense. As depreciation rates and the
remaining life are adjusted over time, any over (under) recovery will be carried forward and the net
(if any) of the original investment less any accumulated reserve will begin to be recovered under the
new and future rate structures. This is the basic concept of remaining life depreciation rates. Thus,
ETI contends that no further actions or adjustments are appropriate.552

The ALJs find that Mr. Pous’ recommendation has previously been rejected, by other
regulatory bodies. There is nothing in the arguments advanced by Cities that changes that fact.
Accordingly, the ALJs recommend the Commission reject Cities’ proposal.

7. Other Depreciation Issues – Accumulated Provision for Depreciation

ETI proposes to amortize the $21 million general plant deficiency over ten years. Both the
Cities and Staff agree with and use the accumulated depreciation reserve amounts per account from
Mr. Watson’s study.553 TIEC witness Pollock, in arguing against amortization of the amortized
general plant reserve deficiency, testified that this reserve deficiency should instead be simply
reallocated to other depreciable general plant accounts that have depreciation surplus.554

Mr. Pollock discussed transferring the depreciation reserve between the amortizable and
depreciable general plant accounts. He failed to show, however, how the reserve reallocation would

551
Id. at 43, 45.
552
ETI Ex. 71 (Watson Rebuttal) at 78.
553
Id. at 77.
554
TIEC Ex. 1 (Pollock Direct) at 38-39.
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be computed and provided no workpapers to substantiate his analysis. ETI argues that without a
verifiable basis for the computations, his recommendations to recompute general plant depreciation
accruals should be rejected.

ETI also argues that Mr. Pollock’s testimony shows that he has reallocated the amortizable
general plant deficiency from the amortized general plant accounts to the depreciable general plant
accounts. The depreciable plant accounts have shorter remaining lives than the ten-year
amortization of the deficiency proposed by ETI.555 ETI contends that common sense dictates that
transferring dollars from an account with a relatively longer remaining life to one with a shorter life
will yield a higher annual depreciation or amortization expense, yet Mr. Pollock somehow takes this
step and still arrives at a lower level of expense.

According to ETI, Mr. Pollock’s methodology has the effect of “amortizing the difference
between the book and theoretical reserve over a time period that is significantly shorter than the
average remaining life of the assets within this function.”556 ETI asserts that such an adjustment to
depreciation and amortization expense was rejected by the Commission in the CenterPoint rate case,
and it should be rejected here.557

TIEC argues that it does not propose any amortization of any accounts. Rather, TIEC states
that it is proposing a more efficient method for ETI to cure its deficits. Because ETI retired
equipment prior to the end of the assumed life of those assets, there is approximately a $21,300,000
deficiency in general plant accounts. ETI seeks to amortize the deficiency over ten years so that the
book reserve will “catch-up” with the theoretical depreciation reserve for the deficient reserve. TIEC
contends that its position is that the catch-up adjustment is not necessary.558

555
ETI Ex. 13 (Watson Rebuttal) at Ex. DAW-1, App. A-1 at 4.
556
ETI Ex. 71 (Watson Rebuttal) at 75.
557
Id. at 75-76.
558
TIEC Ex. 1 (Pollock Direct) at 37.
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The ALJs have reviewed the evidence and arguments advanced by the parties and find that
those of ETI are more persuasive. Accordingly, the ALJs recommend the Commission reject TIEC’s
recommendation.

D. Labor Costs

1. Payroll and Related Adjustments

A number of parties suggest various adjustments to ETI’s proposed payroll and related costs.
In the application, ETI’s Test Year payroll costs were adjusted downward by $957,695 to reflect a
decrease in the employee headcount levels at ETI during the Test Year. At the same time, payroll
costs were increased in the amount of $1,105,871 to account for employee pay raises. The net result
was that ETI’s Test Year payroll expense was adjusted upward by $148,176. Similar calculations
were made for ESI employees, resulting in a net upward adjustment for ESI payroll expenses of
$852,493. Thus, ETI requested an upward adjustment of $1,000,669 ($148,176 plus $852,493) for
ETI and ESI payroll expenses.559

Cities oppose one part of these proposed adjustments. As noted above, ETI is proposing an
upward adjustment to account for pay raises given to ETI and ESI employees. One set of those
raises was given to employees in early August 2011, one month after the end of the Test Year.
Another set of raises was given to employees in April 2012, roughly nine months after the end of the
Test Year. Cities witness Garrett testified that it is acceptable to make an adjustment for the raises
made in August 2011 because they occurred shortly after the end of the Test Year. However, he
stated that it is unreasonable to include an adjustment for the raises given in April 2012. He believes
that any increase in costs due to the April 2012 pay raises might be offset by changes in productivity
and the overall workforce that may occur during the same time period, such as the replacement of
higher-paid workers who retire with new, lower paid employees.560 Thus, Cities propose an
adjustment that would reverse ETI’s proposed increase for the April 2012 pay raises thereby

559
ETI Ex. 8 (Considine Direct) at 24-25; 3 at Sched. A-3 and WP/P AJ22.
560
Cities Ex. 2 (Garrett Direct) at 13-15.
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reducing payroll expense by $1,185,811.561 No other party makes a similar challenge to the April
2012 pay raise.

With regard to the adjustments proposed by ETI, Staff witness Givens accepted the
adjustments for headcount changes and the pay raises, but recommended a further downward
adjustment of $778,034 to account for a further decrease in ETI employee headcount levels from 678
at Test Year-end to 660 as of February 2012. She also recommended an upward adjustment of
$158,589 to account for an increase in ESI employee headcount levels from 3,055 to 3,089 as of
December 2011.562 Ms. Givens also recommended that, in addition to adjusting payroll expense
levels, the more recent headcount numbers should be used to adjust the level of payroll tax expenses,
benefits expenses, and savings plan expenses.563 As an alternative to its primary line of attack
(discussed above), Cities agree with the adjustments recommended by Staff.

ETI also agrees, in concept, with the adjustments recommended by Staff, but contends that
Ms. Givens made some errors in her calculations. First, according to ETI, Ms. Givens used
erroneous headcounts for the end of the Test Year for ETI and ESI. According to the Company,
ETI’s headcount at Test Year-end was 675 and ESI’s was 3,054. Ms. Givens wrongly used
headcounts of 678 and 3,055, respectively, which caused a double counting of three ETI employees
and one ESI employee.564 Second, Ms. Givens made an error in the calculation of benefits costs
associated with the updated ESI headcount. Ms. Givens inadvertently used the ETI percentage in the
calculation rather than the ESI percentage shown on her exhibit.565 Third, Ms. Givens’ adjustment
for savings plan expense was not necessary and is thus inappropriate. According to ETI witness
Considine, savings plan expense is already included in benefits expense levels so it would be double
counting to adjust for both benefits expense and savings plan expense.566 Fourth, Ms. Givens’

561
Id. at 19.
562
Staff Ex. 1 (Givens Direct) at 10-12.
563
Id. at 13-15.
564
ETI Ex. 46 (Considine Rebuttal) at 32-33.
565
Id. at 33.
566
Id.
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full-time equivalent calculations need to be corrected. She included an incorrect assumption
regarding part time employee salaries. Ms. Givens assumed that a part time employee’s average
salary is 50 percent of the full time average salary. In his rebuttal testimony, Mr. Considine
provided the correct calculation of full time equivalents, thereby making it unnecessary to rely upon
an assumed average.567 According to Mr. Considine, the combined impacts of these errors is that
Ms. Givens’ ETI headcount adjustment overstated her O&M payroll reduction by $224,217, and her
ESI headcount adjustment understated her O&M payroll increase by $37,531.568 No party
challenged these corrected numbers.

The ALJs are unpersuaded by Cities’ attempt to exclude the April 2012 pay raises. There
can be no real dispute about the fact that the pay raises are known and measurable. Moreover, there
is an obvious logical inconsistency in the Cities’ position – on the one hand they oppose
consideration of certain pay raises because they fall outside the Test Year, and on the other hand
they support consideration of headcount reductions even though they also fall well outside the Test
Year.

The ALJs are also persuaded that, conceptually, the adjustments suggested by Staff are
reasonable and appropriate. Indeed, all parties agree on this point. Moreover, no party challenged
the corrections to Staff’s adjustments that were suggested by ETI, and the ALJs can find no basis for
challenging those corrections. Thus, the ALJs recommend that the Commission: (1) accept the
payroll adjustments proposed in the ETI application; and (2) accept the further payroll adjustments
proposed by Staff, corrected by ETI.

2. Incentive Compensation

One of the hotly contested issues concerns the extent to which ETI should be allowed to
recover, through its rates, the incentive compensation it pays to its employees. All parties agree that
Commission precedent generally identifies two types of incentive compensation, only one of which
is recoverable. Specifically, pursuant to Commission precedent, incentive compensation that is tied

567
Id. at 34.
568
Id. at MPC-R-5, and MPC-R-6.
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to operational goals is recoverable, while incentive compensation that is tied to financial goals is
not.569 In its application, however, ETI requests that it be allowed to recover its Test Year costs of
all of its incentive compensation costs, regardless of whether those costs are tied to operational goals
or to financial goals.

(a) Financially Based Incentive Compensation Should Not Be Recoverable

ETI acknowledges that costs of incentive compensation tied to financial goals have typically
been disallowed by the Commission. However, ETI asks for the Commission to reconsider its
precedents on this issue.570 ETI argues that the Commission precedent is not, and should not be, a
hard and fast rule. ETI contends that the reason why cost recovery has been denied for incentive
compensation in prior rates cases is that, in those prior cases, there was “a lack of evidence showing
sufficient customer benefits.”571 ETI asserts that, in this case, it has assembled evidence not
previously considered by the Commission that shows the benefits to customers of using financial
measures in incentive compensation programs. For example, ETI argues that incentive
compensation that encourages the financial health of a company also benefits customers because:

(1) if a company maintains a financially healthy position, it will tend to have a
lower cost of capital that will in turn benefit customers through lower rates;
(2) a financially healthy company will be more prepared for emergency events
such as storms (which is particularly important in the Gulf Coast areas served
by ETI, which are subject to experiencing hurricanes); and
(3) with financial health, the costs of doing business with suppliers (of both
goods and services, including labor) will remain lower because, for example,
if a company was not in a financially stable condition, suppliers would tend
to demand higher prices or more onerous credit terms, resulting in higher
costs that would lead to higher rates than would otherwise occur.

569
See, e.g.,TIEC Initial Brief at 51-52; see also AEP Application of AEP Texas Central Company for
Authority to Change Rates, See Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application
of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170
(Aug. 15, 2005).
570
Tr. at 1726.
571
ETI Initial Brief at 129.
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ETI witness Kevin Gardner, Vice President of Human Resources for ESI, testified that
customers receive benefits from those portions of the incentive compensation plans that are tied to
financial goals and measures. He explained that incentive compensation based on financial metrics
is a reasonable, necessary, and common component of compensation for companies like ETI. He
also opined that such incentives are a market necessity that ETI must include in its compensation
package so that it can hire and retain talented employees. He contended that customers benefit from
the incentives because they attract and keep qualified people.572 Mr. Gardner further testified that
disallowing financially-based incentives would only encourage utilities to eliminate them, thus
weakening the alignment of employees’ financial interests with the interest of the ratepayers in
having an efficiently run and financially healthy utility. He opined that having only operational
incentives could encourage utilities to overspend in some areas resulting in an incomplete,
unbalanced incentive program that would be atypical when compared with American industry in
general.573

A second ETI witness, Dr. Jay Hartzell, also testified in favor of the concept of allowing ETI
to recover its costs associated with its financially-based incentive compensation. He is a professor
of finance in the business school at the University of Texas at Austin. Dr. Hartzell acknowledged
the historical distinction that has been made by the Commission between compensation tied to
financial measures and compensation tied to operational measures. However, he argues that this
distinction is based upon a “false dichotomy” and that the more appropriate focus should be on
whether customers benefit from the incentive in question, regardless of whether it is a financial or
operational incentive.574 Dr. Hartzell summarized his key opinion as follows:

In my opinion, a well-designed compensation plan that includes incentive
compensation tied to cost controls, profitability, and stock prices would tend to
provide greater benefits to customers than an otherwise similar compensation plan
that did not include any such incentive compensation.575

572
ETI Ex. 36 (Gardner Direct) at 31.
573
Id. at 32.
574
ETI Ex. 15 (Hartzell Direct) at 3-4, 6, and 9-10.
575
Id. at 7.
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Dr. Hartzell argues that compensation linked to stock prices (provided it is part of a
reasonable, well-designed compensation plan) has four advantages for customers, :

x helps ensure that managers will consider the financial health of the company when they make
decisions, and it is in customers’ interests for the company be financially healthy;
x provides an incentive for managers and employees to ensure that the company operates
efficiently, resulting in lower rates than would otherwise occur;
x provides a monitoring mechanism for managerial decision-making and the overall quality of
management; and
x results in lower customer costs because capital markets will tend to reward efficient long-term
investments or capital expenditures.576

Dr. Hartzell cited a number of studies which support the theory that the benefits of incentive
compensation linked to stock price and profitability measures extend to customers of the company,
such as by lowering the company’s cost of capital, increasing the company’s ability to respond to
external shocks, improving customer satisfaction, and increasing oversight on managerial
decisions.577

Conversely, Dr. Hartzell opined that if the use of incentive compensation linked to
profitability and stock prices is discouraged, via Commission policy disallowing recovery of the
costs of such compensation, then utility customers would be adversely affected. For example, if
employees did not receive any incentive compensation, salaries would have to be higher to attract
and retain the same quality of talent. Dr. Hartzell also testified that a compensation plan solely
consisting of salary and incentives based on operational performance could likely lead to “horizon
problems,” meaning that, absent incentives to focus on the long run health of the company, managers
might maximize their immediate compensation at the expense of longer-run benefits that the
customer could have enjoyed.578

576
Id. at 13-14.
577
ETI Ex. 15 (Hartzell Direct) at 15-21.
578
Id. at 22-25.
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All of the other parties oppose ETI’s efforts to recover the costs of its incentive
compensation tied to financial goals. The parties uniformly agree that the Commission has a well-
established and straightforward policy regarding the recoverability of incentive compensation
through rates: incentive compensation that is tied to operational goals is recoverable; incentive
compensation tied to financial goals is not.579 They contend that ETI’s position in this case flies
directly in the face of that policy. TIEC points out that ETI has offered no legal authority, such as a
statute or rule, which would justify its desire to have the Commission reverse its policy and allow
the recovery of incentive compensation tied to financial goals. State Agencies similarly argue that
ETI failed to establish a reason why the Commission should deviate from its long-standing policy.
The parties also support the reasoning behind the Commission’s policy: that financially-based
incentives are of more immediate benefit to shareholders, not ratepayers, and therefore are not
necessary and reasonable for the provision of service.

State Agencies point out that, in support of his theory that financially-based incentives
provide benefits to ratepayers, Dr. Hartzell relied upon studies of utilities in competitive markets.
Thus, State Agencies contend, the studies are of little to no benefit in evaluating the effects of
financially-based incentives upon ETI customers because ETI is a monopoly that is not subject to
competitive pressures. Moreover, State Agencies examine at length the underlying studies relied
upon by Dr. Hartzell and assert, essentially, that the studies do not fully support the findings that
Dr. Hartzell ascribes to them.

Staff refutes ETI’s contention that the only reason why cost recovery has historically been
denied for financially-based incentive compensation is that there has been a lack of evidence
showing customer benefits. For example, Staff points out that, in one of the prior dockets cited by
ETI, the Commission disallowed recovery for financially-based incentive costs after stating,
“Incentive compensation based on financial measures or goals is of more immediate benefit to

579
TIEC Reply Brief at 35; State Agencies Initial Brief at 14; OPC Reply Brief at 12; Staff Initial Brief at 56;
Cities Initial Brief at 67; see also, Application of AEP Texas Central Company for Authority to Change
Rates, Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application of AEP Texas Central
Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005).
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shareholders.”580 This suggests that the question is not, as ETI contends, whether the incentives
provide any benefit to ratepayers. Rather, the question is whether the incentives are primarily
intended to provide benefits to shareholders.

Mark Garrett, an attorney and certified public accountant who works as a consultant in the
area of public utility regulation, testified on behalf of the Cities in opposition to cost recovery for
financially-based incentive compensation. He stated there are a number of reasons why it makes
sense to exclude financially based incentive costs from rates: (1) there is no certainty from year to
year what the level of incentive payments will be (because incentive payments are conditioned upon
future events and triggers that might not occur), thereby making it difficult to set rates and recover a
level of expense; (2) many of the types of factors that increase earnings per share—such as an
unusually hot summer or customer growth—are outside the control of employees and have no value
to customers; and (3) earnings-based incentives can discourage energy conservation.581 Mr. Garrett
also discussed the results of a survey of 24 other states, which revealed that 17 states closely follow
Texas’ approach, and none allow full recovery of incentive compensation.582

Mr. Garrett testified that ETI will not be placed at a competitive disadvantage in its ability to
obtain and retain qualified employees if its financially-based incentives are disallowed. He stated
that the Company’s total payroll costs for 2011 were 10 percent above the market price, and that
most of the above-market payroll costs derived from the incentive program.583

The ALJs conclude that ETI should not be entitled to recover its financially based incentive
compensation costs. Based upon prior Commission precedents, the ALJs conclude that the issue is
not, as ETI contends, whether such incentives might provide any benefits to customers. The proper
question to be asked is whether they provide benefits most immediately or predominantly to
shareholders. Without a doubt, the primary purpose of financially based incentives, such as

580
Staff Reply Brief at 44, quoting Application of Oncor Electric Delivery Company for Authority to Change
Rates, Docket No. 35717, Order on Rehearing at FoF 92 (Nov. 30, 2009).
581
Cities Ex. 2 (Garrett Direct) at 29-30
582
Id. at 32-38.
583
Id. at 45-46.
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incentives tied to earnings per share or stock price, is to benefit shareholders, not ratepayers. Even
construing Dr. Harzell’s testimony in the most generous light, any benefits that might accrue to
ratepayers would be merely tangential to that primary purpose.

Moreover, even if the ALJs were to completely accept as true the opinions offered by
Dr. Hartzell, it would be of limited benefit to ETI because his opinions were almost completely
theoretical. The premise of his testimony was that “a well-designed compensation plan” that
includes incentive compensation tied to financial goals would “tend to provide greater benefits to
customers” than a plan that did not include such compensation.584 He stressed that the customer
benefits of incentive compensation tied to financial goals can only exist if such compensation is part
of a larger, reasonable, and well-designed overall compensation plan.585 However, he did not
meaningfully apply this abstract theory to ETI’s compensation plan. For example, Dr. Harzell did
not offer an evaluation of ETI’s compensation plan and conclude that it is “well designed,” nor did
he testify that ETI’s incentives tied to financial goals actually provide benefits to its customers. He
admitted that he did not study the details of ETI’s incentive plans, nor did he do any type of analysis
to see if the costs of ETI’s incentive programs outweighed their benefits.586 He did not know the
amounts of incentive compensation that was paid by ETI.587 One of his major premises was that
financially-based incentives can benefit customers by lowering their costs, but he did not know how
ETI customer’s costs compared with customer costs in the other Entergy operating companies.588
Another of his major premises was that financially-based incentives can benefit customers by
ensuring the financial health of the Company, but he made no attempt to determine whether ETI
was, in fact, a financially healthy company.589 By confining his testimony to the abstract, it is
impossible to know whether Dr. Hartzell believes that ETI’s incentive compensation tied to financial
goals achieves the customer benefits that he believes such compensation can theoretically achieve.

584
ETI Ex. 15 (Hartzell Direct) at 7 (emphasis added).
585
See, e.g., ETI Ex. 15 (Hartzell Direct) at 13.
586
Tr. at 484.
587
Tr. at 478.
588
Tr. at 480.
589
Tr. at 481-82.
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It is true that Mr. Gardner described some of the specifics of ETI’s incentive plans. However,
because Dr. Hartzell did not explain the metrics of what he would consider “a well-designed
compensation plan,” it is impossible to know if ETI’s plan meets those metrics.

Simply put, the ALJs conclude that ETI has failed to establish a sufficient justification for
overturning the well-established Commission policy that financially based incentive compensation is
not recoverable.

(b) The Adjustment for Financially-Based Incentive Compensation Costs

Having concluded that ETI is not entitled to recover the costs of its financially based
incentive programs, it is necessary to determine the amount of those costs so that they may be
removed from consideration in this rate case. The parties disagree on the correct amount. Staff
argues that $5.3 million of ETI’s incentive compensation is financially based.590 TIEC contends the
correct number is $6.2 million.591 Cities contend it is $8.4 million.592

Broadly speaking, ETI has two categories of incentive compensation programs – annual
programs and long-term programs. ETI witness Gardner testified that 100 percent of ETI’s
long-term programs are financially based, whereas an average, representing a far lower percentage,
of the Company’s annual programs are financially based.593 Staff witness Givens applied those
percentages to determine her estimate of the amount spent by ETI in the Test Year on financially
based incentives. As to the Company’s long-term programs, she recommended removing the entire
costs of those programs (i.e. 100 percent) from the cost of service. As to the Company’s annual
programs, she recommended removing average percentage of the costs of those programs.
Ms. Givens then applied the FICA tax rate to the total amount she identified as financially based
costs to account for direct taxes that ETI would have paid as a result of those costs. By her estimate,

590
Staff Initial Brief at 56. (As discussed more below, Staff’s original estimate was roughly $5.6 million.
The estimate was reduced, however, in response to supplemental payroll tax information supplied to Staff by
ETI.)
591
TIEC Initial Brief at 53-54.
592
Cities Initial Brief at 70.
593
ETI Ex. 36 (Gardner Direct) at 30.
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the FICA taxes associated with ETI’s financially based incentives paid in the Test Year totaled
$429,096. In total, Ms. Givens recommended removing $5,609,093 (representing ETI’s financially
based incentives paid in the Test Year, plus FICA taxes associated with those payments) from ETI’s
requested O&M expenses. However, based upon subsequent additional information supplied by
ETI594 relative to the actual payroll taxes paid by the Company for its financially based incentive
compensation, Staff has agreed to lower its estimate of FICA taxes from $429,096 to $143,801.
Thus, Staff now recommends removing $5,323,798 (representing ETI’s financially based incentives
paid in the Test Year, plus FICA taxes associated with those payments) from ETI’s requested O&M
expenses.595

Like Ms. Givens for Staff, TIEC witness Pollock relied on the numbers and percentages
concerning ETI’s incentive programs that were provided by Mr. Gardner. However, Mr. Pollock
calculated those numbers and percentages in a slightly different manner, leading to a different
recommended reduction amount. Just as Ms. Givens did, as to the Company’s long-term programs,
he recommended removing the entire costs of those programs from the cost of service. ETI witness
Gardner testified that actual percentages of each annual program were quite different than the
average percentages for all programs used by Ms. Givens.596 Thus, as to the Company’s annual
programs, while Ms. Givens applied the average percentage reduction to all of the annual programs,
Mr. Pollock applied the actual percentage reductions applicable to each of the annual programs.
Based on Mr. Pollock’s calculations, TIEC recommends removing $6,196,037 (representing ETI’s
financially based incentives paid in the Test Year) from ETI’s requested O&M expenses.597 TIEC
appears not to have taken into account any payroll taxes associated with ETI’s financially based
incentives.

Cities witness Garrett took a substantially different approach when he calculated his estimate
of ETI’s financially based incentive costs. He agreed with Ms. Givens and Mr. Pollock that

594
ETI Ex. 46 (Considine Rebuttal).
595
Staff Ex. 1 (Givens Direct) at 15-22; Staff Initial Brief at 56-63.
596
ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
597
TIEC Ex. 1 (Pollock Direct) at 41-45 and JP-7; TIEC Initial Brief at 51-54.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 174
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100 percent of the Company’s long-term program costs should be removed from the cost of service.
As to the annual programs, however, Mr. Garrett defined what qualifies as “financially based” much
more broadly than ETI, Staff, and TIEC. ETI witness Gardner testified that, when the Company’s
five annual programs were averaged together, specific percentages of those programs were
financially based, aimed at “cost control,” and aimed at “cost control, operational, safety.” 598
Mr. Garrett added together the percentages representing the financially-based costs, the cost-control
costs, and roughly one-third of the cost-control, operational safety costs to arrive at the figure he
identified as the amount of ETI’s costs for its annual programs that is “related to financial
performance measures.”599 Cities contend this approach is supported by the decision in a prior
docket.600 Based on Mr. Garrett’s calculations, Cities recommend removing $8,397,232
(representing ETI’s incentives “related to financial performance measures” paid in the Test Year)
from ETI’s requested O&M expenses.601 Mr. Garrett also agreed with Ms. Givens that an additional
reduction should be made to account for the FICA taxes that ETI would have paid as a result of
those costs.602

The ALJs reject Cities’ attempt to broadly expand the definition of what qualifies as a
financially based incentive to include items such as cost control measures. Cities’ primary
justification for doing so is that the Commission has done so previously in the AEP Texas case. As
pointed out by ETI, however, the Commission did so in that case merely because AEP Texas lumped
its cost control measures in with its financially based incentive costs. The evidence in this case
demonstrates that ratepayers benefit when a utility incentivizes its employee to control costs. Even
TIEC witness Pollock testified that “incentives that encourage employees to minimize costs are
probably more or less in the best interest of ratepayers.”603 ETI further provided evidence

598
ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
599
Cities Ex. 2 (Garrett Direct) at 39-40, 46-50, MG2.10.
600
Cities Initial Brief at 68, Application of AEP Texas Central Company for Authority to Change Rages,
Docket No. 28840, Final Order (August 15, 2005).
601
Cities Ex. 1 (Garrett Direct) at 51-52 and MG2.10; Cities Initial Brief at 70.
602
Cities Ex. 1 (Garrett Direct) at 53.
603
Tr. at 1528.
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establishing that cost control incentives that result in lower costs for the Company likewise result in
lower rates for customers.604

As to the approaches advocated by TIEC and Staff, the ALJs conclude that TIEC’s approach
more accurately captures the true cost of ETI’s financially based incentive programs. Rather than
averaging across all of ETI’s annual programs (as was done by Staff), TIEC used the percentage
applicable to the single annual program that included a component of financially based costs. Thus,
the ALJs recommend removing $6,196,037 (representing ETI’s financially based incentives paid in
the Test Year) from ETI’s requested O&M expenses. Additionally, the ALJs agree with Staff and
Cities that an additional reduction should be made to account for the FICA taxes that ETI would
have paid as a result of those costs. That amount is not specifically known at this time.

3. Compensation and Benefits Levels

In the application, ETI included, as part of its labor costs, $54,965,005 in base payroll paid
by ETI and ESI in the Test Year. It also included $20,428,817 in costs associated with various
benefits (such as medical/dental, and life insurance) that ETI and ESI provided to their employees.605
Cities contend that the amounts for base pay and the benefits package should be reduced by
$989,370 and $2,860,034, respectively, because the amounts paid were above the market price.606
No other party challenges the reasonableness of the base payroll and benefits package.

As to base payroll, Cities contends that the amount paid by ETI and ESI was 1.8 percent
above the prevailing market price (above market).607 Cities witness Garrett acknowledges that ETI
and ESI are free to pay their employees at above market wages, but he contends that ratepayers
should only be asked to pay the market rate for wages, which he contends constitute the only
“necessary” costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 1.8 percent

604
ETI Ex. 50 (Gardner Rebuttal) at 6-7, ETI Initial Brief at 137-38.
605
Cities Ex. 2 (Garrett Direct) at 25, MG2.8, and MG2.9.
606
Id.
607
Id. at 25 and MG2.8.
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downward adjustment to base payroll expense (or $989,370) “to bring the company’s base payroll
down to a market-based level.”608

As to the Company’s benefits package, Cities points out that the amount paid by ETI and ESI
was 14 percent above market when compared to a peer group of Fortune 500 companies.609 Cities
witness Garrett again contends that ratepayers should only be asked to pay the market rate for
benefits, which he contends constitute the only “necessary” costs of providing utility service. Thus,
Mr. Garrett and Cities recommend a 14 percent downward adjustment to benefits expenses (or
$2,860,034).610

ETI concedes that its Test Year base pay was 1.8 percent “above the market median,” but
argues that this is not the same thing as being “above market.” As ETI witness Gardner explained,
“being ‘at market’ means being within a reasonable range, such as +/-10 percent, of the market
median; therefore, the Company’s base pay levels are at market.”611 According to Mr. Gardner,
some compensation consultants use an even broader range, such as a +/- 15 percent range, for
determining whether compensation levels are at market.612 Mr. Gardner testified that, because no
two jobs are likely to be identical, attempting to benchmark jobs to a “market price” is an inexact
science, involving inherent imprecision. Thus, Mr. Gardner testified that, when using a benchmark
analysis to compare companies’ levels of compensation, it is advisable to view the market level of
compensation as a range (e.g., +/- 10 percent of a mid-point) rather than a precise, single point.613

ETI also disputes Cities’ contention that the Test Year costs of the Company’s benefits
package were 14 percent “above market.” Mr. Gardner acknowledged that the costs were 14 percent
higher than those of Fortune 500 companies, but he pointed out the costs were only 1 percent above

608
Id. at 26-27 and MG2.8.
609
Id. at 58 and MG2.9; ETI Ex. 36 (Gardner Direct) at 41-42.
610
Cities Ex. 2 (Garrett Direct) at 58-59 and MG2.9.
611
ETI Ex. 50 (Gardner Rebuttal) at 11.
612
ETI Ex. 36 (Gardner Direct) at 23, and ETI Ex. 50 (Gardner Rebuttal) at 11 n. 1.
613
ETI Ex. 50 (Gardner Rebuttal) at 11-12.
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the market median of a peer group of utility companies.614 ETI contends that the comparison against
the peer group of utility companies provides a more appropriate comparison for ETI than Fortune
500 companies. ETI also points out that, even if equal weight were given to the comparisons against
the Fortune 500 companies and the peer utilities group, the value of the Company’s benefit plans
would average within a +/- 10 percent range and, therefore, be at market. Thus, ETI argues that its
benefit plan levels are within a reasonable range, and no disallowance should be required.615

The ALJs conclude that ETI has met its burden to prove the reasonableness of its base pay
and incentive package costs. The ALJs agree that it is reasonable to view market price for these
categories of costs as lying within a range of +/- 10 percent of median, rather than being a single
point along a spectrum. As to both base pay and the incentive package, ETI has proven that its costs
fall within such an acceptable range. Accordingly, the ALJs recommend rejecting the adjustments
sought by Cities.

4. Non-Qualified Executive Retirement Benefits

ETI provides three types of supplemental executive retirement plans: the Pension
Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan.616
In the application, ETI included, as part of its labor costs, $2,114,931 in costs associated with its
executive retirement plans. The expenses represent non-qualifying retirement plan expenses
designed to provide retirement benefits to key managerial employees and executives who are invited
to participate in the plans. They are generally available only to employees and executives earning
more than $245,000 per year.617

On behalf of the Staff, Ms. Givens recommended a complete disallowance of the costs for
these programs, on the grounds that they are offered to only select, highly compensated employees
and are excessive. Ms. Givens offered the opinion that the expenses were not reasonable and

614
ETI Ex. 36 (Gardner Direct) at 42.
615
ETI Ex. 50 (Gardner Rebuttal) at 13-14; ETI Initial Brief at 139-142.
616
ETI Ex. 50 (Gardner Rebuttal) at 14.
617
Staff Ex. 1 (Givens Direct) at 22-23; Cities Ex. 2 (Garrett Direct) at 54.
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necessary for the provision of electric utility service and were not in the public interest.618 On behalf
of Cities, Mr. Garrett agreed with Ms. Givens’ recommendation, arguing that it is fair to have
ratepayers pay for benefits included in regular pension plans, but that shareholders ought to pay for
any additional benefits included in supplemental plans, “since these costs are not necessary for the
provision of utility service, but are instead discretionary costs of the shareholders.”619 Mr. Garrett
also testified that costs associated with supplemental executive retirement plans are typically
excluded by utility commissions in Oklahoma, Oregon, Idaho, Arizona, and Nevada.620 On behalf of
OPC, Dr. Szerszen also recommended a complete disallowance of the portion of these costs
allocated from ESI to ETI.621 She stated that ETI has not shown that ratepayers benefit from the
expenses, the costs are not necessary to provide utility service, and that the ESI allocation method is
unjustified.622

ETI disagrees with all of these criticisms and maintains that the costs of the plans should be
recoverable. ETI witness Gardner testified that the supplemental executive retirement plans are
needed for attracting, retaining, and motivating highly competent and qualified leaders. He
explained that the Pension Equalization Plan provides supplemental retirement benefits to account
for the fact that Internal Revenue Code regulations limit the level of retirement benefits that qualify
for tax treatment favorable to ETI and Entergy. The existence of this supplemental benefit program
allows the Company to pay retirement benefits to highly-compensated employees that are
proportionate to the compensation they receive while active in their employment. The Supplemental
Retirement Plan and the System Executive Retirement Plan provide supplemental benefits beyond
the amounts restricted in the qualified plan to some participants to attract, retain, and motivate
employees.623 According to Mr. Gardner, these types of retirement benefits are widely provided by

618
Staff Ex. 1 (Givens Direct) at 23; Staff Initial Brief at 64.
619
Cities Ex. 2 (Garrett Direct) at 55; Cities Initial Brief at 71-72.
620
Cities Ex. 2 (Garrett Direct) at 56-57.
621
OPC Ex. 1 (Szerzen Direct) at 68. Dr. Szerzen quantifies the costs of the plans as $1,391,861 (a much
lower estimate than those of Ms. Givens and Mr. Garrett).
622
Id. at 68-69.
623
ETI Ex. 50 (Gardner Rebuttal) at 15-16.
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companies within the utility business sector.624 Accordingly, ETI argues that it needs to offer them
in order to be competitive in the employment market with peer companies, and thereby to retain and
adequately compensate these employees in terms of future retirement benefits.

The ALJs conclude that the supplemental executive retirement plans are not reasonable and
necessary for the provision of electric utility service and are not in the public interest. They are
non-qualifying retirement plan available only to employees and executives earning more than
$245,000 per year, and they constitute benefits over and above the Company’s standard retirement
benefits package. Because these costs are not necessary for the provision of utility service, but are
instead discretionary costs, they should be paid by the shareholders. Accordingly, the ALJs
recommend an adjustment to remove $2,114,931, representing the full costs associated with ETI’s
non-qualified executive retirement benefits.

5. Employee Relocation Costs

In the application, ETI included, as part of its labor costs, $436,723 in employee relocation
costs.625 ETI contends that, in order to be competitive in the employment market, it must provide
relocation assistance to certain of its employees. ETI witness Gardner testified that ETI’s relocation
policies and costs are reasonable and consistent with general industry practice. He also testified that
the Company’s average relocation costs are in line with the relocation costs for the companies
surveyed by the Employee Relocation Council.626

Staff recommends an adjustment to remove the entire $436,723 of ETI’s relocation
expenses.627 No other party challenged the legitimacy of relocation expenses. Staff points out that
ETI pays 110 percent of the market median for total annual compensation.628 Staff contends that the
fact that ETI pays more than the average market wage demonstrates that employees should be

624
Id. at 16.
625
Staff Ex. 1 (Givens Direct) at 25.
626
ETI Ex. 36 (Gardner Direct) at 45-46.
627
Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.
628
Staff Ex. 1 (Givens Direct) at 24 (citing ETI Ex. 36 (Gardner Direct) at 26).
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sufficiently enticed to join and move around within its organization without the need for ETI to pay
relocation expenses to attract employees. Therefore, Staff argues that the relocation expenses do not
meet the reasonable and necessary standard required for inclusion in cost of service, nor are the
expenses in the public interest.629 Staff also points out that similar types of payments were removed
from cost of service in recent proceedings, such as in Docket No. 28906, where payments for
moving expenses or signing bonuses were removed from cost of service.630

ETI responds by pointing out that Staff does not challenge the reasonableness of the amount
spent on relocations by ETI. It also contends that most of its peers offer moving assistance. Thus, it
would be competitively disadvantaged if it did not offer it as well. ETI reiterates that its relocation
costs are reasonable and necessary and should be authorized.631

The ALJs conclude that ETI has the better argument. There is no allegation that ETI was too
lavish in its relocation expenditures. The only complaint offered by Staff is that ETI’s overall
compensation costs are 110 percent of the market median. It does not necessarily follow that the
relocation program is unnecessary. ETI provided substantial evidence that, without a relocation
program, it would be at a competitive disadvantage with its peers. Accordingly, the ALJs reject
Staff’s request to disallow the Company’s relocation expenses.

6. Executive Perquisites

In the application, ETI included, as part of its labor costs, $40,620 in costs associated with its
executive perquisites. Those perquisites consist of financial counseling and tax gross-ups for system
officers and executives. Specifically, the financial counseling program promotes maximizing
investment growth opportunities for eligible officers and executives, and allows reimbursement for
certain expenses incurred for personal financial counseling services.632 Staff recommends an

629
Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.
630
Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24, citing Application of LCRA Transmission
Services Corporation to Change Rates, Docket No. 28906, Final Order (Apr. 5, 2005).
631
ETI Initial Brief at 143.
632
Staff Ex. 1 (Givens Direct) at 23.
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adjustment to remove the full cost of the executive perquisites ($40,620), reasoning that the costs are
not reasonable and necessary for the provision of electric utility service.633 ETI does not oppose that
adjustment.634 The ALJs agree that the adjustment is warranted. Therefore, the ALJs recommend an
adjustment to remove $40,620, representing the full cost of ETI’s executive perquisite costs.

E. Interest on Customer Deposits

Staff witness Givens adjusted ETI’s requested interest expense of $68,985 by removing
$(25,938) from FERC account 431.635 This decrease is a result of applying the interest rate of
0.12 percent for calendar year 2012 on deposits held by utilities.636 Using the active customer
deposits amount of $35,872,476 and the 2012 interest rate, Ms. Givens calculated a recommended
interest expense of $43,047 ($35,872,476 multiplied by .12 percent).637

This change, which reflects Commission-approved interest rates for 2012 as set in December
2011, complies with Project No. 39008 and ETI agreed with this amount. Accordingly, the ALJs
recommend that the Commission approve this amount.

F. Property (Ad Valorem) Tax Expense

During the Test Year, ETI’s property tax expense equaled $23,708,829.638 Patricia
Galbraith, ETI’s Tax Officer, testified that a pro forma adjustment should be made to this level of
expense for a known and measurable change that reflects the level of property tax expense ETI will
experience in the Rate Year. Specifically, her proposed adjustment would increase the Test Year
level of expense by $2,592,420 to $26,301,249.639 As Ms. Galbraith testified, ETI’s property tax
expense for the calendar year 2012 will be paid in January of 2013 and be based on 2011 calendar

633
Staff Initial Brief at 65; Staff Ex. 1 (Givens Direct) at 23.
634
ETI Initial Brief at 144.
635
Staff Ex. 1 (Givens Direct) at 24.
636
Setting Interest Rates for Calendar Year 2012, Project No. 39008, Order (Dec. 8, 2011).
637
Staff Ex. 1 (Givens Direct) at 24-25.
638
ETI Ex. 26 (Galbraith Direct) at 5; ETI Ex. 3 at Sched. G-9.
639
ETI Ex. 26 (Galbraith Direct) at 5 and PAG-1; ETI Ex. 3 at Sched. G-9.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 182
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year-end values for both net operating income and net plant amounts.640 Her proposed adjustment is
based on an expected ad valorem rate increase of 1 percent and expected increases in both net plant
values and ETI net operating income that will equal 9.81 percent.641

TIEC, Cities, and Staff oppose the property tax adjustment proposed by ETI. TIEC argues
that ETI’s proposed adjustment should be rejected entirely, on the grounds that it is not a known and
measurable change from ETI’s Test Year property tax costs. Ms. Galbraith admitted that she does
not know, with certainty, what the relevant property tax rate will be in 2012, nor has ETI received
any tax bills advising that tax rates will rise.642 Thus, TIEC witness Pollock testified that ETI’s
proposed adjustment is not known and measurable and recommended that the Commission reject the
adjustment and include only the Test Year level of expense in cost of service.643 TIEC further points
out that the Commission has twice rejected requests to include projected property tax expense in
rates.644 For example, in Docket No. 28813, Cap Rock prepared an independent analysis indicating
that property taxes were expected to increase to $2,700,000 per year from its test year tax level of
approximately $900,000 per year. The analysis used an estimated tax assessment of $110,000 with
an estimated tax rate of $2.47 per $100 of value. The ALJs in that case concluded that the property
tax increases were estimates at the time of the hearing, and thus they were not known and
measurable and should not be allowed.645 Subsequently, the Commission adopted the ALJs’

640
Tr. at 1235.
641
ETI Ex. 26 (Galbraith Direct) at PAG-1.
642
Tr. at 1221, 1238.
643
TIEC Ex. 1 (Pollock Direct) at 40–41.
644
In re Cap Rock Corp., Petition of PUC (Staff) to Inquire into the Reasonableness of the Rates and Services
of Cap Rock Energy Corporation, Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005) (“Cap
Rock failed to prove any increase in property taxes above those in the test year-$899,597-was known and
measurable.”); Application of Gulf States Utilities Company for Authority to Change Rates, Application of
Sam Rayburn G&T Electric Coop., Inc. for Sale Transfer or Merger, Appeal of Gulf States Utilities Company
from Rate Proceedings of Various Municipalities, Docket Nos. 8702, 8922, 8939, 8940, 8946, 8233, 8944,
8945, 8947, 8948 and 8949, Order at FoF 111 (May 2, 1991) (“The 1988 calendar year level of actual
property taxes paid should be used in determining rate year taxes because it is a known and measurable
change.”).
645
Docket No. 28813, PFD at 99 (Mar. 17, 2005).
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finding.646 The Commission rejected a similar request from ETI’s predecessor Gulf States Utilities
(GSU).647 In consolidated Docket No. 8702, the Commission rejected GSU’s request for projected
1989 property taxes and instead only allowed the actual calendar year property tax expenses.648 In
both cases the Commission found that projected tax expense is not a known and measurable
change.649 Accordingly, TIEC contends that ETI’s request for a forecasted tax expense increase
should be rejected.650

Staff concedes that some level of increase is warranted but argues that the increase should be
smaller than ETI is asking for. Rather than an increase of $2,592,420, Staff contends that ETI’s Test
Year property tax expenses should be adjusted upward by only $1,214,688.651 Staff witness Givens
arrived at this increase by applying the effective tax rate for the calendar year 2011 to the Staff’s
Test Year end plant in service recommendation. She testified that both of these inputs to her
calculation are known and measurable and thus may be used to determine the increase.652

Cities also concede that some level of increase is warranted, but argue that the increase
should be smaller than ETI is asking for, and smaller than Staff proposes. Cities contend that ETI’s
Test Year property tax expenses should be adjusted upward by only 1,134,442.653 Cities witness
Garrett offered the opinion that ETI’s proposed adjustment was based on estimates that were
unreasonably high when compared to the actual tax valuation increases experienced since 2008. Mr.
Garrett arrived at his projected increase in tax expense by applying the average annual valuation
increase experienced over the period of 2009-11 to net plant value for 2011. Cities argue that both

646
Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005).
647
Docket No. 8702, Order at FoF 111 (May 2, 1991).
648
Docket No. 8702, Order at 52.
649
Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005); Docket No. 8702, Order at 52, FoF
111 (May 2, 1991).
650
TIEC Initial Brief at 54-56.
651
Staff Ex. 1 (Givens Direct) at 25.
652
Id. at 25-26.
653
Cities Ex. 2 (Garrett Direct) at 61.
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of these inputs to the calculation are known and measurable and thus may be used to determine the
increase.654

ETI responds to its opponents by pointing out that the Commission has, in the past,
recognized that the adjustment proposed by Staff, which was obtained by applying a historical
effective tax rate to the level of test year end plant in service, is known, measurable, and
appropriate.655 ETI also notes that, although it had not done so at the time Ms. Galbraith filed her
testimony, ETI has since filed its 2011 year end FERC Form 1 data and now knows both the final net
income amounts and net plant values for year end 2011 that will be used to determine the
Company’s 2012 tax expense (that will be paid in January of 2013).656 ETI contends that those
known values are substantially larger than the estimates used by Ms. Galbraith when she calculated
the proposed adjustment, such that the known increases in 2011 net operating income and net plant
amounts over 2010 are so large that, even without the 1 percent increase in tax rate assumed in the
property tax adjustment, Rate Year property tax expenses will be larger than the $26,301,249
amount requested by the Company.657

The issue with regard to property taxes is whether a level of increase is known and
measurable. The ALJs conclude that the approach taken by Staff does the best job of generating a
known and measurable value for ETI’s property tax burden in the Rate Year. As explained above,
Staff’s approach is supported by prior Commission precedent. Moreover, unlike the approaches
advocated by ETI and Cities, Staff’s approach requires no guesswork about future tax rates.
Accordingly, the ALJs recommend that ETI’s property tax burden should be adjusted upward by

654
Id.
655
ETI Initial Brief at 145; see also, Application of AEP Texas Central Company for Authority to Change
Rates, Docket No. 28840, Final Order at FOF 189-191 (Aug. 15, 2005); Petition of General Counsel to
Inquire Into the Reasonableness of the Rates and Services of Central Telephone Company of Texas, Docket
No. 9981, 19 Tex. P.U.C. BULL. 936, 1080-82, 1217 (Sept. 8, 1993); Application of Central Power and Light
Company for Rate Changes and Inquiry Into the Company’s Prudence with Respect to South Texas Project
Unit 2, Docket No. 9561, 17 Tex. P.U.C. BULL. 157, 231-232 (Dec. 19, 1990).
656
Tr. at 1236-37.
657
ETI Initial Brief at 146-47.
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applying the effective tax rate for the calendar year 2011 to the final, adopted Test Year-end plant in
service value for ETI.

G. Advertising, Dues, and Contributions

In the application, ETI included, as part of its operating expenses, $2,046,214 in costs
associated with advertising, dues, and contributions.658 Staff recommended an adjustment to remove
$12,800, representing contributions to organizations primarily focused on influencing legislative
activities. Staff reasons that these costs are not reasonable and necessary for the provision of electric
utility service.659 ETI makes no response to the suggested adjustment.660 The ALJs agree that the
adjustment is warranted. Therefore, the ALJs recommend an adjustment to remove $12,800 from
ETI’s costs of advertising, dues and contributions.

H. Other Revenue-Related Adjustments

Several items within the Company’s revenue requirement are interrelated. This means that
changes to one area or item will impact one or more additional items, such as the Texas state gross
receipts tax, the PUC Assessment tax, and Uncollectible Expenses.661 From the discussions in
briefs, it does not appear that there are any substantive differences among the parties regarding these
amounts, which will ultimately be determined during number running.

I. Federal Income Tax

As explained by ETI witness Rory Roberts, the Company calculated its income tax expense
in the cost of service by taking into account only the revenues and expenses included in the cost of
service.662 To the extent the Commission makes changes to the revenues and expenses that are
ultimately included in the cost of service, the income tax expense amount included in the cost of

658
ETI Ex. 3, Sched. G-4.
659
Staff Initial Brief at 66; Staff Ex. 1 (Givens Direct) at 26.
660
ETI Initial Brief at 147.
661
Staff Ex. 1 (Givens Direct) at 28-29.
662
ETI Ex. 21 (Roberts Direct) at 10; Ex. 3 Sched. G-7.
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service will change accordingly. This represents a proper matching of income tax effects to the
expenses and revenues that produced those tax effects.663

Mr. Roberts contended that the Commission’s past practice of reducing tax expense for a
consolidated tax adjustment based on some measure of the tax “savings” the utility realized by
joining in a consolidated group federal income tax return was inappropriate. He testified that it is
improper to reduce tax expense for deductions or losses that are not also included in the cost of
service. In the case of the Commission’s consolidated tax adjustment, tax expense is reduced to the
extent that utility income is used to offset non-utility affiliate losses, even though those losses are
not included in cost of service or borne in any manner by the utility’s customers.664

Despite his disagreement with the approach, Mr. Roberts performed a calculation of the
adjustment using the interest credit methodology adopted by the Commission. He concluded that,
instead of positive taxable income, ETI had net tax losses over the 15-year calculation period and
thus provided no taxable income that could be used to offset affiliate losses.665 In fact, over the
15-year period, ETI’s tax losses were offset by taxable income produced by other affiliates. Thus,
ETI contends that, were the Commission to be consistent in applying its interest credit methodology,
it should increase ETI tax expense included in cost of service due to the fact that its affiliates’
taxable income had to be used to offset ETI’s tax losses. Nevertheless, in its application, ETI
rejected the interest credit methodology and has not requested that ETI’s tax expense be increased as
a result of the consolidated tax adjustment calculation. No other party to the proceeding challenged
the Company’s position on federal income tax expense in testimony or at the hearing. The ALJs find
no reason to do so either.

J. River Bend Decommissioning Expense

ETI has an ownership interest in River Bend. In the application, ETI requested that
$2,019,000 be included in its cost of service to account for the Company’s annual decommissioning

663
ETI Ex. 21 (Roberts Direct) at 10.
664
Id. at 10-11.
665
Id. at 10, and RLR-5.
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expenses associated with River Bend.666 This is the same amount that was requested and approved
on December 13, 2010, in Docket No. 37744.667 The amount of $2,019,000 was derived from an
ETI decommissioning study that was completed in 2009. In this case, ETI chose not to propose any
change to its 2009 estimate. ETI contends that this decision is supported by an August 9, 2011,
letter from the Nuclear Regulatory Commission.668

Cities argue that the decommissioning expense should be reduced to $1,126,000.669 Cities
point out that the larger amount sought by ETI was merely the amount agreed to by the parties, as
opposed to being substantively considered and approved by the Commission in Docket
No. 37744.670 In the current case, ETI was asked through discovery to provide an updated estimate
of the annual decommissioning expense responsibility for Texas retail customers calculated using
the most current Texas jurisdictional decommissioning fund balance. ETI responded that the current
annual decommissioning revenue requirement is $1,126,000.671

Under P.U.C. SUBST. R. 25.231(b)(1)(F)(i), the annual cost of decommissioning for
ratemaking purposes must “be determined in each rate case based on . . . the most current
information reasonably available regarding the cost of decommissioning, the balance of funds in the
decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the
decommissioning trust, and other relevant factors.” The cost determined must then be expressly
included in the cost of service established by the Commission’s order.

The parties agree that $1,126,000 is the best estimate of the current annual revenue
requirement to meet ETI’s estimated decommissioning cost. However, ETI relies on P.U.C. SUBST.
R. 25.231(b)(1)(F)(iv) and Staff witness Cutter’s testimony to contend that it need not adjust the

666
ETI Ex. 3 Scheds. M-1 and M-2; ETI Ex. 8 (Considine Direct) at 57-58.
667
ETI Ex. 8 (Considine Direct) at 58.
668
Id. at 58 and MPC-2.
669
Cities Ex. 2 (Garrett Direct) at 64-65.
670
Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Final Order at
FoF 32 (Dec. 13, 2010); Cities Initial Brief at 73.
671
Tr. at 348-49.
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current amount being charged.672 Pursuant to subpart (iv), ETI is required to periodically study its
decommissioning costs, and such a study must be done “at least every five years.” Because its last
study was done in 2009, ETI contends that it need not do a new study now, but may simply rely of
the outcome of its last study, which showed that its annual revenue requirement is $2,019,000.673

Cities agree that ETI is not required to conduct a new decommissioning study at this time.
However, the most current information reasonably available clearly shows that the annual amount
required to meet the total cost determined in the Company’s last decommissioning study has
decreased. Cities argue that to ignore the most current information available disposal would
unreasonably shift future costs to current customers and would be a violation of P.U.C. SUBST.
R. 25.231(b)(1)(F)(i). The ALJs agree. ETI’s annual decommissioning revenue requirement should
reflect the most current calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro
forma cost of service is needed to reflect the difference between the requested level for
decommissioning costs of $2,019,000 and recommended level of $1,126,000.

K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5]

In prior dockets, the Commission authorized ETI to recover $3,650,000 annually for storm
damage expenses and to maintain a reasonable and necessary storm damage reserve account of
$15,572,000.674 ETI requests to increase the authorized storm damage reserve account to
$17,595,000 (an increase of $2,023,000) and to increase the annual accrual to $8,760,000 (an
increase of $5,110,000). ETI’s proposed annual accrual is composed of two elements: (1) an annual
accrual of $4,890,000 to provide for average annual expected losses from all storms that do not
exceed $100 million; and (2) a 20-year annual accrual of $3,870,000 to bring the reserve up from its
current deficit of $59,799,744 to ETI’s target reserve of $17,595,000.

No party disputes that ETI’s proposal to self-insure for catastrophic property loss is
appropriate under PURA § 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G). However, Cities, OPC,

672
ETI Ex. 46 (Considine Rebuttal) at 38-39.
673
Id.
674
Staff Ex. 4 (Roelse Direct) at 8.
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and Staff oppose the amount of ETI’s proposed annual accrual, and Cities and OPC also oppose
ETI’s proposed target reserve. The parties’ recommendations are:

Annual Accrual Target Reserve
Current $3,650,000 $15,572,000
ETI $8,760,000 $17,595,000
Cities $6,150,339 $15,572,000
OPC-1 $2,335,047 $15,572,000
OPC-2 $3,650,000 $15,572,000
Staff $8,270,000 $17,595,000

The first component of ETI’s requested annual accrual is $4,890,000 for expected annual
losses. ETI explains that this is the amount of annual losses projected to be incurred by ETI from all
storm damage, except those over $100 million (the minimum amount likely to be securitized),675
adjusted to reflect current conditions and current cost levels.676 This recommended accrual was
calculated by ETI witness Gregory Wilson using a Monte Carlo simulation of ETI’s loss history.677
A statistical distribution was estimated from ETI’s trended loss experience, and the model indicated
an average annual loss of $4,890,000. Mr. Wilson excluded losses from Hurricanes Rita, Gustav,
and Ike from the model because those losses were securitized and not recovered through the
insurance reserve.678 ETI adds that results from the model simulation were also adjusted by
removing any simulated year in which the total storm loss exceeded $100 million, which would
likely be securitized.

The second component of the proposed annual accrual is $3,870,000 per year for 20 years to
restore the reserve from the current deficit of $59,799,744 up to the $17,595,000 requested target
level. In ETI’s opinion, a 20-year period balances the interests of future and past ratepayers. It

675
ETI Ex. 19 (McNeal Direct) at 32.
676
ETI Ex. 14 (Wilson Direct) at 5.
677
Id. at Ex. GSW-3.
678
Id. at 9.
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added that Mr. Wilson’s calculations were prepared in accordance with generally accepted actuarial
procedures, with certain adjustments to reflect the nature of ratemaking for public utilities.679

ETI also requests a target reserve of $17,595,000. It argues that this would be an actuarially
sound provision to cover self-insured losses. ETI noted that the target reserve was also developed
by Mr. Wilson through the Monte Carlo simulation based upon the ETI’s loss history.680

Cities recommend maintaining the current target reserve of $15,572,000 and adopting an
annual storm damage accrual of $6,150,399. Cities’ proposed annual accrual is comprised of two
parts: (1) keeping the current accrual of $3,650,000 for projected annual storm expense; and
(2) adding $2,500,399 annually to bring ETI’s reserve deficit amount, as adjusted by Cities, up to a
target reserve of $15,572,000. Cities’ witness Jacob Pous testified that the current target reserve of
$15,572,000 should be maintained given ETI’s plan to divest itself of the transmission system,
which would reduce storm damage expenses.681 For the same reason, Mr. Pous also stated that the
Commission should maintain the current annual accrual amount that was approved most recently in
Docket No. 37744.682

According to Cities, ETI witness Wilson acknowledged that his calculations assumed that the
current transmission system would be owned by ETI, and if the transmission system were sold, his
analysis would need to be adjusted.683 Cities also note that Mr. Wilson included ETI’s 1997 ice
storm expenses within the historical storm data used for his calculations.684 As discussed in
Section V.F., Cities challenge these expenses. If the Commission determines that those costs should
be excluded, Mr. Wilson agreed that it would be inappropriate to include them in his analysis.685 In
addition, Cities stated, Mr. Wilson’s Monte Carlo model analysis has been rejected in several cases

679
ETI Ex. 14 (Wilson Direct) at 11-12.
680
Id. at 9.
681
Cities Ex. 5 (Pous Direct) at 65-66.
682
Id. at 66; see also Docket No. 37744, Final Order at FoF 31 (Dec. 13, 2010).
683
Tr. at 1247.
684
Tr. at 1244-1246.
685
Tr. at 1246-1247.
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by the Commission, as noted by Staff witness Chris Roelse.686 Cities noted that Mr. Wilson limited
the storm reserve expense in his model to $100 million, as anything over that amount might be
securitized.687 But, Cities contend, Mr. Wilson did not consider that the storm loss history provided
to him by ETI included only storm damage expenses and not capital costs, which are also included
when determining the amount capable of being securitized. Thus, in Cities opinion, Mr. Wilson’s
cap of $100 million was overstated, and for all these reasons Cities argues that Mr. Wilson’s analysis
should not be considered reliable.

Finally, Cities note that ETI requested that the annual storm reserve accrual “would be made
. . . only until it reaches the recommended target level, at which point contributions to the reserve
would reduce to the lower of annual expected losses or actual losses.”688 In Cities view, this request
should be rejected and the accrual should only be modified through a future rate case.

OPC also recommends adjustments to the storm damage reserve and the annual accrual. As
discussed in Section V.F., OPC argues that ETI failed to prove that its storm damage expenses
booked since 1996 were reasonable and prudently incurred. Consequently, OPC recommends
disallowing all of those charges. Removing those charges would leave ETI with a positive storm
reserve balance of $41,871,059, which exceeds the currently approved storm reserve balance of
$15,572,000 by $26,299,059. OPC witness Benedict proposed that this surplus be refunded to rate
payers at a rate of $1,314,953 per year for 20 years. He also recommended that current annual storm
damage accrual of $3,650,000 be maintained, less his proposed customer refund of $1,134,953 per
year, leaving a net annual storm damage accrual of $2,335,047 per year. Mr. Benedict
acknowledged that some storm damage expenses incurred by ETI since 1996 likely were reasonable
and necessary. Therefore, as an alternative proposal, Mr. Benedict suggested that ETI’s current
storm balance reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or
deficit) and that the currently approved total annual accrual of $3,650,000 be maintained. In

686
Staff Ex. 4 (Roelse Direct) at 12.
687
ETI Ex. 14 (Wilson Direct) at 9.
688
ETI Initial Brief at 151.
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addition, OPC argues that Mr. Wilson’s Monte Carlo model analysis was flawed because it included
expenses that ETI did not establish were reasonable and prudently incurred.689

Staff witness Chris Roelse agreed that ETI’s proposed target reserve of $17,595,000 is
reasonable. However, he recommended an annual accrual of $8,270,000, which is $490,000 less
than ETI’s request. Mr. Roelse pointed out that ETI’s witness calculated the proposed annual
accrual based on a Monte Carlo simulation, which projects a loss experience over a longer time than
the period captured in the available loss history. However, Mr. Roelse stated, the Commission has
not approved the use of these models in prior dockets; instead, it has relied on averaging known
insurance losses over a period of time to compute the annual accrual. Using historical loss data,
Mr. Roelse calculated an annual expected storm loss of approximately $4,400,000. When this
amount is added to the proposed annual accrual of $3,870,000 to restore the reserve balance from its
current deficit, it produces a total annual accrual of $8,270,000, which Staff recommends.690

In response, ETI agreed that if portions of the underlying costs upon which the Monte Carlo
analysis was performed are removed from the reserve, then the outcome of Mr. Wilson’s analysis
would be different. However, ETI stressed that questions about the underlying expenses are not an
attack on the Monte Carlo analysis itself. Rather, Mr. Wilson provided an analysis based upon
information supplied by ETI, and he did not claim to support the expenses themselves. But ETI
disagreed with the challenges to the underlying costs, as discussed in Section V.F.691

Most of Cities’ and OPC’s objections to ETI’s requested storm damage annual accrual and
target reserve relate to their objections to the underlying expenses, as discussed in Section V.F. For
the reasons stated in that section, the ALJs denied those objections, and they do not support rejecting
ETI’s request for the annual accrual or target reserve. Likewise, the ALJs find that Cities’ concerns
about ETI selling its transmission system are too uncertain to justify altering the storm damage
reserve at this time.

689
OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 14-20; OPC Reply Brief at 13-15.
690
Staff Ex. 4 (Roelse Direct) at 10-15; Staff Initial Brief at 13-14.
691
ETI Reply Brief at 81.
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Cities also raised a question about whether Mr. Wilson properly calculated the cap he used to
exclude from his analysis storms that would likely result in securitized costs. Staff pointed out that
the Commission has not approved the use of the Monte Carlo simulation model in prior dockets.
Rather, the Commission has traditionally used known insurance losses over a period of time. The
ALJs note that neither PURA nor the Commission’s rules either require or prohibit the use of
actuarial models, such as the Monte Carlo simulation. The prior dockets cited by Staff did not adopt
the recommendations developed by actuarial models, but the Commission also did not expressly
reject the models in those cases. Likewise, however, ETI has not cited any Commission decisions
that expressly adopted or used such models.

Staff witness Chris Roelse explained that the Commission has traditionally averaged known
insurance losses over a period of time to compute the annual accrual. He made such a calculation
that produced an annual accrual for storm damage loss of $4,400,000. When added to the proposed
annual accrual of $3,870,000 to restore the reserve balance from its current deficit, the total annual
accrual equals $8,270,000. No party challenged that calculation. Because a question remains as to
whether Mr. Wilson properly calculated his cap to exclude storm damage expenses that would likely
be securitized, the ALJs find it is more reasonable to adopt the annual accrual proposed by Staff.
Therefore, the ALJs recommend that the Commission approve a total annual accrual of $8,270,000,
comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses,
plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The
ALJs also recommend approval of ETI’s proposed target reserve of $17,595,000. Finally, the ALJs
recommend that the Commission require ETI to continue recording its annual accrual until modified
by an order in a future rate case, as requested by Cities. Otherwise, ETI could continue to receive
rates based on the total accrual amount, but not record the receipts in the storm damage reserve. The
ALJs find that such circumstances would not result in just and reasonable rates.

L. Spindletop Gas Storage Facility

Cities challenged ETI’s use of the Spindletop Facility, arguing that the costs of operating it
outweigh the benefits gained from it. In Section V.H., the ALJs rejected Cities’ contention that a
substantial portion of ETI’s annual costs to operate the Spindletop Facility should be removed from
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ETI’s rate base. For the same reason he challenged the Spindletop Facility costs associated with rate
base, Cities witness Nalepa also challenges a portion of ETI’s costs derived from the Spindletop
Facility that are associated with operating expenses. Specifically, Mr. Nalepa and Cities argue that
$2,090,116 (consisting of $309,751 in depreciation expense and $1,780,365 associated with the
Spindletop Facility) ought to be removed from ETI’s operating expenses.692 For the same reason
that they rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject
Cities’ Spindletop Facility arguments relevant to operating expenses.

VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3]

PURA requires that more stringent standards be applied to affiliate expenses than are applied
to other utility company expenses. Section 36.058 begins by stating “except as provided by
Subsection (b),” the PUC may not allow as capital cost or as expense a payment to an affiliate for
the cost of a service, property, right, or other item or interest expense. Subsection 36.058(b)
provides that the Commission may allow an affiliate payment “only to the extent” that the PUC finds
the payment is reasonable and necessary for each item or class of item as determined by the
Commission.

The seminal case interpreting PURA’s affiliate transaction standard under Section 36.058 is
Railroad Commission v. Rio Grande Valley Gas Company.693 In that case, the court recognized that
PURA’s affiliate transaction statute created a presumption that a payment to an affiliate is
unreasonable. The court explained:

Rio’s entire approach has been that the Commission is required to allow the residual
affiliate charges unless they are shown to be imprudent, unreasonable, or out of line.
Although this may be true with respect to arms length transactions, it is not true with
respect to affiliates about which the Legislature has its suspicion and which to any
reasonable mind are clearly tainted with the possibility of self-dealing.

692
Cities Ex. 6 (Nalepa Direct) at 19; Cities Initial Brief at 76.
693
683 S.W. 2d 783 (Tex. App.—Austin 1985, no writ).
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The court went on to state that the burden was upon Rio to show that its affiliate charges
were just and reasonable. The court interpreted the PURA affiliate transaction statute and explained
four major areas in which Rio had failed to meet its burden of proof:

x Plaintiff had the burden of showing that the prices it was charged by its affiliate were no higher
than the prices charged by the supplying affiliate to its other affiliates. . . .

x Plaintiff had the burden of showing that expenses which may not be allowed for rate making
purposes for any reason . . . were not included in the “allocated expenses.” . . .

x Plaintiff had the burden of proving that each item of allocated expense was reasonable and
necessary. . . .

x Plaintiff had the burden of proving that the allocated amounts reasonably approximated the
actual cost of services to it. . . .

In 2000, the Third Court of Appeals once again spoke on the issue of affiliate transactions in
the utility setting. In Central Power and Light Company/Cities of Alice v. Public Utility
Commission, the court cited to Rio Grande Valley Gas Company and stated:

Because of the possibility for self-dealing between affiliated companies, however,
expenses paid to an affiliated entity are presumptively not included in the rate base.
A utility can overcome this presumption against affiliate expenses only if it
demonstrates that its payments are ‘reasonable and necessary for each item or class
of items as determined by the commission.’694

PURA Section 36.058 places a greater burden of proof on the utility to prove the reasonableness and
necessity of its affiliate transactions because of the nature of the relationship between the utility and
its affiliates. These transactions are not considered to be arms-length, and there is a potential for
self-dealing. The transactions must be disallowed for regulatory purposes, unless the utility presents
sufficient evidence that it has met each of the affiliate transaction statutory requirements. If the
regulatory tests for affiliate transactions are not properly enforced, the regulated utility may become
a vehicle for cross-subsidization by ratepayers of other regulated or unregulated affiliates.

694
36 S.W.3d 547 at 564 (Tex. App.—Austin 2000, pet. denied) (citations omitted).
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OPC witness Szerszen was the only witness to challenge ETI’s affiliate transactions,695
recommending a total affiliate disallowance (after erratas) of $8,945,221.696 Dr. Szerszen reviewed
a select subset of ETI’s affiliate expenses using the PURA affiliate transaction standards. She
reviewed the Company’s affiliate transactions on a project by project basis, noting that such a review
was more efficient and easier to understand.697 Dr. Szerszen testified that a review by the
Company’s 25 classes of service presents a far too macro view of affiliate transactions that does not
allow an adequate review of ETI’s affiliate transactions according to PURA mandates and takes the
focus away from the important issues.698

OPC notes that PURA Subsection 36.058(f) requires that if the Commission finds an affiliate
expense for the test period to be unreasonable, then the Commission is to make a determination of
what level of the expense is reasonable. By analyzing ETI’s affiliate transactions on a project basis,
OPC contends that it has facilitated the Commission’s ability to make such a determination for each
of ETI’s classes of service; instead of an “up or down” decision on the macro level of expense for
the class, the Commission can disallow the portion not shown to be reasonable and approve the
remainder as reasonable.

ETI disagrees with OPC’s contentions and argues that Dr. Szerszen’s approach to addressing
the Company’s affiliate case is inappropriate for a number of reasons and should be rejected.

x First, her approach is directly contrary to the Commission’s Guiding Principles included as part
of the Commission’s Transmission and Distribution Cost of Service Rate Filing Package that
was issued on April 2, 2003.699 Item 2 of the Guiding Principles clearly states that a class of

695
Cities witness Mark Garrett recommended disallowance of certain short-term incentive compensation
affiliate costs, but those disallowances are largely also recommended by Dr. Szerszen. See ETI Ex. 69
(Tumminello Rebuttal) at 17. ETI contends that the duplicated disallowances by Dr. Szerszen and Mr. Garrett
would result in double counting $217,520 of the requested affiliate charges and requests that if the ALJs rule
in OPC’s and Cities’ favor regarding these short-term incentive compensation costs, that disallowance should
be reduced by $217,520. ETI Initial Brief at 157, n. 898.
696
Tr. at 1607.
697
OPC Exhibit No. 1 (Szerszen Direct) at 42-43.
698
OPC Exhibit No. 1 (Szerszen Direct) at 42-43; Tr., at 1671-72.
699
See ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1.
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service approach is required for purposes of complying with the provisions of Section 36.058 of
PURA.700 Dr. Szerszen ignores the class of service approach required by Section 36.058 of
PURA as detailed in the Guiding Principles, and instead states OPC’s case on a project code-by-
project code basis.

x Second, Dr. Szerszen’s approach is directly contrary to the Commission’s directives in Docket
No. 16705. In that docket, the Commission disallowed a substantial amount of affiliate expense
because Entergy Gulf States, Inc. had done then what Dr. Szerszen proposes here – based the
affiliate analysis solely on project codes, rather than affiliate classes of service. Because the
Commission found that a scope statement/project code-based affiliate analysis is “impossible,”
the Company, in its subsequent base rate cases, including its filing in this docket, changed to a
class-based presentation, as directed by the Commission.

x Third, by refusing to consider a class-based analysis, Dr. Szerszen has ignored the Company’s
testimony, presented by 19 affiliate witnesses, which explains in detail why the Company’s
affiliate-incurred costs meet the Section 36.058 of PURA and Rio Grande standards.701
According to ETI, the Company’s affiliate class witnesses, who are knowledgeable about the
activities that are encompassed in each of their classes, have each shown why the services
provided through those classes are necessary. They have each also addressed numerous
Commission-recommended metrics to measure the reasonableness of costs, including cost
trends, staffing trends, the budgeting process, and, if applicable, benchmarking and outsourcing
comparisons.702 Their testimony and exhibits, according to ETI, show numerous different
“views” of the costs in their classes, including the project codes that comprise their classes.
Each affiliate witness also addressed the “not higher than” and “reasonably approximates cost”
standards applicable to affiliate costs. ETI contends that the evidence provided by its witnesses
meets the requirements of these Guiding Principles and supports the Company’s burden of proof
for the recovery of affiliate costs. ETI also contends that Dr. Szerszen ignores this overwhelming
evidence and the careful attention paid to presenting it in an organized manner. In addition, she
presents no evidence in accordance with the Guiding Principles that supports her proposed
disallowances.

x Fourth, the Company’s case is much less cumbersome and less complex than the approach
suggested by OPC, which would require a showing on the necessity, reasonableness, “not higher
than,” and “reasonably approximates cost” standards for each of almost 1,300 project codes
subject to this docket. Even if the Company were to do that, Dr. Szerszen’s “cherry picking”
approach among the project codes ignores any savings in other project codes that would

700
Dr. Szerszen conceded that the Guiding Principles require that a utility’s affiliate case be presented in a
sufficient number of class or other logical groupings. Tr. at 1632.
701
Dr. Szerszen claimed that, instead of considering the narrative class testimony, she instead “looked at
more of the detail,” presumably meaning the exhibits. Tr. at 1629.
702
ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1. Dr. Szerszen conceded that the Company’s testimony
included proof items such as benchmarking data, outsourcing, staffing trends, and cost trends. Tr. at 1631.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 198
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comprise a class of affiliate costs, thereby resulting in an overall reasonable level of costs within
the class even assuming that any of her complaints about individual project codes had merit.

x Fifth, ETI contends that Dr. Szerszen fails to mention Section 36.058(f) of PURA, which
requires that the Commission determine the reasonable level of “an affiliate expense” if it first
finds that the expense presented is unreasonable. But rather than offering an alternative
“reasonable” level of an expense“”, she either categorically disallows all costs in that project; or,
in some instances, substitutes an arbitrary sharing or allocation of costs between ETI and its
regulated affiliates, or ETI and its non-regulated affiliates. In doing so, Dr. Szerszen does not
make any evidence-based attempt to ground her alternative allocation (and associated
disallowance of ETI affiliate costs) on any objective basis reflecting cost causation principles.
ETI contends that the effect of her approach is to presume that the Company needs zero dollars
in its cost of service to perform a variety of essential utility support activities.

x Sixth, Dr. Szerszen’s positions in the 2009 Oncor rate case,703 which she agrees are similar to
her positions in this ETI base rate case,704 were rejected by the two SOAH ALJs and the
Commission in that docket. ’’Many of the allegations and arguments made by Dr. Szerszen in
this case are very similar, if not identical, to the points she asserted in the Oncor case.

The ALJs agree that the Commission’s Guiding Principles set forth the minimum that a
utility must present to establish a prima facie case, and it is clear that ETI met that burden. That,
however, is not the end of the question. Permitting a utility to escape further scrutiny of its affiliate
transactions by resting on its prima facie presentation imposes too many limits and, as suggested by
OPC, presents too macro a view to be a legitimate review for rate case purposes.

OPC performed essentially a sample review of ETI’s affiliate transactions. The review was
not exceptionally large, and (as evidenced by ETI’s concurrence in the removal of some of the costs)
it represented an additional layer of review to ensure that improper costs would not inadvertently be
charged to ratepayers. That, of course, is not the sole focus of OPC’s review, but it is important for
purposes of determining whether the review itself is appropriate. If intervenors and Staff were
limited to the macro level of review urged by ETI, such matters would never be revealed and there
would exist a possibility that ratepayers would be charged for matters not their responsibility. The
ALJs do not characterize OPC’s review as “cherry picking.” It is more a reasonable sample for

703
Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 35717
(PFD issued on Jun. 2, 2009; Order on Rehearing issued on Nov. 30, 2009) (Oncor).
704
Tr. at 1656.
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examination that gives ETI a reasonable opportunity to explain the reasons for the charges to
ratepayers. Accordingly, the ALJs find that the Commission’s Guiding Principles do not limit the
review performed by OPC, and the review performed by OPC is not contrary to the Commission’s
holdings in Docket No. 16705.

A. Large Industrial & Commercial Sales Reallocation

OPC contends that ETI incurs considerable amounts of sales and marketing expenses that are
exclusively for the benefit of the larger commercial and industrial customers. However, most of
ESI’s sales, marketing, and customer service expenses are allocated to residential and small business
customers.705 The vast majority of the sales, marketing and customer service expenses are allocated
to the operating companies based on customer counts, the majority of these expenses are
consequently allocated to residential and small business customers. In the test year, residential and
small general service customers made up 94.8 percent of the ETI total customer count. ETI’s
General Service, Large General Service, and Large Industrial Power Service, and Lighting classes
combined comprise only 5.2 percent of ETI’s customers. For the test year, OPC argues that ETI is
requesting the recovery of $2.086 million of sales, marketing, billing and load research expenses that
benefitted only the large customer service classes. OPC contends that it is inappropriate for
residential and small customers to pay for these expenses, when cost causation is so readily
identifiable, particularly since a disproportionately small portion of larger customer sales and
marketing expenses is allocated to ETI’s largest customers.706 The total recommended reallocated
large customer expense is $2,086,145.

ETI and TIEC oppose OPC’s recommendation, arguing that it is “cherry-picking” and that
the evidence does not demonstrate that the $2.086 million of affiliate expense should be directly
assigned to the large commercial and industrial classes.707

705
OPC Ex. 1 (Szerszen Direct) at 45.
706
OPC Ex. 1 (Szerszen Direct) at 45.
707
ETI Ex. 55 (LeBlanc Rebuttal) at 5; TIEC Ex. 3 (Pollock Cross Rebuttal) at 36.
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With respect to the first argument, ETI and TIEC contend that Dr. Szerszen developed her
adjustment by examining a limited sample of affiliate project code summaries and making the call,
based on project code descriptions, that certain affiliate costs for marketing, sales and customer
service expense should be directly assigned to large commercial and industrial customers.708 Both
TIEC and ETI contend that the bias and results-oriented nature of her recommendation became
apparent when Dr. Szerszen admitted on cross examination that she made no effort to examine
whether certain affiliate costs should be directly assigned to residential and small customers.709
Both ETI and TIEC contend that it is inappropriate to take a “limited sample of costs” and directly
assign them to a particular class.

According to TIEC, Dr. Szerszen admitted that it could have been appropriate to make an
adjustment for direct assignment of costs to small commercial and residential customers based on
principles of cost causation.710 However, she made no effort to do that herself, nor did she ask ETI
to conduct such an analysis.711 The parties argue that the evidence shows that Dr. Szerszen’s
recommendation rests on an incomplete analysis of ETI’s affiliate costs and her recommendation
should be rejected because direct assignment of costs is only appropriate if there has been a thorough
and complete cost study analysis to determine what costs are or are not appropriate for direct
assignment to all of the classes.

TIEC further argues that the evidence did not demonstrate that the $2.086 million of affiliate
expense that Dr. Szerszen proposes for direct assignment to large commercial and industrial
customers is solely attributable to costs caused by those customers. Mr. Pollock testified that the
project codes Dr. Szerszen selected include load research expenses that benefit residential and small
commercial customers.712 TIEC pointed out that ETI witness Stokes testified that the billing
methods used for the affiliate expenses for customer service operations and retail operations were

708
Tr. at 1609.
709
Tr. at 1609-10.
710
Tr. at 1685.
711
Tr. at 1613-1624.
712
TIEC Ex. 3 (Pollock Cross Rebuttal) at 35.
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fair and reasonable.713 According to TIEC, Dr. Szerszen’s proposal should be rejected because her
assertion that these expenses exclusively benefit large commercial and industrial customers is
incorrect.

The ALJs have reviewed the arguments of the parties and find that Dr. Szerszen’s analysis is
far from complete. It appears to be result-oriented, ignoring critical aspects (such as failing to make
an adjustment for direct assignment of costs to small commercial and residential customers based on
principles of cost causation). The ALJs believe that Dr. Szerszen’s analysis with respect to this issue
should not be adopted.

B. Administration Costs

Dr. Szerszen recommended disallowance of $94,709 (25 percent) of the charges in
Project F3PCFACALL, contending that ESI failed to directly charge any of the costs in this project
code to ETI. She claimed that the billing method applied to this project code by ESI (that is, Billing
Method “SQFALLC”), which is based on square footage, is not appropriate for these types of
costs.714

ETI witness Plauche explained that the costs captured in this project code are primarily for
the oversight of administrative functions, such as facilities, real estate, and security.715 This project
code applies to the administration of these types of functions. These services benefit all companies
that receive facility services and are not attributable to any one specific Entergy affiliate. Therefore,
it is appropriate to bill these costs to all companies based on their pro rata share of square footage
occupied.716

The ALJs concur that this is the appropriate method to employ and, therefore, recommend
that the Commission approve the inclusion of these costs as requested by ETI.

713
ETI Ex. 66 (Stokes Rebuttal) at 3.
714
OPC Ex. 1 (Szerszen Direct) at 80-82.
715
ETI Ex. 20 (Plauche Direct) at 15-26.
716
ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-2 at 10.
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C. Customer Service Operations Class

Dr. Szerszen recommended disallowances in seven project codes covered primarily by ETI’s
Customer Service Operations Class: (1) F3PCR29324 (Revenue Assurance - Adm.) for a
disallowance of $70,849; (2) F3PCR53095 (Headquarter’s Credit & Collect) for a disallowance of
$110,338; (3) F3PCR73380 (Credit Systems) for a disallowance of $73,562; (4) F3PCR73458
(Credit Call Outsourcing) for a disallowance of $197; (5) F3PCR73381 (Customer Svc Cntr Credit
Desk) for a disallowance of $43,378; (6) F3PCR73390 (Customer Svs Ctl - Entergy Bus) for a
disallowance of $60,926; and (7) F3PCR73403 (Customer Issue Resolution – ES) for a disallowance
of $1,869.717

1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095 (Headquarter’s
Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call
Outsourcing)

For the costs captured by these project codes, Dr. Szerszen recommended that the costs be
reallocated based on the Company’s 10 percent “bad debt” expense percentage.

ETI witness Stokes responded that the costs captured by these project codes are for
management and supervision of credit, collection, and revenue assurance activities for all of the
Operating Companies. These functions ensure the most efficient processes are used in managing
write-offs for all the Operating Companies and have contributed to Entergy’s first quartile ranking in
benchmarking of credit and collection operations. These managerial and supervisory costs, which
include bankruptcy administration, surety administration, arrears management, collection agency
administration, skip tracing, and final bill collections, remain consistent whether ETI’s bad debt
percentage is 10 percent, 30 percent, or any other percent and are appropriately allocated using the
CUSTEGOP billing method, which is based on the number of electric and gas customers for each
Operating Company.718

717
OPC Ex. 1 (Szerszen Direct) at 76-78.
718
ETI Ex. 66 (Stokes Rebuttal) at 15-16.
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ETI has provided credible evidence that it has chosen the correct billing methodology.
Therefore, the ALJs recommend the Commission approve inclusion of these costs as requested by
ETI.

2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer
Svs Ctl - Entergy Bus), and F3PCR73403 (Customer Issue Resolution – ES)

Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing
method. Given ESI’s demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this
project using a 10.8 percent customer call allocator, which is on the low end of the
10.70 percent-11.04 percent Test-Year CUSTCALL allocators.719

ETI witness Stokes believes that Dr. Szerszen’s proposed reallocation is arbitrary and fails to
consider the cost causation associated with the actual project code at issue. These costs are not
driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL
allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick
Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of
calls by customers to the Company.

The ALJs are persuaded that the allocation methodology chosen by ETI is the superior
method and that the CUSTCALL allocator would not be appropriate given the cost causation
associated with the project. Accordingly, the ALJs recommend the Commission approve the costs
proposed by ETI.

D. Distribution Operations Class

Dr. Szerszen addressed three project codes that are within the Distribution Operations Class:
(1) F5PCDW0200 (Lineman’s Rodeo Expenses) for a disallowance of $7; (2) F3PCTJGUSE (Joint

719
OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118; OPC Exhibit No. 27 (ETI’s Ex. SBT-15,
Attachment 6) at 2; Tr., at 838-839.
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Use With Third Party – E) for a disallowance of $6,405; and (3) F3PCTJTUSE (Joint Use With 3rd
Parties – A) for a disallowance of $36,293.720

1. Project F5PCDW0200 (Lineman’s Rodeo Expenses)

Dr. Szerszen claimed that the expenses captured by this project should be disallowed because
ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.

ETI witness Tumminello responds, stating that this minimal amount is related to a safety
competition known as the “Lineman’s Rodeo,” it is not a corporate “image” expense. The cost,
according to Ms. Tumminello, is driven by Entergy employee safety in the Distribution business
units.721

The ALJs agree that the Lineman’s Rodeo competition is not a corporate image expense,
rather it is designed to promote employee safety. The ALJs recommend the Commission approve
inclusion of the costs captured by this project as requested by ETI.

2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and F3PCTJTUSE (Joint
Use With Third Parties – A)

Dr. Szerszen recommends exclusion of these two projects, which she claims represent the
difference between the costs incurred for ETI for pole rental costs and the revenues received from
pole space rentals.

With respect to this proposed disallowance, ETI witness McCulla states that Dr. Szerszen has
confused the rental of space on transmission poles and the rental of space on distribution poles. She
has essentially performed a cost-benefit analysis that erroneously compares the cost of providing
rental space on distribution poles with the income received solely from rental of space on
transmission poles. Mr. McCulla explained that data for the distribution poles show that the more
than $2.5 million in revenues from distribution pole rentals far exceeds the $67,174 in costs billed to

720
OPC Ex. 1 (Szerszen Direct) at 66, 75.
721
ETI Ex. 41 (Tumminello Direct) at Ex. SBT-E at 1234.
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ETI under these two project codes and, therefore, Dr. Szerszen’s misassumption that the revenues
were less than the costs incurred is unfounded.722

The ALJs find that Dr. Szerszen erred. Making the correct comparison, as demonstrated by
Mr. McCula, shows there is no basis for the disallowance claimed by Dr. Szerszen. The ALJs,
therefore, recommend the Commission deny the requested disallowance.

E. Energy and Fuel Management Class

Dr. Szerszen addresses seven project codes that are within the Energy and Fuel Management
Class: (1) F3PCCSPSYS (System Planning And Strategic) for a disallowance of $29,304;
(2) F3PCWE0140 (EMO Regulatory Affairs) for a disallowance of $114,468; (3) F3PPSPE002
(SPO 2009 Renewable RFP Expense) for a disallowance of $3,014; (4) F3PPSPE003 (SPO Summer
2009 RFP Expense) for a disallowance of $56,672; (5) F3PPSPE004 (SPO Summer09RFP
IM&Propslsubmt) for a disallowance of $42,018; (6) F3PPWET300 (SPO 2008 Western Region
RFP-Te) for a disallowance of $645; and (7) F3PPWET303 (SPO2008WinterWestnRegionRFP-IM)
for a disallowance of $4,200.723

1. Project F3PCWE0140 (EMO Regulatory Affairs)

Dr. Szerszen testified that Texas ratepayers do not receive benefits as a result of the costs
captured by this project code and should therefore not be charged those costs.724

ETI witness Cicio explained that Dr. Szerszen misinterpreted an RFI response to conclude
that Texas ratepayers did not receive benefits from the activities whose costs were booked through
this project code. That project code is not intended to capture costs for docketed or large System
Planning and Operations projects. Mr. Cicio states that it is not possible to assign a specific project
code for every discrete activity performed by each employee, nor would it be appropriate to attempt
to do so. Regardless of the number of activities specifically identified through project codes, there

722
ETI Ex. 59 (McCulla Rebuttal) at 8-12.
723
OPC Ex. 1 (Szerszen Direct) at 55, 60, and 65-66.
724
Id. at 55.
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will remain the need to have generic project codes that capture time spent on more general,
undocketed matters and activities that are no less beneficial to ratepayers.725

The ALJs agree that Texas ratepayers receive benefits as a result of the costs charged to this
account. Accordingly, the ALJs recommend the Commission approve inclusion of the costs as
requested by ETI.

2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO
Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM &
Propslsubmt), and F3PPWET303 (SPO2008 Winter Westn RegionRFP-IM)

Dr. Szerszen testified that the costs captured by these projects should be disregarded because
they were incurred during the 2008-2009 period, which is outside of the Test Year, and are
nonrecurring.726

ETI witness Cicio explained that although these projects were initiated prior to the Test Year,
the costs that the Company seeks to recover through these project codes were expenses incurred
during the Test Year, including development activities, request for proposal issuance, bidders
conferences, written and posted questions and answers from market participants and other interested
parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions
and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports,
and regulatory approvals, if necessary. These routinely encompass a multi-year time frame, and the
costs required to perform those activities, although associated with a project that may have been
initiated several years previously, are properly incurred over the life span of the project. He also
states that they are recurring because they reflect the kinds and levels of charges that would be
expected to be incurred on an ongoing basis in association with requests for proposals managed by
ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these
types of solicitations since 2002.727

725
ETI Ex. 45 (Cicio Rebuttal) at 8-9.
726
OPC Ex. 1 (Szerszen Direct) at 65.
727
ETI Ex. 45 (Cicio Rebuttal) at 13-14.
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The ALJs find that the costs captured by these projects were incurred during the Test Year
and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly, the
ALJs recommend that the Commission approve their inclusion as requested by ETI.

3. Project F3PCCSPSYS (System Planning and Strategic)

Dr. Szerszen recommended total disallowance of the costs captured by this project code
because they are allocated based on the total assets of the Entergy affiliates.728 Dr. Szerszen’s
conclusion appears to be that no such corporate-level costs should be allocated to ETI because there
are other project codes that allocate corporate planning and analysis-type costs only to the regulated
utilities, such as ETI; thus, any corporate-level costs that are allocated to all subsidiaries, whether
regulated or non-regulated, should not be charged to ETI.

ETI witness Tumminello testified that Dr. Szerszen’s theory neither considers the Entergy
organization as a family of companies and ETI’s place in that family, nor the fact that these services
are not only relevant to ETI as part of the Entergy family, but are reasonable, necessary and meet the
Commission’s affiliate cost recovery standard. ESI’s corporate oversight services are provided to
both individual companies and groups of companies within the Entergy ’corporate structure. As a
member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and
forecasting activities provided by ESI.729

The ALJs find that ETI (and, therefore, its ratepayers) does receive benefits as a member of
the Entergy family of companies and that it is appropriate for it to receive charges for those services.
Therefore, the ALJs recommend the Commission approve the inclusion of costs as requested by ETI.

F. Environmental Service Class

Dr. Szerszen recommended disallowance of $301,879 in six project codes primarily within
ETI’s Environmental Services Class: (1) F3PCCE0129 (Corporate Sustainability Strat) for a

728
OPC Ex. 1 (Szerszen Direct) at 60-61.
729
ETI Ex. 69 (Tumminello Rebuttal) at 10-11.
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disallowance of $6,781; (2) F3PCCE0193 (Corp Environmental Special Pro) for a disallowance of
$1,203; (3) F3PCCEIE01 (Corp Environmental Initiatives) for a disallowance of $2,413;
(4) F3PCCEII01 (Corp Environmental Initiatives) for a disallowance of $2,413; (5) F3PCCEP001
(Corporate Environmental Policy) for a disallowance of $269,248; and (6) F5PPBCNAVF (Avian
Flu Contingency Planning) for a disallowance of $47.730

Dr. Szerszen’s reasoning for this disallowance was that these six project codes, which all
deal with corporate environmental policy, initiatives, strategy, and consulting services, were
allocated based on Billing Method CAPAOPCO, which is based on the fossil plant capacity of the
regulated utility operating companies, even though “non-regulated entities clearly benefit from the
corporate level expenses.”731 Dr. Szerszen recommended a $47 disallowance for
Project F5PPCCNAVF (Avian Flu Contingency Planning), asserting that this charge is a “corporate
imaging expense that should not be borne by Texas ratepayers.”732

According to ETI, Dr. Szerszen has a fundamental misunderstanding of how the affiliate
billing system works and, as a result, she incorrectly assumed that ESI charges are not being
properly allocated. ETI argues that the non-regulated Entergy affiliates do receive the proper and
appropriate allocation of costs. The two service companies for non-regulated affiliates also provide
services to their non-regulated affiliates directly. There simply is no subsidization or improper
allocation.733

Dr. Szerszen noted that Entergy’s website indicates that nuclear-related environmental issues
are being pursued.734 She argued that this shows that the non-regulated affiliates are under-allocated

730
OPC Ex. 1 (Szerszen Direct) at 62-63.
731
Id.
732
Id. at 66.
733
See, e.g., ETI Ex. 41 (Tumminello Direct) at 10-15. Moreover, while ESI bills the regulated utility
affiliates such as ETI at cost, it bills the non-regulated affiliates at cost plus a 5 percent mark-up pursuant to a
June 1999 Securities and Exchange Commission order. ETI Ex. 41 (Tumminello Direct) at 15. This
5 percent mark-up is then flowed back to entities that receive service from ESI. Therefore, the regulated
affiliates are, by federal order, receiving essentially a rebate from the non-regulated affiliates.
734
OPC Ex. 1 (Szerszen Direct) at 62.
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environmental-related costs. Ms. Stokes explained that the project codes at issue “deal with services
provided to the operating companies. . . . and just looking at the website there are other things . . .
that are not covered or paid for by Texas ratepayers in these project codes that are in this
testimony.”735 Therefore, according to Ms. Stokes, these project codes are not allocated in such a
way that under-recovers costs from the non-regulated affiliates; they pay their own way.

Finally, the Project Summary for the Avian Flu Contingency Planning project shows that
these costs involve developing and communicating Avian Flu business continuity plans and then
maintaining, checking, and adjusting those plans once established.736 These are not “corporate
imaging expenses” as characterized by Dr. Szerszen.

The ALJs agree that ETI’s evidence demonstrates the recoverability of the costs captured by
these project codes. Therefore, the ALJs recommend the Commission approve their recovery.

G. Federal PRG Affairs Class

Dr. Szerszen recommended disallowances for three project codes primarily in the Federal
PRG Affairs Class: (1) F5PPSPE044 (PMO Support Initiative-System) for a disallowance of $344;
(2) F3PPUTLDER (Utility Derivatives Compliance) for a disallowance of $20,447; and
(3) F3PCSYSRAF (System Regulatory Affairs-Federal) for a disallowance of $352,084.737

1. Project F5PPSPE044 (PMO Support Initiative-System)

Dr. Szerszen recommended disallowance of $344.29 from Project F5PPSPE044 (PMO
Support Initiative System). ETI responds, however, that a review of the Project Summary for that
project code in Ex. SBT-E reveals that ETI already removed those costs before even filing its direct

735
Tr. at 884.
736
ETI Ex. 41 (Tumminello Direct) at SBT-E at 1342-43.
737
OPC Ex. 1 (Szerszen Direct) at 46-47, 66-67.
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case. Therefore, according to ETI, Dr. Szerszen is recommending disallowance of a cost that is not
in this case.738

The ALJs agree that examination of the exhibit referenced by ETI appears to reveal that the
costs challenged by Dr. Szerszen have been removed from this case through a pro forma adjustment.
Accordingly, the ALJs recommend the Commission reject OPC’s challenge.

2. Project F3PPUTLDER (Utility Derivatives Compliance)

Dr. Szerszen recommended disallowance of $20,447 of derivatives expenses because ETI did
not use derivative instruments and therefore should not be charged these costs and because
ratepayers do not benefit from derivatives.739

ETI witness Tumminello responded that Project F3PPUTLDER was charged by a group
developing compliance mechanisms to protect Entergy’s regulated utility interests in observance of
the Dodd-Frank Act. Although ETI does not currently use any derivative activities, understanding
the impacts of that Act is necessary to ensure current and future compliance through Entergy. The
definitions under the legislation have not been finalized, and there remain issues that ETI must be
aware of to fully comply. These costs, therefore, are necessary and reasonable charges that should
not be disallowed.740

The explanation offered by ETI for the inclusion of these charges appears reasonable to the
ALJs. Even though ETI does not now use derivatives, it is possible that it will in the future and it is
important that it be aware of the regulatory framework associated with such actions to avoid
problems. The ALJs therefore recommend the Commission approve inclusion of these costs as
requested by ETI.

738
ETI Initial Brief at 174-175.
739
ETI stated that it assumes that Dr. Szerszen must be referring to Project Code F3PPUTLDER (Utility
Derivatives Compliance) because her recommended disallowance is the same total ETI adjusted amount
shown on the Project Summary for that project code. See SBT-E at 1113. The ALJs make the same
assumption as it appears reasonable.
740
ETI Ex. 69 (Tuminello Rebuttal) at Ex. SBT-R-2 at 3.
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3. Project F3PCSYSRAF (System Regulatory Affairs-Federal)

In the regulatory affairs category, ETI requests the recovery of various legal,
testimony-related, communications, and filing costs associated with both Texas-specific regulatory
activities, FERC-related regulatory activities, and non-Texas specific regulatory activities. OPC
witness Szerszen did not recommend a disallowance of the $1,442,223 in adjusted Test Year
expenses for regulatory affairs that ETI has shown to be specific to the Texas jurisdiction.741
Rather, Dr. Szerszen recommended that all regulatory affairs expenses not specific to Texas be
disallowed.742 These expenses total $759,868.743

Project F3PCSYSRAS (System Regulatory Affairs – State) was incurred for administrative
activities for senior management, project work associated with system-wide regulatory matters,
system-wide regulatory strategies and emerging regulatory issues, and it relates to multiple regulated
jurisdictions.744 Project No. F3PCSYSRAF (System Regulatory Affairs – Federal) was incurred for
regulatory oversight and coordination of FERC matters.745 OPC contends that ETI provided no
evidence that Texas ratepayers receive any tangible benefits from “system” regulatory affairs costs
in proportion to the costs being allocated to Texas.

Project F3PCSYSRAS costs are allocated to the subsidiaries based on electric customer
counts, and OPC states that it is questionable whether Entergy’s positions on “emerging” state or
national regulatory issues or “system-wide regulatory strategies” are conveying any benefits to its
electric customers beyond those already captured in the Texas-specific regulatory affairs project
codes.746 In fact, according to OPC, the Company’s shareholders are the primary beneficiaries of
these system-wide regulatory strategies.747 The federal regulatory affairs costs captured under

741
See OPC Ex. 3 (Szerszen Workpapers) at 368-371.
742
OPC Ex. 1 (Szerszen Direct) at 46-47.
743
Id. at 46.
744
OPC Ex. 3 (Szerszen Workpapers) at 365.
745
OPC Ex. 1 (Szerszen Direct) at 46-47; OPC Ex. 3 (Szerszen Workpapers) at 367.
746
OPC Ex. 3 (Szerszen Workpapers) at 368-371.
747
OPC Ex. 1 (Szerszen Direct) at 47.
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Project F3PCSYSRAF are allocated to the regulated subsidiaries based on each company’s load
responsibility ratio; this ratio assumes that every FERC docket and/or FERC issue is related to ETI’s
peak demand. According to OPC, this is not reality, nor is it consistent with FERC’s primary
responsibility to ensure that electric wholesale buyers and sellers are provided open access
transmission across utility systems.

ETI witness May offered the following as rebuttal of Dr. Szerszen’s contentions regarding
these two project codes:

The affiliate charges to Project Codes F3PCSYSRAS and F3PCSYSRAF are directly
associated with the issues and matters within the federal jurisdiction of the Federal
Energy Regulatory Commission (“FERC”) including but not limited to the Open
Access Transmission Tariff (“OATT”) as well as any other federal statutes, rules and
regulations. These are the result of issues and matters raised concerning the OATT,
operations of the transmission system, requests for transmission service and
interpretation of applicable provisions under the jurisdiction of FERC. They are
costs incurred on an Entergy System-wide basis that cannot be directly assigned to
any one Operating Company, such as ETI.748

He then went on to state that the affiliate Test Year issues and costs related to these project codes are
reflective of typical issues and costs that the Company experiences on an ongoing basis.749 With
respect to the benefits derived by Texas ratepayers as a result of activities conducted under these
project codes, Mr. May stated that:

the benefit to ETI involves a multitude of issues that are directly related to the
jurisdiction of the FERC, including but not limited to any revisions to Service
Schedules under the System Agreement that applies to all operating companies
including ETI, power purchase agreements for cost-based, short-term power sales,
and compliance with FERC by each Operating Company to the market-based rate
tariff and cost-based rate tariff. The Entergy Operating Companies’ market-based
rate tariff and cost-based rate tariff are joint tariffs containing terms and conditions
of service.750

748
ETI Ex. 57 (May Rebuttal) at 25.
749
ETI Ex. 57 (May Rebuttal) at 25.
750
ETI Ex. 57 (May Rebuttal) at 27-28; see also, Tr. at 370-371.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 213
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Mr. May also explained why the billing methods applied to these two project codes are appropriate.
The cost drivers for Project F3PCSYSRAF are labor, employee expenses, consultant expenses, and
other general operating expenses incurred for the benefit of the Entergy Operating Companies and
their regulated customers. Therefore, a billing method based on load responsibility –
“LOADOPCO” – is appropriate for this type of project code. Project F3PCSYSRAS captures costs
associated with general regulatory support work that is applicable across all of the jurisdictions. The
primary activities associated in this project code include but are not limited to: special project work
associated with system-wide regulatory matters, analysis of emerging state or national regulatory
and accounting issues affecting the Entergy System, and internal process improvement work. What
drives the cost of this project code is the average number of both electric and gas customers served –
CUSTEGOP – because all such customers benefit from these services provided by ESI to ETI.751 In
short, according to ETI, the activities undertaken under both of these project codes benefit Texas
ratepayers, and they are properly allocated to the regulated operating companies using the billing
methods employed.

The ALJs believe that resolution of this question is a close call. Although ETI provided an
adequate explanation of the reasons underlying the allocation of costs to Texas ratepayers and the
appropriateness of the allocation methodologies used, the one troubling aspect, as noted by OPC,
was that Mr. May’s testimony regarding Projects F3PCSYSRAF and FP3PCSYSRAS contradicted
the fact that ESI has a specific project dedicated to open access transmission issues entitled “FERC-
Open Access Transmission” (Project F3PCE01601).752 As OPC notes, if Mr. May was correct that
OATT issues have been included in Projects F3PCSYSRAF and FP3PCSYSRAS the project pages
should arguably be more specific about the purpose of the expenditure. Nevertheless, the ALJs find
ETI’s testimony credible and recommend that the costs of Projects F3PCSYSRAF and
FP3PCSYSRAS not be disregarded.

751
ETI Ex. 57 (May Rebuttal) at 28-29.
752
OPC Ex. 11; also found in OPC Exhibit No. 3 (Szerszen Workpapers)at 363-364.
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H. Financial Services Class

Dr. Szerszen recommended disallowances in nine project codes that are primarily captured
within ETI’s Financial Services Class of affiliate costs: (1) F3PCF05700 (Corporate Planning &
Analysis) for a disallowance of $4,254; (2) F3PCF21600 (Corp Rptg Analysis & Policy) for a
disallowance of $320,157; (3) F3PCFF1000 (Financial Forecasting) for a disallowance of $96,734;
(4) F3PPADSENT (Analytic/Decision Support-Entergy) for a disallowance of $93,544;
(5) F3PPSPSENT (Strategic Planning Svcs-Entergy) for a disallowance of $45,265;
(6) F3PCR73345 (Quick Payment Center, Adm) for a disallowance of $14,484; (7) F3PCF20990
(Operations Exec VP & CFO) for a disallowance of $146,267; (8) F3PCFF1001 (OCE Support) for
a disallowance of $1,923; and (9) F3PCF23936 (Manage Cash) for a disallowance of $15,677.753

1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg
Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT
(Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-
Entergy)

Dr. Szerszen proposed to disallow all costs related to these five project codes, which she
collectively describes as addressing Corporate Planning, Reporting, and Forecasting issues because
she contends that an assets-based allocator should not be used to allocate these costs and, regardless
of the allocator used, these types of services do not benefit Texas ratepayers because ESI has, in
other instances, directly billed corporate-level services to ETI.

ETI witness Tumminello responded, stating that Dr. Szerszen failed to consider the Entergy
organization as a family of companies and ETI’s place in that family. The services provided under
these project codes are not only relevant to ETI as part of the Entergy family, but are reasonable and
necessary. ESI’s corporate oversight services are provided to both individual companies and groups
of companies within the Entergy Companies’ corporate structure. As a member of the corporate
group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities
provided by ESI. Ms. Tumminello contested that the use of an asset-based allocator is appropriate

753
OPC Ex. 1 (Szerszen Direct) at 56, 60-62, and 74, and Schedules CAS-9, CAS-10, and CAS-15.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 215
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because this is an example of the stewardship of the company-wide assets and such an allocator is,
therefore, appropriate.754 The ALJs agree.

The ALJs find that ETI’s proposed allocator is appropriate and that the costs benefit Texas
ratepayers. Accordingly, the ALJs recommend the Commission approve the costs proposed by ETI.

2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE
Support)

Dr. Szerszen recommended disallowance of all costs captured by these project codes
because, in her opinion: (1) there are “no perceivable benefits to ETI’s ratepayers”; (2) they should
be paid for by the parent entity (presumably meaning Entergy’s shareholders); and (3) an assets-
based allocator is not appropriate.755

As to Dr. Szerszen’s assertion that Texas ratepayers do not benefit from the costs captured by
these project codes, ETI witness Domino, President of Entergy, provided anecdotal evidence that
that Entergy was vital to ETI’s restoration efforts on two fronts. First, the parent provided cash to
ETI for its hurricane restoration efforts; second, ETI was not required to pay dividends to the parent
while it was strapped for funds due to hurricane restoration efforts.756 With respect to the argument
that an asset-based allocator is not appropriate, Ms. Tumminello testified that the functions covered
by this project code relate to the oversight of all system operations and the stewardship of corporate
assets and that because ETI is part of a corporate group, the allocated charges associated with these
services are relevant to ETI as part of that group. Furthermore, ETI argues, the asset-based allocator
is appropriate because it reflects the cause of the costs incurred, in that services provided relate to
the stewardship of all the corporation’s assets.757

754
ETI Ex. 69 (Tumminello Rebuttal) at 10-11.
755
OPC Ex. 1 (Szerszen Direct) at 56-57.
756
Tr. at 141.
757
ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
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Dr. Szerszen took too narrow a view and, without justification, argued that these costs
provide no benefit to Texas ratepayers. There are innumerable benefits provided by the corporate
structure adopted; those mentioned by Mr. Domino are just a few. Ms. Tumminello’s testimony
explained why an asset-based allocator is appropriate. Accordingly, the ALJs recommend the
Commission approve the inclusion of these costs as requested by ETI.

3. Project F3PCR73345 (Quick Payment Center, Adm)

Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing
method. Given ESI’s demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this
project using a 10.8 percent customer call allocator, which is on the low end of the
10.70 percent-11.04 percent Test-Year CUSTCALL allocators.758 As a result of Dr. Szerszen’s
reallocation, $14,484 associated with this project should, according to Dr. Szerszen, be
disallowed.759

ETI witness Stokes responded, stating that Dr. Szerszen’s proposed reallocation is arbitrary
and fails to consider the cost causation associated with the actual project code at issue. These costs
are not driven by a specific proportion of calls from each Operating Company (that is, by the
CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing
the Quick Payment Center vendors in each of the Entergy Operating Companies, regardless of the
number of calls by customers to the Company.760

The ALJs are persuaded that the allocation methodology chosen by ETI is the superior
method and that the CUSTCALL allocator would not be appropriate given the cost causation
associated with the project. Accordingly, the ALJs recommend the Commission approve the costs
proposed by ETI.

758
OPC Exhibit No. 27 (ETI’s Ex. SBT-15, Attachment 6) at 2; Tr. at 838-839.
759
OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118.
760
ETI Ex. 66 (Stokes Rebuttal) at 11.
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4. Project F3PCF23936 (Manage Cash)

Dr. Szerszen recommended disallowance of $15,677 from Project F3PCF23936 (Manage
Cash), arguing that this project: (1) is duplicative of ETI-specific financing and cash management
activates; (2) the allocator is wrong; and (3) Entergy, not ETI ratepayers, should pay for this
activity.761

ETI witness McNeal testified that the services are not duplicative of the cash management
services performed by the Cash Management department in the Treasury Class. The services
provided under Project F3PCF23936 are associated with daily cash management responsibilities,
such as loading bank balances, setting daily cash position for all the Entergy Companies,
transmitting wire/ACH files to Entergy Company banks for vendor payments, and maintaining
proper cash controls over these cash functions. These services are necessary for the daily operation
of all the Entergy Companies, including ETI, and are thus not directly associated with any one
specific legal entity. The costs are driven by the time spent on the daily cash management activities,
which is directly related to the number of bank accounts that the Entergy Companies have open.
Since the services provided under this project code cannot be identified to a particular Entergy
Company, the billing method based on the number of open bank accounts is the best allocation.
Billing method BNKACCTA does that and, according to Mr. McNeal, is therefore appropriate for
allocating costs for this project code.762

The evidence demonstrates that the activities captured by this project code are not directly
associated with any one specific entity; rather, they benefit all the entities under the Entergy
umbrella. It also appears that a billing method based on the number of open bank accounts is the
appropriate allocation methodology. Accordingly, the ALJs recommend the Commission approve
inclusion of costs as requested by ETI.

761
OPC Ex. 1 (Szerszen Direct) at 74 and Schedule CAS-15.
762
ETI Ex. 61 (McNeal Rebuttal) at 4, 6; Tr. at 546-547.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 218
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I. Human Resources Class

Dr. Szerszen recommended disallowances for three project codes that are primarily within
the Human Resources Class of affiliate costs: (1) F3PCHRCCSM (HR Competitive Compensation)
for a disallowance of $20,146; (2) F5PCZUBENQ (Non-Qualified Post-Retirement) for a
disallowance of $115,078; and (3) F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl) for a
disallowance of $241,073.763

1. Project F3PCHRCCSM (HR Competitive Compensation)

Dr. Szerszen testified that an asset-based allocator is not appropriate for a project, such as
Project F3PCHRCCSM, that captures overall executive management-related costs.764

ETI contends that the functions covered by this project code relate to the oversight of all
system operations and the stewardship of corporate assets and that because ETI is part of a corporate
group, the allocated charges associated with these services are relevant to ETI as part of that group
of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects
the cause of the costs incurred, in that services provided relate to the stewardship of all the
corporation’s assets.765

A corporation cannot function without executives, who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class
costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a
logical allocator – the assets the executives are charged with overseeing. The ALJs recommend that
OPC’s challenge be rejected.

763
OPC Ex. 1 (Szerszen Direct) at 56, 68.
764
OPC Ex. 1 (Szerszen Direct) at 56.
765
ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 219
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2. Projects F5PCZUBENQ (Non-Qualified Post-Retirement) and F5PPZNQBDU
(Non-Qual Pension/Benf-Dom Utl)

With respect to Projects F5PCZUBENQ and F5PPZNQBDU, Dr. Szerszen testified that:
(1) there is no evidence that Texas ratepayers benefit from the pension-related benefits in these
codes; and (2) the LBRBILAL allocator (Labor Billings to All) is not appropriate because the
benefits are unrelated to ESI labor costs.766

Initially, ETI agrees that $112,531 of the costs in total for both of these project codes should
be excluded because that amount is attributable to nuclear and non-regulated employees.767

With respect to the remaining costs, ETI disagrees. The ALJs, however, have already
resolved this issue in their discussions related to Section VII.D.4, above, where they concluded that
that the supplemental executive retirement plans are not reasonable and necessary for the provision
of electric utility service and are not in the public interest. Accordingly, the ALJs recommend the
Commission accept OPC’s proposed disallowance of $356,151 (which includes the $112,531 agreed
to by ETI).

J. Information Technology Class

Dr. Szerszen recommended disallowances in two project codes that are primarily within
ETI’s Information Technology Class: (1) F3PPFXERSP (Evaluated Receipts Settlement) for a
disallowance of $10,279; and (2) F3PCFX3555 (BOD/Executive Support) for a disallowance of
$3,148.768

766
OPC Ex. 1 (Szerszen Direct) at 68.
767
ETI Initial Brief at 179.
768
OPC Ex. 1 (Szerszen Direct) at 56, 71.
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1. F3PPFXERSP (Evaluated Receipts Settlement)

Dr. Szerszen testified that Project F3PPFXERSP is not moving forward due to tax and freight
implications and, as such, the cost is not recurring.769 Ms. Tumminello testified in response that the
“Evaluated Receipt Settlement” program was originally being capitalized in a capital project. But
when it was decided that the program would be cancelled, the capital project was closed and the
charges to the project were expensed. Although the costs for this particular project do not recur
every year, they are part of normal utility operations, and this type of project does recur as
necessary.770

Although the ALJs understand the concept of normally recurring cost types, they do not
believe that the costs captured by this project code fall within that category. Those costs related to a
project that was cancelled and sufficient explanation of how similar projects in the future might
occur was not provided. Accordingly, the ALJs recommend the Commission reject inclusion, as
proposed by OPC.

2. Project F3PCFX3555 (BOD/Executive Support)

Dr. Szerszen argued that Project F3PCFX3555 is an executive-related project that does not
provide perceivable benefits to ETI ratepayers, the Entergy shareholders should bear this cost, and
an assets-based allocator is not appropriate.771

ETI argues that the functions covered by this project code relate to the oversight of all system
operations and the stewardship of corporate assets and that because ETI is part of a corporate group,
the allocated charges associated with these services are relevant to ETI as part of that group of
companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the

769
OPC Ex. 1 (Szerszen Direct) at 71.
770
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4.
771
OPC Ex. 1 (Szerszen Direct) at 56.
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cause of the costs incurred, in that services provided relate to the stewardship of all the corporation’s
assets.772

A corporation cannot function without executives who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her arguments. The utility and executive management class
costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a
logical allocator – the assets the executives are charged with overseeing. The ALJs recommend that
OPC’s challenge be rejected.

K. Internal and External Communications Class

Dr. Szerszen recommended disallowances in four project codes that are primarily within
ETI’s Internal and External Communications Class: (1) F3PCR40118 (Utility Communications for a
$6 disallowance; (2) F5PCZPDEPT (Supervision and Support – Public) for a $138 disallowance;
(3) F5PPICC000 (Integrated Customer Communications) for a $199 disallowance; and
(4) F5PPICCEMP (ICC - Employee Education Initiative) for a $3 disallowance.773

ETI witness Tumminello responded to Dr. Szerszen’s claim that the costs captured by these
project codes are corporate image costs by stating that the costs are for advertising activities that are
of a good will or institutional nature, which is primarily designed to improve the image of the utility
or the industry, including advertisement which inform the public concerning matters affecting the
Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the
quality of service, the Company’s efforts to improve and protect the environment. According to
FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According
to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.774

772
ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
773
OPC Ex. 1 (Szerszen Direct) at 66.
774
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 222
PUC DOCKET NO. 39896

OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did little better, but it did provide the testimony of
Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and
are, therefore, recoverable. In the end, the ALJs must go with the weight of the evidence, which is
in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs covered
by these project codes are not recoverable.

L. Legal Services Class

Dr. Szerszen recommended disallowances in 13 project codes that are primarily within the
Legal Services Class: (1) F3PPCASHCT (Contractual Alternative/Cashpo) for a disallowance of
$2,553; (2) F3PCF99180 (CORP. COMPLIANCE TRACKING SYS) for a disallowance of $9;
(3) F3PPINVDOJ (DOJ Anti Trust Investigation) for a disallowance of $1,039,664;775
(4) F3PCE01601 (Ferc - Open Access Transmission) for a disallowance of $84,183;
(5) F3PCERAKTL (RAKTL Patent Matter) for a disallowance of $75; (6) F3PPEASTIN
(Willard Eastin et al) for a disallowance of $19,714; (7) F3PPTCGS11 (TX Docket Competitive
Generation) for a disallowance of $310,746; (8) F5PCE13759 (Jenkins Class Action Suit) for a
disallowance of $205,107; (9) F5PCZLDEPT (Supervision & Support – Legal) for a disallowance of
$225,794; (10) F3PCCDVDAT (Corporate Development Data Room) for a disallowance of $6,147;
(11) F3PCSYSAGR (System Agreement-2001) for a disallowance of $880,841; (12) F3PPWET302
(SPO 2008 Winter Western Region) for a disallowance of $13,919; and (13) F3PPWET308 (SPO
Calpine PPA/Project Houston) for a disallowance of $435,963.

775
Dr. Szerszen also proposed disallowance of $765 in charges for related Project Code F3PPTDHY19
(Dept. of Justice Investigation), which is actually primarily attributable to the Transmission Operations Class,
rather than the Legal Services Class. Because the issues are intertwined, that project will be discussed here,
rather than in the Transmission Operations Class.
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1. Project F3PPCASHCT (Contractual Alternative/Cashpo)

With respect to Project F3PPCASHCT ($2,553 disallowance), ETI agrees that these costs are
non-recurring and should be disallowed. Accordingly, the ALJs recommend the Commission
exclude those costs.

2. Project F5PCZLDEPT (Supervision & Support – Legal)

As to Project F5PCZLDEPT ($225,794), OPC, through its Second Errata, removed that
proposed disallowance, and it is no longer contested by Dr. Szerszen. Accordingly, the ALJs
recommend the Commission approve inclusion of those costs.

3. Project F3PCF99180 (Corp. Compliance Tracking Sys)

F3PCF99180 (Corp. Compliance Tracking Sys) is one of the project codes that Dr. Szerszen
claimed should be disallowed because ETI is a monopoly and Texas ratepayers should not have to
pay for corporate image costs.776

ETI witness Tumminello testified that these costs are for advertising activities that are of a
good will or institutional nature, which is primarily designed to improve the image of the utility or
the industry, including advertisement which inform the public concerning matters affecting the
Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the
quality of service, the Company’s efforts to improve and protect the environment. According to
FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According
to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.777

OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did little better, but it did provide the testimony of

776
OPC Ex. 1 (Szerszen Direct) at 66.
777
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 224
PUC DOCKET NO. 39896

Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and
are, therefore, recoverable. The weight of the evidence is in ETI’s favor. The ALJs recommend the
Commission reject OPC’s contention that costs covered by these project codes are not recoverable.

4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of
Justice Investigation)

Entergy is currently under investigation by the Department of Justice (DOJ) for certain
business practices of the Operating Companies, including the procurement of generating assets and
power, dispatch of generation within the Entergy system, and transmission capacity expansion. This
is a civil investigation under Section 2 of the Sherman Act and Section 7 of the Clayton Act. The
investigation has been ongoing since 2010, and Entergy does not know when the investigation will
conclude.778

Dr. Szerszen testified that there are two reasons why ratepayers should not pay for the DOJ
expenses. First, ETI does not have the ability to make its own power procurement, generation
dispatch, or transmission capacity decisions. These decisions are made by ESI and Entergy’s
corporate management, which has traditionally planned and managed the electric operating
companies’ generation and transmission functions on a system-wide basis. Second, ETI is not
responsible for the development and administration of the system agreement, and should not be held
responsible for these antitrust investigation expenses. Furthermore, according to Dr. Szerszen, if the
DOJ finds that Entergy has acted illegally, it is even more inappropriate to charge ETI ratepayers for
corporate-level illegal actions. These expenses should be borne by Entergy’s corporate parent
and/or the corporation’s shareholders, and not the ratepayers.779

ETI contends that Dr. Szerszen fundamentally misunderstands the nature of the System
Agreement and the benefits that ETI derives from that agreement. All of the Entergy Operating
Companies voluntarily entered into the System Agreement so that the Entergy system can be
planned and operated on a total system basis, in order to maximize economic benefit and reliability

778
OPC Ex. 1 (Szerszen Direct) at 51-52.
779
Id. at 52.
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PUC DOCKET NO. 39896

of service. All of the Operating Companies benefit from integrated planning and operations in this
manner. This does not mean that ETI has no decision-making role in these activities. ETI notes that
under Section 5.01 of the System Agreement, the agreement is administered through an Operating
Committee, which includes an ETI representative, as well as representatives of the other Operating
Companies and Entergy. ETI’s representative is one of the voting members of the Committee, and
all decisions of the Operating Committee must be approved by a majority vote. As a voting member
of the Operating Committee, ETI is responsible for administering the System Agreement and does
participate in decision-making on generation and transmission matters.780

ETI acknowledges that ESI is tasked with providing services and making decisions related to
generation dispatch, power procurement, and transmission operations on behalf of the Entergy
Operating Companies and at the direction of the Operating Committee, but these activities are for
the benefit of the Operating Companies and their ratepayers. ETI receives the benefits of these
services and integrated planning and operations under the System Agreement and, according to ETI,
should also be responsible for its portion of costs related to those services and operations.781

As to Dr. Szerszen’s contention that the costs should be disallowed because DOJ might find
that Entergy acted illegally, ETI notes that the DOJ is not an adjudicatory body or regulatory agency
and, thus, it does not make “findings of fact.” If DOJ believes the civil antitrust laws have been
violated, it can file a complaint in federal district court. To date, no complaint has been filed. ETI
points out that ESI routinely incurs legal costs in responding to regulatory audits and investigations
on behalf of ETI and the other Operating Companies in the same manner in which other operating
costs are incurred. ESI is authorized to retain legal counsel on behalf of, and for the benefit of, ETI
and the other Entergy Operating Companies. ESI is authorized to allocate the respective costs to the
Operating Companies under a service agreement with the Entergy Operating Companies designated
as Rate Schedule FERC No. 435. This service agreement is on file with, and was approved by,

780
ETI Ex. 65 (Sloan Rebuttal) at 8.
781
Id.
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FERC under FERC Docket No. ER07-38-000.782 Thus, according to ETI, it is appropriate that ETI
is allocated its share of the costs of legal services related to the DOJ investigation.783

The DOJ antitrust investigation is a massive undertaking. Unfortunately, it is a part of the
ordinary course of modern business life. OPC’s arguments that ESI is solely responsible for
decision-making under the System Agreement miss the mark, as pointed out by ETI. It is clear that
ETI and the other Operating Companies play an active role in the decision-making. As to OPC’s
arguments about what would happen if Entergy were found to have violated the antitrust laws, those
arguments are little more than speculation. As ETI noted, the DOJ is not an adjudicatory body and
its investigation can only result in the filing of a complaint in Federal court (if the DOJ believes that
such an action is justified). Until that time, it is imperative for the company to fully respond to the
DOJ investigation. The ALJs find that ETI has met its burden of proving that Texas ratepayers
should be charged the costs of the DOJ investigation allocated to them by ETI.

5. Project F3PCE01601 (Ferc - Open Access Transmission)

Project F3PCEO1601 costs are incurred to manage costs associated with regulatory oversight
and coordination of the Entergy System Open Access Transmission Service before FERC. OPC
contends that not only are most of the FERC dockets accruing costs under Project F3PPEO1601 no
longer open as of December 31, 2011,784 most of the closed dockets have absolutely nothing to do
with Texas operations.785 Furthermore, according to OPC, ETI witness Sloan agreed that only three
of the dockets shown in OPC Exhibit No. 12 were open at the end of the test year, and one of the
open dockets involves a transmission service agreement involving the Missouri Joint Municipal
Electric Utility Commission and various cities in Missouri and Arkansas.786

782
Entergy Serv. Inc., 117 FERC ¶ 61,288 (2006).
783
ETI Ex. 65 (Sloan Rebuttal) at 8-9.
784
OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. 3 (Szerszen Workpapers) at 363.
785
OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. 1 (Szerszen Direct) at 54.
786
Tr. at 280.
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ETI responds that the activities in this project relate to oversight and coordination of the
OATT proceedings before the FERC. Costs billed to this project code are related to ESI’s
representation of the Operating Companies, including ETI, before the FERC on OATT issues.
Revenues derived from provision of service under the OATT are credited to all of the Operating
Companies on a load responsibility ratio basis. ETI’s retail share of these revenues was $168,366
during the test period, demonstrating the benefits derived by Texas ratepayers as a result of the
activities undertaken through this project code.787

Activities relating to a company’s OATT are not one-time activities; they will continue from
year to year. OPC’s contention that because most of the dockets listed as having taken place during
the Test Year were completed by the end of the Test Year they should be disregarded is not
well-founded. It is clear that the activities covered by this project code not only benefit ETI’s Texas
ratepayers, but will continue (albeit under new docket numbers) into future years. The ALJs
recommend that costs under this project code be allowed.

6. Project F3PCERAKTL (RAKTL Patent Matter)

The costs under this project code involve the RAKTL patent, which relates to call center
operations. RAKTL is a patent infringement claim lodged against several Entergy companies. The
alleged patents are for voice prompting technology used in call centers.788

Dr. Szerszen testified that it is not appropriate to charge ETI for the costs associated with this
litigation because ETI did not purchase the call center telephone equipment at issue, and therefore
should not be required to pay any legal costs associated with patent infringement investigation or
settlement costs. ESI is totally responsible for system-wide technology purchases and operations,
and, according to Dr. Szerszen, it is not reasonable to require the operating companies to pay legal
costs associated with ESI technology acquisition or technology application errors.789

787
ETI Ex. 65 (Sloan Rebuttal) at 10.
788
Id. at 4; OPC Ex. 1 (Szerszen Direct) at 49-50.
789
OPC Ex. 1 (Szerszen Direct) at 50.
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ETI contends that ESI incurred the legal expenses on this patent matter on behalf of the
Entergy Operating Companies, whose residential and small commercial customers call into the call
centers to obtain customer service for issues related to connection and disconnection of electric
service, billing issues, and other customer transactions. The call centers provide an interface
between ETI customers and the Entergy Operating Companies and, as such, are valuable in
providing quality service to customers. Consequently, according to ETI, costs related to the call
centers, including the costs of defending lawsuits involving technologies used at those call centers, is
a reasonable and necessary expense that is appropriately allocated to ETI.790

OPC tends to ignore the purpose and benefits of a centralized service company such as ESI.
If ETI were to fund stand-alone call centers, it is likely that the costs to Texas ratepayers would be
higher than those proposed by ETI in this case. Part of the costs that ESI incurs is the cost of patent
claims. Those are legitimate costs that should be borne by all who receive service from ESI.
Accordingly, the ALJs recommend the Commission reject OPC’s challenge.

7. Project F3PPEASTIN (Willard Eastin et al.)

This project code, which contains costs in the amount of $19,714, collects costs related to an
age discrimination law suit filed by Willard Eastin, et al. against Entergy. The defendants to the
lawsuit were Entergy, ESI, Entergy Louisiana, Inc. (ELL), and Entergy New Orleans, Inc. (ENOI).
The plaintiffs to the lawsuit were employees of ESI, ELL, and ENOI.791

OPC witness Szerszen testified that ETI should not be required to pay any of the costs of this
litigation. Although ESI provides services to the Operating Companies, this does not imply that the
Operating Companies should be charged costs associated with the service company’s employment
practice problems or errors according to Dr. Szerszen.792

790
ETI Ex. 65 (Sloan Rebuttal) at 4.
791
ETI Ex. 65 (Sloan Rebuttal) at 2; OPC Ex. 1 (Szerszen Direct) at 49-50.
792
OPC Ex. 1 (Szerszen Direct) at 50.
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ETI argues that costs are driven by ESI having the need for legal services to defend itself. As
shown on the Project Code Summary for this project, since all ESI functions are in service to the
various affiliates and arise as a consequence of providing such services, it is appropriate to relate
these legal costs to the total ESI billings to the affiliates.793

ETI has provided little in the way of explanation regarding these costs or the litigation that
generated them. What is troubling to the ALJs is that the only named defendants are Entergy, ESI,
ELL, and ENOI; ETI is not included among the named defendants. If this were simply a cost of
doing business for ESI, as claimed by ETI, why were ELL and ENOI named? No explanation was
offered. It appears to the ALJs that although this litigation is related to ESI’s operations, it is more
immediately related to ELL and ENOI. The ALJs do not believe that ETI’s Texas ratepayers should
be charged for these costs; therefore the ALJs recommend that $19,714 not be included.

8. Project F3PPTCGS11 (TX Docket Competitive Generation)

The costs billed through this project code all pertain to ETI’s CGS matter currently pending
before the Commission in Docket No. 38951.794

OPC witness Szerszen testified that because no decision has been made yet as to the
disposition of the expenses associated with the CGS tariff, ETI should not be expensing the costs
associated with that docket. Dr. Szerszen disallowed $310,746 in Test-Year expenses, and
recommended that ETI be allowed to defer the expenses until the Commission determines the
appropriate regulatory treatment.795

ETI argues that these costs were incurred during the Test Year in a pending Commission
docket, and ETI continues to incur costs related to this matter. As such, according to ETI, these

793
ETI Ex. 65 (Sloan Rebuttal) at 2.
794
Id. at 5; OPC Ex. 1 (Szerszen Direct) at 50.
795
OPC Ex. 1 (Szerszen Direct) at 50.
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costs are appropriately included in ETI’s cost of service and should neither be disallowed nor
deferred.796

OPC’s arguments with respect to these costs are not well-founded. It appears to be likening
these regulatory costs to rate case expense, which would be subject to Commission review and
approval in the proceeding to which they relate. But that is not the nature of these expenses. They
are simply regulatory expenses incurred in the course of ongoing regulatory proceedings. They are
ordinary and necessary expenses, the reasonableness of which OPC did not challenge. Accordingly,
the ALJs find that it is appropriate for ETI to charge these expenses to its Texas ratepayers.

9. Project F5PCE13759 (Jenkins Class Action Suit)

The project code relates to a class action lawsuit filed in Texas District Court in 2003 on
behalf of all Texas retail customers served by ETI’s predecessor-in-interest, EGSI (Jenkins Class
Action). The Jenkins Class Action plaintiffs allege that they have been damaged due to
manipulation of the dispatch and pricing of the Entergy system’s generating units and electricity
purchases. As a result of this alleged manipulation, they contend that ETI’s Texas retail customers
were charged more than they should have been for purchased power.797 Dr. Szerszen asserted there
are three reasons why these legal expenses should not be borne by ETI:

x ESI charges 100 percent of the legal expenses to ETI, even though ETI is only one of
several defendants;

x ETI claims that it is defending practices relating to system operations, but fails to
acknowledge that Entergy’s system operations are comprised of many generation and
transmission components other than those of ETI; and

x ETI does not have any authority to administer the System Agreement, that being a function
solely within the purview of ESI.798

796
ETI Ex. 65 (Sloan Rebuttal) at 5.
797
OPC Ex. 1 (Szerszen Direct) at 49; ETI Ex. 65 (Sloan Rebuttal) at 2-3.
798
OPC Ex. 1 (Szerszen Direct) at 49.
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Dr. Szerszen testified that “[i]t would be more appropriate for the Entergy parent to be charged for
these lawsuit expenses, particularly since ETI cannot make unilateral power purchases and power
sales decisions.”799

ETI responds that the plaintiffs in this lawsuit are challenging the reasonableness of ETI’s
Commission-set rates and that the Commission has filed an amicus brief in support of ETI’s position
in the case. ETI further argues that retail ratepayers are benefitting from ETI’s pursuit of the
litigation because ETI is defending practices that are in place to ensure the lowest reasonable cost
consistent with system reliability. Finally, ETI states that the costs are reasonable and necessary
expenses because the plaintiffs purport to represent only ETI’s ratepayers and seek to recover
damages inconsistent with ETI’s filed rates approved by the Commission.800

The ALJs understand Dr. Szerszen’s concerns that there are multiple defendants involved in
this litigation, there are many aspects to Entergy’s system operations, and ETI does not have power
to unilaterally make decisions under the System Agreement. The crucial point, however, is that
these are Texas ratepayers pursuing a challenge to ETI’s Texas rates. The matter centers around
Texas, and the costs of the litigation should be borne by Texas ratepayers.

10. Project F3PCSYSAGR (System Agreement-2001)

OPC witness Szerszen disallowed $880,841 in legal expenses regarding the 2001 complaint
filed by the Louisiana Public Service Commission and the City of New Orleans seeking revisions to
the Entergy System Agreement.801 OPC states that it generally agrees with ETI witness Sloan that
the complaint challenges the equalization of costs between all Entergy Operating Company
jurisdictions.802 However, OPC does not agree that the inquiry “will” affect all Entergy
jurisdictions. Texas has benefitted from the complaint primarily through the past receipt of
equalization payments pursuant to FERC’s decision in this complaint matter. However, Entergy’s

799
Id.
800
ETI Ex. 65 (Sloan Rebuttal) at 3.
801
OPC Ex. 1 (Szerszen Direct) at 53.
802
ETI Ex. 65 (Sloan Rebuttal) at 9.
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SEC Form10-K shows that for 2012 and 2013, ETI will receive no equalization payments, and
further shows that ETI received no rough production cost equalization payments in 2010.803 Thus,
according to OPC, the legal expenses sought to be recovered under Project F3PCSYSAGR are non-
recurring for ETI and therefore not representative of future costs and should be removed from ETI’s
cost of service.804

ETI established that this litigation involved the System Agreement, which governs the
equalization of costs between all of the Entergy Operating Company jurisdictions, it provides
benefits to ETI’s Texas ratepayers as well as those of the other Entergy Operating Companies.
OPC’s argument that ETI did not receive equalization payments in 2010 and is non-recurring for
ETI does not overcome the benefits received by ETI’s Texas ratepayers. The ALJs recommend that
OPC’s disallowance be denied.

11. Project F3PCCDVDAT (Corporate Development Data Room)

ETI requests the recovery of $6,147 in ESI allocated costs for the corporate development
data room. The stated purpose of the data room is for due diligence reviews associated with Entergy
merger, acquisition, or diversification activities. The expenses associated with the corporate
development data room are for the gathering, collating, indexing, manning, and storage of data
during the due diligence reviews.805 OPC contends that the costs incurred for the corporation’s
analysis of merger, acquisition, and diversification opportunities should not be charged to ETI’s
ratepayers. Entergy has not acquired any utilities or utility operations that might produce
system-wide benefits to utility customers.806 The $6,147 of expenses for the corporate development
room are not reasonable and necessary expenses that ratepayers should shoulder and therefore,
according to OPC, recovery of these expenses should be disallowed.

803
ETI Ex. 98 (Entergy’s SEC Form 10-K) at 79-80.
804
OPC Ex. 1 (Szerszen Direct) at 52-53.
805
OPC Ex. 3 (Szerszen Workpapers) at 394.
806
OPC Ex. 1 (Szerszen Direct) at 45-46.
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ETI responds that these costs are driven by each company’s need for corporate services and
the costs, therefore, are appropriately allocated based on the level of service provided by ESI, which
is a reasonable proxy of each company’s need for corporate services.807 Further, just because
Entergy has not acquired any utility or utility operations in the recent past does not mean that these
are not reasonable and necessary costs. Entergy points out that as Dr. Szerszen noted in her
description of this project, it is not only for the acquisition of other operating units, but also used to
analyze diversification activities, which is a legitimate and reasonable undertaking by an integrated
utility and its parent company.

The ALJs believe that there are legitimate costs that may not on their face appear to be
properly allocable to entities such as ETI, but on closer examination they merit such an allocation.
These fall into that class. As Ms. Tumminello testified, the Corporate Development Data Room
includes costs not only related to mergers and acquisitions, but also diversification activities that
could benefit ETI ratepayers. Accordingly, they are properly allocated to ETI ratepayers.

12. Project F3PPWET302 (SPO 2008 Winter Western Region)

Dr. Szerszen argued that Project F3PPWET302 costs should be disregarded because they
were incurred during the 2008-2009 period, which is outside of the Test Year, and they are
nonrecurring.808

ETI witness Cicio explained that although this project was initiated prior to the Test Year,
the costs that the Company seeks to recover through this project code were expenses incurred during
the Test Year. These costs included development activities, requests for proposal issuance, bidders’
conferences, written and posted questions and answers from market participants and other interested
parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions
and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports,
and regulatory approvals, if necessary. He stated that these types of costs routinely encompass a
multi-year time frame, and the costs required to perform those activities, although associated with a

807
ETI Ex. 69 (Tumminello Rebuttal) Ex. SBT-R-2 at 1.
808
OPC Ex. 1 (Szerzen Direct) at 65.
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project that may have been initiated several years previously, are properly incurred over the life span
of the project. He also stated that they are recurring because they reflect the kinds and levels of
charges that would be expected to be incurred on an ongoing basis in association with request for
proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has
been involved in these types of solicitations since 2002.809

The ALJs find that the costs captured by Project F3PPWET302 were incurred during the Test
Year and represent the kinds and levels of costs routinely incurred on a recurring basis.
Accordingly, the ALJs recommend the Commission approve their inclusion as requested by ETI.

13. Project F3PPWET308 (SPO Calpine PPA/Project Houston)

With respect to Project F3PPWET308, which deals with the Calpine-Carville purchased
power agreement, Dr. Szerszen testified that the costs were either non-recurring, or rate case
expenses, or expenses that should have been charged to Louisiana ratepayers.810

ETI witness Cicio explained that these are recurring costs because they reflect the kinds and
levels of charges that the Company expects to incur on an ongoing basis in association with RFPs
managed by ESI on behalf of the Entergy Operating Companies; they were not incurred as part of
some rate case preparation and, therefore, are not a rate case expense that is otherwise sought for
recovery by ETI; and the costs in the matter are costs that were billed only to Texas and should not
have been billed to Louisiana because there is a separate project code that captures the Louisiana
costs that are billed to Louisiana.811

The ALJs find that these costs, like those captured by Project F3PPWET302, are recurring in
that they represent the kinds and levels of costs routinely incurred on a year-in and year-out basis.
Further, the ALJs find that the costs should not have been charged to Louisiana and that there

809
ETI Ex. 45 (Cicio Rebuttal) at 13-14.
810
OPC Ex. 1 (Szerszen Direct) at 65-66.
811
ETI Ex. 45 (Cicio Rebuttal) at 14-17.
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existed a separate project code to capture costs attributable to Louisiana. Accordingly, the ALJs
recommend the Commission approve the inclusion of these costs as requested by ETI.

M. Other Expenses Class

Dr. Szerszen recommended disallowances in 11 project codes that are primarily within the
Other Expenses Class of affiliate costs: (1) F3PCSPETEI (Entergy-Tulane Energy Institute) for a
disallowance of $14,288; (2) F3PCC08500 (Executive VP, Operations) for a disallowance of $4,117;
(3) F3PPBFMESI (ESI Function Migration Relocation) for a disallowance of $4,187;
(4) F3PPBFRESI (ESI Business Function Relocation) for a disallowance of $11,444;
(5) F3PPDRPESI (ESI Disaster Recovery Plan Charge) for a disallowance of $761;
(6) F5PPBFMREL (Business Function Migration Employee) for a disallowance of $33,624;
(7) F5PPBFRREL (Business Function Relocation) for a disallowance of $15,624; (8) F5PPBFRSEV
(Business Function Relocation Severance) for a disallowance of $3,066; (9) F5PPDRPREL (Disaster
Recovery Plan Relocation) for a disallowance of $31,006; (10) F5PPETXRFI (2009 Texas Ike
Recovery Filing) for a disallowance of $441; and (11) F5PPKATRPT (Storm Cost Processing &
Review) for a disallowance of $929.812

1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT
(Storm Cost Processing & Review)

ETI agrees with Dr. Szerszen that the $14,288 amount she proposed to disallow for Project
F3PCSPETEI (Entergy-Tulane Energy Institute) can be treated as a donation, and so should be
removed from ETI’s cost of service. ETI also agrees with Dr. Szerszen to remove the $929 billed to
ETI under Project F5PPKATRPT (Storm Cost Processing & Review). The charges for the
remaining nine project codes, however, are contested.

812
OPC Ex. 1 (Szerszen Direct) at 56, 67, and 72.
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2. Project F3PCC08500 (Executive VP, Operations)

As to Project F3PCC08500 (Executive VP Operations), Dr. Szerszen testified that an
asset-based allocator is not appropriate for these types of executive management costs, and there is
“no perceivable benefit” to ETI ratepayers for these types of allocated costs.813

Ms. Tumminello disagreed, stating that asset-based allocation methods are selected for
projects where the costs are driven by the oversight and stewardship of corporate assets of the
Entergy Companies including, but not limited to, services provided by financial management and
certain finance functions, among others. Each Entergy affiliate with assets on Entergy’s
consolidated balance sheet will be billed their proportionate share of the costs. The use of the Total
Assets allocation method is, in fact, an appropriate method to allocate corporate-level corporate
governance type services.814

The ALJs find credible ETI’s assertion that the costs captured by this project code are for
oversight and stewardship of the corporate assets of Entergy and, therefore, an asset-based allocator
is appropriate. Accordingly, the ALJs recommend the Commission reject OPC’s challenge to the
inclusion of these costs.

3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI
Business Function Relocation), F3PPDRPESI (ESI Disaster Recovery Plan Charge),
F5PPBFMREL (Business Function Migration Employee), F5PPBFRREL (Business
Function Relocation), F5PPBFRSEV (Business Function Relocation Severance),
F5PPDRPREL (Disaster Recovery Plan Relocation), and F5PPETXRFI (2009
Texas Ike Recovery Filing)

The remaining eight of the project codes attributable to the Other Expenses Class all deal
with system restoration and business continuity resulting from Hurricane Katrina, with one applying
to Hurricane Ike. Dr. Szerszen testified that these costs should be disallowed because they should
not be considered to be system restoration costs or, if they are, citing to PURA § 36.405, ETI should
have requested recovery of these costs in its first base rate following Hurricane Katrina (Docket

813
Id. at 56-57.
814
ETI Ex. 69 (Tumminello Rebuttal) at 9-10.
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No. 34800). She also testified that ETI has not shown that Texas ratepayers benefited from these
costs.815

Ms. Tumminello testified that because of the magnitude of Hurricane Katrina, these expenses
were necessary so that activities in connection with the restoration of service and infrastructure
associated with electric power outages affecting customers could continue. These expenses relate to
critical functions needed to support storm restoration, such as business function relocation, and
provided a direct benefit to ratepayers. Ms. Tumminello stated that the costs in seven of these
project codes (F3PPBFMESI, F3PPBFRESI, F3PPDRPESI, F5PPBFMREL, F5PPBFRREL,
F5PPBFRSEV, and F5PPDRPREL) are being amortized over five years. Though these particular
costs do not recur every year, they are a part of ETI’s normal utility operations given the service area
served by ETI, and do recur as necessary.816

As to Dr. Szerszen’s legal conclusion that ETI is no longer authorized to recover Hurricane
Katrina costs, ETI argues that PURA § 36.405 does not restrict or even apply to ETI’s recovery of
such costs. That section deals with securitization of system restoration costs, but ETI did not seek to
securitize any Hurricane Katrina costs. Even so, argues ETI, if that section did apply, it does not
restrict system restoration cost recovery solely to Docket No. 34800; that is, the “next base rate
proceeding” following the hurricane. Instead, the final clause in PURA § 36.405(a) states in full that
the Company is entitled to recover such costs “in its next base rate proceeding or through any other
proceeding authorized by Subchapter C or D.” The same point applies to the Hurricane Ike costs;
while ETI did securitize the Hurricane Ike costs that it had incurred up to the date subject to that
securitization, it continued to incur costs in this test year for that storm restoration (in this case, $441
billed to the Ike-related project code). The costs in these projects were incurred during the test year
for this docket and could not have been recovered in an earlier docket. Moreover, ETI’s filing in

815
OPC Ex. 1 (Szertrszen Direct) at 72, Schedule CAS-14.
816
ETI Ex. 69 (Tumminello Rebuttal) at16.
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this docket was filed in accordance with PURA Subchapter C as a rate change proposed by a utility.
As such, ETI contends that it is entitled to recover these costs.817

To the ALJs, the most important part of the argument is that ETI did not seek to avail itself
of PURA § 36.405 with respect to Hurricane Katrina costs. It is difficult to understand how that
section, which deals with securitization of hurricane costs, could block recovery when ETI did not
seek to securitize those costs. Similarly, with respect to Hurricane Ike costs, the $441 challenged by
Dr. Szerszen was not incurred until the Test Year and could not have been securitized.
Ms. Tumminello provided testimony that the costs were reasonable and necessary, representing a
part of ETI’s normal utility operations. Accordingly, the ALJs recommend the Commission approve
inclusion of the costs.

N. Regulatory Services Class

Dr. Szerszen challenged one project code that is primarily within the Regulatory Services
Class of affiliate costs: Project F3PPE9981S (Integrated Energy Management for ESI) for a
disallowance of $171,032.

Dr. Szerszen testified that these costs were incurred for the implementation, coordination,
and promotion of demand side and supply side management and energy efficiency programs. But,
she stated, these costs should instead have been recovered through ETI’s Energy Efficiency Cost
Recovery Factor (EECRF) Rider and, as such, it is inappropriate to recover these costs through
affiliate billings in base rates.818

ETI witness May testified that recovery of these costs through base rates rather than through
the EECRF Rider is appropriate because these activities are not subject to an active ETI energy
efficiency program. These activities are more in the nature of general research and development
activities that help drive the Company’s strategy on these topics, such as the timing of implementing
related programs. In the meantime, until these activities result in an actual program proposal, these

817
ETI Initial Brief at 188-189.
818
OPC Ex. 1 (Szerszen Direct) at 69-70.
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are legitimate known and measurable costs that the Company has incurred and should then be
recovered from retail customers.819 At the hearing, Mr. May further explained that the costs in this
project code are labor costs that are “not really consistent” with the energy efficiency rule, but
instead involve “primarily costs of investigating” potential future activities (such as smart meters
and electric vehicle chargers) that are generally not consistent with the energy efficiency rider.820
ETI witness Considine also addresses this issue from a regulatory accounting perspective. He
testified: “Because these are not costs that must be, or are currently being recovered through the
EECRF, they are not double recovered and should be included in the Company’s cost of service.”821
According to ETI, the costs in this project code, therefore, are not costs that should or can be
recovered through ETI’s EECRF Rider.

This is a close call. The Commission’s Energy Efficiency Rule places limits on the amount
of research and development costs a utility may recover,822 which supports the argument that the
costs should be included in the EECRF. Further, it appears to the ALJs that research and
development costs, by their very nature, do not relate to an active program, which negates many of
the arguments advanced by ETI witnesses May and Considine. In the end, the ALJs believe that
these costs should be included in the EECRF. Accordingly, the ALJs recommend the Commission
disallow costs in the amount of $171,032 relating to Project F3PPE9981S.

O. Retail Operations Class

Dr. Szerszen challenged three project codes that are primarily within ETI’s Retail Operations
Class of affiliate costs: (1) F5PPICCIMG (ICC – “Image” Message) for a disallowance of $3,912;
(2) F3PPR56640 (Wholesale - EGS-TX) for a disallowance of $229,938; and (3) F3PPR56920
(Wholesale - All Jurisdictions) for a disallowance of $333.

819
ETI Ex. 57 (May Rebuttal) at 30-31.
820
Tr. at 1929-1930 and 1934-1935.
821
ETI Ex. 46 (Considine Rebuttal) at 36.
822
P.U.C. SUBST. R. 25.181(i).
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1. Project F5PPICCIMG (ICC – “Image” Message)

Project Code F5PPICCIMG (ICC-“Image” Message) is one of the project codes that
Dr. Szerszen testified should be disallowed because ETI is a monopoly and Texas ratepayers should
not have to pay for corporate image costs.823

Ms. Tumminello testified that the costs are for advertising activities that are of a good will or
institutional nature, which is primarily designed to improve the image of the utility or the industry,
including advertisement which inform the public concerning matters affecting the Company’s
operations, such as, the costs of providing service, the Company’s efforts to improve the quality of
service, the Company’s efforts to improve and protect the environment. According to FERC, such
costs are properly includable in FERC Account 930.1 and are recoverable. According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.824

OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did provide the testimony of Ms. Tumminello, which
confirms that the costs are properly includable in FERC Account 930.1 and are, therefore,
recoverable. In the end, the weight of the evidence is in ETI’s favor. The ALJs recommend the
Commission reject OPC’s contention that costs covered by these project codes are not recoverable.

2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920 (Wholesale - All
Jurisdictions)

As to Projects F3PPR56640 and F3PPR56920, Dr. Szerszen stated that these costs are
associated with assisting ETI’s wholesale customers in evaluating alternative energy supply and

823
OPC Ex. 1 (Szerszen Direct) at 66.
824
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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demand options and that ETI’s retail customers should not be charged for expenses associated with
ETI’s wholesale customers.825

ETI witness Stokes noted that ETI has allocated costs to its single large wholesale customer
through its jurisdictional allocation in this rate case and, therefore, to disallow the costs in these two
project codes would essentially result in a double disallowance of those costs. She also explained
that the costs were properly allocable to ETI (keeping in mind that ETI then allocated costs to this
customer) as reasonable and necessary due to the need to have staff on hand to handle contract
negotiations and the like with this large wholesale customer.826

The ALJs are persuaded by ETI’s argument that disallowing the costs associated with
Projects F3PPR56640 and F3PPR56920, which are already allocated to ETI’s single large wholesale
customer through its jurisdictional allocation, would constitute a double disallowance. Accordingly,
the ALJs recommend the Commission reject OPC’s challenge to these costs.

P. Supply Chain Class

Dr. Szerszen challenged two project codes that are primarily within the Supply Chain Class:
(1) F3PPH54075 (Business Development - TX) for a disallowance of $1,888; and (2) F5PCZSDEPT
(Supervision & Support - Supply) for a disallowance of $146. Dr. Szerszen claimed the costs
associated with these project codes should be disallowed because ETI is a monopoly and Texas
ratepayers should not have to pay for corporate image costs.827

Ms. Tumminello testified that the costs are for advertising activities that are of a good will or
institutional nature, which is primarily designed to improve the image of the utility or the industry,
including advertisement which inform the public concerning matters affecting the Company’s
operations, such as, the costs of providing service, the Company’s efforts to improve the quality of
service, the Company’s efforts to improve and protect the environment, etc. According to FERC,

825
OPC Ex. 1 (Szerszen Direct) at 73.
826
ETI Ex. 66 (Stokes Rebuttal) at 6-9.
827
OPC Ex. 1 (Szerszen Direct) at 66.
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such costs are properly includable in FERC Account 930.1 and are recoverable. According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.828

OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly. ETI did
provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in
FERC Account 930.1 and are, therefore, recoverable. The ALJs go with the weight of the evidence,
which is in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs
covered by these project codes are not recoverable.

Q. Transmission and Distribution Support Class

Dr. Szerszen challenged three project codes that are included within the Company’s
Transmission and Distribution Support Class of affiliate costs: (1) F3PCT53130 (Operations
Manager, Claims Management) for a disallowance of $42,287.50; (2) F3PCTDAMAG (Damage
Claims Of Entergy Property) for a disallowance of $5,555; and (3) F3PCTPUBLC (Public Claims)
for a disallowance of $3,968. Dr. Szerszen’s rationale for disallowing 50 percent of the costs in each
of these codes is the same. She believes that ETI’s property damage and workers compensation
claims should be direct billed instead of allocated through a customer count-based allocator;
managerial and supervisory costs should be allocated to the jurisdictions based on the jurisdictional
direct charges; and the Company has not met its burden of proof as to these charges.829

Ms. Tumminello addressed Project F3PCT53130, stating that workers’ compensation claims
are tracked by jurisdiction as Dr. Szerszen suggested, and are the basis for billing method
COMCLAIM. Project F3PCTWCOMP is used to capture the costs of workers’ compensation
claims, and bills to both regulated and non-regulated affiliates. Project F3PCT53130 captures costs
that are primarily for the oversight of the Entergy Companies’ Claims Management organization as
it relates to property damage and liability. These services benefit only the companies that serve

828
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
829
OPC Exhibit No. 1 (Szerszen Direct) at 79-80.
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retail electric and gas customers. Since only the regulated utility operating companies (and not the
non-regulated companies) serve retail customers, it is appropriate to bill these costs to the regulated
companies based on their pro-rata share of total customers.830

Projects F3PCTDAMAG and F3PCTPUBLC are addressed by ETI witness Corkran. With
respect to Project F3PCTDAMAG, Mr. Corkran stated that the costs associated with this project are
associated with the Public Claims employees in the Claims Management Organization. Those
employees pursue the recovery of claims allowed by law when the public inflicts damage to
Company property. The costs of this service are allocated among all of Entergy’s Operating
Companies through billing method CUSTEGOP, which allocates costs based on the number of
customers in each Operating Company. Dr. Szerszen claimed that the affiliate costs associated with
pursuing those claims should be directly charged to each Entergy Operating Company based on the
extent to which each claim pertains to the Operating Company instead of generally allocating the
costs to all utility customers. Mr. Corkran testified that the allocation methodology is appropriate
because the Public Claims employees provide knowledgeable, centralized, and consistent pursuit of
damage claims. The actual monies recovered for damage to ETI’s property are returned to ETI
ratepayers as credits against the cost of repairing those damaged facilities, i.e., the recoveries are not
allocated pursuant to CUSTEGOP. Only the Public Claims employees’ time and overheads are
allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time
spent by Public Claims employees in pursuing the recovery of claims is driven by the number of gas
and electric customers in each Operating Company.831

With respect to Project F3PCTPUBLC, Mr. Corkran stated that the costs associated with this
project are related to Public and Auto Liability employees in the Claims Management Organization.
These employees pursue the resolution and settlement of damage claims made against the Operating
Companies in a timely and fair manner through denials, negotiations, and payments. Such claims
include allegations of damaged appliances due to voltage fluctuation, food loss due to power
outages, and damage caused by Company vehicles (e.g., mailboxes, fence posts, and automobiles).

830
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 10.
831
ETI Ex. 48 (Corkran Rebuttal) at 13-15.
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This is an important process that ensures that only warranted and justifiable claims are paid. The
CUSTEGOP billing method is appropriate because the Public and Auto Liability employees provide
knowledgeable, centralized, and consistent resolution of damage claims. The actual payments
associated with ETI public damage claims are charged to ETI through the use of other project codes.
Only the Public and Auto Liability employees’ time and overheads are allocated pursuant to
CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public and Auto
Liability employees in processing claims is driven by the number of gas and electric customers in
each Operating Company.832

The explanations that ETI provides for the charges captured by these project codes and the
method of allocation employed makes sense to the ALJs. In a large organization, it is necessary to
have a group of people to process claims efficiently so that economies of scale can be realized; that
is what ETI is doing with these project codes. These costs benefit all companies within the Entergy
umbrella (or within the regulated entities portion as noted), so the allocation methodology employed
is appropriate. The ALJs recommend the Commission reject OPC’s challenge to the recovery of
these costs.

R. Tax Services Class

Dr. Szerszen proposed a 25 percent ($221,007) disallowance of costs billed to ETI from a
single project code in this Tax Services Class: Project Code F3PCF10445 (Entergy Consolidated
Tax Services). The costs in this project were incurred in the preparation, research, and other costs
associated with Entergy’s consolidated tax return. Dr. Szerszen testified that an assets-based
allocator is not appropriate for these costs and that the costs in the project should instead be directly
billed to each affiliate based on the time spent on preparing that affiliate’s income and expense
data.833

Company witness Galbraith, who sponsors ETI’s Tax Services Class, stated that Dr. Szerszen
apparently believes that all costs associated with the preparation of Entergy’s consolidated tax return

832
Id.
833
OPC Ex. 1 (Szerszen Direct) at 63.
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are captured by this project code and are allocated, when they should be direct-billed. Most of the
costs associated with preparation of Entergy’s consolidated tax return, according to Ms. Galbraith,
are assigned to other project codes and are direct billed. Ms. Galbraith then explained that:
(1) 56 percent of the time that Tax Services spent on the Entergy consolidated tax return were direct
billed through other project codes to the affiliates; (2) the project code also captures costs for tax
research (both federal and state and local), monthly closing activities not specific to one legal entity,
tax training that is not jurisdiction specific, compliance with file retention policy, and administration
staff time; and (3) why the assets-based allocator is the best method for allocating these departmental
costs. According to Ms. Galbraith, the costs captured by this code are not susceptible to direct
billing.834

The ALJs find that Dr. Szerszen did fail to consider that most of the costs of preparing
Entergy’s tax return are direct billed and that the costs covered by this project code are not
susceptible to such a billing, which is why they are allocated. The ALJs, therefore, recommend the
Commission reject OPC’s challenge to ETI’s allocation of these costs.

S. Transmission Operations Class

Dr. Szerszen challenged three project codes that are primarily within the Transmission
Operations Class: (1) F3PPTDHY19 (Dept. of Justice Investigations) for a disallowance of $765;
(2) F3PPTREORG (Transmission Re-Organization) for a disallowance of $3,661; and
(3) F3PPF30211 (ESI Transmission Bldg (Reclassification)) for a disallowance of $229,991.835

Dr. Szerszen addressed Project F3PPTREORG (Transmission-Reorganization) and testified
that costs covered by this project were incurred in 2009 and 2010 and, therefore, are not recurring.836
Ms. Tumminello responds that, while these particular costs do not recur every year, they are

834
ETI Ex. 26 (Galbraith Direct) at 10-12.
835
Project F3PPTDHY19 (Dept. of Justice Investigations) was discussed in Section VIII.L. (Legal Services
Class) and will not be repeated here
836
OPC Ex. 1 (Szerszen Direct) at 54, Schedule CAS-8.
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representative of normal recurring utility operations and do recur as necessary and, as such, they
should not be disallowed.837

Dr. Szerszen testified that Project F3PPF30211 (ESI Transmission Bldg.) captures interest
costs after the ESI transmission building was placed in service. She contends that the costs are
reclassified pre-Test Year payments and post-Test Year interest costs that are not known and
measureable.838 Ms. Tumminello testified that Dr. Szerszen has misconstrued accounting entries.
She explains that these charges capture 12 months of interest payments and the annual bond fee
incurred only during the Test Year.839

The ALJs find that the costs associated with Project F3PPTREORG are representative of
costs that recur every year and should not be disallowed. It appears to the ALJs that Dr. Szerszen
did misconstrue accounting entries in preparing her analysis of Project F3PPF30211and that the
charges in that project capture fees paid during the Test Year. Accordingly, the ALJs recommend
that OPC’s proposed disallowance be denied.

T. Treasury Operations Class

Dr. Szerszen challenged three project codes that are primarily within the Treasury Operations
Class: (1) F5PCZZI07P (Directors & Officers (EIM)) for a disallowance of $14,483;
(2) F3PCF25300 (Daily Cash Mgt Activities) for a disallowance of $7,286; and (3) F3PCF26022
(Financing & Short Term Funding) for a disallowance of $96,700.

With respect to Project F5PCZZ107P (Directors & Officers (EIM)), Dr. Szerszen testified
that the directors and officers liability insurance subject to this project code is primarily aimed at

837
ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 1.
838
OPC Ex. 1 (Szerszen Direct) at 71.
839
ETI Ex. 69 (Tumminello Rebuttal) at 15. See also Ex. SBT-R-5.
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benefiting shareholders, rather than ratepayers and, because ETI does not manage ESI’s operations,
it should not be responsible for indemnifying against shareholder lawsuits.840

ETI witness McNeal stated that ESI provides essential administrative and operational
services to ETI on a daily basis. To do this, it must employ (and retain) qualified officers and
directors. These individuals must be assured that they can make reasoned decisions without fear of
personal liability and the manner to provide them this assurance is to purchase director’s and
officer’s liability insurance. Because ETI benefits from the services provided by the officers and
directors, ETI argues, it is appropriate to allocate a portion of the cost of the director’s and officer’s
liability insurance to ETI.841

Dr. Szerszen addressed Projects F3PCF25300 (Daily Cash Mgt Activities) and F3PCF26022
(Financing & Short Term Funding), contending that these projects are duplicative of ETI-specific
financing and cash management activities; that these costs should be borne by Entergy shareholders;
and that the bank accounts-based and level of service-based allocators applicable to this projects are
not appropriate.842

ETI responds that Project F3PCF25300 captures costs for activities performed by the Cash
Management Department for work associated with maintaining bank relationships, bank fee
analysis, administrative of bank systems and controls, and all other banking and cash management
activities that are general in nature. These are not specific to any one company, but are applicable to
all of the companies within the umbrella of the Entergy corporate family. There are Company-
specific activities that are charged directly to ETI under different project codes, and this constitutes
the majority of financing and cash management activities during the Test Year. For
Project F3PCF25300, the costs are driven by cash management products and services delivered to all
the Entergy companies. Because the number of transactions executed on behalf of each Entergy
company is directly related to the number of bank accounts by company irrespective of account size,

840
OPC Ex. 1 (Szerszen Direct) at 59.
841
ETI Ex. 61 (McNeal Rebuttal) at 7-8.
842
OPC Ex. 1 (Szerszen Direct) at 74-75, Ex. CAS-15.
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billing method BNKACCTA, which allocates costs based on the number of open bank accounts is,
according to ETI, the appropriate method to allocate the costs of these services.843

With respect to Project F3PCF26022, ETI explains that the project code captures costs for
managing Entergy companies’ liability portfolios comprised of Entergy company securities, bank
lines, and project financings. The work is performed for the benefit of all companies under the
Entergy corporate umbrella, not just ETI and is not duplicative of services performed for ETI. When
work is performed by ESI personnel that relates specifically to ETI, then ETI is charged directly
under a different project code. The services include analyzing and supporting general capital
structure policy, developing and analyzing general financial policies, investigating and evaluating
financing options generally that might prove beneficial for any or all Entergy companies, including
ETI, and facilitating ongoing administration related to all Entergy Operating Company financings.
Accordingly, ETI argues that it is appropriate to allocate a share of those costs to ETI. The costs of
this project are driven by the level of service needed to complete the project or activity. Allocator
LVSVCAL allocates costs based upon the overall service level of ESI. This allocation is appropriate
because ESI is providing the service and no one Operating Company alone benefits from the
services provided under this project code.844

OPC appears to have taken too narrow a view with respect to these project codes. First, it
appears that where services are performed solely for ETI, they are charged to ETI through specific
project codes. The project codes that OPC challenges are for company-wide services that are
partially allocated to ETI. It is logical to assume that a certain level of services can be performed
more efficiently at a company-wide level and that Texas ratepayers will benefit by paying only the
allocated portion of those costs, as is done in these cases. The allocators chosen by ETI appear to
reasonably reflect the cost-causation. Therefore, the ALJs recommend that OPC’s challenge be
rejected.

843
ETI Ex. 61 (McNeal Rebuttal) at 3-6; Tr. at 546.
844
ETI Ex. 61 (McNeal Rebuttal) at 2-3; Tr. at 547-548.
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U. Utility and Executive Management Class

OPC challenges five project codes that are primarily within the Utility & Executive
Management Class: (1) F3PPCCS010 (Climate Consulting Services) for a disallowance of $19,821;
(2) F3PCCPM001 (Corporate Performance Management) for a disallowance of $173,867;
(3) F3PCC31255 (Operations-Office of the CEO) for a disallowance of $372,919; (4) F3PPCAO001
(Chief Administrative Officer) for a disallowance of $177,156; and (5) F3PPCOO001 (Chief
Operating Officer) for a disallowance of $74,485.

As to the first, Project F3PPCCS010 (Climate Counseling Services), Dr. Szerszen testified
that these costs are incurred for the development of company-wide environmental policies,
procedures, and programs; that expenses are improperly allocated to the subsidiaries based on each
company’s fossil operating capacity; and, as a result, the non-regulated affiliates are not allocated
any environmental initiative expenses. She therefore recommended that 50 percent of this project’s
costs be disallowed.845

ETI witness Stokes addressed Dr. Szerszen’s challenge to this project. Ms. Stokes explained
that although nuclear-related environmental projects are being pursued, they are not being pursued
using the project code referenced by Dr. Szerszen in her challenge. The costs for non-regulated
affiliates are charged to projects not included in ETI’s affiliate costs in this case. Non-regulated
affiliates use project codes specific to their businesses to maintain a separation of costs between
regulated and non-regulated Entergy subsidiaries.846

For the remaining four project codes in this class, Dr. Szerszen stated that executive
management is primarily concerned with overall corporate functions rather than issues for any one
specific subsidiary, and there is no relationship between an assets-based allocator and executive
management.847

845
OPC Ex. 1 (Szerszen Direct) at 62.
846
ETI Ex. 66 (Stokes Rebuttal) at 5.
847
OPC Ex. 1 (Szerszen Direct) at 56, 60.
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ETI responds to these arguments by stating that the functions covered by these project codes
relate to the oversight of all system operations and the stewardship of corporate assets and that
because ETI is part of a corporate group, the allocated charges associated with these services are
relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based
allocator is appropriate because it reflects the cause of the costs incurred, in that, services provided
relate to the stewardship of all the corporation’s assets.848

A corporation cannot function without executives, who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class
costs that she challenges are reasonable and necessary costs that are allocated to ETI based on a
logical allocator – the assets the executives manage. The ALJs recommend that OPC’s challenge be
rejected.

IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order
Issue No. 13]

Jurisdictional cost allocation involves the proper method for allocating production costs
between ETI’s Texas retail customers and its wholesale customers, which are subject to FERC
jurisdiction. During the Test Year, ETI provided electric service to retail customers and to three
wholesale customers—including ETEC—under service agreements and rates approved by FERC.
ETEC is a partial requirements customer, and it will be ETI’s only wholesale customer during the
Rate Year. ETI estimated its cost of serving wholesale customers in a jurisdictional separation study
that split ETI’s cost of service between retail and the wholesale jurisdictions.849

To calculate the wholesale cost allocation factor, ETI proposed the use of 150 MW for the
wholesale load. This results in a retail production demand allocation factor of 95.3838 percent. The
150-MW load represents the contractual minimum amount of capacity for which ETEC is obligated

848
ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
849
Cities Ex. 4 (Goins Direct) at 4.
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to pay under its partial requirements agreement. No party contests this aspect of ETI’s proposed
allocation of costs between retail and wholesale customers.850

However, Cities contest the type of allocation methodology used to assign demand-related
(fixed) production costs to each jurisdiction. In this proceeding, ETI used the A&E 4CP allocation
method. Although this is the same methodology ETI used in this proceeding’s class cost-of-service
study (to assign demand-related production costs to each retail customer class), ETI used a different
methodology – 12 Coincident Peak (12CP) – in its last rate case to assign costs between
jurisdictions.851

A. A&E 4CP

Kroger witness Kevin C. Higgins explained the A&E 4CP method:

[T]he Average and Excess Demand method uses an average demand or total energy
allocator to allocate that portion of the utility’s generating capacity that would be
needed if all customers used energy at a constant 100 percent load factor. The cost
of capacity above average demand is then allocated in proportion to each class’s
excess demand, where excess demand is measured as the difference between each
class’s individual peak demand and its average demand. In this manner, the
incremental amount of production plant that is required to meet loads that are above
average demand is assigned to the users who create the need for the additional
capacity. . . . the A&E/4CP variant . . . uses 4 CP to measure excess demand,
whereas the conventional version uses class non-coincident peak . . . .852

ETI witness Myra L. Talkington also explained that the A&E 4CP method, noting that ETI’s
coincident peak demand is measured for the months of June through September. Ms. Talkington
recommends the A&E 4CP allocation because it “reasonably reflects the mix of the Company’s
customers and their respective electrical load characteristics and the relative cost incurred to serve

850
ETI Ex. 7 (May Direct) at 23-24. Ms. Talkington used the 150 MW number sponsored by Mr. May, and
the associated energy use, to calculate the jurisdictional allocation factor. ETI Ex. 22 (Talkington Direct)
at 11-12.
851
Cities Ex. 4 (Goins Direct) at 10.
852
Kroger Ex. 2 (Higgins Cross Rebuttal) at 3 (footnotes deleted).
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such loads.”853 She also believes this allocation methodology provides a reasonable balance
between the contribution to the system peak and energy requirements.854

As noted above, ETI’s use of A&E 4CP is a change from the 12CP methodology it used
when it operated within two states. Ms. Talkington testified that 12CP was appropriate in the past
because System Agreement costs were allocated between Entergy Operating Companies using 12CP.
The Texas retail portion of the production costs were then allocated between the retail classes using
the A&E 4CP methodology (as ETI is doing in this case). However, according to Ms. Talkington,
now that ETI operates in only one state, no jurisdictional allocation among states is necessary;
therefore, only one allocation methodology, i.e., A&E 4CP, should be used to allocate production
costs between the retail classes and the wholesale jurisdiction. Ms. Talkington testified that the
A&E 4CP methodology factors in year-round demand through the average and excess function and
also matches the allocator used to allocate costs within the retail class.855

Cities opposes the use of A&E 4CP and suggest a 12CP methodology is preferable.
Commission Staff does not oppose ETI’s use of A&E 4CP. No other party takes a position on this
issue.

B. 12CP

The12CP methodology allocates production capacity costs in proportion to each class’s
demands that occur on the date and time of ETI’s system peak in each of the 12 months.856 Cities
believe it is more appropriate for ETI to allocate fixed production costs between the wholesale
customers and Texas retail customers using 12CP. Cities witness Dennis W. Goins testified that the
12CP approach is consistent with the cost-of-service approach FERC typically uses to allocate
demand-related production costs reflected in wholesale rate schedules, and it is consistent with the
assignment of MSS-1 costs (as well as MSS-2 transmission costs) to ETI under the Entergy System

853
ETI Ex. 23 (Talkington Direct) at 6; OPC Ex. 6 (Benedict Direct) at 17.
854
ETI Ex. 23 (Talkington Direct) at 6.
855
ETI Ex. 67 (Talkington Rebuttal) at 6-7.
856
TIEC Ex. 3 (Pollock Cross Rebuttal) at 26.
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Agreement. Dr. Goins reviewed ETI’s Rate Year purchased power capacity costs month by month.
He determined that ETI’s heavy reliance on capacity purchases to serve retail and wholesale load,
and the relative stability of those projected monthly purchased power capacity costs, suggest that the
12CP method should properly split ETI’s demand-related production costs between the Texas retail
and wholesale jurisdictions.857

Dr. Goins calculated Test Year 12CP allocation factors for the Texas retail and wholesale
jurisdictions, and provided them to Cities witness Karl Nalepa for inclusion in his jurisdictional
separation study. He determined the following:858

Jurisdiction A&E 4CP 12CP
Texas Retail 95.3838% 94.6208%
Wholesale 4.6162% 5.7923%
Total 100% 100%

In making this calculation, Dr. Goins used a loss-adjusted 150 MW (ETEC’s monthly
billing MW) as a proxy for the 12 monthly CPs. In his view, the 150 MW is indicative of ETI’s
capacity obligations to ETEC, and it reflects known and measurable changes compared to test-year
wholesale CPs (which would include CPs for wholesale customers that ETI no longer serves).859

Cities point out that ETI previously allocated production costs to the wholesale jurisdiction
on a 12CP basis. ETI first requested that the Commission change the 12CP method in Docket
No. 37744.860 According to Cities, ETI’s request to change the 12CP methodology in Docket
No. 37744 is significant because ETI’s wholesale load consisted of Brazos Electric Cooperative, Inc.
(Brazos) and ETEC. The Brazos contract assigned Brazos’ share of ETI’s production costs based
upon a 12CP allocator. Thus, contends Cities, all costs that would have been over-allocated to retail

857
Cities Ex. 4 (Goins Direct) at 10-12.
858
Cities Ex. 4 (Goins Direct) at 12.
859
Cities Ex. 4 (Goins Direct) at 10-12.
860
The parties in that docket stipulated the majority of issues in the case, including issues relating to
jurisdictional allocation.
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customers would have been pocketed by ETI (if the 12CP allocator had changed). Cities argue that
ETI’s request to deviate from its approved 12CP allocator will result in retail customers subsidizing
production costs. Dr. Goins calculated that the 12CP allocation factor for ETI’s wholesale
jurisdiction is approximately 5.38 percent versus 4.62 percent under the A&E 4CP method.861 Cities
conclude that retail customers will subsidize the difference between the two allocators, which is
0.76 percent. Because the allocation is applied to all production costs, including purchased power
capacity costs, the 0.76 percent difference is significant, contend Cities.

According to ETI, Cities’ arguments are based on a non-existent situation—the provision of
service to Brazos—and should be rejected. The ALJs acknowledge that ETI is no longer serving
Brazos. Dr. Goins noted such in his testimony. Rather, the basis for his recommendation was:
(1) the 12CP approach is consistent with FERC’s wholesale rate allocation; (2) the 12CP method is
used to derive each Entergy Operating Company’s load responsibility ratio and share of monthly
MSS-1 and MSS-2 charges; and (3) ETI’s purchased power capacity costs do not vary significantly
month to month. Although Ms. Talkington understood that the A&E 4CP methodology is the same
one used to allocate production costs between classes, TIEC witness Pollock noted that it is often not
appropriate to use the same allocation method for both jurisdictional and class allocations. He noted
that, in jurisdictional separation, allocations are between retail and wholesale entities, with
wholesale subject to FERC regulation.862 ETI did not fully explain why A&E 4CP is the best
methodology for allocation production costs between the retail and wholesale jurisdictions.
Dr. Goins’ and Mr. Pollock’s testimonies were ultimately more persuasive on this issue.
Accordingly, the ALJs recommend the use of 12CP to allocate capacity-related production costs
between the retail and wholesale jurisdictions.

861
Cities Ex. 4 (Goins Direct) at 11-12.
862
TIEC Ex. 3 (Pollock Cross Rebuttal) at 29. The ALJs acknowledge that Mr. Pollock does not contest
ETI’s use of the A&E 4CP jurisdictional allocation methodology—rather, his testimony was explaining why
12CP is not appropriate as an allocator among the different customer classes.
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X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary
Order Issue No. 1]

ETI witness Talkington testified regarding the allocation methods for each of the major
function/classification cost categories used in the Company’s retail class cost-of-service study.
Ms. Talkington also sponsors ETI’s proposed rate design. Contested issues are set out below.

A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19]

The Legislature has established a goal for the installation of an additional 5,000 MW of
generating capacity from renewable energy technology. It also set out annual goals for electric
utilities to meet on a cumulative basis in order to encourage the development of renewable energy
generation in Texas.. A utility may meet its annual goals by installing generation, by purchasing
capacity based on renewable energy technology, or by purchasing sufficient renewable energy
credits (RECs).863

1. ETI’s Proposed Cost Recovery

Staff witness William B. Abbott explained that the Company currently recovers its REC
costs through base rates. Each credit represents one megawatt-hour (MWh) of renewable energy
that meets certain criteria set forth in P.U.C. SUBST. R. 25.173(e), and these credits can be traded
among participants in the Texas market. ETI proposes to remove these costs from base rates and
implement a REC Rider to recover its projected REC costs. After the initial rider is established, the
REC Rider would be reset annually to recover projected REC costs for the upcoming year, adjusted
by any past over- or under-recovery and any revenue-related expenses.864 With the introduction of
the REC Rider, ETI would withdraw its current Renewable Portfolio Standard Calculation Opt-Out
Credit Rider, which provides a credit to offset the base rate REC costs for certain customers who are

863
PURA §39.904(a) and (b).
864
See ETI Ex. 31 (LeBlanc Direct) at 26.
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exempt from paying REC costs. These customers would instead be exempt from charges under the
proposed REC Rider.865

ETI suggests that a rider is necessary because the level of REC costs incurred from year to
year is not known, and the cots are unknowable and very volatile. ETI witness Heather G. LeBlanc
testified that certain customers can opt out, and a rider is the most efficient manner to administer
such opt out.866

Initially, ETI based its rates for the proposed rider on the Company’s Test Year renewable
energy credit costs, which were incurred on a Texas retail basis for the 12 months ending June 30,
2011. ETI requested $623,303 and, after applying the revenue-related expense factor of 1.01307,
proposed a revenue requirement of $631,450.867 In rebuttal testimony, Ms. LeBlanc stated that the
Company’s proposal should be updated to reflect the most current data available. She stated that
“events” since the Company’s initial filing in November 2011 caused costs for the Company to
increase.868 She calculated an updated amount of $1,145,043, which, when the revenue-related
expense factor is applied, results in an updated revenue requirement of $1,160,008.869 She believes
that the updated amounts further support the Company’s position that REC costs are volatile.

2. Opposition to ETI’s Proposal

Cities, OPC, State Agencies, and Commission Staff oppose ETI’s proposed REC Rider.

State Agencies argue that ETI’s proposed REC Rider should be rejected because it deviates
from the Commission’s ratemaking policies and is inconsistent with PURA. State Agencies witness
Kit Pevoto testified that the proposed rider is not appropriate because: (1) the rider is piecemeal
ratemaking, which deviates from the Commission’s traditional ratemaking policies and is

865
Staff Ex. 7 (Abbott Direct) at 11-12.
866
ETI Ex. 31 (LeBlanc Direct) at 25.
867
Id. at 24. This amount is then divided by all non-transmission level kWh sales.
868
ETI Ex. 55 (LeBlanc Rebuttal) at 10-11.
869
Id. at 11. This amount is then divided by all non-transmission level kWh sales.
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inconsistent with PURA; (2) the reconciliation (true-up) process in the proposed tariff is not
specifically provided for by PURA or PUC rule, or required to implement the REC process; (3) the
redetermination of rates in the proposed annual filings would be based on projected or estimated
costs, rather than historical test year costs; which is not in compliance with PURA or the
Commission’s rules; and (4) ETI has not justified the need to have a rate recovery for REC costs
outside of the traditional PURA base rate recovery. Ms. Pevoto explained that the traditional test
year cost of service ratemaking process, including regulatory lag, helps to match costs and revenues
and to provide incentives that balance the utility’s and its customers’ interests. The proposed REC
rider deviates from the traditional PURA rate-setting because it allows the Company to reset its rates
automatically each year without going through a comprehensive rate proceeding. In her view, the
rider would eliminate the regulatory lag incentive for ETI to prudently manage these costs because
the rider allows for annual cost recovery adjustments. Ms. Pevoto observed that various provisions
in PURA authorize riders for collection of other expenses, but no such provision exists for recovery
of REC expenses, even though the Legislature mandated that utilities be responsible for a certain
level of REC MWs. And she noted that if ETI’s REC expenses increase due to increases in total
REC MW requirements, ETI can request to include those increased costs in a future rate case.870

In reference to Ms. LeBlanc’s rebuttal testimony that “events” caused ETI’s REC costs to
increase, State Agencies contend that ETI may have paid more for RECs during the Test Year
because it contacted suppliers only after the REC requirement was mandated. ETI acknowledged
that RECs were in the $1.10 to $1.25 range at the beginning of the year and then appreciated to over
$2.00 and peaked out at $2.55 in the first quarter of 2012. Moreover, one of the largest REC
suppliers unexpectedly withdrew its offers in March of 2011, which also led to price increases.
March 31 is the end of the compliance period, and the deadline may increase the volume of
purchases, which can add to price increases.871 State Agencies note that ETI did not participate in
the competitive REC market until February 2012 and bought its RECs near the peak price. State
Agencies contend that only Test Year costs of $623,303 should be included in base rates.

870
State Agencies Ex. 2 (Pevoto Direct) at 6, 8-11.
871
State Agencies Ex. 12, RFI.
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Cities witness Karl Nalepa also opposed the REC Rider. He testified that the Commission
should not permit ETI to single out REC costs from base rates because it presented no evidence that
these costs should be treated differently than they are now. He added that RECs are not related to
fuel so much as they are related to retail sales and plant output. In his opinion, the Test Year amount
for REC of $633,985 should be included in base rates.872 Cities witness James Z. Brazell also
testified that ETI currently recovers a large portion of its revenues through non-fuel piecemeal
riders. While he believes some riders are necessary and appropriate, ETI’s general movement of cost
recovery from base rates to riders (as evidenced in this proceeding) is inconsistent with PURA and
the prohibition against piecemeal ratemaking.873

OPC also opposed ETI’s proposed REC Rider on the basis that it constitutes piecemeal
ratemaking. OPC witness Nathan A. Benedict noted that in Project No. 35628, the Commission
rejected alternative mechanisms for the recovery of REC costs but reserved the right to consider the
issue at a later date.874 He stressed that, when rejecting alternative recovery mechanisms for REC
costs, the Commission recognized that REC costs are variable, that the purchase of RECs is
mandated by law, and that certain customers can opt out of the Renewable Portfolio Standard
program. Thus, in Mr. Benedict’s view, the Commission has already rejected the arguments
advanced by ETI here. He added that ETI did not indicate a negative and substantial impact as a
result of transmission customers opting out of the Renewable Portfolio Standard program, and ETI
appears to be currently administering the program effectively without REC Rider. In short,
Mr. Benedict concluded that costs related to renewable energy credits should be recovered through
base rates, and ETI’s current opt-out rider should continue as the vehicle for ETI to handle
transmission-level opt-outs.875

872
Cities Ex. 6 (Nalepa Direct) at 30-32. Mr. Nalepa’s figure of $633,985 differs from that the figure of
$623,303 found in ETI’s testimony at ETI Ex. 31 (LeBlanc Direct) at 24 and State Ex. 9.
873
Cities Ex. 1 (Brazell Direct) at 14-16.
874
OPC Ex. 6 (Benedict Direct) at Ex. NAB-8, Project No. 35628, Rulemaking Relating to Industrial
Customer Opt-Out of Renewable Portfolio Standard, Order at 6 (December 4, 2008).
875
OPC Ex. 6 (Benedict Direct) at 37-41. ETI currently has a Renewable Portfolio Standard Calculation
Opt-Out Credit Rider to credit REC costs collected in base rates from transmission level customers who have
opted out of the program.
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Commission Staff also opposes ETI’s request, stating that it amounts to unauthorized
piecemeal ratemaking that should be disallowed. In Staff’s view, the existing opt-out rider should be
maintained but updated to reflect the test year data used to set the ETI’s base rates. Because ETI’s
proposed rider would include a true-up provision that would guarantee recovery of all of its REC
costs, Staff witness Abbott testified that it would violate PURA § 36.051, which provides the utility
a reasonable opportunity to earn a reasonable return on invested capital but does not guarantee full
recovery of all costs. Mr. Abbott acknowledged that the Legislature has authorized the recovery of
certain specific costs outside of base rates, but no such authorization exists for the recovery of REC
costs.876

In addition, Mr. Abbott criticized the proposed REC rider because in the future it would
allow prospective recovery of estimated REC costs. He believed that such an arrangement would
eliminate any regulatory lag and thus eliminate any incentive for ETI to minimize the costs of
purchasing the required RECs.877 Mr. Abbott also pointed out that the proposed rider contains a
single rate for all customer classes and includes a “revenue related expense factor,” which increases
the overall rider revenue requirement to, in part, account for projected uncollectable bills.878 This
would shift the costs of uncollectable bills from customer classes with greater bad debt onto
customer classes with lower bad debt. Further, Mr. Abbott stated, the proposed true-up portion of
the REC Rider would eliminate the need for a bad debt factor, as any actual under-collected amounts
would carry forward and could be recovered in future filings. Also, the single rate could result in
cost-shifting between customer classes, as over- or under- recoveries resulting from billing
determinant forecast error would vary by customer class. Finally, Mr. Abbott stated, the ETI’s
proposed billing determinants are based on a historical year. But if load grows over the long term,

876
Staff Ex. 7 (Abbott Direct) at 12-13. Mr. Abbott cites to PURA §§ 36.203 (Fuel Cost Recovery), 36.205
(Purchased Power Cost Recovery), 36.209 (Transmission Cost Recovery), 36.210 (Distribution Cost
Recovery), 39.107(h) (Advanced Meter Deployment Surcharge), 39.461 (Hurricane Reconstruction Costs),
39.905(b)(1) (Energy Efficiency Cost Recovery).
877
While the price of RECs at any point in time are set by the market, presumably a purchaser has some
ability to seek relatively better terms—such as making an effort to accurately forecast the number of credits
required and perhaps purchasing or contracting to purchase available credits beforehand if prices are
favorable, seeking volume discounts, banking excess credits when prices are favorable, etc.
878
Schedule Q-8.8 at 45.4.
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this will lead to persistent over-recovery of the REC Rider revenue requirements, as Rate Year
billing determinants will tend to exceed the historical billing determinants systematically.879

Based on these concerns, Mr. Abbott recommended that the Commission deny ETI’s request
for a REC Rider, and that the ETI’s Test Year REC costs of $623,303 be included in base rates.
Additionally, he recommended that the Renewable Portfolio Standard Calculation Opt-Out Credit
Rider should be maintained; however, the credit rates should be updated to reflect the Test Year data
used to set ETI’s base rates. In the alternative, if the Commission approves the REC Rider requested
by ETI, Mr. Abbott recommended the following changes from the Company’s request:

¾ The REC Rider should be set every year to collect the previous year’s actual REC
costs (instead of projected REC costs), plus any over- or under- recovery from prior
periods.

¾ The previous year’s actual REC costs should be allocated to each customer class
based upon each class’s actual energy usage over the time period for which the RECs
were acquired.

¾ Any over- or under- recovery balances should be tracked by each customer class, and
thus a separate REC Rider rate should be calculated for each customer class based on
that class’s allocated REC costs adjusted by that class’s over- or under- recovery
balance.

¾ The REC Rider rates should be calculated using billing determinants based upon
ETI’s best forecast of each customer class’s energy usage over the rider’s Rate
Year.880

3. ETI’s Response

ETI contends that adoption of the rider does not result in piecemeal ratemaking because these
are the types of costs that the Company cannot control. Ms. LeBlanc believes that there is a greater

879
Staff Ex. 7 (Abbott Direct) at 13-14.
880
Staff Ex. 7 (Abbott Direct) at 14-15.
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risk of over-recovery of REC costs through base rates than there would be under the proposed
rider.881

As to the issue that the Company would be disincentivized to purchase RECs at an
appropriate time, ETI claims that the proposed rider has a true-up mechanism that would allow for
review. ETI disputes State Agencies’ claims that ETI could have purchased RECs at a lower level at
other points in the year, stating there is no evidence that the Company could have bought RECs at a
lower level at other points in the year.

Finally, ETI takes issue with the parties’ argument that there is no statutory recovery for
REC costs outside of base rates. ETI argues that there is no statutory authority requiring the
Company to refund costs to opt-out industrial customers. According to ETI, no explicit statutory
authority is necessary, and the parties have failed to establish that any harm would result from
implementation of the rider.

4. ALJs’ Analysis

The ALJs are persuaded by the testimonies of Staff and intervenor witnesses Pevoto, Nalepa,
Abbot, Benedict, and Brazell that ETI’s proposed REC rider should be rejected. The testimony
supports a finding that adoption of the rider results in piecemeal ratemaking. ETI’s argument that
costs are volatile and, therefore, should be isolated and recovered in a manner similar to an annual
fuel factor filing was not supported by sufficient evidence. Additionally, the ALJs agree that the
proposed rider eliminates any incentive for ETI to minimize the costs of purchasing the required
RECs. ETI proffered unconvincing argument and insufficient evidence that standard cost recovery
was insufficient for ETI to recover its total REC costs and a reasonable return.

The ALJs further find that the Test Year expense of $623,303 should be used for setting rates
in this case.882 ETI failed to proffer sufficient evidence and argument to support any increase to its

881
ETI Ex. 55 (LeBlanc Rebuttal) at 11.
882
This is the amount referenced in Ms. LeBlanc’s testimony at ETI Ex. 31 at 24 and confirmed in State
Agencies Ex. 9.
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initial request through rebuttal testimony. As recommended by Staff witness Abbott, the Renewable
Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the
credit rates to reflect the Test Year data used to set ETI’s base rates.

B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14]

A cost-of-service study is an analysis used to determine the responsibility for a utility’s costs
for each customer class. Thus, it determines whether the revenues a class generates cover that
class’s cost-of-service. A class cost-of-service study separates the utility’s total costs into portions
incurred on behalf of the various customer groups. Most of a utility’s costs are incurred to jointly
serve many customers. For purposes of rate design and revenue allocation, customers are grouped
into homogeneous classes according to their usage patterns and service characteristics.

The parties generally agreed that ETI’s cost-of-service study comported with accepted
industry practices, but some parties had issues with specific items discussed below.

1. Municipal Franchise Fees

Municipal Franchise Fees (MFF) are charges for a utility’s use of municipal rights-of-way.
The charges are levied by municipalities based on the amount of electricity sold within the municipal
boundaries. They are also referred to as street rental taxes. The MFF charged to ETI are based on
ordinances passed by the cities in which ETI makes retail sales. Different cities have enacted
different levels of MFF on in-city kWh sales, ranging from 0.0956¢ to as much as 0.2644¢ per
kWh.883 For the portion of fees ETI collects through base rates, ETI proposes to allocate among
customer classes based on customer class revenues relative to total revenues.884 Once MFF costs are

883
TIEC Ex. 1 (Pollock Direct) at 52 and Ex. JP-9. Nineteen cities also charge MFF through separate
“Incremental Franchise Fee Recovery” Riders. These incremental MFF are not included in ETI’s proposed
revenue requirements in this case. TIEC Ex. 1 (Pollock Direct) at 53.
884
Schedule P-13 at10, lines 32-33; the allocation factor “RSRRTOA-Total” is rate schedule revenue.
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allocated to the rate classes, ETI proposes to collect the costs from all customers regardless of their
geographic location.885

ETI proposes the same allocation and collection of MFF in this case as was approved by the
Commission in Docket No. 16705, ETI’s last litigated rate case.886 The positions of the parties, as
set out in testimony and briefs, are listed below:

Party/Precedent MFF Allocation Between Collection of MFF Expenses From:
Customer Classes By:
ETI Total revenues All customers
Cities Total revenues All customers
OPC kWh sales in city All customers
Staff kWh sales in city All customers
TIEC Franchise fee payments in city Only from municipal customers
Docket No. 16705 Total revenues All customers

(a) MFF Allocation Between Customer Classes

Cities and ETI recommend adoption of ETI’s proposal to allocate to customer classes based
on total rate schedule revenues, which the Commission approved in Docket No. 16705. ETI notes
that it is following Commission precedent, and it opposes the use of different allocation factors for
these FERC accounts: Account 408.152, Franchise Tax State; Account 408.154 Franchise Tax
Local; and Account 408.163, Street Rental.

OPC witness Benedict testified that MFF should be allocated on the basis of in-city kWh
sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale
occurred. Staff witness Abbot concurs. Stated differently, Messrs. Benedict and Abbot suggest

885
OPC Ex. 8 (Benedict Cross Rebuttal) at 9.
886
Application of Entergy Gulf States, Inc. for Approval of Its Transition to Competition Plan and the Tariffs
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to
Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, Second Order on Rehearing at 98
(FoF 224) (Oct. 13, 1998).
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allocating MFF relative to each class’s inside-city kWh sales with the same MFF per unit cost (i.e.,
0.1965¢ per kWh) for all customer classes.887 Mr. Benedict noted that this allocation method is
based on Commission precedent, as indicated in the recent CenterPoint rate case, Docket No. 38339:

CenterPoint’s allocation of municipal franchise fees to the customer classes based
upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers
within the customer class is reasonable and consistent with Commission precedent.888

Mr. Benedict also noted that allocating on the basis of in-city kWh sales is consistent with PURA
§ 33.008(b).889

Commission Staff supports Mr. Benedict’s analysis. Staff points out that PURA § 33.008(b),
which authorizes the collection of municipal franchise fees, states that “[t]he compensation a
municipality may collect from each electric utility . . . shall be equal to the charge per kilowatt hour .
. . times the number of kilowatt hours delivered within the municipalities boundaries.”890 According
to Staff, PURA § 33.008(b) plainly links the amount of municipal franchise fees to each class’s
in-city kWh sales. Moreover, the Commission has an established policy of allocating municipal
franchise fees based on in-city kWh sales.891 According to Staff, the Commission should reaffirm

887
See OPC Ex. 7 (Benedict Cross Rebuttal) at 4-5; Staff Ex. 7 (Abbott Direct) at 22; TIEC Ex. 3 (Pollock
Cross Rebuttal) at 34.
888
OPC Ex. 6 (Benedict Direct) at Ex. NAB-1, Application of CenterPoint Electric Delivery Company, LLC,
for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 34, (FoF 179) (June 23, 2011).
889
OPC Ex. 7 (Benedict Cross Rebuttal) at 5.
890
PURA § 33.008(b)(emphasis added).
891
Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA
§ 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350, Order at FoF 156
(Oct. 4, 2001). The Commission reached an identical conclusion in Application of Reliant Energy HL&P for
Approval of Unbundled Cost of Service Rate Pursuant to PURA 39.201 and Public Utility Commission
Substantive Rule 25.344, Docket No. 22355, Order at FoF 222A (Oct. 4, 2001). More recently, Application of
CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on
Rehearing at FoF 179 (June 23, 2011) (stating that “CenterPoint’s allocation of municipal franchise fees to the
customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers
within the customer class is reasonable and consistent with Commission precedent.”).
Staff notes in their initial brief that the Commission has further indicated that this allocation should be
conducted without any adjustment for differences in the rates charged by individual municipalities within a
utility’s service territory. Application of AEP Texas Central Company for Authority to Change Rates, Docket
No. 33309, Order on Rehearing at FoF 150 (Mar. 4, 2008) (stating in connection with a proposed municipal
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 265
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this precedent in this case by allocating ETI’s MFF to each customer class on the basis of in-city
kWh sales.

TIEC witness Pollock disagrees with OPC’s and Staff’s proposed allocation method,
although Mr. Pollock stated their proposal was better than ETI’s proposed allocation. He believes
OPC’s and Staff’s proposal fails to recognize the different MFF rates charged by cities. Because
cities that have a preponderance of industrial sales generally charge lower MFF rates, this proposal
would require LIPS customers to pay 0.1965¢ per kWh, which is more than the weighted average
MFF cost to the LIPS class of 0.1612¢ per kWh. Thus, Mr. Pollock argues that this would require
LIPS customers to subsidize other customer classes and would not be consistent with cost causation.
Mr. Pollock thought his proposal to allocate MFF by city by class resulted in each customer class
paying only the MFF expenses actually incurred.892

The ALJs find OPC’s and Staff’s proposed allocation methodology best comports with
PURA § 33.008 and Commission precedent. As noted by Mr. Benedict, PURA was amended after
the Commission’s decision in Docket No. 16705, which allocated MFF on the basis of rate schedule
revenue. PURA § 33.008 expressly calls for a kWh basis for allocation and this is confirmed in the
cases litigated since Docket No. 16705, which were cited by Commission Staff. Accordingly, the
ALJ recommend that MFF be allocated on the basis of in-city kWh sales, without an adjustment for
the MFF rate in the municipality in which a given kWh sale occurred.

(b) MFF Collection

All parties except TIEC recommend that the Commission approve ETI’s proposed allocation
of franchise fee rentals to all customers. Cities witness Mr. Brazell testified that franchise fees are in
the nature of a rental, not a tax, and like all rental charges ETI incurs, the expense should be spread
among all customers. He stated that MFF charges have always been collected from all customers,
whether or not they take service within the corporate limits, except for the limited incremental

franchise fee expense rider that “[h]aving different rates in each municipality in TCC’s service territory is
contrary to the Commission’s desire for uniform, simple rates”).
892
TIEC Ex. 3 (Pollock Cross Rebuttal) at 8, 33-35.
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franchise fees specifically addressed by PURA § 39.456. Mr. Brazell explained that electrical
facilities within ETI’s system are physically interconnected and electrically synchronized. The
facilities located within a city’s boundaries are not isolated physically or electrically from the
facilities outside the city limits. Rather, they are tied to one another and function as a single
integrated system, and ETI’s facilities inside each city benefit all customers in ETI’s service area,
whether or not those customers are within the city. Therefore, Mr. Brazell recommended that the
Commission approve ETI’s request to recover MFF in base rates from all customers.893

Mr. Benedict holds the same opinion. He stated that the Commission’s policy to collect MFF
from all customers within a customer class is also consistent with the concept that MFF are system
costs that are rightly paid by all customers taking service from the system. He explained that MFF
are paid by a utility to municipalities for use of the municipalities’ rights-of-way. Because these
rights-of-way are necessary to operate an integrated electric delivery system from which all
customers benefit, regardless of geographic location, Mr. Benedict stated that MFF should be
collected uniformly from all customers within a given rate class. He stressed that the Commission
agreed with this reasoning in Docket No. 16705, where the Commission concluded:

Current cost of services studies are not based on geographical differences. Classes
are not divided based on geography, and industrial sites are not self-sufficient
islands. The use of city streets and property enables [EGSI] to have an integrated
utility system from which all ratepayers benefit.894

Mr. Pollock objected to the proposals by Mr. Brazell and Mr. Abbott. He stated that
Mr. Brazell’s recommendation to adopt ETI’s proposed MFF allocation should be rejected because
there is no evidence that outside city customers benefit from ETI’s use of city streets and rights-of-
way or that the benefits are evenly distributed between inside and outside city customers. Further,
according to Mr. Pollock, the standard used in class cost-of-service studies is cost causation, not

893
Cities Ex. 1 (Brazell Direct) at 28-32.
894
OPC Ex. 6 (Benedict Direct) at Ex. NAB-2, Docket No. 16705, Second Order on Rehearing at 98,
(FoF 224).
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benefits, and he believes allocating MFF based on outside city usage is contrary to cost causation
principles.895

The ALJs recommend adoption of ETI’s proposal to collect costs from all customers taking
service from the system. The ALJs find persuasive the fact that MFF is compensation for the use of
municipalities rights-of-way, which is used to operate an integrated electric delivery system from
which all customers benefit.

2. Miscellaneous Gross Receipts Taxes

Miscellaneous gross receipts taxes (MGRT) are state taxes imposed on each utility
company’s taxable gross receipts derived from sales in an incorporated city or town having a
population of more than 1,000. Like MFF, these taxes are levied only on sales within the cities. ETI
proposes to allocate MGRT to all retail customer classes based on customer class revenues relative
to total revenues.896

TIEC objects to ETI’s allocation of MGRT based on class revenues for the same reasons
stated for ETI’s allocation of MFF. It argues that these costs should be allocated and charged to
customers within the municipalities to which the MGRT applied.

The allocation of MGRT is similar to the allocation of MFF and should be similarly applied.
For the reasons set out above and to ensure consistent treatment, the ALJs do not recommend the
direct method of allocation suggested by TIEC. Rather, these costs should be allocated to the rate
classes according to ETI’s cost of service study.

895
TIEC Ex. 3 (Pollock Cross Rebuttal) at 7, 32-33.
896
ETI Ex. 3, Schedule P-13 at 10, line 34.
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3. Capacity-Related Production Costs

(a) Allocation Methodology

ETI proposes to allocate capacity-related production and transmission costs to the retail
classes on the basis of A&E 4CP. As noted by TIEC and Commission Staff, this allocation
methodology is consistent with the method ETI used in Docket No. 16705, its last contested rate
proceeding:

Finding of Fact No. 221. The continued use of the A&E 4CP allocator is the most
reasonable methodology for allocating production and transmission plant among
classes. The A&E 4CP allocator sufficiently recognizes customer demand and
energy requirements and assigns cost responsibility to peak and off-peak users. It
best recognizes the contribution of both peak demand and the pattern of capacity use
through the year.

Finding of Fact No. 222. The A&E 4CP method is also preferable because it is
devoid of any double counting problem.897

ETI witness Ms. Talkington explained that the A&E 4CP allocation is appropriate because it
is a method that reasonably reflects the mix of the Company’s customers, their respective electrical
load characteristics, and the relative costs incurred to serve such loads. She testified that the
A&E 4CP method provides a reasonable balance between the two primary costing concerns:
contribution to the system peak and energy requirements. While the contribution made to the system
peak is inherently recognized with the use of the average four coincident peaks, energy is also
recognized by reflecting the average demands.898

OPC witness Benedict proposed the use of the average and single coincident peak (A&P)
method to allocated production (and transmission costs, which are discussed in the section below)

897
Docket No. 16705, Second Order on Rehearing at 97, FoF 221 and 222 (Oct. 14, 1998).
898
ETI Ex. 22 (Talkington Direct) at 5. As noted previously, A&E 4CP is developed by adding each rate
class’s average demand for the test year (the “average” component representing the rate class’s average
energy consumption), weighted by the ETI system load factor, to each rate class’s amount of average
coincident peak demand for the months of June through September in excess of its average demand, weighted
by one minus the ETI system load factor.
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among retail classes. As noted in the discussion concerning jurisdictional allocation, A&E 4CP is a
variant of the A&E allocator. Mr. Benedict believes that A&E 4CP fails to properly assign cost
responsibility to both peak and off-peak usage.899 Instead, he found that the A&E 4CP allocator
results in the same factors reached by the 4CP method, which means that A&E 4CP assigns cost
responsibility only to peak demand and not to off-peak demand. He believes that the A&P
methodology is the proper plant allocator because it takes into account both peak usage and off-peak
usage patterns.900

Mr. Benedict’s methodology and recommendation was disputed by Kroger witness Higgins.
He indicated that the A&E method does not converge to a CP result. Rather, the A&E method
addresses a fundamentally important question in production cost allocation—once capacity needed
to serve the average demand on the system is accounted for, how does the regulator fairly assign the
responsibility for the additional or excess capacity that is needed to meet the various capacity
requirements (placed on the system by each customer class). Mr. Higgins concluded that the A&E
method makes an objective and reasonable allocation. However, he did not advocate changing
ETI’s use of A&E 4CP.901

Mr. Higgins explained that:

[T]he Average and Excess demand method begins by allocating a portion of costs on
the basis of average demand—or energy. The remaining (or “excess”) capacity
needs of the system are then allocated to classes based on peak usage—class NCP in
the case of the “standard” approach, 4 CP in the case of the A&E/4CP method. In
contrast, the A&P method proposed by Mr. Benedict, which is classified by the
NARUC Manual as a “Judgmental Energy Weighting” approach, incorporates a
subjective determination that includes the full value of average demand both in the
“average” component of the A&P calculation as well as in the peak component of
that calculation.902

899
Mr. Benedict performed a mathematical proof that he believed demonstrated that the A&E 4CP allocator
is nearly identical to the 4CP allocator. OPC Ex. 6 (Benedict Direct) at 21-22.
900
Id.
901
Kroger Ex. 2 (Higgins Cross Rebuttal) at 4-5.
902
Id. at 6 (emphasis in originial).
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TIEC witness Pollock also disputed Mr. Benedict’s proposed methodology, stating that A&P
does not reflect cost causation and is not reasonable for ETI. He believes that Mr. Benedict’s
support of the A&P method is based on an oversimplification of the planning process. He also noted
that A&E is recognized in the NARUC Electric Utility Cost Allocation Manual and has been
repeatedly used by the Commission.903

The following calculations performed by Messrs. Benedict and Higgins demonstrate the
different results stemming from the allocation methodologies:904

ETI OPC Kroger
Proposed Recommended Standard Alternative
Rate Class A&E/4CP (%) A&P (%) A&E 12CP
Residential 47.4494 40.1181 48.4013 43.4768
Small General Service 2.0990 2.0595 2.7209 2.0169
General Service 18.0259 19.4933 18.5183 18.6122
Large General Service 7.0794 8.3822 6.6558 7.4339
Lg. Indust. Power Serv. 20.4401 25.5485 20.2122 22.9417
Total Lighting 0.2900 0.2768 0.4042 0.1394
Total Texas Retail 95.3838 95.8784 96.9127 94.6208
Total Wholesale and 4.6162 4.1216 3.0873 5.3792
Wheeling
Total Company 100.0000 100.0000 100.0000 100.0000

The ALJs recommend the use of A&E 4CP to allocate capacity-related production costs, as
proposed by ETI. The weight of the evidence as well as Commission precedent does not support the
methodology proposed by Mr. Benedict. A&E 4CP was approved for the Company in Docket
No. 16705, and the extensive testimonies (which included calculations and graphs) of
Messrs. Higgins and Pollock indicate that, not only is the methodology frequently adopted by the
Commission, it is also a standard and reasonable methodology. As noted by ETI, it reasonably
reflects the mix of the Company’s customers and their respective load characteristics and the relative

903
TIEC Ex. 3 (Pollock Cross Rebuttal) at 12-14, citing the NARUC Electric Utility Cost Allocation Manual,
January 1992.
904
OPC Ex. 6 (Benedict Direct) at 25; Kroger Ex. 2 (Higgins Cross Rebuttal) at 5.
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costs incurred to serve such loads. It recognizes the contribution of both peak demand and the
pattern of capacity use throughout the year.905 It also recognizes that ETI, like all Texas utilities, is a
summer peaking utility. The ALJs recommend that ETI’s allocation of capacity production costs be
adopted.

(b) Reserve Equalization Payments

A subset of the Company’s requested capacity-related production costs relate to reserve
equalization payments made by the Company pursuant to the Entergy System Agreement (Service
Schedule MSS-1). The System Agreement, which is approved by the FERC, prescribes a method by
which each Entergy Operating Company’s share of Entergy system reserves are calculated. ETI, as
one of the Operating Companies, is responsible to provide the system with its allocated share of
system reserves. Some Entergy Operating Companies own less than their share of system reserves
and are considered “short” with respect to generation capability. Companies that own more than
their share are considered “long” companies. Short companies make payments to long companies
pursuant to the terms of the System Agreement. Because ETI is a short company, it makes reserve
equalization payments which are included in the cost of service.906

ETI allocates MSS-1 payments using A&E 4CP. Mr. Benedict argues that this allocation
method is not consistent with the way costs are incurred, as ETI does not make MSS-1 payments on
the basis of A&E 4CP. According to Mr. Benedict, ETI incurs costs by being short with respect to
system reserves—the payment is simply the number of MW by which it is short, multiplied by a
$/MW rate as determined by a contract formula. The degree to which ETI is short is determined by
comparing its generation capability to its allocated share of system reserves. Total system reserves
are allocated to the other Operating Companies on the basis of the Responsibility Ratio. Thus, as
determined by the Responsibility Ratio, ETI’s share of system reserves relative to its generating
capability is what causes ETI to make MSS-1 Reserve Equalization payments.907

905
See Docket No. 16705, Second Order on Rehearing at FoF 221 (Sept. 4, 1998).
906
OPC Exhibit No. 6 (Benedict Direct) at 29-30.
907
Id.
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Mr. Benedict concluded that, because Reserve Equalization payments are incurred on the
basis of ETI’s Responsibility Ratio, which is a rolling 12CP allocator, the payments should be
allocated to ETI’s rate classes on a similar basis. As a result, he recommended that Reserve
Equalization payments be allocated on the basis of 12CP.908

According to OPC, Mr. Benedict’s proposal for allocating MSS-1 payments has been
criticized because 12CP measures class demands at ETI’s peak monthly demands whereas the
Responsibility Ratio is measured at the Entergy system’s peak monthly demands. OPC agrees that
12CP uses peak hours that may differ from those used to compute the Responsibility Ratio, but
contends that the Company fails to mention that the A&E 4CP method it uses to allocate MSS-1
payments is also subject to the same critique. When choosing between the 12CP allocator and the
A&E 4CP allocator for the purpose of allocating reserve equalization payments, OPC believes 12CP
is more desirable. ETI’s contributions to the Entergy system’s peaks in all 12 months, not just the
four summer months, determine ETI’s share of Entergy system reserves. ETI’s share of system
reserves, relative to its generation capability, is what causes reserve equalization payments to the
other Entergy Operating Companies. Moving to a 12CP allocation for MSS-1 payments aligns cost
allocation more closely with cost causation.

TIEC witness Pollock explained that the Entergy System Agreement is regulated by the
FERC, which does not control the rate design policy applicable to Texas retail customers under
Commission jurisdiction. He views the System Agreement as an accounting mechanism to equalize
the benefits and costs associated with interconnected operation and joint planning. In his opinion, it
is not relevant to determining which production capacity allocation method best reflects cost
causation for Texas retail customer. According to Mr. Pollock, the MSS-1 payments are no different
in concept from the costs associated with ETI’s high-voltage transmission lines, which are allocated
on an A&E 4CP basis. He further indicated that the 12CP method ignores the reality the ETI is a
predominantly summer peaking utility.909

908
Id. at 31.
909
TIEC Ex. 3 (Pollock Cross Rebuttal) at 27-29.
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The ALJs do not find sufficient support to allocate the reserve equalization payments
differently than other capacity-related production costs. For the same reasons noted in the section
above, the ALJs find the weight of the evidence supports allocation using A&E 4CP. While 12CP is
a reasonable methodology for jurisdictional separation between retail and wholesale entities, the
evidence does not support this methodology for allocation of reserve equalization payments.

4. Transmission Costs

As noted above, ETI also allocates transmission costs using the A&E 4CP methodology.
Again, TIEC and Staff cite to the Commission’s decision in Docket No. 16705, which adopted the
A&E 4CP approach for both production and transmission costs. OPC witness Benedict, however,
proposes allocating transmission plant using A&E methodology that he proposed for the allocation
of production plant.910

TIEC argues that methodologies similar to Mr. Benedict’s proposal have been repeatedly
rejected by the Commission, and the A&E 4CP methodology has been repeatedly approved. TIEC
suggests that Mr. Benedict offers no rationale for a different result for transmission costs. According
to TIEC, the rationale that he offers for using the A&P method for production costs—the potential
trade-off between capital costs and fuel costs—is entirely absent with respect to transmission plant.
Mr. Benedict does not even assert that such trade-offs exist. Rather, the only basis he offers for
using the average and peak methodology is his assertion that the A&E 4CP allocator
“mathematically reduces to a 4CP allocator.”911 TIEC points out that the Commission, by rule, has
adopted the 4CP method for the allocation of transmission plant within ERCOT.912

ETI witness Talkington indicated the same reasons and rationale for using the A&E 4CP
methodology to allocate transmission costs as she noted for capacity-related production costs.913

910
OPC Ex. 6 (Benedict Direct) at 26-28.
911
TIEC Initial Brief at 68, citing OPC Ex. 6 (Benedict Direct) at 27.
912
P.U.C. SUBST. R. 25.192 specifically provides that transmission costs are allocated based on the
“coincident peak demand for the months of June, July, August, and September (4CP) . . . .”
913
ETI Ex. 67 (Talkington Rebuttal) at 8-9.
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Kroger witness Higgins also disputed the use of A&E 4CP for allocation of transmission
costs for the same reasons noted above concerning production cost allocation. Moreover, he
compared the different allocation factors—specifically, ETI’s proposed A&E 4CP, the A&E, and
Mr. Benedict’s recommended A&P. His calculations indicated that A&E 4CP and the A&E produce
similar results, while A&P radically departs from ETI’s proposed allocations.914

The ALJs do not find sufficient or persuasive evidence to change ETI’s proposed
methodology for allocation of transmission costs. A&E 4CP is a well-accepted method for
allocating such costs, which the Commission has repeatedly adopted. The ALJs recommend the use
of the A&E 4CP to allocate ETI’s transmission costs.

C. Revenue Allocation

Wal-Mart, Kroger, TIEC, and Commission Staff advocate that the rates be set on the basis of
the utility’s costs of service. These parties recommends the adoption of ETIs proposed base rate
revenue allocation, recovering from each class 100 percent of it respective Test-Year base rate costs
per the revenue requirement ultimately adopted.

TIEC witness Pollock testified that revenue allocation is the process of determining how any
base revenue change approved by the Commission should be spread to each customer class served
by the utility. ETI proposed an overall increase in non-fuel revenues of 17.53 percent, but the
increase is not spread proportionally to all the classes.915 Rather, ETI proposed class revenue
requirements that are closely aligned with the Company’s proposed cost of service. Set out below is
the impact of ETI’s proposed base rate increase for each class:916

Class Change in Base Revenues
Residential 25.10%

914
Kroger Ex. 2 (Higgins Cross Rebuttal) at 5-6.
915
ETI’s revenue requirement does not include the costs associated with its requested REC Rider.
916
See Kroger Ex. 1 (Higgins Direct) at 5-6; see also Cities Ex. 6 (Nalepa Direct) at 34.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 275
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Small General Service 1.82%
General Service 5.54%
Large General Service 19.06%
Large Industrial Power Service 11.17%
Lighting Service 29.36%
System Average 17.53%

The contested issue concerns whether rates should be set at cost, and any approved change in
base rate revenues should reflect the actual cost of providing service, or whether any rate increase
should be phased in for certain classes (notably Residential and Lighting classes) to reduce the
impact (rate shock)

1. Argument for Moving Rates to Cost

ETI and the parties in support of ETI’s class revenue allocation contend it is appropriate to
set rates at each class’ cost of service as ETI has proposed in order to avoid continuing inappropriate
and inequitable cost shifting between customer classes. TIEC witness Mr. Pollock testified that
cost-based rates send the proper price signals to customers. He noted other reasons for using cost-
of-service principles: equity, engineering efficiency (cost-minimization), stability, and conservation.
If rates are not based on cost, then some customers subsidize part of the cost of providing service to
other customers. Moreover, he suggested that by providing balanced price signals, cost-based rates
encourage conservation and may prevent waste or inefficient use. If rates are not based on a class
cost-of-service study, then consumption choices can be distorted.917

Mr. Pollock developed a class revenue allocation based on his proposed jurisdictional and
class cost-of-service studies. If these recommendations are adopted, his class revenue allocation
produced the following results:

917
TIEC Ex. 1 (Pollock Direct) at 63-65.
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Rate Class Present Non-Fuel Proposed Base
Revenues Revenue Increases
Service Percent Increase
Residential $379,382,000 $80,390,000 21.2%
Small General $26,430,000 $283,000 1.1%
General $159,768,000 $9,797,000 6.1%
Large General $49,380,000 $8,714,000 17.6%
Large Indus. Power $104,308,000 $9,862,000 9.5%
Lighting $10,813,000 $2,143,000 19.8%
Total $730,080,000 $111,189,000 15.2%

As discussed below, Mr. Pollock also recommended lower rates for Schedules SMS and
AFC, which would reduce ETI’s revenues by about $2 million. To offset this loss, he testified that
revenues would need to be increased for other classes to achieve the total increase requested by ETI.
These changes would produce the following results:918

Rate Class Service Present Non-Fuel Proposed Base Percent Increase
Revenues Revenue Increases
Residential $379,382,000 $81,500,000 21.5%
Small General $26,430,000 $340,000 1.3%
General $159,768,000 $10,205,000 6.4%
Large General $49,380,000 $8,860,000 17.9%
Large Indus. Power $104,308,000 $10,153,000 9.7%
Lighting $10,813,000 $2,160,000 20.0%
Total $730,080,000 $113,218,000 15.5%
SMS/AFC Impacts $13,816,000 ($2,029,000) -14.7%
Total Sales $743,896,000 111,189,000 14.9%

918
Id. at 63-67 and Exs. JP-12 and JP-13.
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If the Commission disallows other elements of ETI’s rate request, Mr. Pollock testified that
class revenue allocation should be reduced in accordance with how such disallowed costs were
allocated to each rate class.919

Mr. Pollock’s tables provide examples of the impact on each class of customers when the
Commission makes final decisions concerning the Company’s proposed rate design and the final
revenue requirement.

Staff witness Abbott testified that the Commission ordinarily sets rates for each customer
class to recover the costs incurred by the utility to serve that class. In this case, ETI’s proposed
revenues for all customer classes result in base revenues that are close to the cost of service allocated
costs. No single customer class’ proposed revenue requirement differs from ETI’s calculated cost to
serve that class by more than 3 percent. Staff acknowledges that certain classes face proportionally
larger rate increases to bring them closer to unity, where revenue recovery is based on actual cost of
service. However, Staff agrees with Mr. Pollock that setting each customer class at their cost of
service avoids inflating rates for some customer classes and subsidizing the usage of others. Staff
believes that recovering from each class its respective base rate cost is equitable and provides
appropriate pricing signals to facilitate the most efficient use of resources in the provision and
consumption of electricity. Staff also argues that the Commission has approved such class cost of
service allocation in recent rate cases.920

Wal-Mart and Kroger concur with Staff and TIEC.

919
Id. at 67.
920
Staff cites Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates,
Docket No. 28339, Order at FoF 175 (May 12, 2011) and Docket No. 16705, Second Order on Rehearing at
FoF 245 (Sept. 4, 1998). TIEC witness Pollock also testified that Commission precedent supports allocation
of costs based on the cost of service study. He also cited to the CenterPoint case and to Application of AEP
Texas Central for Authority to Change Rates, Docket No. 28840, Order at 50 (Aug. 15, 2005). TIEC Ex. 1
(Pollock Direct) at 65.
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2. Argument for Gradualism

Cities witness Karl Nalepa pointed out that, under ETI’s proposed rates, the Residential and
Lighting customer classes receive the highest rate increases while the Small General Service,
General Service, and Large Industrial Power Service classes receive below system average rate
increases of 1.62 percent, 4.81 percent, and 10.77 percent, respectively. However, he examined Test
Year customer quantities, energy and loads by customer class for each of ETI’s last three cases, and
he concluded that residential and lighting customers are not imposing an undue cost burden on the
system. Instead, other classes are growing at a faster rate, causing system costs to increase.
Moreover, Mr. Nalepa testified that a number of events are occurring with the Entergy system that
will have significant impact on costs, including: Entergy’s efforts to join MISO; plans by EAI and
EMI to leave the Entergy System Agreement; and the possible divestiture of the transmission system
by all Entergy Operating Companies. Given these uncertainties, Mr. Nalepa proposed that any rate
increase or decrease be spread proportionately across the system classes. Then, once Entergy and
ETI address the proposed system cost changes, a reasonable class cost allocation study can be
presented.921

State Agencies do not take a position on overall class revenue allocation but request that
ETI’s proposed rate increase for the Lighting class be moderated. ETI proposes to set base rate
revenues for the Lighting class based on the class cost allocation study, without any adjustment,
which would result in a 20.38 percent increase to the Lighting class, when the entire ETI system
would receive a 15.32 percent increase. Thus, under ETI’s proposal, this class would receive a
percentage increase about 1.33 times the system average. Ms. Pevoto contended that that this
increase would be excessive and would create significant rate shock to the class. Because the
services of the Lighting class provides benefits all customers on the system, Ms. Pevoto believes it
would be reasonable to mitigate the rate shock so that lighting customers can afford to continue their
lighting service. Otherwise, she suggested, some lighting customers may reduce lighting services or

921
Cities Ex. 6 (Nalepa Direct) at 34-37.
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refrain from ordering additional lights. This, in turn, would adversely affect the benefits that
lighting service provides to the public.922

Ms. Pevoto also pointed out that in 2009, the Commission adopted a rate moderation
proposal for a similar rate class served by another utility. In that case, the Commission recognized
that the Lighting class was unique in the combination of the public good it performs and in its
demand characteristics.923 To mitigate the rate shock on the lighting customers in the present case,
Ms. Pevoto recommended a cap on any base rate increase that would be equal to the smaller of:
(1) the lighting class percentage rate increase resulting from the PUC-approved cost of service
allocation study, or (2) the allowed system percentage rate increase. If the percentage rate increase
is smaller than the allowed system percentage rate increase, then no mitigation adjustment would be
necessary. However, if the PUC-approved cost of service allocation results in a percentage base rate
increase for the lighting class that is greater than the allowed system percentage increase, then she
urged that a mitigation reduction should occur. She also proposed that any mitigation reduction for
the lighting class should be spread to other remaining classes, based on each class’ cost of service.924

ETI argues that the State Agencies are proposing the continuation of a significant subsidy by
other classes. The Company notes that its allocation of costs to the Lighting class is based on the
revenue requirement developed for that class. ETI acknowledges that its proposed increase for the
Lighting class is 20.38 percent greater than the system average increase, but it is less than the
Residential class’s proposed increase of 21.64 percent. ETI witness Ms. Talkington testified that the
Company does not support any subsidies between rate classes. She testified that previous rate cases
with subsidies for the Lighting class have pushed the class farther away from cost.925

OPC argues that cost of service should not be the sole factor in setting rates and that
gradualism should be used in appropriate circumstances. OPC witness Benedict disagreed with

922
State Agencies Ex. 2 (Pevoto Direct) at 12-13.
923
Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order
on Rehearing at 32 (Nov. 30, 2009).
924
State Agencies Ex. 2 (Pevoto Direct) at 15-16.
925
ETI Ex. 67 (Talkington Rebuttal) at 18-19.
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Mr. Pollock’s (and Staff’s) citation to the CenterPoint and AEP TCC rate cases to reject the concept
of gradualism because both CenterPoint and TCC are unbundled transmission and distribution
(T&D) utilities whose charges had a small impact on retail customers’ total bill. He noted that the
number runs for TCC and CenterPoint showed retail revenue increases of only 0.14 percent and
1.30 percent, respectively, with some classes receiving rate decreases.926 Mr. Benedict cited the
following language by the Commission in its Order for the TCC case:

The Commission declines to adopt gradualism in this case. This proceeding
develops the T&D rates, as opposed to the broader rates developed for a fully
integrated utility. As the T&D rates are only a subset of the total rates paid by
customers, changes to the T&D rates would not have as large an impact as they
would if the broader rates for a customer class were changed by the same percentage.
. . . 927

In Mr. Benedict’s opinion, gradualism should be employed when setting rates for ETI because ETI is
an integrated utility and has proposed a large rate increase.928

Mr. Benedict also emphasized the imprecise nature of a cost of service study. He noted that
ETI’s cost of service study had 47 allocation factors and, even at the summary level, 22 expense
categories and 24 rate base categories.929 Thus, he stated, there are a host of decisions made by the
cost of service analyst which, in combination with the various account entries, yield a class’ reported
cost of service. Mr. Benedict also pointed to disagreement among qualified experts on the “correct”
allocation for certain classes of costs.930 In addition to these allocation questions, Mr. Benedict
stated that any disallowances made to ETI’s requested costs will have asymmetric effects on class

926
OPC Ex. 8 (Benedict Cross Rebuttal) 11-12; Ex. NAB-4, Docket No. 28840, TCC Number Run (July 21,
2005); and Ex. NAB-5, Docket No. 38339, Revised Number Running Schedules (Feb. 18, 2011).
927
Id. citing Docket No. 28840, Order at 23 (Aug. 15, 2005).
928
OPC Ex. 8 (Benedict Cross Rebuttal) at 9-14.
929
Allocation factors are provided in Schedule P-7.1; Expenses are summarized in Schedule P-7.4; Rate Base
is summarized in Schedule P-7.5.
930
He noted, for example, that his direct testimony and Mr. Nalepa’s direct testimony proposed a different
allocation methodology for production-related capacity costs, transmission costs, and certain System
Agreement costs. Mr. Pollock proposed a different allocation method for municipal franchise fees and local
gross receipts taxes. Mr. Abbott recommended different allocation methods for municipal franchise fees and
other franchise taxes.
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cost of service depending on how the costs were allocated. Thus, while the cost of service study is
an important element of ratemaking, Mr. Benedict stressed that it is not the only consideration.931

Due to the wide variation of rate increases obtained from ETI’s cost of service study,
Mr. Benedict thought that rate moderation (gradualism) would be appropriate. However, he added,
until decisions are made regarding the cost disallowances and allocation modifications proposed by
the parties, it is unclear which rate classes should be granted rate moderation and the degree to
which rate moderation is needed. Mr. Benedict said that the system average rate increase should be
used as a benchmark for rate moderation, but not assigned uniformly to all classes as Mr. Nalepa
proposed or to just one class as Ms. Pevoto suggested. Instead, he believed it would be reasonable
to establish a floor and a ceiling for the increases in revenue from each class, such that a class’
individual percentage increase in revenue requirement is within a defined range of the system’s
average revenue increase. Therefore, Mr. Benedict recommended that any rate increase for a
particular class be restricted to a range of 0.75 to 1.25 times the system’s average increase. This
would result in rate increases up to 25 percent lower or 25 percent higher than the average rate
increase for the system as a whole. Based on a system average increase of 17.53 percent, individual
class increases would range from 13.15 percent to 21.91 percent under Mr. Benedict’s proposal.932

3. ALJs’ Recommendation

The parties presented persuasive argument on both sides of the issue. Clearly, in any rate
case, movement toward unity—setting rates to cost—is appropriate when such movement does not
result in rate shock to a particular class or classes. If rate shock is likely, Commission precedent
supports the use of gradualism. These policies apply to both a fully integrated utility, as well as a
T&D. The salient issue is whether the utility’s proposed increase is so out of proportion or harsh to
a particular class that some form of gradualism should be applied. In this rate case, the
preponderance of the evidence does not support the use of gradualism, even for the Lighting class.
While that class may receive an increase almost 1.33 times the system average increase, Commission

931
OPC Ex. 8 (Benedict Cross Rebuttal) at 14-17.
932
OPC Ex. 8 (Benedict Cross Rebuttal) at 17-19.
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precedent indicated an appropriate ceiling of 1.5 or even 1.75 times the system average is
appropriate.933 As to applying OPC’s proposed floor and ceiling approach, this method was
introduced in cross-rebuttal with no calculations depicting the impact on each class. The ALJs do
not recommend its adoption because it fails to offer significant movement towards class
responsibility for cost of service. The ALJs do not recommend Mr. Nalepa’s suggestion to impose
any revenue change on an equal percent basis because it offers no movement towards unity.
Accordingly, the ALJs concur with the parties supporting ETI that revenue allocation in this case
should be based on each class’s cost of service and consistent with the ALJs’ recommendations in
the PFD that impact revenue allocation.

D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20]

Staff explained that the Commission has traditionally established class costs of service based
on the principle of cost causation. Staff believes the Commission has consistently required
substantial justification for departing from this principle when setting rates that result in
cross-subsidization between customer classes. With respect to intra-class cost causation and rate
design, Staff maintains that the considerations are somewhat different. Rather, the Commission has
traditionally given more weight to policy considerations other than cost causation in determining
intra-class rate design issues because the danger of permanent subsidies within a particular class is
relatively low.934 For instance, Staff witness Abbott testified that customer usage within a class may
vary throughout the year. He noted that a low-load-factor customer might become a high-load-factor
customer, resulting in a different mix of charges throughout the year.935 While an individual
customer’s usage characteristics might frequently change and thereby lessen the impact of cost
shifting within a class, Mr. Abbott testified that such customers were unlikely to shift to a different
customer class.936 While subsidies in the customer class allocation context might be permanent, this

933
See Docket No. 28840, Order at 23 (rejecting ALJs’ proposed ceiling of 1.75 times the system average).
934
Staff cites to Mr. Abbott’s cross-examination at Tr. at 1818 (“Q: And is there a distinction between factors
that you would consider such as costs or other factors when you’re discussing class allocation as opposed to
rate design issues? A: I would say there are different considerations and weights to considerations and the
analysis of allocating costs to classes versus the analysis of allocating costs to rates within a class.”).
935
Tr. at 1818.
936
Id.
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was not necessarily the case for intra-class rates. Moreover, these shifting usage characteristics
make it more difficult to identify cost drivers within a rate class. Staff suggests that consideration be
given to policies such as customer impact and energy efficiency.

The ALJs agree with Staff’s analysis. Mr. Abbott recommended that the Commission apply
gradualism—limiting the magnitude of rate changes—to help stabilize customer expectations and
reduce risk.937 ETI witness Talkington also advised caution in response to suggested changes to
ETI’s proposed rate design, noting that the ultimate impact on a customer’s bill is important.938
However, the ALJs’ rate design recommendations are based on the evidence and argument for each
customer class or rate schedule. Thus, the ALJs’ recommendation on the specific rates or charges
for the industrial customers will impact all other customer classes but that impact is not known at
this time.

1. Lighting and Traffic Signal Schedules

Cities witness Dennis W. Goins explained ETI’s Lighting and Traffic Signal Schedules.
ETI’s principal rate schedule for street lighting customers is Schedule SHL (Street and Highway
Lighting Service), while Schedule TSS (Traffic Signal Services) is the principal rate schedule for
ETI’s traffic lighting customers that own and maintain their lighting facilities. For Schedule SHL,
the rate includes four categories of service (Rate Groups A, C, D, and E). Rate Group A includes
ETI’s standard fixture and lamps mounted on existing standard wood poles that ETI installs and
maintains. If a customer wants nonstandard lighting facilities (those not provided in Rate Group A),
the customer is assigned to Rate Group C and required to prepay ETI for the incremental cost of the
nonstandard facilities. Lighting facilities that are customer-owned and customer-maintained are
assigned to Rate Group D, while incidental lighting services (for example, underpass lighting) are
assigned to Rate Group E. Customers in Rate Groups A and C pay a fixed monthly charge per
lighting fixture, while customers in Rate Groups D and E pay a fixed (and identical) energy charge
per kWh. Each customer’s monthly bill also includes charges for ETI’s fixed fuel factor

937
Staff Ex. 7 (Abbott Direct) at 25-26.
938
ETI Ex. 67 (Talkington Rebuttal) at 16.
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(Schedule FF) and applicable riders applied to monthly kWh per fixture. Under Schedule TSS,
traffic signal customers are subject to a minimum monthly charge ($3.20 proposed) per point of
delivery, plus a fixed kWh rate and all applicable rider charges.939

Cities request that the Commission require ETI to institute a discounted lighting rate for
Light Emitting Diode (LED) installations. Mr. Goins testified that the basic structure and pricing
provisions of the SHL and TSS rates were designed for lighting fixtures that use older, less
energy-efficient bulb technology, and ETI did not conduct any analyses to estimate the cost
differential of serving street lighting and traffic signal customers that use energy-efficient LED
fixtures. In fact, Dr. Goins noted that the basic structure and pricing provisions of the SHL and TSS
rates have been place for years.940

In Dr. Goins’ opinion, adoption of LED lighting rates would help reduce energy consumption
in Texas because such rates help offset the high front-end cost of LED lights and encourage
municipalities to adopt energy-efficient LED options. In 2010, the Commission approved a street
and traffic signal rate for El Paso Electric Company that included separate charges for LED traffic
signals.941 In that case, the fixed monthly rate for LED signals was generally less than one-third the
comparable rate for incandescent signals.

Dr. Goins recommended that the Commission require ETI to modify monthly fixed charges
in Schedule SHL (Rate Groups A and C) and the monthly minimum charge in Schedule TSS to
reflect a 25 percent discount for LED installations. Under his proposal, the discounted Rate
Group A fixed charges (if applicable) in Schedule SHL would be applied according to the estimated
monthly kWh consumption of the installed LED fixture. In addition, he recommended reducing by
25 percent the Schedule SHL kWh charges applicable to LED customers assigned to Rate Groups D
and E to reflect the lower cost of operating and maintaining LED fixtures. And he added that, in the

939
Cities Ex. 4 (Goins Direct) at 22-23.
940
Id. at 23.
941
Application of El Paso Electric Company to Change Rates, to Reconcile Fuel Costs, to Establish
Formula-Based Fuel Factors, and to Establish an Energy Efficiency Cost Recovery Factor, Docket No.
37690 (July 30, 2010).
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future, ETI should be required to provide detailed information regarding differences in the cost of
serving LED and non-LED lighting customers.942

Dr. Goins also requested that the Commission require ETI to eliminate the service condition
applicable to Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a
functioning light with a lower-wattage bulb. He stated that this fee actively discourages customers
from adopting more energy-efficient lighting technologies (for example, LED devices), and was not
supported in ETI’s filing. In Dr. Goins’ view, this barrier to conservation and efficiency
improvements should be eliminated.943

Staff disagrees with Cities’ request that ETI institute a discounted lighting rate for LED
installations. Mr. Abbott testified that Cities did not provide empirical cost data to support this
request. Without data on which to base an LED installation discount, he recommended that the
Commission not require ETI to provide such a discount at this time. However, because of the
growing use of LED installations and the potential cost savings to be realized from these
installations, Mr. Abbott did recommend that the Commission require ETI to perform a cost study to
determine appropriate cost-based rates for LED installations. This cost study could be used to
develop LED lighting rates, which Mr. Abbott recommended ETI be required to submit as part of its
next base-rate case.944

ETI is willing to perform a study to determine the feasibility of implementing LED lighting
rates as part of its next base rate case filing. ETI witness Talkington explained that the Company
does not currently offer ETI-owned LED lights but may do so in the future. She stated that if a
customer wishes to use LED technology, it can install LE fixtures and receive service under
Schedule SHL, Rate Groups D and E, or the existing Schedule TSS.945

942
Cities Ex. 4 (Goins Direct) 22-26.
943
Id.
944
Staff Ex. 7 (Abbott Direct) at 28.
945
ETI Ex. 67 (Talkington Rebuttal) at 17.
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Ms. Talkington took issue with Dr. Goins’ proposed 25 percent decrease in Schedule SHL
(Rate Groups A and C) and Schedule TSS for an LED option because the 25 percent rate reduction
was not calculated. Thus, ETI prefers that it propose rates after a cost study. Ms. Talkington also
disagreed with Dr. Goins’ proposal for a 25 percent decrease in the energy-only options under
Schedule SHL, Rate Groups D and E or Schedule TSS for customer-owned lights. She believes that
a customer will have the benefit of more efficient LED lights by the reduction in energy
consumed.946

The ALJs find persuasive Dr. Goins’ testimony that: (1) the cost of street and traffic lighting
services can be significant for many cities and towns; (2) government agencies face increasing
pressure to control budgets and energy-efficient lighting is a good option; (3) LED fixtures use
significantly less energy than incandescent and most other light options, last longer, and may require
less maintenance; and (4) LED lighting rates would encourage municipalities to adopt
energy-efficient LED options and help offset the high front-end cost of LED lights.947 However, the
ALJs concur with ETI and Staff that ETI should be directed to perform a LED lighting cost study
before extensive changes are made to its lighting rates. The ALJs further recommend that ETI
conduct this study before filing its next rate case and provide the results of any completed study to
Cities and interested parties as soon as practicable but no later than the filing of its next rate case, as
requested by Cities. Further, the ALJs recommend that the study include detailed information
regarding differences in the cost of serving LED and non-LED lighting customers, if ETI has LED
lighting customers taking service at the time it conducts its study. Finally, the ALJs note that ETI
did not dispute Dr. Goins’ suggestion to eliminate the service condition for Rate Groups A and C in
Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage
bulb. As noted by Dr. Goins, this fee discourages customers from adopting more energy-efficient
lighting (such as LED devises). The ALJs concur and recommend that ETI modify the applicable
tariffs to eliminate this fee for any replacement of a functioning light with a lower-wattage bulb.

946
Id. at 17-18.
947
Cities Ex. 4 (Goins Direct) at 24-25.
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2. Demand Ratchet

Staff witness Abbott testified that a demand ratchet is a provision in a utility’s tariff that
allows it to bill a customer based upon on the greater of either demand by that customer in the
current month, or some fixed percentage of the customer’s demand occurring during previous
months. The Commission approved a settlement in Docket No. 37744, ETI’s last base rate case, in
which, among other things, ETI agreed to eliminate all life-of-contract demand ratchets from its
tariffs for new customers with the implementation of rates. ETI further agreed that, in its next rate
case, it would eliminate the life-of-contract ratchet for existing customers.948 The Docket No. 37744
stipulation stated:

Life-of-Contract Demand Ratchet. The Signatories agree that the life-of-contract
demand ratchet provision in Rate Schedules Large Industrial Power Service [LIPS],
Large Industrial Power Service-Time of Day [LIPS-TOD], General Service [GS],
General Service-Time of Day [GS-TOD], Large General Service [LGS], and Large
General Service-Time of Day [LGS-TOD] shall be excluded from the rate schedules
in ETI’s next rate case. The Signatories further stipulate that the foregoing rate
schedules will be revised so that the life-of-contract demand ratchet provision shall
not be applicable to new customers and, for existing customers, shall not exceed the
level in effect on August 15, 2010.949

ETI then filed compliance tariffs in Docket No. 37744, which implemented the first part of
the settlement by excluding new customers from its proposed life-of-contract demand ratchet. The
following is the relevant sections from that compliance tariff, which is applicable to Large Industrial
Power Service (LIPS) customers (all customers taking service under this tariff are required to enter
into a service agreement contract with ETI):

948
Staff Ex. 7 (Abbott Direct) at 16; Application of Entergy Texas, Inc., for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744, Order at FOF 26(f) (Dec. 13, 2010). The ratchet is applicable to the
General Service (GS), General Service – Time of Day (GS-TOD), Large General Service (LGS), Large
General Service – Time of Day (LGS-TOD), Large Industrial Power Service (LIPS), and Large Industrial
Power Service – Time of Day (LIPS-TOD).
949
TIEC Ex. 27 (Docket No. 37744 Stipulation and Settlement Agreement) at 6.
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VI. DETERMINATION OF BILLING LOAD
The kW of Billing Load will be the greatest of the following:
(A) The Customer’s maximum measured 30-minute demand during any
30-minute interval of the current billing month, subject to §§ III, IV and V
above; or
(B) 75% of Contract Power as defined in § VII; or
(C) (1) For existing accounts with contracts for service for loads existing
prior to August 15, 2010 – 60% of the Highest Contract Power
established prior to August 15, 2010 as defined in § VII, (2) For new
accounts with contracts for service for loads not existing prior to
August 15, 2010 – Does Not Apply; or
(D) 2,500 kW.

VII. DETERMINATION OF CONTRACT POWER
Unless Company gives Customer written notice to the contrary, Contract
Power will be as defined below:

Highest Contract Power – the greater of (i) the highest Billing Load
established under the currently effective contract, or (ii) the kW
specified in the currently effective contract.

Contract Power- the highest load established under § VI (A) above during the
12 months ending with the current month. For the initial 12 months of
Customer’s service under the currently effective contract, the Contract Power
shall be the kW specified in the currently effective contract unless exceeded
in any month during the initial 12-month period.950

In this case, ETI changed the tariff provisions for all customers:

VI. DETERMINATION OF BILLING LOAD
The kW of Billing Load will be the greatest of the following:
(A) The Customer’s maximum measured 30-minute demand during any
30-minute interval of the current billing month, subject to §§ III, IV and V
above; or
(B) 75% of Contract Power as defined in § VII; or
(C) 2,500 kW; or
(D) 60% of the kW specified in the currently effective contract.

VII. DETERMINATION OF CONTRACT POWER
Unless Company gives Customer written notice to the contrary, Contract
Power will be as defined below:

950
TIEC Ex. 29 (Tariff Approved in Docket No. 37744)(emphasis added).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 289
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Contract Power shall be the highest load established under § VI(A) above
during the 12 months ending with the current month. For the initial 12
months of Customer’s service under the currently effective contract, Contract
Power shall be the kW specified in the currently effective contract unless
exceeded in any month during the initial 12-month period.951

The contested issue concerns ETI’s new language. ETI maintains the new language is not a
life-of-contract ratchet. Commission Staff, TIEC, and DOE disagree. Stated simply, Department of
Energy (DOE) witness Dwight D. Etheridge testified that the introduction of the term “kW specified
in the currently effective contract” transforms what was a 12-month ratchet into a life-of-contract
ratchet.952

At the outset, the ALJs note that some of ETI’s proposed tariffs do comply with the
stipulation in the prior case. ETI eliminated the life-of-contract provisions for the GS and GS-ToD
customer classes. However, ETI’s new language for the remaining ratchet classes, according to
Staff witness Mr. Abbott, has the effect of maintaining a slightly different type of life-of-contract
demand ratchet.953 The discussion in this section applies to the LIPS class but the same argument
follows for LGS and GS classes.

The parties contesting ETI’s demand ratchet language argue that: (1) ETI’s compliance tariff
in Docket No. 37744 was consistent with the parties’ agreement; (2) ETI’s proposal imposes a life-
of-contract demand ratchet; (3) the service agreement and tariff are linked; and (4) the new demand
ratchet is not equitable or cost-based. These arguments are set out below.

951
ETI 67 (Talkington Direct) at Ex. MLT-R-4 at 15 (emphasis added). ETI changed the relevant language
in its tariff in its rebuttal testimony. Thus, the testimony of Messrs. Etheridge and Abbott can be slightly
confusing because these witnesses address the tariff initially proposed by ETI.
952
DOE Ex. 1 (Etheridge Direct) at 11.
953
Staff Ex. 7 (Abbott Direct) at 16-19.
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¾ The agreed tariff from Docket No. 37744 was consistent with the parties’
agreement and shows how LIPS billing load should be calculated.

Staff, TIEC, and DOE agree that when ETI filed the compliance tariff in Docket No. 37744,
the only demand ratchet that remained in the LIPS tariff for ETI’s new customers was a 12-month
demand ratchet. ETI removed the life-of-contract ratchet that set a perpetual obligation for a
customer to pay for power based on its highest contract power or a percentage of its contract power.
Staff, DOE, and TIEC argue that ETI’s action in removing those provisions was consistent with the
agreement and is evidence of what ETI should have done in this case. They contend that ETI
witness Ms. Talkington agreed that the settlement eliminated both the highest load established under
the currently effective contract and the amount specified in the contract.954 In other words, the
compliance tariff tracked the agreement.

ETI does not directly respond to this argument: Ms. Talkington did not address this in her
rebuttal testimony. However, ETI states that the ALJs should “not be distracted by ETI’s initial
error of unintentionally removing the contracted capacity provision as to new customers in its
compliance tariffs in Docket No. 37744.”955 Apparently, ETI believes that the tariffs it filed in
compliance with the Docket No. 37744 agreement were in error.

¾ ETI proposes a demand ratchet in this case that is based on the contracted quantity
stated in the tariff-required service agreement.

All parties agree that what ETI proposes in this docket is different from the Docket
No. 37744 tariff, as evidenced by Ms. Talkington:

Q: So last time, when the company and the parties implemented the elimination
of the life-of-contract ratchet, it eliminated the 60 percent ratchet applicable
to both actual demand during the contract period or the contract – the amount
specified in the contract.
A. Yes, the way it’s put in the schedule, yes.
Q: And that’s different than what you proposed in this case?

954
Tr. at 1432.
955
ETI Reply Brief at 91.
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A: It is.
Q: And do you apply a different meaning to the agreement of what the life of
contract ratchet meant than was applied in the tariff?
A: Yes. What we have in this case is that the life-of-contract power relates to
the highest load established under the currently effective contract . . . 956

According to ETI, its proposed language does not impose life-of-contract ratchet, as defined
by Mr. Pollock in Docket No. 37744 or by Messrs. Etheridge and Abbot in this case.

Witness Definition
Pollock “A life-of-contract ratchet is based on the highest demand ever imposed
by a customer during the term of the contract.” He further explained
that ETI’s proposed Docket No. 37744 tariff had “a life-of-contract
ratchet [which] imposes a perpetual obligation to pay a minimum
demand charge throughout the term of the contract.”957
Etheridge “A life-of-contract ratchet is a ratchet where you’re not looking solely at
current loads but some other loads in some prior period, so it creates a
perpetual obligation to pay.”958
Abbott “[A] life of contract demand ratchet, which is based upon the highest
demand established in the time period. . . . is one type of life-of-contact
demand ratchet”959

ETI argues that the above definitions all make reference to the demand actually imposed by the
operations of the customer’s physical plant. But the contracted quantity provision it proposes is a
minimum kW amount contractually agreed between the two parties to the service agreement, which
is a required contract between the customer and ETI.960 ETI argues the provision is not set by actual
events during the term of the contract or in a prior period of the term of the contract, or in a monthly
or 30-minute time period within the term of the contract; rather, it is set in the contract:

956
Tr. at 1432-1433 (emphasis added).
957
DOE Ex. 3 (Docket No. 37744 testimony excerpt) at 5-6.
958
Tr. at 2004.
959
Tr. at 1817.
960
Mr. Etheridge testified that customers taking service under Schedule LIPS must sign a contract for service.
Tr. at 1991.
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That contracted quantity is set as, to use Mr. Etheridge’s words, “an estimate” that
cannot be unilaterally changed by the Company; instead, a change to that kW amount
could only be made through negotiation between the two parties or through a
proceeding before the Commission. To use Mr. Pollock’s definition, it is not a
demand “imposed by the customer during the term of the contract.” It is instead a
fixed, contractually agreed to amount that is set as a condition of service prior to the
contract term.961

In sum, ETI argues the provision in question are not life-of-contract ratchets that lock the
customer into the highest demand ever imposed by the customer’s actual load during the term of the
contract. Rather, they are, at most, 12-month ratchets that set the billing demand over a 12-month
period, but not the life of the contract, at 75 percent.

Staff suggests that the Commission does not, fortunately, have to determine what contract
provision may or may not constitute a life-of-contract demand ratchet. Rather, the Commission must
ensure that ETI fulfilled its obligations under the Docket No. 37744 settlement. Staff believes that
the parties to that settlement understood the meaning of the life-of-contract term, ETI followed
through with compliance tariffs that evidenced its understanding, and now ETI should be required to
stick with its agreement.

¾ The service agreement and tariff are linked.

According to TIEC, ETI tries to make the argument that its proposal is justified because ETI
and its large customers may sign an agreement for service that specifies a customer’s contract
power. This does not justify ETI’s proposal because ETI’s form “Agreement for Electric Service”
expressly states that the agreement is subject to the terms of “applicable rate schedules.”962 Thus,
maintains TIEC, the LIPS tariff billing load provisions impact a customer’s contract power and can
reasonably reduce a customer’s billing load below its contract power if the customer has a reduction
in load lasting longer than 12 months.

961
ETI Initial Brief at 211 (footnotes omitted), citing Tr. at 1994, 2012.
962
ETI Ex. 3, Schedule Q 8.8 at 11.1.
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ETI’s proposal should be rejected, argues TIEC, because it would allow the utility to
indefinitely seek revenue from a customer that has nothing to do with the customer’s actual usage or
the utility’s costs. For example, if a plant took 150 MW of load in its heyday, under ETI’s proposal,
the plant would be obligated to pay demand charges based on 60 percent of its original contract
power. This is because ETI’s standard agreement requires the utility’s “express approval” to set a
new contract power and the utility therefore could choose not to negotiate (or negotiate in a timely
manner) a new contract power.963 If LIPS billing load is tied to contract power, then its customers
would be completely at its mercy to negotiate a reasonable contract power based on the customer’s
actual usage for the time period. TIEC contends this is a ridiculous result and would render the
parties’ agreement to eliminate the life-of-contract ratchet meaningless.

¾ ETI’s new demand ratchet is not equitable or cost-based.

TIEC does not dispute that a 12-month ratchet is reasonable. However, Mr. Pollock, in
Docket No. 37744, explained why a perpetual obligation to pay demand costs for load that the utility
does not serve is objectionable:

While it is appropriate to require customers to pay for the facilities they use, a
perpetual obligation is both extreme and unnecessary. Typical demand ratchets
reach back twelve months. A life-of-contract ratchet can reach back decades. This is
particularly inappropriate when longstanding customers have permanently reduced
operations. A customer that has reduced operations is not purchasing the same level
of generation and transmission services as in the past, nor is ETI procuring the same
level of generation and transmission services for the customer. Further, because of
load growth on the ETI system, the capacity no longer being used by the customer
would be used by other customers. Thus, a life-of-contract ratchet does not properly
reflect cost-causation.964

¾ Witness Recommendations.

Staff witness Mr. Abbott recommended that ETI be required to eliminate from its LGS,
LGS-ToD, LIPS, and LIP-ToD tariffs the language that results in a ratchet based upon the current

963
ETI Ex. 3, Schedule Q 8.8 at 11.2.
964
DOE Ex. 3.
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effective contract-specific demand. Also, if the Commission approves Mr. Abbott’s
recommendation, he stated that the billing determinants used to calculate the rates for the affected
customer classes will likely change. Therefore, ETI should be required to update the affected billing
determinants and reflect the resulting change in its rates in the compliance filing of this docket.965

DOE witness Etheridge also recommends that same for the LIPS tariff. He specified
language that will exclude the life-of-contract ratchet language and retain the existing rolling
12-month ratchet language in Schedule LIPS.966 Specifically, he proposed the following:

VI. DETERMINATION OF BILLING LOAD
The kW of Billing Load will be the greatest of the following:

(A) The Customer’s maximum measured 30-minute demand during any
30-minute interval of the current billing month, subject to §§ III, IV and V
above; or
(B) [60%] of Contract Power as defined in § VII; or
(C) 2,500 kW.

VII. DETERMINATION OF CONTRACT POWER
Unless Company gives Customer written notice to the contrary, Contract
Power will be as defined below:

Contract Power- the highest load established under § VI (A) above during the
12 months ending with the current month. For the initial 12 months of
Customer’s service under the currently effective contract, the Contract Power
shall be the kW specified in the currently effective contract unless exceeded
in any month during the initial 12-month period.

¾ ALJs Recommendation.

The ALJs find that ETI violated its agreement with the signatories in Docket No. 37744: the
tariff language proposed by ETI is a life-of-contract demand ratchet. ETI failed to explain how the
compliance tariffs adopted in Docket No. 37744 were in error. ETI’s argument that its new
language is not a life-of-contract demand ratchet was unpersuasive. To justify its modification, ETI

965
Staff Ex. 7 (Abbott Direct) at 20.
966
ETI can adopt similar language for its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 295
PUC DOCKET NO. 39896

relied only on a portion of Mr. Pollock’s Docket No. 37744 definition. Moreover, both
Messrs. Abbott and Etheridge were unequivocal that ETI, contrary to its agreement in the previous
rate case, is imposing a life-of-contract or perpetual obligation to pay. Finally, the weight of the
evidence supports a finding that the demand ratchet ETI proposes in this case is not equitable or cost
based. The ALJs recommend that ETI’s proposed LIPS tariff be amended to include the language
proposed by Mr. Etheridge. The ALJs concur with Mr. Etheridge that, with such language, ETI has
a financial incentive to negotiate the maximum possible contracted level of capacity, not the
minimum, and the result is consistent with the Docket No. 37744 agreement.

3. Large Industrial Power Service (LIPS)

TIEC witness Pollock explained that Schedule LIPS recovers base rates through a seasonally
adjusted demand charge (per kW) and a two-step non-fuel energy charge (per kWh). The demand
charges are also adjusted (either up or down) to reflect the differences in costs by delivery voltage.
ETI’s existing LIPS schedule has no customer charge. In its initial filing, ETI removed all
purchased power capacity costs from base rates and proposed recovering them through a PPR as a
demand charge. When it did so, the proposed demand charges were increased, but the proposed
non-fuel energy charges were substantially reduced. Following the Supplemental Preliminary Order,
which removed the PPR from further consideration, ETI proposed to roll these costs back into base
rates. The resulting rebundled demand and energy charges would increase by about the same
percentage.967

Mr. Pollock testified that the proposed structure of Schedule LIPS does not track costs as
derived in ETI’s class cost-of-service study. Specifically, he complained: (1) there is no customer
charge, despite the fact that the customer costs allocated to the LIPS class would translate into a
monthly rate of over $6,000, and (2) the proposed non-fuel energy charges would recover a
significant amount of demand related costs. According to Mr. Pollock, production/transmission
demand-related costs are $8.47 per kW, and distribution costs add another $0.99 per kW, for a total
of $9.46 per kW. The proposed LIPS demand charges are $7.07 per kW for transmission delivery

967
TIEC Ex. 1 (Pollock Direct) at 68-69.
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and an additional $1.82 for distribution service, for a total of $8.89 per kW. Thus, in Mr. Pollock’s
opinion, the proposed demand charges (given ETI’s requested rate increase) are too low. By
contrast, he noted, non-fuel energy costs are about 0.226¢ per kWh, while the proposed non-fuel
energy charges would average over 0.600¢. Thus, these charges are 2.5 times higher than the
non-fuel energy costs based on ETI’s filing.968

(a) A New Customer Charge

TIEC urged that any increase in Schedule LIPS should be used to create a customer charge.
Mr. Pollock calculated that a cost-based customer charge should be about $6,050 per month, and he
recommended an initial customer charge of $6,000 per month. This would collect approximately
$5.9 million ($6,000 x 984 bills). He added that any remaining increase not accounted for by the
initial customer charge should be collected in the demand charges. He also stated that the non-fuel
energy charges should not be changed unless the LIPS class is allocated less than a $5.9 million
increase. In that event, he recommended that the non-fuel energy charges should be decreased. This
would gradually correct the imbalance between the below-cost demand charges and above-cost
energy charges. Mr. Pollock further stated that the delivery voltage adjustment applicable to
distribution service should be retained so that the rate better reflects the cost. Should the LIPS class
not receive an increase or if base rates are decreased, Mr. Pollock recommended that the customer
charge should be reduced proportionally. Any remaining revenue surplus should be applied to
reduce the non-fuel energy charges to cost and then to reduce the demand charges.969

Staff witness Abbott also recommends the introduction of a customer charge, but a much
smaller one than that recommended by Mr. Pollock – $630.970

DOE supports Staff’s proposed $630 customer charge. DOE witness Etheridge testified that
TIEC’s proposed $6,000 customer charge far exceeds a reasonable initial customer charge for
Schedule LIPS. For example, the existing Commission-approved monthly customer charge for

968
TIEC Ex. 1 (Pollock Direct) at 69-70.
969
Id. at 70.
970
Staff Ex. 7 (Abbott Direct) at 27.
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Schedule LGS is $425.05. Mr. Etheridge stated that the introduction of a $6,000 customer charge
will lead to large shifts in intra-class revenue responsibility from high load factor customers to low
load factor customers because a customer charge does not vary with usage. He noted, as an
example, that TIEC’s proposal would increase DOE’s Big Hill annual costs by $72,000 or nearly
10 percent. Moreover, Mr. Etheridge pointed out that two parties are proposing to lower the
Schedule LGS customer charge—approving either of these recommendations and TIEC’s would
levy Schedule LIPS customers with a new customer charge that is over 23 times the level of the LGS
class. He believes such inconsistencies are inexplicable. Additionally, such disparity would present
a challenge to any customer migrating from the LGS to the LIPS class.971

DOE witness Etheridge agreed that is appropriate to move toward cost-based rates, however,
he indicated that gradualism should be properly applied to move rates toward cost without undue
impact on low usage and low load factor customers in the LIPS class. If a new customer charge for
the LIPS class is to be imposed—it should be that recommended by Commission Staff.972

The ALJs are persuaded by Mr. Etheridge’s testimony that the adoption of a $6,000 customer
charge far exceeds ETI’s existing customer charge in the LGS Schedule and results in a significant
and inappropriate impact to low load factor customers. Rather, Mr. Abbott’s proposed customer
charge of $630 is an appropriate charge to this customer class, particularly as ETI’s current rates
applicable to LIPS customers do not include any customer charge.973

(b) Demand and Energy Charges

In an effort to move more towards cost-based rates, Mr. Abbott recommends a slight
decrease in the LIPS energy charges and an increase in the demand charges from current rates.974
Mr. Pollock does not recommend an increase in energy charges. However, he recommends
increasing demand charges to cover any remaining revenue increase for the LIPS class that is not

971
DOE Ex. 2 (Etheridge Cross-Rebuttal) at 3-4.
972
DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
973
TIEC Ex. 1 (Pollock Direct) at 70.
974
Staff Ex. 7 (Abbott Direct) at 27.
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PUC DOCKET NO. 39896

accounted for with the customer charge. He suggested that such a change will gradually correct the
imbalance between the below-cost demand charges and above-cost energy charges.975

DOE witness Etheridge expressed concerns with both proposals. He stated that
Schedule LIPS customers are, on average, substantially more energy intensive than customers taking
service under Schedule LIPS-TOD customers. He indicated that TIEC’s proposed rate design (with
the $6,000 customer charge) would double the cost increase associated with base rates and the fuel
factor for LIPS-TOD customers compared with the average cost increase for the class as a whole.
Customers with lower load factors than Schedule LIPS-TOD customers would fare even worse.976

Mr. Etheridge also was concerned about Staff’s proposed charges, noting that Mr. Abbott
failed to explain how the slight decrease in the LIPS energy charge and the large increase in the
demand charge would affect customers with changes in the revenue requirement ultimately assigned
to the class. Mr. Etheridge stated that even Staff’s proposed changes will noticeably shift intra-class
cost responsibility toward Schedule LIPS customers with relatively low load factors. To address his
concern that changes in the revenue requirement may have a significant impact even with Staff’s
gradual movement in rates, Mr. Etheridge recommended that Staff’s proposal should set the limit on
intra-class cost responsibility shifts.977

The ALJs find evidentiary support for and recommend the adoption of Mr. Abbott’s
proposed changes to Schedule LIPS. There is sufficient evidence, based on Mr. Pollock’s testimony,
that Mr. Abbott’s suggested changes gradually move the rates towards cost without the risk of rate
shock. TIEC’s demand and energy proposals result in unreasonable large shifts in intra-class revenue
responsibility. However, the ALJs also agree with Mr. Etheridge that Staff’s proposal may need to
be adjusted depending on the ultimate revenue requirement adopted.

975
TIEC Ex. 1 (Pollock Direct) at 70.
976
DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
977
DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
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4. Schedulable Intermittent Pumping Service (SIPS)

DOE proposes that a new rider, Schedulable Intermittent Pumping Service (SIPS), be
included in the LIPS tariff. This will allow DOE and other customers with intermittent pumping
loads to avoid application of a demand ratchet to schedulable, temporary, increased demand during
off-peak months when ETI’s costs are lowest. DOE suggests that the proposed rider will allow the
DOE to schedule important testing and oil exchanges, when possible, during off-peak months, is
consistent with existing riders, and does not adversely impact other customers.

DOE explained that its Strategic Petroleum Reserve (Reserve) Texas sites—Big Hill in
Jefferson County and Bryan Mound in Brazoria County—play an important role in ensuring the
energy security of the United States. With a crude oil inventory of about 726.5 million barrels in
2010, the Reserve is the largest emergency supply of oil in the world. The Reserve was established
by Congress as a result of the oil supply disruption in the early 1970s.978

DOE witness Etheridge testified that DOE takes service to its Big Hill site under
Schedule LIPS at an annual cost of approximately $770,000. Mr. Etheridge explained that the
Reserve’s sites typically operate in standby mode, with routine cyclical tests of pumping equipment.
The largest of these tests is performed every other year. These cyclical equipment tests can be
coordinated with ETI so that they occur during low peak periods.979

On rare occasions, the Reserve can also be tapped. In its nearly 35 years of operations, there
have been three Presidential-ordered drawdowns: January 1991, the beginning of Desert Storm;
September 2005, Hurricane Katrina; and July-August 2011, the International Energy Agency
coordinated release. The latter was the largest of the three drawdowns at 30.6 million barrels.
Additionally, the Reserve has provided support to the oil industry in localized emergency or
operational situations involving a disruption in supply, such as ship channel closures and hurricanes.

978
DOE Ex. 1 (Etheridge Direct) at 3.
979
DOE Ex. 1 (Etheridge Direct) at 3-4
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When oil is exchanged during these situations, the Reserve will operate pumps at higher levels than
would occur during normal standby operations.980

Mr. Etheridge proposed a rider to Schedule LIPS where maximum demands during pre-
scheduled, non-summer month operations of a limited duration are not subject to demand ratchets.
For this new rider, he proposed that the non-summer months be classified as October through May to
give customers and ETI more flexibility. (Under Schedule LIPS, non-summer months are November
through April.) Key provisions of the proposed SIPS rider include:

¾ A requirement that customers schedule with ETI limited duration
operations during non-summer months four weeks in advance.

¾ ETI must approve scheduled operations.

¾ Operations would not be allowed to exceed 10,000 kW in magnitude nor
last for more than 80 hours per year.

¾ ETI could cancel operations at any time if a capacity constraint develops.
If a customer failed to comply, the customer would incur costs
associated with ETI’s ratchet.

¾ A customer in compliance would not be subject to ETI’s demand ratchets
for loads established during those operations, but would pay the demand
charge in the month in which the operations occur.981

Mr. Etheridge gave an example of charges under Schedule LIPS versus charges if the rider
were adopted. In September 2010, Big Hill conducted a test and established a maximum measured
demand of 11,640 kW, well above the site’s average maximum demand of approximately 3,000 kW.
DOE paid demand charges on the 11,640 kW in September 2010. In October 2010, ETI billed DOE
for 75 percent of that level of demand or 8,730 kW based on the rolling 12-month ratchet. Its actual
demand was 2,520 kW. In terms of actual costs, DOE paid $683,000 for its September usage. Under
the 75 percent ratchet, DOE would pay $609,000 per month. Mr. Etheridge estimated that the

980
DOE Ex. 1 (Etheridge Direct) at 3-4.
981
DOE Ex. 1 (Etheridge Direct) at 18.
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charges amounted to $59/kW per year, which could easily represent nearly one-half of the annual
carrying cost of a combustion turbine. Whereas, under the proposed rider, if DOE conducted the test
in February as it intended to, it would have paid ETI for the 11,640 kW level of demand, but the
usage would not be used in conjunction with ETI’s ratchets. Mr. Etheridge concluded ETI’s tariff is
not equitable. At the hearing, Mr. Etheridge estimated that the rider’s impact on other customer
classes at approximately $500,000, where Schedule LIPS base rate revenues are approximately
$110 million.982

According to DOE, for 15 years, June 1996-June 2011, ETI, by contract, accommodated the
Reserve’s intermittent load by allowing the DOE to, once annually, “reset” the demand level to be
used by ETI when applying demand ratchets. The DOE was able to avoid significant demand
charges when typical demand was very low. After June 2011, ETI declined to apply the terms of the
long-time contract and allow the reset. DOE concedes that cost-based rates to reflect the Reserve’s
unique operations should ultimately be addressed by contract and/or new tariffs.

DOE notes that the very purpose of some riders is to address specific customer
characteristics. For instance, Standby and Maintenance Service is available only to those customers
that co-generate electricity; the Optional Rider to Schedule LIPS for Pipeline Pumping Service alters
the designation of on peak-hours only for customers with pipeline pumping stations. Other riders,
claims DOE, seek a win-win for all customers. For instance, the Rider to LIPS for Planned
Maintenance rewards customers for scheduling routine maintenance and idling facilities during
ETI’s peak summer months of June through September by waiving the demand ratchet. DOE argues
that the proposed SIPS rider mirrors Planned Maintenance by waiving the demand ratchet if
customers are able to schedule intermittent loads outside of ETI’s peak summer months. Moving
toward cost-based rates is not discriminatory, claims DOE. Nor is rewarding customers who use
their load scheduling flexibility for the benefit of all customers.

DOE’s proposed SIPS rider is opposed by ETI, TIEC, and Staff.

982
DOE Ex. 1 (Etheridge Direct) at 19-20; Tr. at 2034.
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ETI witness Talkington testified that the actual Reserve load, as Mr. Etheridge described,
does not appear to match the parameters of his proposed SIPS rider. As recently as July and August
2011, the Reserve sites had significant load requirements in order to pump vast quantities of oil. She
further testified that the Reserve loads are random in occurrence and are significant. ETI must at all
times maintain generation resources to meet this significant and randomly occurring load. In
addition, the Company has invested in transmission and other facilities to serve this customer even if
there is no or very little consumption. She believed it would not be appropriate or equitable to other
customers to remove or forgive the 12-month ratchet provision after the Company made these
investments to serve the Reserve and while the Company has maintained generation to meet its load.
If the 12-month ratchet were forgiven, then the costs incurred to serve DOE would have to be borne
by other customers in the LIPS rate class.983

TIEC witness Pollock complained that Mr. Ethridge failed to analyze the impact on other
LIPS customers. Mr. Pollock contended the rider would discriminate against both Schedule LIPS
customers (by redefining the summer billing period) and Schedule SMS customers (whose ability to
schedule maintenance power could be subordinate to LIPS customer taking advantage of the new
Rider).984

Staff is concerned that the rider’s unusual eligibility requirements—that a customer must
schedule load four weeks in advance, limit the high load occurrence to “off-peak months” (which is
redefined in the rider), and limit the yearly hours of load—indicate it is tailored solely to meet the
unique needs of the Reserve. According to Staff, DOE conceded that, although other customers with
intermittent loads might take advantage of the proposed SIPS rider, Mr. Etheridge was not aware of
any other actual customer that could do so.985 Staff argues the rider appears to offer unreasonably
preferential treatment to the DOE and should be rejected.

983
ETI Ex. 67 (Talkington Rebuttal) at 41.
984
TIEC Ex. 3 (Pollock Cross Rebuttal) at 9-10, 44-46.
985
Tr. at 2008 (“Q: Now, who else would take advantage of this SIPS rate schedule, other than DOE? A: It’s
written such that any other customer that would have an intermittent schedulable load could take advantage of
it. But I’m not sure if there are other customers on Entergy’s system that could take advantage of it. Q: So
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Beyond issues of discrimination, Staff is also concerned that the rider would shift costs from
the DOE to other LIPS customers. Although DOE indicates that any shift would have a small
overall impact on the LIPS class, Staff argues that the Commission should not endorse any
discriminatory rate rider.

Although Staff and TIEC claim the proposed rider is discriminatory, other riders applicable
to Schedule LIPS customers are available at different times of the year as well (Planned
Maintenance is available only during the months of June through September) and others are limited
to customer-specific needs—such as PPS for pipeline customers. Mr. Etheridge testified that this
rider could apply to any customer—it is not restricted solely to the DOE. The ALJs do not find this
rider to be unreasonably discriminatory. As to ETI’s concern on this issue, it was focused on
whether the DOE’s load met the proposed rider’s requirements. However, if a customer taking
service under the rider is unable to schedule its maintenance and oil exchanges with ETI, then the
usage would be under the SIPS Schedule and the SIPS tariffed demand ratchet would apply.
Moreover, Mr. Etheridge testified that the impact on other customer classes is limited. As to ETI’s
cost recovery, the LIPS rider customers will pay a demand charge to cover the costs they impose on
the system in the month SIPS service is taken. The ALJs agree with DOE that the SIPS rider is
reasonable and should be adopted.

5. Standby Maintenance Service (SMS)

TIEC witness Pollock explained that Schedule SMS applies to customers that use
self-generation to supply a portion of their electricity requirements. These customers contract with
ETI for either standby and/or maintenance power service to replace capacity or energy normally
generated by the customer’s on-site generation. Standby (or backup) power is electric energy or
capacity supplied to replace energy or capacity that is unavailable due to an unscheduled or forced
outage of the facility. Thus, backup power must be available at any time. Maintenance power is
electric energy or capacity supplied during a scheduled outage. Unlike backup power, maintenance
power must be arranged with 24-hour notice and only during such times and at such locations that,

you don’t know that there are others who could use it. This could apply just to DOE? A: It could.”).
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in ETI’s opinion, will not result in adversely affecting or jeopardizing firm service to other
customers, prior commitments, or commitments to other utilities. In addition, the customer must
make arrangements and schedule maintenance power in writing in advance and confirmed in writing
by ETI. ETI can also limit requests for maintenance power and allocate and schedule available
service, if requests are made from more than one customer. Thus, Mr. Pollock stated that
maintenance power is of a lower quality of service than backup or standby power. He also indicated
that, because the Company can limit the amount of maintenance power, it is more likely that
customers would prefer to schedule maintenance power during the non-summer months.986

ETI witness Talkington explained that standby service includes both the readiness to serve
and the actual delivery of power and energy delivered when a customer requires service due to a
forced outage or a planned maintenance period. She indicated that many utilities offer a
combination of pricing and terms for demand and energy service as well as a form of reservation
charge dealing with the readiness to serve. She further indicated that the actual rate design may
differ, but standby tariffs usually contain provisions for back-up (forced outage) or maintenance
(planned outage). She concluded that ETI’s current rate schedule provides for these features, and
ETI is not proposing to change Schedule SMS in this proceeding.987

TIEC proposes to redesign SMS service to better reflect the cost characteristics of standby
and maintenance power customers. Mr. Pollock provided his analysis to support TIEC’s position.
Under the current Schedule SMS, customers pay a monthly demand (or billing load) charge of
$1.12 per kW for backup power. The corresponding charges for maintenance power are $1.12 per
kW for outages during the summer months (May through October) and $0.84 per kW for outages
during the non-summer months. Thus, the non-summer month charge is 75 percent of the summer
month charge. Energy is priced under an array of time-differentiated charges, as shown in the table
below:988

986
TIEC Ex. 1 (Pollock Direct) at 70-71.
987
ETI Ex. 67 (Talkington Rebuttal) at 19-20.
988
TIEC Ex. 1 (Pollock Direct) at 72-73.
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Current Schedule SMS Non-Fuel Energy Charges
(¢ per kWh)
On-
Delivery Voltage Off-Peak
Peak989
Distribution (less than 69KV) 3.386¢ 0.514¢
Transmission (69KV and
greater) 2.334¢ 0.211¢

Mr. Pollock examined P.U.C. SUBST. R. 25.242(k)(1) and concluded that, for Standby
Service, cost-based standby rates should recognize system-wide costing principles and must not be
discriminatory. According to his analysis, the SMS demand charges should be $0.82 per kW for
delivery at transmission and $2.64 per kW for delivery at distribution. He also determined that cost-
based energy charges should be as follows:990

Cost-Based Schedule SMS Non-Fuel Energy Charges
(¢ per kWh)
Delivery Voltage On-Peak Off-Peak

Distribution (less than 69KV) 0.955¢ 0.639¢
Transmission (69KV and
greater) 0.916¢ 0.614¢

Mr. Pollock explained that, on average, 7 percent of Schedule SMS billing demand was
coincident with ETI’s summer month system peaks. This compares to 74 percent for Schedule
LIPS; thus, the ratio of the SMS to LIPS coincidence factors is 12 percent. By Mr. Pollock’s
calculations, the resulting demand charge for transmission service would be $0.82 per kW ($7.07 x
12 percent), and the corresponding SMS distribution demand charge would be the sum of the
transmission charge and the Schedule LIPS distribution demand charge, or $2.64 per kW ($0.82 +
$1.82).991

989
On-peak hours are from 1:00 p.m. to 9:00 p.m., Monday through Friday of each week, beginning on May
15 and continuing through October 15. In addition, fuel charges are priced at avoided energy cost as
calculated under Schedule LQF. TIEC Ex. 1 (Pollock Direct) at 72.
990
TIEC Ex. 1 (Pollock Direct) at 73-74 and Ex. JP-15.
991
Id. at 72-74.
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Mr. Pollock testified that he combined production and transmission costs in deriving a
cost-based schedule SMS demand charge for transmission delivery, because both production and
transmission demand-related costs are allocated to customer classes using the A&E 4CP method.
This method recognizes that production/transmission plant is sized to meet the diversified summer
peak demands of all ETI customers. That is, Mr. Pollock stated, the 4CP demands are a primary
driver of the costs of the power plants, PPAs, and transmission facilities. As noted above,
Mr. Pollock contended and verified by analysis that a cost-based Schedule SMS demand charge
should be only 12 percent of the corresponding demand charge for Schedule LIPS.992

Mr. Pollock also stated that he proposed to differentiate the standby demand charge by
delivery voltage because it more directly recognizes the different costs to provide service at
transmission and distribution voltage. He added that this recommendation is consistent with the
current Schedule SMS energy charges.993 However, Mr. Pollock did not apply the 12 percent
coincidence ratio to determine the distribution-related schedule SMS demand charge. He explained
that distribution facilities are electrically closer to customers, so a customer’s peak demand
determines how distribution facilities must be sized to ensure reliable service. He stated that ETI
recognized this driver by using maximum diversified demand to allocate distribution demand-related
costs. For this reason, Schedule SMS customers require the same amount of distribution capacity as
a similarly sized Schedule LIPS customer. Thus, according to Mr. Pollock, the Schedule SMS
distribution demand charge should be the same as the corresponding Schedule LIPS demand
charge.994

Concerning energy charges, Mr. Pollock testified that the Schedule SMS energy charge
should reflect the composite Schedule LIPS energy charges, or 0.614¢ per kWh. In his view, a
Schedule SMS customer should also pay additional demand charges during on-peak hours, because
this would recognize that an SMS customer that purchases more energy during on-peak hours would
more closely resemble a LIPS customer. For this reason, cost-based on-peak energy charge should

992
Id. at 75-77.
993
TIEC Ex. 1 (Pollock Direct) at 77.
994
Id. at 77-78.
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be a composite of the Schedule LIPS energy charge and the remaining demand charges (not
collected in the SMS demand charge). He calculated an additional on-peak energy charge of 0.303¢,
which yields a total on-peak energy charge of 0.917¢. Under this structure, an SMS customer that
experiences an outage would pay approximately the same for electricity as a LIPS customer.995

In summary, Mr. Pollock contended that Schedule SMS should be reduced to more closely
reflect the cost of providing standby service as follows:996

Cost-Based Schedule SMS Charges
Based on ETI’s Proposed Schedule LIPS Design
Distribution Transmission
Charge (less than (69kV and
69kV) greater)
Billing Load Charge ($/kW)
Standby $2.64 $0.82
Maintenanc
$2.44 $0.62
e
Non-Fuel Energy Charge (¢/kWh)
On-Peak 0.955¢ 0.916¢
Off-Peak 0.639¢ 0.614¢

Using his recommended Schedule LIPS rate design, he proposed Schedule SMS charges
shown in the table below:997

TIEC Proposed SMS Charges
Distribution Transmission
Charge (less than (69kV and
69kV) greater)
Customer Charge
$6,000
(Stand Alone)
Billing Load Charge ($/kW)
Standby $2.46 $0.79
Maintenance $2.27 $0.60
Non-Fuel Energy Charge (¢/kWh)
995
Id. at 77-78; Ex. JP-15.
996
Id. at 79.
997
TIEC Ex. 1 (Pollock Direct) at 80.
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On-Peak 0.881¢ 0.846¢
Off-Peak 0.575¢ 0.552¢

Mr. Pollock based his recommended charges on ETI’s proposed revenue requirements and
class revenue allocation. If the Schedule LIPS revenue requirement is reduced, the charges should
be correspondingly reduced. Mr. Pollock also added a customer charge, but he stated that the
customer charge should not apply if a Schedule SMS customer also purchased supplementary power
under another applicable rate.998

To determine maintenance power charges, Mr. Pollock maintained the same relationship; that
is, the current maintenance power demand charge is 75 percent of the standby power demand charge.
He stated that the 75 percent should apply to the production/transmission component of the
recommended standby power demand charge because distribution costs are caused by maximum
demands occurring at any time, as previously discussed. This would result in a $0.20 and
$0.19 per kW differential based on ETI’s proposed and Mr. Pollock’s recommended Schedule LIPS
designs, respectively.999

The ALJs note that Mr. Pollock’s suggested changes to Schedule SMS are extensive. For
instance, he introduced a $6,000 customer charge and, for the monthly billing load (demand)
charges, he introduced separate rates for distribution and transmission customers.1000

Ms. Talkington testified that Mr. Pollock erred in using load data for the period of 2007
through 2011 to develop a coincidence factor that he then uses to develop a lower back-up and
maintenance demand charge for transmission-level customers, while significantly increasing the
charge for distribution-level customers. She also stated that Mr. Pollock’s proposal fails to
recognize the “readiness to serve” aspect of standby service. ETI must be ready to serve the load

998
Id. at 79.
999
TIEC Ex. 1 (Pollock Direct) at 80.
1000
TIEC Ex. 1 (Pollock Direct) at 80.
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represented by the largest generation unit taking standby service, plus account for the forced outage
rates for all other existing customer-owned generators.1001

Ms. Talkington also stated Mr. Pollock failed to recognize that standby load does not lend
itself to the typical rate design practices. She opined that the cost of providing SMS service is not
driven only by the degree to which standby customers contribute to peak demand, but also by the
Company’s obligation to serve whenever called upon. This is the major reason Schedule SMS is not
included in the development of allocation factors.1002

Ms. Talkington admitted that she is not familiar with how ETI originally developed
Schedule SMS, but stated that she knows that when a customer takes back-up or maintenance
service, costing is generally designed to mimic what the customer would have paid on standard rates,
absent the use of its own generator. She concluded that Mr. Pollock’s analysis is over-simplified
and incomplete.1003

In rebuttal testimony, Ms. Talkington proposed a new rate design for SMS service, including
a new service, Non-Reserved Service, which is an optional service designed to supplement
Maintenance Service. ETI’s new SMS proposal increases ETIs test year base rate revenues by
53.27 percent, with an overall increase of $5.1 million. ETI did not include this rate increase in its
notice.1004 Accordingly, the ALJs determine that ETI’s new SMS proposal is not an option to be
considered in this case.

Commission Staff does not oppose ETI’s request to retain its current Schedule SMS.

1001
ETI Ex. 67 (Talkington Rebuttal) at 20-21.
1002
ETI Ex. 67 (Talkington Rebuttal) at 21.
1003
ETI Ex. 67 (Talkington Rebuttal) at 21-22.
1004
PURA § 36.102 and P.U.C. PROC. R. 22.51 require a utility to publish notice of its intent to change rates,
with proposed revisions of tariffs and a detailed statement of each proposed change, the effect it is expected to
have on revenues, the class and number of customers affected by the change.
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ETI did not demonstrate how its current rates are just and reasonable. Rather, ETI’s
evidence on the reasonableness of Schedule SMS is conclusory and insufficient in light of
Mr. Pollock’s testimony that the rates are not cost-based. Moreover, although Ms. Talkington
indicated her concern with Mr. Pollock’s analysis, she provided no quantitative support for her
concern. The ALJs, however, are concerned that Mr. Pollock’s suggested changes are not
accompanied by a rate impact analysis. And, as noted above, his suggested changes are extensive.
Mr. Pollock’s recommendations included a significant increase in the charge for distribution-level
customers. Consistent with his Schedule LIPS recommendation, Mr. Pollock also included a $6,000
customer charge when no previous customer charge existed. Again, there is no analysis as to the
effect such a charge would have on customer bills. The testimony of witnesses Benedict, Abbott,
Higgins, and Pevoto caution that gradualism should be considered in rate design. As noted by Mr.
Higgins, “full movement to cost-based rates in a single step is sometimes opposed on the grounds of
intra-class rate impacts.”1005 However, the rate impact at this time is not known.

Based on the evidence and discussion above, the ALJs recommend adoption of Mr. Pollock’s
suggested changes to Schedule SMS , with the exception of a $6,000 customer charge. Consistent
with the ALJs’ recommendation that a new LIPS charge of $630 is reasonable, the SMS charge
should be limited to $630 and, as suggested by Mr. Pollock, not apply if a Schedule SMS customer
also purchased supplementary power under another applicable rate.

6. Additional Facilities Charge (AFC)

Mr. Pollock testified that Schedule AFC is the mechanism for charging customers directly
for the costs of transformers, breakers and lines when those facilities provide service only to specific
customers. Some of these facilities are booked to transmission accounts while others are booked to
distribution accounts. Schedule AFC is applied as a percentage of the original (un-depreciated) cost
of the facilities.1006

1005
Kroger Ex. 1 (Higgins Direct) at 10.
1006
TIEC Ex. 1 (Pollock Direct) at 81.
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TIEC contends that the Schedule AFC charges should be revised. According to Mr. Pollock,
the current charges exceed ETI’s ownership and O&M costs; therefore, he recommended that the
monthly charges in Schedule AFC be reduced. Under this rate schedule, there are two separate
pricing options. Option A charges 1.49 percent per month; Option B applies when a customer elects
to amortize the direct assigned facilities over a shorter term, ranging from one to ten years. Thus,
the Option B Monthly Recovery Term charge varies depending on the length of the amortization
period of the directly assigned investment. A 0.453 percent Monthly Post-Recovery term charge
also applies after a facility has been fully depreciated. ETI did not propose to change either the
Option A or Option B charges in Schedule AFC.1007

According to Mr. Pollock’s analysis, charges imposed under Option A should be
1.20 percent per month under ETI’s proposed revenue requirements. Under Option B, Mr. Pollock
proposes various changes to the Recovery Term charges, and reduces the Monthly Post-Recovery
term to 0.35 percent per month. Further, if the Commission approves a lower base revenue
requirement than ETI has proposed, Mr. Pollock stated that the recommended Schedule AFC
charges (both Option A and Option B) should be reduced in proportion to any authorized reduction
in ETI’s proposed rate of return, O&M expense, and property tax expense.1008

In reaching this recommendation, Mr. Pollock used two different methods to derive a cost-
based rate: a levelized cost analysis and a revenue requirement analysis. The former resulted in an
Option A rate of 1.20 percent per month, and the revenue requirement analysis resulted in a
weighted average rate of 1.18 percent. For Option B charges, Mr. Pollock also used a levelized cost
analysis for each of the Option B amortization periods, which resulted in lower charges.1009

ETI witness Talkington disagrees with Mr. Pollock’s description of Schedule AFC. She
testified that the rate schedule encompasses the costs associated with the installation of facilities
other than those normally furnished. Or, under one option, the rates are like a monthly rental charge

1007
Id. at 82-85.
1008
TIEC Ex. 1 (Pollock Direct) at 81-85 and at Exs. JP-17 and JP-18. See ETI Ex. 3, Sch. Q-8-8 at 24.
1009
TIEC Ex. 1 (Pollock Direct) at Ex. JP-18.
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paid for facilities that would not normally be supplied by the Company. She also stated that
Mr. Pollock’s example of facilities (transformers, breakers and lines) is understated.1010

ETI contends that revisions to this discretionary rate are unwarranted at this time. The
Commission approved this rate structure (and rate) in Docket No. 16705. Moreover, ETI witness
Talkington testified that this rate is voluntary—a customer has alternatives beyond those offered by
ETI. Therefore, it is actually a market-driven rate. If a customer does not want to use this schedule
to obtain the services it provides, the customer can secure services through other sources—either
ETI-owned or otherwise. Ms. Talkington further stated that Mr. Pollock’s suggested changes would
be detrimental to the customers who do not have AFC rates because the AFC revenue is treated as an
offset to the revenue requirement to the rate classes.1011

Staff does not oppose ETI’s request to retain the AFC rate as it is currently designed.

The ALJs find insufficient support in the record to retain ETI’s Schedule AFC as-is. As
noted by TIEC, there is no evidence in this case to support ETI’s claim that: (1) the rate is a
voluntary rate; (2) there are other options in the market for customers; or (3) that the rate continues
to be based on a cost that the market will bear (as the Commission found years ago in Docket
No. 16705).1012 While Ms. Talkington disagreed with Mr. Pollock’s proposal because he did not
take into consideration the scope of facilities provided and that his proposal could be detrimental to
other ratepayers because ETI’s revenues from this rate will decrease, she did not quantify her
concerns.1013 The evidence supports a change to Schedule AFC that will move the rate more
towards costs, and TIEC’s proposals are the only ones for which there is evidence in the record. The
ALJs further agree with Mr. Pollock that his numbers should be reduced in proportion to any
authorized reduction in ETI’s proposed rate of return, O&M expense, and property tax expense.

1010
ETI Ex. 67 (Talkington Rebuttal) at 31.
1011
ETI Ex. 67 (Talkington Direct) at 27-28.
1012
See Docket No. 16705, Final Order, FoFs 292-296.
1013
Tr. at 1437, 1439-1440.
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7. Large General Service (LGS)

Kroger witness Kevin C. Higgins testified that the LGS rate schedule serves customers with
monthly billing demands between 300 kW and 2,500 kW. ETI proposes to increase the LGS
demand charge from $8.56 per kW-month to $10.25 per kW-month and to increase the energy
charge from $.00854 per kWh to $.01023 per kWh. The Company proposes no change in the
customer charge of $425.05 per month.1014

Mr. Higgins testified that ETI’s proposed LGS demand charge would recover only
72 percent of LGS demand-related costs. To compensate for the resultant revenue shortfall, the LGS
energy charges proposed by ETI would significantly over-recover energy-related costs. Specifically,
the overall LGS energy charge is proposed to be 428 percent of base energy costs. In addition,
although the customer charge is proposed to be unchanged, it is set at 328 percent of cost. If,
instead, the LGS customer charge were set at cost, it would only be $129.60 per month.1015

Mr. Higgins illustrated his findings in the table below:1016

LG Total Class Functionalized Cost Recovery

Functions Costs Collected in (Under)/Over Percentage
Rates Collection Recovered
Demand $46,266,083 $33,116,674 $(13,149, 409) 71.6%
Energy $3,6625,811 $15,556,253 $11,920,442 427.9%
Customer $561,445 $1,841,316 $1,279,871 328.0%
Total $50,463,339 $50,514,243 $50,904

Mr. Higgins stated that if a utility proposes a demand charge that is below the cost, it is going
to seek to recover its class revenue requirement by over-recovering its costs in another area,
typically through an energy charge that is above unit energy costs. In his opinion, for LGS, when
demand charges are set below costs and energy charges are set above cost, customers with relatively

1014
Kroger Ex. 1 (Higgins Direct) at 7.
1015
Id. at 8.
1016
Kroger Ex. 5.
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higher load factors are required to subsidize the costs of lower load factor customers within the rate
class. The subsidy is different for each higher load factor customer (a customer whose load factor is
greater than the average for the rate schedule) and consists of the net increase in rates paid by these
customers as a result of setting energy charges above energy costs and demand charges below
demand related costs. When the customer charge is set significantly above costs, smaller customers
are overcharged and subsidize the larger customers.1017

Recognizing that a full movement towards cost-based rates (without gradualism) in a single
step may create intra-class rate impacts, Mr. Higgins proposed the following changes to better align
costs:1018

ETI Kroger
Proposed % of Proposed % of
Functions
Charge Cost Charge Cost
Demand ($/kW) $10.25 72% $12.81 90%
Energy ($/kWh) $0.01023 428% $0.00513 216%
Customer ($/Mo) $425.05 328% $260.00 201%

Mr. Higgins developed his proposed rate impacts, which indicated a smaller rate impact on
higher load factor customers than those with low load factors. He found them to be comparable to
the rate impact found in ETI’s proposed rates.1019

ETI witness Talkington did not object to gradually moving rates toward setting demand
energy and customer components closer to cost of service in the LGS class.1020

Based on principles of cost-based rates and of gradualism, Staff witness Abbott
recommended a decrease in the LGS customer charge to $397.02 from the current (and Company

1017
Kroger Ex. 1 (Higgins Direct) at 9.
1018
Id. at 10-11.
1019
Id. at 11, Ex. KCH-3.
1020
Tr. at 1452.
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proposed) $425.05, and an increase in the energy charges, which is less than the increase proposed
by the Company.1021

The ALJs found Mr. Higgins’ proposed changes reasonable and well supported.
Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet,
and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is applicable to
this class.

8. General Service (GS)

Based on principles of cost-based rates and of gradualism, Staff witness Abbott
recommended a decrease in the GS customer charge to $39.91 from the current (and Company
proposed) rate of $41.09. Staff also recommended a decrease in the energy charges.1022

No party disputed Staff’s recommendations, which the ALJs adopt. Schedule GS also has a
demand ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is
applicable to this class.

9. Residential Service (RS)

ETI’s RS rate schedule is composed of two elements: a customer charge of $5 per month
and a consumption-based energy charge. The Energy charge is a fixed rate of 5.802ȼ per kWh from
May through October (Summer). In the months November through April (Winter), the rates are
structured as a declining block, in which the price of each unit is reduced after a defined level of
usage. For instance, the same energy charge of 5.802ȼ applies, but only for each of the first 1,000
kWh consumed. Each kWh consumed beyond 1,000 is billed at a lower rate of 3.834ȼ.1023

1021
Staff Ex. 7 (Abbott Direct) at 25-27.
1022
Id.
1023
OPC Ex. 6 (Benedict Direct) at 41, Ex. NAB-1, ETI’s Response to State RFI No. 4-17; ETI Ex. 67
(Talkington Rebuttal) at 9.
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ETI proposes to retain the general structure of the RS rate design but proposes an increase in
the dollar amount of each rate element. OPC witness Benedict noted ETI’s proposed changes in his
testimony, as set out below:1024

ETI ETI Percent
Rate Element Current Proposed Increase
Customer Charge (per month) $5.00 $6.00 20.0%
Energy Charge (Summer, all 25.3%
$0.05802 $0.07268
kWh)
Energy Charge (Winter, kWh ≤ 25.3%
$0.05802 $0.07268
1000)
Energy Charge (Winter, kWh > 25.2%
$0.03834 $0.04799
1000)

OPC criticized ETI’s declining block rate structure as being contrary to energy efficiency
efforts. OPC witness Benedict noted that under ETI’s proposed rate structure, once kWh usage
exceeds 1,000 in a winter month, the per-kWh cost of consumption falls by 34 percent. Thus,
because a declining block rate structure lowers the per-unit rate for high levels of consumption,
heavy users are induced to consume more than they would otherwise. In his view, this runs contrary
to the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as
stated in PURA § 39.905:

(a) It is the goal of the legislature that: . . . (2) all customers, in all customer classes,
will have a choice of and access to energy efficiency alternatives and other choices
from the market that allow each customer to reduce energy consumption, summer
and winter peak, or energy costs.

Therefore, Mr. Benedict recommended that the declining block rate be phased out over time. He
stated this would ease the transition to a rate structure without a declining block, and it would allow
time for customers to switch to more efficient heating systems. Mr. Benedict proposed that the
phase-out take place over three rate cases, beginning with a one-third reduction in the block
differential proposed by ETI in this case. Reducing ETI’s proposed block differential from 2.469ȼ

1024
OPC Ex. 6 (Benedict Direct) at 42.
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PUC DOCKET NO. 39896

to 1.645ȼ accomplishes the initial one-third reduction, as illustrated below (using ETI’s requested
revenue requirement):1025

Reduced
ETI ETI Percent Block Rate Percent
Rate Element Current Proposed Increase Differential Increase
Customer Charge (per month) $5.00 $6.00 20.0% $6.00 20%
Energy Charge (Summer, all 25.3% 23.1%
$0.05802 $0.07268 $0.07141
kWh)
Energy Charge (Winter, kWh ≤ 25.3% 23.1%
$0.05802 $0.07268 $0.07141
1000)
Energy Charge (Winter, kWh > 25.2% 43.3%
$0.03834 $0.04799 $0.05496
1000)

Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended
to affect the amount of revenue to be collected from the residential class or any other class. If,
however, the Commission approves a different revenue requirement for the residential class to
reflect various proposed adjustments, rates for the class will need to be recomputed regarding a
reduced block differential1026

Staff generally agreed with OPC’s recommendation for a reduction in the rate differential
between the residential winter kWh ≤ 1000 block and the winter kWh > 1000 block, due to the
inconsistency between the incentives produced under declining block rates and the State’s energy
efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011
demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid
encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate
block differential is warranted to better encourage wintertime energy conservation at the margin.1027

ETI witness Talkington testified that the RS rates are cost-based with a declining block rate
in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage
increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She

1025
OPC Ex. 6 (Benedict Direct) at 43-45.
1026
OPC Ex. 6 (Benedict Direct) at 46.
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provided analysis to support her position.1028 Ms. Talkington explained that residential rates do not
include demand charges because of the absence of residential demand meters. However, residential
energy rates can be structured the same as the non-residential classes; that is, customer charge,
demand charge and energy charge. She developed residential rates on this basis to show that the
declining block rate is appropriate to account for reductions in the cost of service to residential
customers as consumption increases. With no declining block rate, high load factor customers are
disadvantaged as the customer charge is reduced and the demand charge is moved into the energy
charge. She believes that declining block rates alleviate the disadvantage.1029

Ms. Talkington illustrated the impact of Mr. Benedict’s suggestion to phase out the declining
block rate for RS customers. Approximately 54 percent of ETI’s residential customers use more
than 1,000 kWh in January and February. For a customer using 3,000 kWh in a winter month of
November-April, this customer’s bill would increase by 16.28 percent or about $48 over current
rates. (Of ETI’s total number of RS customers, approximately 10 percent use 3,000 kWh or more in
the months of January and February.) For that same customer, ETI’s as-filed proposal shows an
increase of 11.96 percent or approximately $35. Mr. Benedict’s proposal is $13 greater than ETI’s
proposal for one winter month at 3,000 kWh. That dollar amount is over a third of the total increase
ETI is proposing.1030

After Mr. Benedict’s proposed phase-out is completed, based on the proposed residential
rates in the Company’s case, the residential rate would be $0.06887 per kWh in both summer and
winter. A customer using 3,000 kWh in a winter month of November-April would see an increase of
24.89 percent or about $73 over current rates. After the final phase out, Mr. Benedict’s proposal is
$38 per month greater than ETI’s as-filed proposal of $35 for one winter month at 3,000 kWh.1031

1027
Staff Ex. 7 (Abbott Direct) at 27.
1028
ETI Ex. 67 (Talkington Rebuttal) at 13, Ex. MLT-R-1.
1029
Id. at 14.
1030
Id. at 15.
1031
Id. at 15-16.
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Ms. Talkington further noted that rate design professionals always take into consideration the
effect on customer bills. Even though Mr. Benedict proposes to implement the change over the next
three rate cases, she concludes there will still be winners and losers within the residential class as a
result of his proposed change. According to Ms. Talkington, some customers have made decisions
about investing in electric appliances based on the current rate design. The elimination of the
declining block in the winter time changes the economics of customer decisions that have already
been made. She believes that great caution needs to be exhibited and very good reasons need to be
demonstrated before changes are made to the rate design. She recommended that if a change to the
rate structure is recommended, the initial phase-in should be reduced to 10 percent rather than one-
third and subsequent reductions should be reviewed for consideration at the occurrence of each rate
case filing and not mandated at this time.1032

The ALJs concur with OPC and Staff that the structure of the declining block winter rates
provide a disincentive to energy efficiency. However, ETI provided evidence that OPC’s suggested
changes, combined with ETI’s proposed rate increase, will have too great an impact. OPC suggested
a one-third reduction in the differential, while Ms. Talkington suggested a 10 percent reduction, with
subsequent reductions reviewed before being mandated. The ALJs recommend an initial 20 percent
reduction, which should alleviate some of ETI’s concerns but still reduce the block differential
sufficiently to move towards compliance with the energy goals set out in PURA. The ALJs further
recommend that 20 percent subsequent reductions of the differential be required in the next three
rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable.

XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31]

In the application, ETI seeks to reconcile approximately $1.3 billion in fuel and purchased
power expenses incurred over the 24 month Reconciliation Period. Summaries of ETI’s total fuel
and purchased power expenses and over/under recovery balance are shown below.

1032
ETI Ex. 67 (Talkington Rebuttal) at 15-17.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 320
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Fuel Reconciliation
Gas and Oil $616,248,686
Emissions Allowance 360,236
Coal 90,821,317
Total Fuel: $707,430,239

Purchase Power Expense 990,041,434
Off-system Sales Revenues (376,671,969)
Total Purchased Power: $613,369,465

Total Fuel Costs: $1,321,799,704

Over-recovery Balance: $243,339,353

Special Circumstances $99,715
Sources: ETI Ex. 3 Schedules I-16, H-12.4a-g, H-12.5b-e, I-21; ETI Ex. 11 (McCloskey Direct); ETI Ex. 23 (Zakrzewski
Direct).

ETI contends, and the evidence presented at the hearing demonstrates, that these fuel factor
expenses were eligible for reconciliation and were reasonable and necessary to provide reliable
service to ETI’s customers during the Reconciliation Period. With the exception of three minor
issues that are discussed below, none of the intervenors raised a substantive issue with respect to
ETI’s fuel reconciliation request.

During the Reconciliation Period, ETI’s Texas fuel factor revenues over-recovered total fuel
and purchased power expense by $243,339,353, inclusive of interest. The Commission authorized
the refund of the fuel over-recovery balance in Docket Nos. 37580, 38403, and 38967. ETI proposes
that the amount of any fuel over-recovery balance not already refunded or authorized for refund be
rolled forward as the beginning balance for the next reconciliation period.1033

P.U.C. SUBST. R. 25.236(d)(1) states that in a fuel reconciliation proceeding, the utility has
the burden of showing that:

(A) its eligible fuel expenses during the fuel reconciliation period were
reasonable and necessary expenses incurred to provide reliable electric
service to retail customers;

1033
ETI Ex. 40 (Thiry Direct) at 7.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 321
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(B) if its eligible fuel expenses for the reconciliation period included an item or
class of items supplied by an affiliate of the electric utility, the prices charged
by the supplying affiliate to the electric utility were reasonable and necessary
and no higher than the prices charged by the supplying affiliate to its other
affiliates or divisions or to unaffiliated persons or corporations for the same
item or class of items; and
(C) it has properly accounted for the amount of fuel-related revenues collected
pursuant to the fuel factor during the reconciliation period.

In Docket No. 15102, an EGSI fuel reconciliation case, the Commission explained the
traditional prudence standard to be applied in reviewing decisions made by the utility:

The exercise of that judgment and the choosing of one of that select range of options
which a reasonable utility manager would exercise or choose in the same or similar
circumstances given the information or alternatives available at the point in time
such judgment is exercised or option is chosen.

There may be more than one prudent option within the range available to a utility in
any given context. Any choice within the select range of reasonable options is
prudent, and the Commission should not substitute its judgment for that of the utility
. . . . The reasonableness of an action or decision must be judged in light of the
circumstances, information, and available options existing at the time, without
benefit of hindsight.1034

ESI purchases power and procures fossil fuels on behalf of the individual Operating
Companies. Fossil fuel costs are borne directly by the Operating Company that contracts for and
uses the fuel. Once resources are procured to meet forecasted demand, the system is operated during
the current day using all of the resources available to the system to meet the total system demand.
Throughout the course of the day, system operators may modify planned operations to maintain
reliability, take advantage of less-expensive resources in the hourly wholesale power markets, or
make off-system sales. For example, when spot market power purchases are available at a cost

1034
Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on
Rehearing at 2 (Jun. 24, 1997).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 322
PUC DOCKET NO. 39896

lower than the cost of energy that can be generated by units owned by the Operating Companies, that
energy is purchased to displace owned generation, subject to operating constraints.1035

Expenses for coal, gas, power purchases, and fuel oil are incurred directly by the respective
Operating Company. For example, if coal is purchased for ETI’s share of Nelson Station, Unit 6,
then ETI is responsible for the invoiced cost and makes payment directly to the supplier. Wholesale
power, purchased and sold for the system, however, is accounted for per the terms of the System
Agreement. After dispatch, or after-the-fact, the System Agreement prescribes an accounting
protocol to bill the costs of operating the system to the individual Operating Companies.1036

The following Fuel Reconciliation-related issues were uncontested:

¾ Natural Gas Purchases

ETI witness Karen McIlvoy presented direct testimony describing ETI’s natural gas
procurement policies and strategies. She explained that the Company buys gas through a long-term
contract with Enbridge, through participation in the monthly and daily markets depending on fuel
needs, and on a delivered-to-plant basis or arrange for transportation to the plant. Ms. McIlvoy
described how the gas buyers for ETI survey the markets and solicit offers for gas supplies.
Ms. McIlvoy also provided a comparison of the Company’s gas costs to the Inside FERC and Gas
Daily published indices for the Houston Ship Channel.1037 No party challenged the Company’s
natural gas purchases.

¾ Fuel Oil

Ms. McIlvoy testified that the Company purchased fuel oil for start-up and flame
stabilization at certain units. Fuel oil can also be used for emergency back-up fuel or as an economic
alternative to natural gas at certain units. During the Reconciliation Period, the Company purchased

1035
ETI Ex. 40 (Thiry Direct) at 18-21.
1036
ETI Ex. 39 (Cicio Direct) at 31-37.
1037
ETI Ex. 28 (McIlvoy Direct) at 23, Ex. KDM-3.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 323
PUC DOCKET NO. 39896

all fuel oil on a short-term basis from spot market sources after solicitation of bids from multiple
potential suppliers.1038 No party contested ETI’s fuel oil costs.

¾ Longer-Term Purchased Power

ETI witness Robert R. Cooper addressed the Entergy system’s long-term planning process
and described the Strategic Resource Plan process. He explained how the system determined its
capabilities and needs for additional resources to reliably serve system load requirements.
Mr. Cooper described the process by which the system developed requests for proposals and
analyzed a combination of capacity and firm energy contracts to satisfy the system’s identified
resource needs.1039 A portion of these system purchases was allocated to ETI. No party proposed a
disallowance of these purchases on the basis of prudence.

¾ Short-Term Purchased Power

Ms. Thiry described the Power Marketing Team’s procurement strategies, practices and
procedures during the Reconciliation Period. Ms. Thiry testified that the Power Marketing Team
fulfilled its objective of purchasing energy in the wholesale market when it was more economical
than using the system’s generation and in order to maintain system reliability. Ms. Thiry
demonstrated that third-party purchases for the system compared favorably to market price indices
and to proxy costs of avoided generation.1040 The Power Marketing Team maintained effective cost
controls and procured a diverse portfolio of product to provide electricity for customers at a
reasonable cost.1041 No party contested the prudence of ETI’s short-term power purchases.

¾ Coal Commodity and Transportation

ETI has ownership interest and/or obtains power through Schedule MSS-4 of the Entergy
System Agreement, in two coal-burning generating units – Nelson and BCII/U3. ETI owns a

1038
ETI Ex. 28 (McIlvoy Direct) at 5-6.
1039
ETI Ex. 34 (Cooper Direct) at 6-10.
1040
ETI Ex. 40 (Thiry Direct) at 24.
1041
Id.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 324
PUC DOCKET NO. 39896

29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in
BCII/U3, but the unit is operated by a third party. ETI witness Ryan Trushenski, the Manager of
Coal Supply for ESI, testified that ETI prudently managed its coal supply and transportation
expenses during the Reconciliation Period.1042

With respect to coal and transportation expenses at Nelson 6, ETI obtained coal during the
Reconciliation Period under a supply contract previously reviewed by the Commission, and entered
into a new coal supply contract after a competitive bid process. ETI chose the supplier with the
lowest priced coal that met the specifications necessary for use at Nelson 6. Similarly, ETI arranged
for transportation of coal according to transportation contracts previously reviewed in prior fuel
reconciliations. When those contracts expired, ETI initiated a competitive bid process and chose the
lowest cost option available that met its requirements. With respect to BCII/U3, ETI incurred costs
to run the unit and took reasonable steps to ensure that the third party operator properly charged for
coal and transportation expenses under an arrangement previously reviewed and approved in prior
fuel reconciliations.1043 No party challenged the reasonableness and necessity of ETI’s coal or
transportation expense during the Reconciliation Period

The three contested issues are discussed below.

A. Spindletop Gas Storage Facility

During the Reconciliation Period, ETI incurred $10,261,663 of non-fuel expense associated
with operating the Spindletop Facility. Cities challenged ETI’s use of the Spindletop Facility,
arguing that the costs of operating it outweigh the benefits gained from it. For the same reason he
challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also
challenges ETI’s non-fuel expense associated with the facility. Specifically, Mr. Nalepa
recommends that ETI’s total fuel reconciliation balance be reduced by $6,595,290, which he
calculates as the difference between the $10,261,633 non-fuel operational costs associated with the
Spindletop Facility over the Reconciliation Period and the costs of alternative sources of providing a

1042
ETI Ex. 33 (Trushenski Direct) at 2.
1043
Id. at 11-13.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 325
PUC DOCKET NO. 39896

reliable and flexible gas supply over the same period.1044 In Section V.H., above, the ALJs rejected
Cities’ contention that the Spindletop Facility is not used or useful. For the same reason they
rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject Cities’
Spindletop Facility arguments relevant to Fuel Reconciliation.

B. Use of Current Line Losses for Fuel Cost Allocation

Cities propose that the allocation of fuel costs incurred over the Reconciliation Period reflect
the current line loss study performed by ETI for this case and recommended for approval on a going
forward basis. In the fuel reconciliation case, ETI proposes to allocate costs to customers using a
line loss study performed in 1997, which Cities claim does not reflect the current cost of providing
service to the current wholesale customers and to the various retail customers.1045 According to
Cities, updating ETI’s allocation of fuel costs to reflect current line losses and the cost of providing
service to customers results in a $3,981,271 reduction to the Texas retail fuel expenses incurred over
the Reconciliation Period.1046

ETI responds that the Cities’ recommendation is unprecedented. It notes that the
Commission’s substantive rules require use of “a commission-approved adjustment to account for
line losses corresponding to the voltage at which the electric service is provided.”1047 Moreover,
ETI argues that retroactive use of new loss factors to calculate its fuel over/under-recovery balance
would result in a mismatch between the revenues recovered under the fuel factor and the costs billed
and allocated to the various customer classes.1048

Fuel costs are collected through Commission-approved fixed fuel factors. One of the
elements the fuel factor is required to take into account is line losses. P.U.C. SUBST.
R. 25.237(c)(2)(B) states that the utility must prove that: “the proposed fuel factors utilize a

1044
Cities Ex. 6 (Nalepa Direct) at 42-43; Cities Initial Brief at 84.
1045
Cities Ex. 6 (Napala Direct) at 44; see also Tr. at 1469-1470.
1046
Cities Ex. 6 (Napala Direct) at 47, Table 14.
1047
ETI Ex. 58 (McCloskey Rebuttal) at 2, quoting P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1048
Tr. at 1484.
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commission-approved adjustment to account for line losses corresponding to the voltage at which the
electric service is provided.”1049 If the Commission were to adopt Cities’ recommendation that the
newly-developed line losses be used in the reconciliation of fuel costs, the allocation of those costs
would not match the collections (determined through the use of historical line losses). This
mismatch could result in some customers receiving more than they are entitled and others receiving
less than they are entitled. The ALJs find that the Commission’s rules require the use of
Commission-approved line losses that were in effect at the time fuel costs were billed to customers
in a fuel reconciliation. The ALJs, therefore, recommend that the Commission reject the Cities’
proposed adjustment.

C. ETI’s Special Circumstances Request

In the application, ETI seeks to include $99,715 in the Fuel Reconciliation to allow it to
recover “the reversal of certain credits that were previously included in the Company’s [Incremental
Purchased Capacity Rider] Rider IPCR.”1050 ETI witness Zakrzewski explained that the FERC
revised the amount of purchased capacity-related production costs allocable to ETI through the
FERC-approved Rough Production Cost Equalization mechanism for allocating production costs
among the Operating Companies. As Mr. Zakrzewski explained, the result of the decision was a
recalculation of ETI’s capacity costs recoverable through the Commission-approved Rider IPCR,
which expired during the Reconciliation Period.1051

During the hearing, no party contested ETI’s special circumstances request of $99,715 with
regard to the IPCR-related adjustment. For the first time in its Initial Brief, however, Cities opposed
the request, asserting that it conflicts with the settlement reached in Docket No. 37744.1052 The
ALJs are not swayed by Cities’ argument. As pointed out by ETI,1053 Cities provided no testimony
or other evidence to support its position. Furthermore, Cities failed to explain how a settlement

1049
P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1050
ETI Ex. 23 (Zakrzewski Direct) at 13.
1051
Id.
1052
Cities Initial Brief at 86.
1053
ETI Reply Brief at 93.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 327
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agreement reached in Docket No. 37744 could or should trump the FERC’s jurisdiction to determine
the amount of purchased capacity costs attributable to ETI. The only evidence in the record supports
ETI’s recovery of these costs. Accordingly, the ALJs recommend that these FERC-imposed costs
should be found to be recoverable and Cities’ request to deny their recovery should be rejected.

In summary, the ALJs conclude that, consistent with the requirements of P.U.C. SUBST.
R. 25.236(d)(1), ETI met its burden to prove that: (1) its eligible fuel expenses during the
Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric
service to its retail customers; (2) the prices charges by its affiliates were reasonable and necessary
and no higher than the prices charged by the supplying affiliates to other affiliates or to unaffiliated
persons; and (3) ETI has properly accounted for the amount of fuel-related revenues collected
pursuant to the fuel factor during the Reconciliation Period.

XII. OTHER ISSUES

A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket
No. 39741 Preliminary Order Issue Nos. 1-9]

Entergy is seeking to transfer operational control of the Entergy Operating Companies’
transmission assets to the MISO Regional Transmission Organization (RTO). ETI expects its share
of the costs for this transfer will include approximately $17 million of expense.1054 ETI has made
two alternate proposals to recover these expenses. ETI’s first proposal requests the Commission to
approve a deferred accounting of its transition expense incurred on or after January 1, 2011, and to
approve accrual of interest on the deferred amount at ETI’s overall rate of return. Under this
proposal, ETI would present the resulting regulatory asset for review in a future proceeding. ETI
originally requested this deferred accounting in Docket No. 39741, which was later consolidated into
this case for all purposes. In its Preliminary Order in Docket 39741, the Commission stated that it
had authority to allow such a deferral of costs “when it is necessary to carry out a provision of
PURA.” It also stated that whether ETI’s request met this requirement “hinges on the factual issue
of necessity . . . .”

1054
ETI Ex. 42 (Lewis Supplemental Direct) at 5.
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As an alternative proposal, ETI requested the Commission to include $4 million of transition
expense in base rates set in the present case, based on a three-year amortization of a total of
$12 million in MISO transition expenses. ETI’s Test Year MISO transition expenses totaled only
$916,535, but ETI’s request for deferred accounting addressed expenses incurred on or after
January 1, 2011, which is after the Test Year concluded. ETI argues that its request is a
conservative known and measureable change because the post-Test-Year expenses will be
significantly more than $4 million per year. Further, these costs would be removed from ETI’s cost
of service if its deferred accounting proposal is approved.

As noted, ETI’s proposals concern MISO transition expenses incurred on or after January 1,
2011. However, ETI also incurred $263,908 in these expenses during the 2010 portion of the Test
Year. ETI has proposed a five-year amortization of this amount ($52,800 per year), assuming either
its primary proposal or its alternative proposal is adopted. However, if ETI’s primary and
alternative proposals are both rejected, ETI requested that no reduction be made to its total Test Year
amount of $916,535.1055

Cities, TIEC, State Agencies, and Staff opposed ETI’s requests. They argue that ETI failed
to establish that the proposed deferred accounting is necessary to carry out a provision of PURA, as
required by the Commission’s Preliminary Order. They also contended that ETI’s alternate request
to include $4 million in base rates is not a known and measureable change and should be disallowed.

The ALJs recommend that the Commission deny ETI’s request for deferred accounting of its
MISO transition expenses to be incurred on or after January 1, 2011. However, the ALJs do
recommend that the Commission authorize ETI to include $2.4 million of MISO transition expense
in base rates set in the present case, based on a five-year amortization of $12 million in total
projected expenses.

1055
ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L.
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1. Deferred Accounting

In support of its deferred accounting request, ETI cited State v. Public Utility Comm’n of
Texas.1056 In that case, the Texas Supreme Court stated that a deferred accounting is “necessary”
when it will “ensure that the requirements of [PURA] are met.”1057 In ETI’s opinion, deferred
accounting is necessary in the present case to ensure that PURA §§ 36.051 and 36.003(a) are met
(i.e., that utilities have a reasonable opportunity to recover their expenses and receive reasonable
rates). ETI also relied on Hammack v. Public Utility Commission of Texas, which stated that “a need
. . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1058

ETI-witness Brett Perlman testified that deferred accounting is also necessary to ensure the
requirements of PURA § 31.001(c) are carried out.1059 That section encourages development of a
competitive wholesale electric market. ETI noted that the Hammack opinion stated that
Section 31.001(c) amounts to a “legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market.”1060 Therefore, ETI asserted
that RTO membership and deferred accounting are necessary because they will ensure that the
Commission meets its obligation under Section 31.001(c). More specifically, ETI stated, both RTO
membership and deferred accounting itself constitute examples of policies required by section
31.001(c) to support wholesale competition. Therefore, ETI argues that its request for deferred
accounting should be approved because it is necessary to carry out PURA §§ 36.051, 36.003, and
31.001(c).1061

Cities argue that ETI’s request for deferred accounting of MISO transition expenses should
be denied because deferred accounting is not necessary to carry out any requirement of PURA.

1056
883 S.W.2d 190 (Tex. 1994).
1057
883 S.W.2d at 194.
1058
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1059
ETI Ex. 43 (Perlman Supplemental Direct) at 7.
1060
131 S.W.3d at 723.
1061
ETI’s Initial Brief at 231-234; ETI Ex. 42 (Lewis Supplemental Direct) at 2-4; ETI Ex. 43 (Perlman
Supplemental Direct) at 5-7.
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Cities witness James Brazell stated that ETI’s proposed transition to MISO is not mandatory, and the
anticipated expenses are not extraordinary. He added that ETI has been exploring membership in an
RTO for over ten years and those costs have historically been included in ETI’s base rates; therefore,
he concluded that deferred accounting was not necessary in the past and is not necessary now. Cities
stressed that ETI conceded that deferred accounting of these expenses is not necessary to maintain
its financial integrity, and in Cities’ opinion, both State v. Public Utility Comm’n of Texas,1062 and
the Commission’s Preliminary Order require a showing of impairment of financial integrity to
conclude that deferred accounting is necessary to comply with PURA § 36.051. Cities also stated
that ETI failed to show that deferred accounting is necessary to comply with PURA §§ 36.003 and
31.001(c); therefore, Cities argues that ETI’s request for deferred accounting should be denied.

TIEC also opposed ETI’s request for deferred accounting, arguing that ETI failed to
demonstrate that it is necessary to carry out PURA §§ 36.051, 36.003, or 31.001(c). TIEC witness
Jeffry Pollock stated there is no indication that deferred accounting treatment is necessary for ETI to
earn a reasonable return on its invested capital or that denying the deferred accounting would
prevent ETI from having just and reasonable rates. Further, Mr. Pollock asserted there is no
evidence that a lack of deferred accounting treatment for ETI would prevent Entergy from pursuing
its MISO proposal.1063 Mr. Pollock added that ETI has incurred other similar costs to carry out
various purposes of PURA without deferred accounting. For example, since 2005, ETI has spent
nearly $20 million pursuing various similar activities, including transitioning to competition,
investigating RTO options, examining changes to the Entergy System Agreement, and supporting
the Entergy OATT. Yet, ETI did not seek deferred accounting for any of those costs. Finally,
Mr. Pollock testified that the projected transition costs are not material. He noted that ETI expects
to incur $17 million of transition costs.1064 This equates to $5.8 million per year, which is only
1 percent of ETI’s Test Year operating revenues, according to Mr. Pollock. In his opinion, this level

1062
883 S.W.2d 190 (Tex. 1994).
1063
TIEC Ex. 1 (Pollock Direct) at 46-47.
1064
ETI Ex. 42 (Lewis Supplemental Direct) at 5.
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of MISO transition costs is easily subsumed in the normal variation in ETI’s year-to-year
expenses.1065

TIEC also disagreed with ETI’s interpretation of State v. Public Utility Comm’n of Texas.1066
In TIEC’s view, that case held that deferred accounting is necessary only when needed to protect
the financial integrity of the utility. Likewise, TIEC disagreed with ETI’s argument that
Hammack1067 held that “need” is a relative requirement that must be viewed in light of legislative
policy directives.1068 TIEC noted that Hammack had nothing to do with deferred accounting.
Instead, it was limited to the issue of whether, in granting a certificate of convenience and necessity
for a transmission line under PURA §37.056, the Commission should include evidence that
considered customers and market participants throughout the state.1069 In TIEC’s view, the
Hammack case is irrelevant in determining whether deferred accounting is necessary to carry out the
provisions of PURA §§ 36.003, 36.051, and 31.003(c). State Agencies made similar arguments.

Commission Staff also argues that ETI did not establish why deferred accounting is
necessary to carry out a provision of PURA. In Staff’s view, the applicable court cases and other
precedent required ETI to show that deferred accounting is necessary to maintain its financial
integrity, in order to carry out the provisions of PURA § 36.051. Staff argues that the Commission’s
Preliminary Order did not reject the financial integrity standard when it stated: “[t]his standard is
not appropriate, however, for all circumstances and the Commission has applied different standards
in various circumstances.”1070 Rather, Staff stated, the Commission merely declined to designate a
specific standard.

1065
ETI Ex. 1 (Pollock Direct) at 48-49 and Ex. JP-8.
1066
883 S.W.2d 190 (Tex. 1994).
1067
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1068
ETI Initial Brief at 232-233.
1069
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 724 (Tex .App.−Austin 2004, pet. denied).
1070
Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to
Membership in The Midwest Independent Transmission System Operator, Docket No. 39741 Preliminary
Order at 9 (Sep. 2, 2011).
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Staff also rejected ETI’s argument that deferred accounting will “ensure that the Commission
meets its obligation under Section 31.001(c) to support the achievement of a competitive wholesale
market.”1071 First, Staff noted, the Commission stated in the Preliminary Order that merely showing
movement towards a policy goal is not a sufficient standard upon which to approve deferral.1072
Thus, ETI’s statement that deferred accounting will “support” wholesale competition addresses a
standard that the Commission already rejected. Second, Staff argues that ETI failed establish that
deferred accounting is “necessary” to support a competitive wholesale market or that failure to allow
deferred accounting would prevent that goal. In other words, ETI did not show that, absent deferral,
it would not join MISO; thus, ETI did not show how deferral would “ensure” that it joins an RTO.
Therefore, Staff concluded, because ETI failed to prove that deferred accounting is necessary to
carry out any provision of PURA, ETI’s request should be denied.

In response to these arguments, ETI noted that no party disputed that the Commission may
grant deferred accounting “when it is necessary to carry out a provision of PURA.” It also argues
that Staff and intervenors misinterpreted State v. Public Utility Comm’n of Texas1073 as holding that
deferred accounting is necessary to carry out PURA § 36.051 only when a utility’s financial integrity
is at stake. Although lack of financial integrity is an indication that PURA § 36.051 has not been
carried out, ETI noted that this section contains other express requirements that can be met through
deferred accounting, such as ensuring utilities a reasonable opportunity to recover their costs. ETI
also cited other Commission cases in which it authorized deferred accounting when financial
integrity was not at stake, such as deferral of rate case expenses and merger costs for subsequent
review and recovery.1074 ETI added that deferred accounting would permit the Commission to
review ETI’s transition expenses in a subsequent proceeding, after determining whether ETI’s
transition to MISO is in the public interest. Thus, under ETI’s proposal, there is no risk that ETI
would recover such costs absent a finding that they are reasonable and necessary.

1071
ETI Initial Brief at 234.
1072
Docket No. 39741, Preliminary Order at 11.
1073
883 S.W.2d 190 (Tex. 1994).
1074
ETI Reply Brief at 95-96.
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As for Staff and TIEC’s argument that deferred accounting is not necessary to carry out
PURA § 31.001(c), ETI argues that the “necessary” standard is not a “but for” test. In response to
arguments that the proposed deferred accounting will merely further policy objectives of
Section 31.001(c), which the Commission has deemed insufficient to meet the “necessary”
standard,1075 ETI reiterated that the Hammack opinion held that “the Commission’s interpretation of
need must be viewed in light of the legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market,” as well as “overall policy
objectives.”1076 Thus, ETI argues, that it has demonstrated that deferred accounting is necessary to
carry out Section 31.001(c) – i.e., it will “ensure” that the requirements of that provision are carried
out, and in particular ensure that the Legislature’s specific instruction to develop the wholesale
market is carried out.1077

Although ETI’s proposal for deferred accounting has some practical appeal, the ALJs
conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The ALJs
find that ETI was not required to show that a deferred accounting is necessary to maintain its
financial integrity, as argued by intervenors. In State v. Public Utility Comm’n of Texas,1078 the
Texas Supreme Court held that preserving the financial integrity of a utility was necessary to carry
out a provision of PURA, and thus justified deferred accounting for certain expenses in that case, but
the court did not hold that preserving financial integrity was the sole basis upon which a deferred
accounting could be approved. Likewise, in its Preliminary Order for the present case, the
Commission stated: “This standard [financial integrity] is not appropriate, however, for all
circumstances and the Commission has applied different standards in various circumstances,
although none of these standards or circumstances has been reviewed by any court.”1079 On the
other hand, the ALJs also find that ETI’s contention that deferred accounting of the MISO transition
expenses will help the development of a competitive wholesale electric market, as described in

1075
Docket No. 39741, Preliminary Order at 7.
1076
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1077
ETI Reply Brief at 97-99.
1078
883 S.W.2d 190 (Tex. 1994).
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PURA § 31.001(c), is not sufficient to authorize deferred accounting. Again, the Commission stated
in the Preliminary Order that “to carry out a provision of PURA” means more than undefined
progress or movement towards a statutory objective.1080

The Commission made clear that ETI’s burden was not only to show that a provision of
PURA would be carried out by an accounting deferral of the MISO transition expenses, but that the
deferral is necessary to carry out that provision. The Commission added that necessity was a
question of fact that “can only be determined after development of an adequate factual record that
demonstrates the necessity, of whatever degree.”1081 Intervenors argue that Entergy’s efforts to
transfer operational control of the Entergy Operating Companies’ transmission assets to MISO will
proceed with or without the deferred accounting requested by ETI; thus, deferred accounting is not
necessary. Likewise, intervenors argue that ETI’s alternate proposal to recover the transition costs
through base rates shows that deferred accounting is not necessary. ETI, however, asserted that
necessity should not be considered a “but for” requirement. It noted that no provision of PURA
would be impossible to carry out absent a deferral of rate case expenses or merger expenses, yet the
Commission has allowed deferred accounting of such expenses in other cases. ETI also cited the
statement in Hammack v. Public Utility Commission of Texas that “a need . . . is a relative
requirement, ranging from an imperative need to one that is minimal . . . .”1082 Intervenors criticized
ETI’s reliance on the Hammack case because it concerned a transmission line. While that is correct,
the case does make the general point that the question of need is not an absolute “but for” test. This
is also consistent with the Commission’s statement in the Preliminary Order that ETI’s burden was
to demonstrate necessity, “of whatever degree.”

ETI’s complaint is that its MISO transition expenses will soon increase above the Test Year
amount, from $916,535 for the Test Year to over $5 million per year, but it will not be able to
recover the increased costs through normal Test Year cost-of-service ratemaking principles. Thus,

1079
Docket No. 39741, Preliminary Order at 9 (Nov. 22, 2011).
1080
Id. at 11.
1081
Id. at 8.
1082
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
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although ETI’s financial integrity may not be jeopardized, ETI argues that it nevertheless will not be
able to have a reasonable opportunity to recover its expenses and receive reasonable rates as
required by PURA §§ 36.051 and 36.003(a). Therefore, ETI believes the proposed deferred
accounting is necessary to carry out those provisions of PURA.

The ALJs find that the essence of ETI’s complaint is that regulatory lag works against it in
this particular situation. But as noted by the court in State v. Public Utility Comm’n of Texas,
regulatory lag is an ordinary element of risk for utilities.1083 One of the characteristics of Test Year
cost-of-service ratemaking is that some expenses upon which rates are based may go up and others
may go down during the time the rates are in effect. Such changes can be corrected in future
ratemaking proceedings, but in this case ETI desires to ensure that it will recover all of its MISO
transition costs. But State v. Public Utility Comm’n of Texas and the Commission’s Preliminary
Order in this case make clear that eliminating the normal effects of regulatory lag by allowing a
deferred accounting should not be undertaken lightly. If ETI’s arguments were taken to their
extreme, a utility could obtain deferred accounting any time it anticipated a post Test Year increase
in a particular expense, under the argument that it must be allowed to recover all of its expenses to
carry out the requirements of PURA §§ 36.051 and 36.003(a). In this case, ETI’s estimated MISO
transition costs will equal about $5.8 million per year. As Mr. Pollock noted, this is only
one percent of ETI’s Test Year operating revenues, which may easily be subsumed in the normal
variation in ETI’s year-to-year expenses. Under these circumstances, ETI has not shown that
granting its requested deferred accounting is necessary to carry out the requirements of PURA
§§ 36.051 and 36.003(a) that it receive just and reasonable rates. Therefore, the ALJs recommend
that the Commission deny ETI’s request for deferred accounting treatment of its MISO transition
expenses to be incurred on or after January 1, 2011.

1083
883 S.W.2d 190, 196 (Tex. 1994).
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2. Base Rate Recovery

As mentioned above, if the Commission denies ETI’s request for deferred accounting, ETI
requested the Commission to include $4 million of MISO transition expense in base rates set in the
present case, based on a three-year amortization of $12 million in total projected expenses.

Cities disputed the amount of MISO expenses ETI requested in this proposal. Cities witness
Mark Garrett testified that a $4 million annual expense is inconsistent with ETI’s own projected
costs. The Test Year expenses were $916,535, and the actual expenses incurred during January
through November 2011 were only $2.513 million, which annualized would be $2.742 million..
For 2013, ETI projected MISO transition expenses of only $2.587 million, although ETI’s
projected 2012 level of $8.9 million. However, Mr. Garrett added that 2012 is an estimated level
and is not consistent with actual 2011 results. In his opinion, the actual 2011 level of about $2.7
million or the expected 2013 level of about $2.6 million should be the outside range of what the
Commission should use for setting prospective rates. In any event, however, Cities argue that these
projected levels are not sufficiently known and measurable to include for ratemaking purposes.
Cities pointed out that it is unknown whether ETI’s proposed move to MISO will even be approved,
or whether the ETI will even continue to incur costs toward a MISO transition. Therefore, Cities
argues that only the Test Year level of $916,535 should be included in rates, which would result in a
downward adjustment of $3,083,462 to ETI’s request.1084

TIEC also argues that ETI’s alternative proposal should be rejected. Mr. Pollock complained
that this proposal would allow ETI to recover post Test Year expenses that are not known and
measureable. Mr. Pollock noted that ETI’s own estimate of its share of transition costs has changed.
When ETI filed its request for deferred accounting in Docket No. 39741, it estimated transition costs
of $12 million. Now it estimates costs of $17 million, an increase of over 40 percent. Further,
Mr. Pollock stated, ETI based its share of the estimated transition costs by assuming a 17 percent
responsibility ratio, but ETI’s future responsibility ratios are not known because they are based on
projected growth rates of ETI relative other Entergy Operating Companies. Thus, Mr. Pollock

1084
Cities Ex. 2 (Garrett Direct) at 61-63 and Ex. MG2.14; Cities Initial Brief at 89-91; Cities Reply Brief
at 112-113.
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concluded that ETI’s share of future MISO transition costs cannot be appropriately measured.1085 In
summary, TIEC argues that the Commission should deny ETI’s request for deferred accounting and
should allow ETI to recover only Test Year MISO transition expenses.1086 Commission Staff made
arguments similar to Cities and TIEC.1087

In response, ETI argues that the $4 million annual expense requested is known and
measurable. ETI noted that it already incurred over $3.6 million in transition expense in the nine
months since the end of the Test Year,1088 which equates to $4.8 million on an annual basis.
Furthermore, ETI’s expects $17 million in transition expenses to be incurred over three years, which
equates to $5.8 million annually.1089 In ETI’s view, the issue is whether it is sufficiently known that
ETI will incur at least $12 million in transition expense, not whether ETI can predict an exact level
of future expense.1090

The ALJs recommend that the Commission authorize ETI to include $2.4 million in base
rates set in the present case for MISO transition expense incurred on or after January 2, 2011, based
on a five-year amortization of $12 million in total projected expenses. The primary argument of
intervenors against the adjustment is that the total of $12 million is not a known and measurable
change. However, the ALJs find that ETI’s evidence established that such expenses will total at
least $12 million. It is true that the Test Year expenses were less, but ETI filed its application to
effectuate the transfer to MISO in 2012, so it is clear that those expenses will increase significantly
to levels well above the Test Year amount. It is true that ETI has not established the precise total
amount of MISO transition expenses it will incur, but the ALJs find that those expenses will likely
exceed the $12 million included in ETI’s request. ETI requested that the $12 million total be
amortized over three years, which would produce a $4 million annual cost. However, ETI also

1085
TIEC Ex. 1 (Pollock Direct) at 49-50.
1086
TIEC Initial Brief at 97-98; TIEC Reply Brief at 70-71.
1087
Staff Reply Brief at 65-66.
1088
ETI Ex. 46 (Considine Rebuttal), Ex. MPC-R-1.
1089
TIEC Ex. 1 (Pollock Direct) at 48:3-4.
1090
ETI Initial Brief at 236-239; ETI Reply Brief at 99-100.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 338
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requested to amortize over five years its $263,908 in MISO transition expenses that were incurred
during the 2010 portion of the Test Year ($52,800 per year). If a five-year amortization is
appropriate for those expenses, a five-year amortization would also be appropriate for the post Test
Year MISO transition expenses. Therefore, the ALJs recommend that the Commission authorize
ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test
Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800.

B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]

In its Supplemental Preliminary Order, the Commission found that it would be appropriate to
establish for ETI baseline values for a TCRF and a DCRF, which may be established in future
dockets. ETI’s filing package included worksheets for these baseline values,1091 and ETI attached
revised versions of the worksheets to its initial brief to reflect ETI’s revised depreciation
calculations. The revised version of the transmission worksheet calculated total transmission cost
baseline revenue requirements of $75,074,987-Total Company and $74,997,366-Retail.1092
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised
TCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of
the Commission.1093 TIEC, Cities, and Staff also point out that various items in ETI’s calculation
have been contested. Therefore, they also recommend that the baseline values be set during the
compliance phase of this case. The ALJs agree that TCRF baseline values should be set during the
compliance phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]

As discussed above, the Commission found in its Supplemental Preliminary Order that it
would be appropriate to establish for ETI baseline values for a DCRF, which may be established in a

1091
ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1092
ETI Initial Brief at 239 and Attachment 1.
1093
ETI Initial Brief at 239.
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future docket. ETI’s filing package included worksheets for a DCRF baseline value,1094 and ETI
attached a revised version of the worksheet to its initial brief to reflect ETI’s revised depreciation
calculations. The revised version of the distribution worksheet calculated total distribution cost
baseline revenue requirements of $163,560,232-Total Company and $161,537,490-Retail.1095
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised
DCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions
of the Commission.1096 TIEC, Cities, and Staff also recommend that the baseline values be set
during the compliance phase of this case. The ALJs agree that DCRF baseline values should be set
during the compliance phase of this docket, after the Commission makes final rulings on the various
contested issues that may affect this calculation.

D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary
Order Issue No. 1]

ETI requested a PPR rider in its application, but the Commission held in its Supplemental
Preliminary Order that the proposed rider should not be considered due to the pending rulemaking
Project No. 39246, which was opened to consider purchased capacity riders. However, the
Commission did add the following issue to the present case: “What is the amount of purchased-
capacity costs that are proposed to be included in Entergy’s base rates?” ETI requested authority to
include $275,809,485 in its PPR rider, but because the Commission excluded the PPR rider from
consideration, this amount would now be included in base rates. ETI acknowledged that this amount
should be revised to correspond with the Commission’s final decision on purchased power capacity
recovery (See Section VII.A.). 1097

State Agencies noted that ETI’s purchased power request included the following:

1094
ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1095
ETI Initial Brief at 239 and Attachment 2.
1096
ETI Initial Brief at 239.
1097
ETI Initial Brief at 240.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 340
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1. Third-party contracts;
2. Legacy affiliate contracts;
3. Other affiliate contracts; and
4. Reserve Equalization.

The costs for all of these but third-party contracts are determined through various MSS Schedules in
the FERC-approved Entergy System Agreement. Therefore, State Agencies argue that if the
Commission decides to allow purchased capacity cost recovery riders in Project No. 39246, the
baseline costs for ETI should be limited to only the purchased capacity costs associated with
non-affiliate third-party contracts. In State Agencies’ opinion, ETI should not be allowed to pass
through purchased capacity costs associated with legacy and other affiliate contracts or reserve
equalization purchases, because those are not market competitive contracts. Instead, according to
State Agencies, the affiliate contracts and reserve equalization purchases are essentially agreements
to share centralized planned generation capacity resources among Entergy Operating Companies and
to allocate generation costs among those companies. State Agencies also noted that these capacity
payments are determined based on formulae in Service Schedules MSS-1 and MSS-4, included in
the FERC-approved Entergy System Agreement. In other words, these costs are not driven by
market prices and are not subject to market price volatility. Therefore, State Agencies argue that
purchases other than third-party contracts should not be used as a baseline for any rider intended to
address market price volatility and competitive wholesale market pressure for purchased generation
capacities.1098

Cities agree with the arguments of State Agencies. In addition, Cities stressed that if the
Commission establishes a baseline for purchased power capacity costs, the baseline should reflect
the unit cost of capacity rather than total dollars. Cities witness Nalepa testified that the unit cost
would provide a more accurate measure than total dollars. In Cities’ opinion, if a unit cost finding is
not made in this case, then Commission will be prevented from considering all options in the
rulemaking.

1098
State Agencies Ex. 2 (Pevoto Direct) at 17.
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TIEC points out that the notice in Project No. 39246 provided that “[t]he purpose of this
rulemaking project is to address the recovery of purchased power capacity costs considering
generation embedded in base rates, load growth, and the impact of purchased power capacity
recovery on the financial standing of the utility.”1099 Accordingly, TIEC argues that the baseline set
in this proceeding should reflect ETI’s total purchased power and installed capacity costs determined
to be properly included in base rates on a total cost basis and on a per unit ($/MW) basis.1100

As discussed in Section VII.A., the ALJs find that the appropriate amount for ETI’s
purchased power capacity expense to be included in base rates is $245,432,884. This responds to the
issue included in the Commission’s Supplemental Preliminary Order. This amount includes third-
party contracts, legacy affiliate contracts; other affiliate contracts; and reserve equalization.
Whether the amounts for all contracts should be included in the baseline for a purchased capacity
rider that may be approved in Project No. 39246 is an issue that should be decided in that
proceeding, not in the present case. Therefore, the ALJs make no recommendation on that issue
raised by the intervenors.

XIII. CONCLUSION

The ALJs recommend that the Commission implement the findings of the ALJs set forth in
the discussion above by adopting the following proposed findings of fact and conclusions of law in
the Commission’s final order.

XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
ORDERING PARAGRAPHS

A. Findings of Fact

Procedural History

1. Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
service area located in southeastern Texas.

1099
Project No. 39246, Public Notice (May 10, 2011).
1100
TIEC Initial Brief at 99.
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2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
Commission (FERC) regulates ETI’s wholesale electric operations.

3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted test year
revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing
Package for Generating Utilities (RFP) accompanying ETI’s application and including new
riders for recovery of costs related to purchased power capacity and renewable energy credit
requirements; (3) a request for final reconciliation of ETI’s fuel and purchased power costs
for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to
the instructions in RFP Schedule V accompanying ETI’s application.

4. The 12-month test year employed in ETI’s filing ended on June 30, 2011 (Test Year).

5. ETI provided notice by publication for four consecutive weeks before the effective date of
the proposed rate change in newspapers having general circulation in each county of ETI’s
Texas service territory. ETI also mailed notice of its proposed rate change to all of its
customers. Additionally, ETI timely served notice of its statement of intent to change rates
on all municipalities retaining original jurisdiction over its rates and services.

6. The following parties were granted intervenor status in this docket: Office of Public Utility
Counsel (OPC); the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton,
Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange,
Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour
Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co. (Kroger); State Agencies
(State Agencies); Texas Industrial Energy Consumers (TIEC); East Texas Electric
Cooperative, Inc. (ETEC); the United States Department of Energy (DOE); and Wal-Mart
Stores Texas, LLC, and Sam’s East, Inc. (Wal Mart). The Staff (Staff) of the Public Utility
Commission of Texas (Commission or PUC) was also a participant in this docket.

7. On November 29, 2011, the Commission referred this case to the State Office of
Administrative Hearings (SOAH).

8. On December 7, 2011, the Commission issued its order requesting briefing on threshold
legal/policy issues.

9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues
to be addressed in this proceeding.

10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2,
which approved an agreement among the parties to establish a June 30, 2012 effective date
for the Company’s new rates resulting from this case pursuant to certain agreed language and
consolidate Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its
Proposed Transition to Membership in the Midwest Independent System Operator, Docket
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No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose
the consolidation.

11. On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for
admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate
as counsel for Kroger and the motion for admission pro hac vice filed by Rick D.
Chamberlain to appear and participate as counsel for Wal-Mart.

12. On January 19, 2012, the Commission issued a Supplemental Preliminary Order identifying
two additional issues to be addressed in this case and concluding that the Company’s
proposed purchased power capacity rider should not be addressed in this case and that such
costs should be recovered through base rates.

13. ETI timely filed with the Commission petitions for review of the rate ordinances of the
municipalities exercising original jurisdiction within its service territory. All such appeals
were consolidated for determination in this proceeding.

14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues
into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket
No. 39896, Docket No. 40295 (pending).

15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
revenues to approximately $104.8 million over adjusted Test Year revenues.

16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.

17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012.

Rate Base

18. Capital additions that were closed to ETI’s plant-in-service between July 1, 2009, and June
30, 2011, are used and useful in providing service to the public and were prudently incurred.

19. ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when
Docket No. 37744 concluded because the asset would have then begun earning a rate of
return as part of rate base.

21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
Test Year in the present case, and less the amount of additional insurance proceeds received
by ETI after the conclusion of Docket No. 37744.
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22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
remain in rate base, applying a five-year amortization rate beginning August 15, 2010.

23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.

24. The Company requested in rate base its Prepaid Pension Assets Balance of $55,973,545,
which represents the accumulated difference between the Statement of Financial Accounting
Standards (SFAS) No. 87 calculated pension costs each year and the actual contributions
made by the Company to the pension fund.

25. The Prepaid Pension Assets Balance includes $25,311,236 capitalized to construction work
in progress (CWIP).

26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
was insufficient evidence showing that major projects under construction were efficiently
and prudently managed.

27. The portion of the Prepaid Pension Assets Balance that is capitalized to CWIP should not be
included in ETI’s rate base.

28. The remainder of the Prepaid Pension Assets Balance should be included in ETI’s rate base.

29. ETI should be permitted to accrue an allowance for funds used during construction on the
portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.

30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48),
“Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of its uncertain
tax positions by evaluating the tax position on its technical merits to determine whether the
position, and the corresponding deduction, is more-likely-than-not to be sustained by the
Internal Revenue Service (IRS) if audited.

31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
purposes and record it as a potential liability with interest to better reflect the Company’s
financial condition.

32. At Test Year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 Liability) in reliance upon
tax positions that the Company believes will not prevail in the event the positions are
challenged, via an audit, by the IRS.

33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 Liability.

34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 Liability.

35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.
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36. ETI may never have to pay the IRS the FIN 48 Liability.

37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48 Liability
funds.

38. Until actually paid to the IRS, the FIN 48 Liability represents cost-free capital and should be
deducted from rate base.

39. The amount of $4,621,778 (representing ETI’s full FIN 48 Liability of $5,916,461 less the
$1,294,683 cash deposit ETI has made with the IRS for the FIN 48 Liability) should be
added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

40. ETI’s application and proposed tariffs do not include a request for a tracking mechanism or
rider to collect a return on the FIN 48 Liability.

41. ETI has not proven that a tracking mechanism or rider to collect a return on FIN 48 Liability
is necessary.

42. Investor-owned electric utilities may include a reasonable allowance for cash working
capital in rate base as determined by a lead-lag study conducted in accordance with the
Commission’s rules.

43. Cash working capital represents the amount of working capital, not specifically addressed in
other rate base items, that is necessary to fund the gap between the time expenditures are
made and the time corresponding revenues are received.

44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for
known and measurable changes, and is consistent with P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii).

45. It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead-lag
study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved for
ETI in this case.

46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008)
and Docket No. 37744, the Commission did not approve ETI’s storm damage expenses since
1996 and its storm damage reserve balance.

47. ETI established a prima facie case concerning the prudence of its storm damage expenses
incurred since 1996.

48. Adjustments to the storm damage reserve balance proposed by intervenors should be denied.

49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.
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50. ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51. The amount of $9,846,037, representing the value of the average coal inventory maintained
at ETI’s coal-burning facilities, is reasonable, necessary, and should be included in rate base.

52. The Spindletop gas storage facility (Spindletop Facility) is used and useful in providing
reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek generating
plants.

53. The Spindletop Facility is critical to the economic, reliable operation of the Sabine Station
and Lewis Creek generating plants due to their geographic location in the far western region
of the Entergy system.

54. It is reasonable and appropriate to include ETI’s share of the costs to operate the Spindletop
Facility in rate base.

55. Staff recommended updating ETI’s balance amounts for short-term assets to the 13-month
period ending December 2011, which was the most recent information available. Staff’s
proposed adjustments should be incorporated into the calculation of ETI’s rate base.

56. The following short-term asset amounts should be included in rate base: prepayments at
$8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the
Spindletop facility, represent actual costs incurred to process and close the acquisition, not
mere mark-up costs.

58. ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because
ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its
retail customers.

59. In its application, ETI capitalized into plant in service accounts some of the incentive
payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60. A portion of those capitalized incentive accounts represent payments made by ETI for
incentive compensation tied to financial goals.

61. The portion of ETI’s incentive payments that are capitalized and that are financially-based
should be excluded from ETI’s rate base because the benefits of such payments inure most
immediately and predominantly to ETI’s shareholders, rather than its electric customers.

62. The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the
reasonableness of ETI’s capital costs (including capitalized incentive compensation) for that
prior period was dealt with by the Commission in that proceeding and is not at issue in this
proceeding.
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63. In this proceeding, ETI’s capitalized incentive compensation that is financially-based should
be excluded from rate base, but only for incentive costs that ETI capitalized during the
period from July 1, 2009 (the end of the prior Test Year) through June 30, 2010 (the
commencement of the current Test Year).

Rate of Return and Cost of Capital

64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity
to earn a reasonable return on its invested capital.

65. The results of the discounted cash flow model and risk premium approach support a ROE of
9.80 percent.

66. A 9.80 percent ROE is consistent with ETI’s business and regulatory risk.

67. ETI’s proposed 6.74 percent embedded cost of debt is reasonable.

68. The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent
common equity.

69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in
light of ETI’s business and regulatory risks.

70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI
attract capital from investors.

71. ETI’s overall rate of return should be set as follows:

CAPITAL WEIGHTED AVG
COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL
LONG-TERM DEBT 50.08% 6.74% 3.38%
COMMON EQUITY 49.92% 9.80% 4.89%
TOTAL 100.00% 8.27%

Operating Expenses

72. ETI’s Test Year purchased capacity expenses were $245,432,884.

73. ETI requested an upward adjustment of $30,809,355 as a post-Test Year adjustment to its
purchased capacity costs. This request was based on ETI’s projections of its purchased
capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
Rate Year).
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74. ETI’s purchased capacity expense projections were based on estimates of Rate Year
expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments under
third-party capacity contracts; and (c) payments under affiliate contracts.

75. ETI’s projection of its Rate Year reserve equalization payments under Schedule MSS-1 is
based on numerous assumptions, including load growths for ETI and its affiliates, future
capacity contracts for ETI and its affiliates, and future values of the generation assets of ETI
and its affiliates.

76. There is substantial uncertainty with regard to ETI’s projection of its Rate Year reserve
equalization payments under Schedule MSS-1.

77. ETI’s projection of its Rate Year third-party capacity contract payments includes numerous
assumptions, one of which is that every single third-party supplier will perform at the
maximum level under the contract, even though that assumption is inconsistent with ETI’s
historical experience.

78. There is substantial uncertainty with regard to ETI’s projection of its Rate Year third-party
capacity contract payments.

79. ETI’s estimates of its Rate Year purchases under affiliate contracts are based on a
mathematical formula set out in Schedule MSS-4.

80. The MSS-4 formula for Rate Year affiliate capacity payments reflects that these payments
will be based on ratios and costs that cannot be determined until the month that the payments
are to be made.

81. Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI
WBL Contract) that was not signed until April 11, 2012.

82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the Rate
Year than it purchased in the Test Year.

84. ETI experienced substantial load growth in the two years before the Test Year, and it
continues to project similar load growth in the future.

85. ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment
of $30,809,355 should be made to its Test Year purchased capacity expenses.

86. ETI’s purchased capacity expense in this case should be based on the Test Year level of
$245,432,884.

87. ETI incurred $1,753,797 of transmission equalization expense during the Test Year.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 349
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88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense.
This request was based on ETI’s projections of its transmission equalization expenses
during the Rate Year.

89. The transmission equalization expense that ETI will pay in the Rate Year will depend on
future costs and loads for each of the Entergy operating companies.

90. ETI’s projection of its Rate Year transmission equalization expenses is uncertain and
speculative because it depends on a number of variables, including future transmission
investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
expenses, and loads of each of the Entergy operating companies.

91. ETI seeks increased transmission equalization expenses for transmission projects that are not
currently used and useful in providing electric service. ETI’s post-Test Year adjustment is
based on the assumption that certain planned transmission projects will go into service after
the Test Year. At the close of the hearing, none of the planned transmission projects had
been fully completed and some were still in the planning phase.

92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
expenses related to projects that are not yet in-service.

93. ETI’s request for a post-Test Year adjustment of $8,942,785 for Rate Year transmission
equalization expenses should be denied because those expenses are not known and
measurable. ETI’s post-Test Year adjustment does not with reasonable certainty reflect what
ETI’s transmission equalization expense will be when rates are in effect.

94. ETI’s transmission equalization expense in this case should be based on the Test Year level
of $1,753,797.

95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the accumulation
of recognized allocations of original cost, representing the recovery of initial investment
over the estimated useful life of the asset.

96. Except in the case of the amortization of the general plant deficiency, the use of the
remaining life depreciation method to recover differences between theoretical and actual
depreciation reserves is the most appropriate method and should be continued.

97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis
over the remaining, expected useful life of the item or facility.

98. Except as described below, the service lives and net salvage rates proposed by the Company
are reasonable, and these service lives and net salvage rates should be used in calculating
depreciation rates for the Company’s Production, Transmission, Distribution, and General
Plant assets.

99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production
plant depreciation rates.
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100. The retirement (actuarial) rate method, rather than the interim retirement method, should be
used in the development of production plant depreciation rates.

101. Production plant net salvage is reasonably based on the negative five percent net salvage in
existing rates.

102. The net salvage rate of negative 10 percent for ETI’s transmission structures and
improvements (FERC Account 352) is the most reasonable of those proposed and should be
adopted.

103. The net salvage rate of negative 20 percent for ETI’s transmission station equipment (FERC
Account 353) is the most reasonable of those proposed and should be adopted.

104. The net salvage rate of negative five percent for ETI’s transmission towers and fixtures
(FERC Account 354) is the most reasonable of those proposed and should be adopted.

105. The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures (FERC
Account 355) is the most reasonable of those proposed and should be adopted.

106. The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors and
devices (FERC Account 356) is the most reasonable of those proposed and should be
adopted.

107. A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures and
improvements (FERC Account 361) are the most reasonable of those proposed and should be
approved.

108. A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles, towers,
and fixtures (FERC Account 364) are the most reasonable of those proposed and should be
approved.

109. A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead
conductors and devices (FERC Account 365) are the most reasonable of those proposed and
should be approved.

110. A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution underground
conductors and devices (FERC Account 367) are the most reasonable of those proposed and
should be approved.

111. A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line
transformers (FERC Account 368) are the most reasonable of those proposed and should be
approved.

112. A service life of 26 years and a dispersion curve of L4 for ETI’s distribution overhead
service (FERC Account 369.1) are the most reasonable of those proposed and should be
approved.
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113. The net salvage rate of negative five percent for ETI’s distribution structures and
improvements (FERC Account 361) is the most reasonable of those proposed and should be
adopted.

114. The net salvage rate of negative 10 percent for ETI’s distribution station equipment (FERC
Account 362) is the most reasonable of those proposed and should be adopted.

115. The net salvage rate of negative seven percent for ETI’s distribution overhead conductors
and devices (FERC Account 365) is the most reasonable of those proposed and should be
adopted.

116. The net salvage rate of negative five percent for ETI’s distribution line transformers (FERC
Account 368) is the most reasonable of those proposed and should be adopted.

117. The net salvage rate of negative 10 percent for ETI’s distribution overhead services (FERC
Account 369.1) is the most reasonable of those proposed and should be adopted.

118. The net salvage rate of negative 10 percent for ETI’s distribution underground services
(FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119. A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and
improvements (FERC Account 390) are the most reasonable of those proposed and should be
approved.

120. The net salvage rate of negative 10 percent for ETI’s general structures and improvements
(FERC Account 390) is the most reasonable of those proposed and should be adopted.

121. It is reasonable to convert the $21.3 million deficit that has developed over time in the
reserve for general plant accounts to General Plant Amortization.

122. A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable
and should be adopted.

123. FERC pronouncement AR-15 requires amortization over the same life as recommended
based on standard life analysis. A standard life analysis determined that a five-year life was
appropriate for general plant computer equipment (FERC Account 390.2). Therefore, a five
year amortization for this account is reasonable and should be adopted.

124. ETI proposed adjustments to its Test Year payroll costs to reflect: (a) changes to employee
headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases
set to go into effect after the end of the Test Year.

125. The proposed payroll adjustments are reasonable but should be updated to reflect the most
recent available information on headcount levels as proposed by Commission Staff. In
addition to adjusting payroll expense levels, the more recent headcount numbers should be
used to adjust the level of payroll tax expense, benefits expense, and savings plan expense.
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126. Staff has appropriately updated headcount levels to the most recent available data but errors
made by Staff should be corrected. The corrections related to: (a) a double counting of three
ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the
calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when
such costs were already included in the benefits percentage adjustments; and (d) corrections
for full-time equivalents calculations. Staff’s ETI headcount adjustment (AG-7) overstated
operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount
adjustment (AG-7) understated O&M payroll increase by $37,531.

127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128. The compensation packages that ETI offers its employees include a base payroll amount,
annual incentive programs, and long-term incentive programs. The majority of the
compensation is for operational measures, but some is for financial measures.

129. Incentive compensation that is based on financial measures is of more immediate and
predominant benefit to shareholders, whereas incentive compensation based on operational
measures is of more immediate and predominant benefit to ratepayers.

130. Incentives to achieve operational measures are necessary and reasonable to provide utility
services but those to achieve financial measures are not.

131. The $5,376,975 that was paid for long term incentive programs was tied to financial
measures and, therefore, should not be included in ETI’s cost of service.

132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
was tied to financial measures and, therefore, should be disallowed.

133. In total, the amount of incentive compensation that should be disallowed is $6,196,037
because it was related to financial measures that are not reasonable and necessary for the
provision of electric service.

134. The amount of incentive compensation that should be included in the cost of service is
$7,991,707.

135. To attract and retain highly qualified employees, the Entergy Companies provide a total
package of compensation and benefits that is equivalent in scope and cost with what other
comparable companies within the utility business and other industries provide for their
employees.

136. When using a benchmark analysis to compare companies’ levels of compensation, it is
reasonable to view the market level of compensation as a range rather than a precise, single
point.

137. ETI’s base pay levels are at market.

138. ETI’s benefits plan levels are within a reasonable range of market levels.
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139. ETI’s level of compensation and benefits expense is reasonable and necessary.

140. ETI provides non-qualified supplemental executive retirement plans for highly compensated
individuals such as key managerial employees and executives that, because of limitations
imposed under the Internal Revenue Code, would otherwise not receive retirement benefits
on their annual compensation over $245,000 per year.

141. ETI’s non-qualified supplemental executive retirement plans are discretionary costs designed
to attract, retain, and reward highly compensated employees whose interests are more closely
aligned with those of the shareholders than the customers.

142. ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not
reasonable or necessary to provide utility service to the public, not in the public interest, and
should not be included in ETI’s cost of service.

143. For the employee market in which ETI operates, most peer companies offer moving
assistance. Such assistance is expected by employees, and ETI would be placed at a
competitive disadvantage if it did not offer relocation expenses.

144. ETI’s relocation expenses were reasonable and necessary.

145. The Company’s requested operating expenses should be reduced by $40,620 to reflect the
removal of certain executive prerequisites proposed by Staff.

146. Staff properly adjusted the Company’s requested interest expense of $68,985 by removing
$25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
2012), leaving a recommended interest expense of $43,047.

147. During the Test Year, ETI’s property tax expense equaled $23,708,829.

148. ETI requested an upward pro forma adjustment of $2,592,420, to account for the property
tax expenses ETI estimates it will pay in the Rate Year.

149. ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon the
prediction that ETI’s property tax rate will be increased in 2012, a change that is speculative
is not known and measurable.

150. Staff’s recommendation to increase ETI’s Test Year property tax expenses by $1,214,688 is
based on the historical effective tax rate applied to the known Test Year-end plant in service
value, consistent with Commission precedent, and based upon known and measurable
changes.

151. ETI’s Test Year property tax burden should be adjusted upward by $1,214,688.

152. Staff recommended reducing ETI’s advertising, dues, and contributions expenses by
$12,800. The recommendation, which no party contested, should be adopted.
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153. The final cost of service should reflect changes to cost of service that affect other
components of the revenue requirement such as the calculation of the Texas state gross
receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
Expenses.

154. The Company’s requested Federal income tax expense is reasonable and necessary.

155. ETI’s request for $2,019,000 to be included in its cost of service to account for the
Company’s annual decommissioning expenses associated with River Bend is not reasonable
because it is not based upon “the most current information reasonably available regarding the
cost of decommissioning” as required by P.U.C. SUBST. R. 25.231(b)(1)(F)(i).

156. Based on the most current information reasonably available, the appropriate level of
decommissioning costs to be included in ETI’s cost of service is $1,126,000.

157. ETI’s appropriate total annual self-insurance storm damage reserve expense is $8,270,000,
comprised of an annual accrual of $4,400,000 to provide for average annual expected storm
losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its
current deficit.

158. ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.

159. ETI should continue recording its annual storm damage reserve accrual until modified by a
Commission order.

160. The operating costs of the Spindletop Facility are reasonable and necessary.

161. The operating costs of the Spindletop Facility paid to PB Energy Storage Services are
eligible fuel expenses.

Affiliate Transactions

162. ETI affiliates charged ETI $78,998,777 for services during the Test Year. The majority of
these O&M expenses—$69,098,041—were charged to ETI by ESI. The remaining affiliate
services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, L.L.C.;
Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy
Operations, Inc.; and non-regulated affiliates.

163. ESI follows a number of processes to ensure that affiliate charges are reasonable and
necessary and that ETI and its affiliates are charged the same rate for similar services. These
processes include: (a) the use of service agreements to define the level of service required
and the cost of those services; (b) direct billing of affiliate expenses where possible;
(c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting
processes and controls to provide budgeted costs that are reasonable and necessary to ensure
appropriate levels of service to its customers; and (e) oversight controls by ETI’s Affiliate
Accounting and Allocations Department.
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164. Affiliates charged expenses to ETI through 1292 project codes during the Test Year.

165. ETI agreed to remove the following affiliate transactions from its application:
(1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
(2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and
(3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with
Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual
Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of
electric utility service and are not in the public interest.

167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement)
are not normally-recurring costs and should not be recoverable.

168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related
to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy
New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management
for ESI) are research and development costs related to energy efficiency programs. As such,
they should be recovered through the energy efficiency cost recovery factor rather than base
rates.

170. Except as noted in the above Findings of Fact Nos. 162-169, all remaining affiliate
transactions were reasonable and necessary, were allowable, were charged to ETI at a price
no higher than was charged by the supplying affiliate to other affiliates, and the rate charged
is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation

171. ETI has one full or partial requirements wholesale customer – East Texas Electric
Cooperative, Inc.

172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the
wholesale load results in a retail production demand allocation factor of 95.3838 percent.

173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by
the FERC to allocate between jurisdictions.

174. Using 12CP methodology to allocate production costs between the wholesale and retail
jurisdictions is the best method to reflect cost responsibility and is appropriate based on
ETI’s reliance on capacity purchases.
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Class Cost Allocation and Rate Design

175. There is no express statutory authorization for ETI’s proposed Renewable Energy Credits
Rider (REC Rider).

176. REC Rider constitutes improper piecemeal ratemaking and should be rejected.

177. ETI’s Test Year expense for renewable energy credits, $623,303, is reasonable and necessary
and should be included in base rates.

178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
public rights-of-way to locate its facilities within municipal limits.

179. ETI is an integrated utility system. ETI’s facilities located within municipal limits benefit all
customers, whether the customers are located inside or outside of the municipal limits.

180. Because all customers benefit from ETI’s rental of municipal right-of-way, municipal
franchise fees should be charged to all customers in ETI’s service area, regardless of
geographic location.

181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA) § 33.008(b)
that MFF be allocated to each customer class on the basis of in-city kilo-watt hour (kWH)
sales, without an adjustment for the MFF rate in the municipality in which a given kWH sale
occurred.

182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-
181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The
Company’s proposed allocation of these costs to all retail customer classes based on
customer class revenues relative to total revenues is appropriate.

183. The Average and Excess (A&E) 4CP method for allocating capacity-related production
costs, including reserve equalization payments, to the retail classes is a standard
methodology and the most reasonable methodology.

184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and
the most reasonable methodology.

185. ETI appropriately followed the rate class revenue requirements from its cost of service study
to allocate costs among customer classes. ETI’s revenue allocation properly sets rates at
each class’s cost of service.

186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
replacement of a functioning light with a lower-wattage bulb.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 357
PUC DOCKET NO. 39896

187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study
regarding the feasibility of instituting LED-based rates and, if the study shows that such rates
are feasible, ETI should file proposals for LED-based lighting and traffic signal rates it next
rate case.

188. An agreement was reached by the parties and approved by the Commission in Docket
No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial
Power Service-Time of Day, General Service, General Service-Time of Day, Large General
Service, and Large General Service-Time of Day rate schedules.

189. ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet from
these rate schedules consistent with the parties’ agreement in Docket No. 37744.

190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is
not reasonable.

191. ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
agreement that was adopted by the Commission as just and reasonable in Docket No. 37744.
Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194.

192. ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read:

DETERMINATION OF BILLING LOAD

The kW of Billing Load will be the greatest of the following:

(A) The Customer’s maximum measured 30-minute demand
during any 30-minute interval of the current billing month,
subject to §§ III, IV and V above; or

(B) 60% of Contract Power as defined in § VII; or

(C) 2,500 kW.

193. ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read:

DETERMINATION OF CONTRACT POWER

Unless Company gives customer written notice to the contrary,
Contract Power will be defined as below:

Contract Power - the highest load established under § VI(A) above
during the 12 months ending with the current month. For the initial
12 months of Customer’s service under the currently effective
contract, the Contract Power shall be the kW specified in the
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 358
PUC DOCKET NO. 39896

currently effective contract unless exceeded in any month during the
initial 12-month period.

194. The Large General Service and Large General Service-Time of Day schedules should be
similarly revised to eliminate ETI’s life-of-contract demand ratchet.

195. In its proposed rate design for the LIPS class, the Company took a conservative approach
and increased the current rates by an equal percentage. This minimized customer bill
impacts while maintaining cost causation principles on a rate class basis.

196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS
rate schedule with subsequent increases to be considered in subsequent base rate cases.

197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges
and increase the demand charges as proposed by Staff witness William B. Abbott.

198. DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent Pumping
Service” (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-
season (November through April), that can be cancelled at any time, and for load not lasting
more than 80 hours in a year. For customers whose loads match these SIPS characteristics
(for example, DOE’s Strategic Petroleum Reserve), the 12-month demand ratchet provision
of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The
monthly demand set under the SIPS provisions would be applicable for billing purposes only
in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in
that month, it would be forgiven and not applicable in the succeeding 12 months.

199. DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It
more closely addresses specific customer characteristics and provides for cost-based rates, as
does another ETI rider applicable to Pipeline Pumping Service.

200. Standby Maintenance Service (SMS) is available to customers who have their own
generation equipment and who contract for this service from ETI.

201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance
power to qualifying facilities should recognize system wide costing principles and should not
be discriminatory.

202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing
supplementary power under another applicable rate; and (b) revising the tariff as follows:
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 359
PUC DOCKET NO. 39896

Distribution Transmission
Charge (less than (69KV and
69KV) greater)
Billing Load Charge ($/kW):
Standby $2.46 $0.79
Maintenanc
e $2.27 $0.60
Non-Fuel Energy Charge (¢/kWh)
On-Peak 0.881¢ 0.846¢
Off-Peak 0.575¢ 0.552¢

203. ETI’s Additional Facilities Charge Rider (Schedule AFC) prescribes the monthly rental
charge paid by a customer when ETI installs facilities for that customer that would not
normally be supplied, such as line extensions, transformers, or dual feeds.

204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
Option B, which applies when a customer elects to amortize the directly-assigned facilities
over a shorter term ranging from one to ten years, has a variable monthly charge. There is
also a term charge that applies after the facility has been fully depreciated.

205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per
month of the installed cost of all facilities included in the agreement for additional facilities.

206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the
Post Term Recovery Charge as follows:

Selected Recovery Term Recovery Term Charge Post Recovery Term Charge
1 10.88% 0.35%
2 5.39% 0.35%
3 3.92% 0.35%
4 3.20% 0.35%
5 2.76% 0.35%
6 2.48% 0.35%
7 2.28% 0.35%
8 2.14% 0.35%
9 1.97% 0.35%
10 1.94% 0.35%

207. The revisions in the above Findings of Fact to Schedule AFC rates reasonably reflect the
costs of running, operating, and maintaining the directly-assigned facilities.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 360
PUC DOCKET NO. 39896

208. It is reasonable to modify the Large General Service rate schedule by increasing the demand
charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to $.00513; and
maintaining the customer charge at $425.05.

209. Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS
customers towards their cost of service by recommending a decrease in the customer charge
from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable
and should be adopted.

210. ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer
charge of $5 per month and a consumption-based energy charge. The Energy charge is a
fixed rate of 5.802ȼ per kWh from May through October (Summer). In the months
November through April (Winter), the rates are structured as a declining block, in which the
price of each unit is reduced after a defined level of usage.

211. ETI’s Schedule RS declining block rate structure is contrary to energy efficiency efforts and
the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as
stated in PURA § 39.905.

212. Schedule RS winter block rates should be modified consistent with the goal set out in PURA
§ 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed
by ETI and subsequent reductions should be reviewed for consideration at the occurrence of
each rate case filing.

213. Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation

214. ETI incurred $616,248,686 in natural-gas expenses during the Reconciliation Period, which
is from July 2009 through June 2011.

215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
negotiated operational balancing agreements with various pipeline companies.

216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its
natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217. ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide
reliable electric service to retail customers.

218. ETI incurred $90,821,317 in coal expenses during the Reconciliation Period.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 361
PUC DOCKET NO. 39896

219. ETI prudently managed its coal and coal-related contracts during the Reconciliation Period.

220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at
the Big Cajun II, Unit 3 facility.

221. ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable
electric service to retail customers.

222. ETI incurred $990,041,434 in purchased-energy expenses during the Reconciliation Period.

223. The Entergy System’s planning and procurement processes for purchased power produced a
reasonable mix of purchased resources at a reasonable price.

224. During the Reconciliation Period, ETI took advantage of opportunities in the fuel and
purchased-power markets to reduce costs and to mitigate against price volatility.

225. ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to
provide reliable electric service to retail customers.

226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its
purchased-power planning and procurement processes and its actual power purchases during
the Reconciliation Period.

227. The Entergy system sold power off system when the revenues were expected to be more than
the incremental cost of supplying generation for the sale, subject to maintaining adequate
reserves.

228. The System Agreement is the tariff approved by the FERC that provides the basis for the
operation and planning of the Entergy system, including the six Operating Companies. The
System Agreement governs the wholesale-power transactions among the Operating
Companies by providing for joint operation and establishing the bases for equalization
among the Operating Companies, including the costs associated with the construction,
ownership, and operation of the Entergy system facilities.

229. Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues
and expenses from off-system sales.

230. During the Reconciliation Period, ETI recorded off-system sales revenue in the amount of
$376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues
and margins from off-system sales to eligible fuel expenses.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 362
PUC DOCKET NO. 39896

231. ETI properly recorded revenues from off-system sales and credited those revenues to eligible
fuel costs.

232. The Entergy system consists of six Operating Companies, including ETI, which are planned
and operated as a single, integrated electric system under the terms of the System
Agreement.

233. Service Schedule MSS-1 of the System Agreement determines how the capability and
ownership costs of reserves for the Entergy system are equalized among the Operating
Companies. These inter-system “reserve equalization” payments are the result of a formula
rate related to the Entergy system’s reserve capability that is applied on a monthly basis.

234. Reserve capability under Service Schedule MSS-1 is capability in excess of the Entergy
system’s actual or planned load built or acquired to ensure the reliable, efficient operation of
the electric system.

235. By approving Service Schedule MSS-1, the FERC has approved the method by which the
Operating Companies share the cost of maintaining sufficient reserves to provide reliability
for the Entergy system as a whole.

236. Service Schedule MSS-3 of the System Agreement determines the pricing and exchange of
energy among the Operating Companies. By approving Service Schedule MSS-3, the FERC
has approved the method by which the Operating Companies are reimbursed for energy sold
to the exchange energy pool and how that energy is purchased.

237. Service Schedule MSS-4 of the System Agreement sets forth the method for determining the
payment for unit power purchases between Operating Companies. By approving Service
Schedule MSS-4, the FERC has approved the methodology for pricing Inter-Operating
Company unit power purchases.

238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
horizons. Once the planning process has identified the most economical resources that can
be used to reliably meet the aggregate Entergy system demand, the next step is to procure the
fuel necessary to operate the generating units as planned and acquire wholesale power from
the market.

239. Once resources are procured to meet forecasted load, the Entergy system is operated during
the current day using all the resources available to meet the total Entergy system demand.

240. After current-day operation, the System Agreement prescribes an accounting protocol to bill
the costs of operating the system to the individual Operating Companies. This protocol is
implemented via the Intra-System Bill (ISB) to each Operating Company on a monthly basis.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 363
PUC DOCKET NO. 39896

241. ETI purchased power from affiliated Operating Companies per the terms of Service
Schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to
affiliated Operating Companies are reasonable and necessary, and the FERC has approved
the pricing formula and the obligation to purchase the energy. ETI pays the same price per
megawatt hour for energy under Service Schedule MSS-3 as does any other Operating
Company purchasing energy under Service Schedule MSS-3 during the same hour.

242. The Spindletop Facility is used primarily to ensure gas-supply reliability and guard against
gas-supply curtailments that can occur as a result of extreme weather or other unusual
events.

243. The Spindletop Facility provides a secondary benefit of flexibility in gas supply. ETI can
back down gas-fired generation to take advantage of more economical wholesale power, or
use gas from storage to supplement gas-fired generation when load increases during the day
and thereby avoid more expensive intra-day gas purchases.

244. ETI’s customers received benefits from the Spindletop Facility during the Reconciliation
Period through reliable gas supplies and ETI’s monthly and daily storage activity.

245. ETI prudently managed the Spindletop Facility to provide reliability and flexibility of gas
supply for the benefit of customers.

246. ETI proposed new loss factors, based on a December 2010 line loss study, to be applied for
the purpose of allocating its costs to its wholesale customers and retail customer classes.

247. ETI’s proposed loss factors are reasonable and shall be implemented on a prospective basis
as a result of this final order.

248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC’s
reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat
such costs as eligible fuel expense.

249. Special circumstances exist and it is appropriate for recovery of the rough production cost
equalization costs reallocated to ETI as a result of the FERC’s decision in Order No. 720-A.

Other Issues

250. A deferred accounting of ETI’s Midwest Independent Transmission System Operator
(MISO) transition expenses is not necessary to carry out any requirement of PURA.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 364
PUC DOCKET NO. 39896

251. ETI should include $2.4 million in base rates for MISO transition expense incurred on or
after January 2, 2011, based on a five-year amortization of $12 million in total projected
expenses.

252. ETI should include an additional $52,800 in base rates for MISO transition expenses
incurred during the 2010 portion of the Test Year, based on a five-year amortization of
$263,908 in such expenses.

253. Transmission Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase
of this docket, after the Commission makes final rulings on the various contested issues that
may affect this calculation.

255. The appropriate amount for ETI’s purchased power capacity expense to be included in base
rates is $245,432,884.

256. The amount of ETI’s purchased power capacity expense includes third-party contracts,
legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
amounts for all contracts should be included in the baseline for a purchased capacity rider
that may be approved in Project No. 39246 is an issue that should be decided in that project.

B. Conclusions of Law

1. ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric utility”
as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.101–.111, and 36.203.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation
of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. GOV’T CODE
ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act, TEX. GOV’T CODE ANN. Chapter 2001.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 365
PUC DOCKET NO. 39896

6. Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded
jurisdiction to the Commission has jurisdiction over the Company’s application, which seeks
to change rates for distribution services within each municipality.

7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
municipality’s rate proceeding.

8. ETI has the burden of proving that the rate change it is requesting is just and reasonable
pursuant to PURA § 36.006.

9. In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding
permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used
and useful in providing service to the public in excess of its reasonable and necessary
operating expenses.

10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original
cost, less depreciation, of property used and useful to ETI in providing service.

11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and
P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

12. Including the cash working capital approved in this proceeding in ETI’s rate base is
consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
allowance for cash working capital to be included in rate base.

13. The ROE and overall rate of return authorized in this proceeding are consistent with the
requirements of PURA §§ 36.051 and 36.052.

14. The affiliate expenses approved in this proceeding and included in ETI’s rates meet the
affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.—Austin
1984, no writ).

15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and
P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in
this case is based on the most current information reasonably available regarding the cost of
decommissioning, the balance of funds in the decommissioning trust, anticipated escalation
rates, the anticipated return on the funds in the decommissioning trust, and other relevant
factors.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 366
PUC DOCKET NO. 39896

17. ETI has demonstrated that its eligible fuel expenses during the Reconciliation Period were
reasonable and necessary expenses incurred to provide reliable electric service to retail
customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted for
the amount of fuel-related revenues collected pursuant to the fuel factor during the
Reconciliation Period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during
the Reconciliation Period.

19. The Reconciliation Period level operating and maintenance expenses for the Spindletop
Facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover
rough production equalization payments reallocated to ETI by the FERC.

21. ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with
PURA § 36.003.

C. Proposed Ordering Paragraphs

In accordance with these findings of fact and conclusions of law, the Commission issues the
following orders:

1. The Proposal for Decision prepared by the SOAH ALJs is adopted to the extent consistent
with this Order.

2. ETI’s application is granted to the extent consistent with this Order.

3. ETI shall file tariffs consistent with this Order within 20 days of the date of this Order. No
later than ten days after the date of the tariff filings, Staff shall file its comments
recommending approval, modification, or rejection of the individual sheets of the tariff
proposal. Responses to the Staff’s recommendation shall be filed no later than 15 days after
the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff
sheet, effective the date of the letter.

4. The tariff sheets shall be deemed approved and shall be become effective on the expiration
of 20 days from the date of filing, in the absence of written notification of modification or
rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed
revisions of those sheets in accordance with the Commission’s letter within ten days of the
date of that letter, and the review procedure set out above shall apply to the revised sheets.
SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 367
PUC DOCKET NO. 39896

5. Copies of all tariff-related filings shall be served on all parties of record.

6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of
instituting LED-based rates and, if the study shows that such rates are feasible, ETI should
file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED
lighting customers taking service, the study shall include detailed information regarding
differences in the cost of serving LED and non-LED lighting customers. ETI shall provide
the results of this study to Cities and interested parties as soon as practicable but no later
than the filing of its next rate case.

7. All other motions, requests for entry of specific findings of fact and conclusions of law, and
any other requests for general or specific relief, if not expressly granted, are denied.

SIGNED July 6, 2012.
 APPENDIX B

Commission's Order on Rehearing in Docket No. 39896
 PUC DOCKET NO. 39896
SOAH DOCKET NO. XXX-XX-XXXX

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, § OF TEXAS
AND OBTAIN DEFERRED §
ACCOUNTING TREATMENT §

ORDER ON REHEARING

This Order addresses the application of Entergy Texas, Inc. for authority to change rates,
reconcile fuel costs, and defer costs for the transition to the Midwest Independent System
Operator (MISO). In its application, Entergy requested approval of an increase in annual base-
rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff
schedules, including new riders to recover costs related to purchased-power capacity and
renewable-energy credit requirements, requested final reconciliation of its fuel costs, and
requested waivers to the rate-filing package requirements.

On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law
judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase
for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781
million. The ALJs also recommended approving total fuel costs of approximately $1.3 billion.
The ALJs did not recommend approving the renewable-energy credit rider and the Commission
earlier removed the purchased-power capacity rider as an issue to be addressed in this docket.1
On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the
exceptions and replies of the parties.2 Except as discussed in this Order, the Commission adopts
the proposal for decision, as corrected, including findings of fact and conclusions of law.

Parties filed motions for rehearing on September 25 and October 4, 2012 and filed replies
to the motions for rehearing on October 15, 2012. The Commission considered the motions for

1
Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012).
2
Letter from SOAH judges to PUC (Aug. 8, 2012).
PUC Docket No. 39896 Order on Rehearing Page 2 of 44
SOAH Docket No. XXX-XX-XXXX

rehearing at the October 25, 2012 open meeting. The Commission granted Commission Staff’s
motion for rehearing that requested technical corrections to reflect the rates that resulted from the
Commission Staff number-running memo that was filed on August 28, 2012. The Commission
modifies findings of fact 205, 206, 208, and 210 as requested by Commission Staff and attaches
Commission schedules I through V to reflects its decisions. The Commission granted the
Department of Energy’s motion for rehearing requesting that finding of fact 198 be modified to
reflect the applicable off-season for the schedulable intermittent pumping service. Finding of
fact 198 is modified to reflect that the off-season is October through May. In its motion for
rehearing, Entergy noted that findings of fact 17B and 17D should be modified to more
accurately reflect the procedural history. The Commission modifies findings of fact 17B and
17D to state that Entergy agreed to extend time to provide the Commission sufficient time to
consider the issues in this proceeding on two occasions—at the July 27 and August 30, 2012
open meetings.

I. Discussion

A. Prepaid Pension Asset Balance
Entergy included in rate base an approximately $56 million item named Unfunded
Pension.3 This amount represents the accumulated difference between the annual pension costs
calculated in accordance with the Statement of Financial Accounting Standards (SFAS) No. 87
and the actual contributions made by Entergy to the pension fund—Entergy contributed nearly
$56 million more to its pension fund than the minimum required by SFAS No. 87.4

In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding
the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued
deferred federal income taxes (ADFIT) to be included in rate base.5 For the excluded portion,
the Commission allowed the accrual of an allowance for funds used during construction

3
Proposal for Decision at 23 (July 6, 2012) (PFD).
4
PFD at 23-24.
5
Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on
Rehearing (March 4, 2008).
PUC Docket No. 39896 Order on Rehearing Page 3 of 44
SOAH Docket No. XXX-XX-XXXX

(AFUDC).6 The ALJs concluded that this approach was sound and should be followed in this
case.7 Thus, the ALJs recommended that the CWIP-related portion of Entergy’s prepaid pension
asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However,
the ALJs did not address ADFIT.

The Commission agrees that the CWIP-related portion of Entergy’s pension asset should
be excluded from the asset and that this excluded portion should accrue AFUDC. However, the
Commission also finds that the impact of this exclusion on Entergy’s ADFIT should be reflected.
When items are excluded from rate base, the related ADFIT should also be excluded. The
adjusted ADFIT for the prepaid pension asset remaining in Entergy’s rate base should be reduced
by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds
new finding of fact 28A to reflect this modification to Entergy’s ADFIT.

B. FIN 48
The Financial Accounting Standards Board’s Interpretation No. 48 (FIN 48) prescribes
the way in which a company must analyze, quantify, and disclose the potential consequences of
tax positions that the company has taken that are legally uncertain. Entergy reported that its
uncertain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on
Entergy’s balance sheet as a tax liability. Entergy also reported that it made a cash deposit with
the IRS in the amount of $1,294,683 associated with its FIN 48 liability.9

The ALJs concluded that Entergy’s FIN 48 liability should be included in its ADFIT
balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy’s
FIN 48 liability should not be included in Entergy’s ADFIT balance. Accordingly, the ALJs
recommended that $4,621,778 (Entergy’s FIN 48 liability of $5,916,461 less the $1,294,683 cash
deposit Entergy has already made with the IRS) be added to Entergy’s ADFIT balance and thus

6
Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change
Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011).
7
PFD at 26.
8
Id. at 24-26.
9
PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony
of Roberts, Entergy Ex. 64 at 8).
PUC Docket No. 39896 Order on Rehearing Page 4 of 44
SOAH Docket No. XXX-XX-XXXX

be used to offset Entergy’s rate base.10 The ALJs did not recommend the addition of a deferred-
tax-account rider because no party expressly advocated the addition of such a rider.11

The Commission adopts the proposal for decision regarding the adjustment to Entergy’s
ADFIT for the amount attributable to Entergy’s FIN 48 liability. However, the Commission also
follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the
proposal for decision on this point. In CenterPoint’s Electric Delivery Company’s last rate case,
Docket No. 38339,12 the Commission found that tax schedule UTP—on which companies must
describe, list, and rank each uncertain tax position—would provide the IRS auditors sufficient
information to quickly determine which uncertain tax positions are of a magnitude worth
investigating and that an IRS audit would be more likely to occur on some uncertain tax
positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome,
the utility would not be able to earn a return on the amount paid to the IRS until the next rate
case.

Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable
FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on a prospective basis
an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN-
48 unfavorable-tax-position audit. The return will be applied prospectively to FIN-48 amounts
disallowed by an IRS audit after such amounts are actually paid to the federal government. If
Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position
decision by the IRS, then any amounts collected under rider related to that overturned decision
shall be credited back to ratepayers.

The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent
with its decision to authorize the deferred-tax-account tracker.

10
PFD at 29.
11
Id. at 29.
12
Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates, Docket
No. 38339, Order on Rehearing at 3-4 (June 23, 2011).
PUC Docket No. 39896 Order on Rehearing Page 5 of 44
SOAH Docket No. XXX-XX-XXXX

C. Capitalized Incentive Compensation
Entergy capitalized into plant-in-service accounts some of the incentive payments made
to employees and sought to include those amounts in rate base. The ALJs determined that
Entergy should not be able to recover its financially based incentive-compensation costs.13
Therefore, the portion of Entergy’s incentive-compensation costs capitalized during the period
July 1, 2009 through June 30, 2010 that were financially based was excluded from Entergy’s rate
base. The ALJs also determined that the actual percentages should be used to determine the
amount that is financially based.14

In discussing Entergy’s incentive compensation as a component of operating expenses,
the ALJs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for
calculating the amount of the financially based incentive costs. This method uses the actual
percentage reductions applicable to each of the annual incentive programs that included a
component of financially-based costs.15

In its exceptions regarding capitalized incentive compensation, Entergy advocated for the
use of TIEC’s methodology to also calculate the amount of capitalized incentive compensation
that is financially based. Entergy also noted that the amount of the disallowance reflected in the
schedules, $1,333,352, was calculated using a disallowance factor that included incentive
compensation tied to cost-control measures, which the ALJs found to be recoverable in the
operating-cost incentive-compensation calculation.16 When the TIEC methodology is applied to
the capitalized incentive-compensation costs in rate base, the net result under TIEC’s
methodology is that only $335,752.96 should be disallowed from capital costs.17

The Commission agrees that capitalized incentive compensation that is financially based
should be excluded from rate base and that the exclusion only applies to incentive costs that
Entergy capitalized during the period from July 1, 2009 through June 30, 2010. However, the
Commission finds that a consistent methodology should be used to calculate the amount to be

13
PFD at 171.
14
Id. at 72.
15
Id. at 174; see also Entergy’s Exceptions to the Proposal for Decision at 25-26 (July 23, 2012).
16
Entergy’s Exceptions to the Proposal for Decision at 25-26.
17
Id. at 25-26.
PUC Docket No. 39896 Order on Rehearing Page 6 of 44
SOAH Docket No. XXX-XX-XXXX

excluded and therefore that TIEC’s methodology should also be used for calculating the amount
of capitalized financially based incentive-compensation costs that should be excluded from rate
base. Accordingly, the total amount of capitalized incentive-compensation costs that should be
disallowed from rate base is $335,752.96. Finding of fact 61 is modified to reflect this
determination.

As noted by Commission Staff, this disallowance to plant-in-service alters the expense
for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad
valorem taxes is $24,921,022,18 an adjustment of $1,222,106 to Entergy’s test year amount.
Finding of fact 151 is modified to reflect this adjustment to property taxes.

D. Rate of Return and Cost of Capital
The ALJs found the proper range of an acceptable return on equity for Entergy would be
from 9.3 percent to 10.0 percent.19 The mid-point of the range is 9.65 percent. The ALJs found
that the effect of unsettled economic conditions facing utilities on the appropriate return on
equity should be taken into account and that the effect would be to move the ultimate return on
equity towards the upper limits of the range that was determined to be reasonable.20 The ALJs
found that the reasonable adjustment would be 15 basis points, moving the reasonable return on
equity to 9.80 percent.21

The Commission must establish a reasonable return for a utility and must consider
applicable factors.22 The Commission disagrees with the ALJs that a utility’s return on equity
should be determined using an adder to reflect unsettled economic conditions facing utilities.
The Commission agrees with the ALJs, however, that a return on equity of 9.80 percent will
allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but
finds this rate appropriate independent of the 15-point adder recommended by the ALJs. A
return on equity of 9.80 percent is within the range of an acceptable return on equity found by

18
Commission Number-Run Memorandum at 2 (Aug. 28, 2012).
19
PFD at 94.
20
Id.
21
Id. at 94.
22
PURA §§ 36.051, .052.
PUC Docket No. 39896 Order on Rehearing Page 7 of 44
SOAH Docket No. XXX-XX-XXXX

the ALJs. Accordingly, the Commission adds new finding of fact 65A to reflect the
Commission’s decision on this point.

E. Purchased-Power Capacity Expense
The ALJs rejected Entergy’s request to recover $31 million more in purchased-power
capacity costs than its actual test-year expenses because Entergy had failed to prove that the
adjustment was known and measurable,23 and because the request violated the matching
principle.24 Consequently, the ALJs recommended that Entergy’s test-year expenses of
$245,432,884 be used to set rates in this docket.25

Entergy pointed to an additional $533,002 of purchased-power capacity expenses that
were properly included in Entergy’s rate-filing package, but not provided for in the proposal for
decision.26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for
Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for
an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of
purchased-power capacity costs were incurred during the test-year and should be added to the
purchased-power capacity costs in Entergy’s revenue requirement. The Commission modifies
findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year
purchased-power capacity costs, increasing the total amount to $245,965,886.

F. Labor Costs – Incentive Compensation
The ALJs found that $6,196,037, representing Entergy’s financially-based incentives paid
in the test-year, should be removed from Entergy’s O&M expenses.27 The ALJs agreed with
Commission Staff and Cities that an additional reduction should be made to account for the
FICA taxes that Entergy would have paid for those costs,28 but did not include this reduction in a
finding of fact.

23
PFD at 108-09.
24
Id. at 109.
25
Id.
26
Entergy’s Exceptions to the Proposal for Decision at 51.
27
PFD at 175.
28
Id. at 175-76.
PUC Docket No. 39896 Order on Rehearing Page 8 of 44
SOAH Docket No. XXX-XX-XXXX

The Commission agrees with the ALJs, but modifies finding of fact 133 to specifically
include the decision that an additional reduction should be made to account for the FICA taxes
Entergy would have paid on the disallowed financially-based incentive compensation. The
Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this
Order.29

G. Affiliate Transactions
OPUC argued that Entergy’s sales and marketing expenses exclusively benefit the larger
commercial and industrial customers, but the majority of the sales, marketing, and customer
service expenses are allocated to the operating companies based on customer counts. Therefore,
the majority of these expenses are allocated to residential and small business customers. OPUC
argued that it is inappropriate for residential and small business customers to pay for these
expenses.30 The ALJs did not adopt OPUC’s position on this issue.

The Commission agrees with OPUC and reverses the proposal for decision regarding
allocation of Entergy’s sales and marketing expense and finds that $2.086 million of sales and
marketing expense should be reallocated using direct assignment. The Commission has
previously expressed its preference for direct assignment of affiliate expenses.31 The
Commission finds that the following amounts should be allocated based on a total-number-of-
customers basis: (1) $46,490 for Project E10PCR56224 – Sales and Marketing – EGSI Texas;
(2) $17,013 for Project F3PCD10049 – Regulated Retail Systems O&M; and (3) $30,167 for
Project F3PPMMALI2 – Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power
Service.32 The reallocation has the effect of increasing the revenue requirement allocated to the
large business class customers and reduces the revenue requirement for small business and
residential customers. New finding of fact 164A is added to reflect the proper allocation of these
affiliate transactions.

29
See Commission Number Run-Memorandum at 3 (Aug. 28, 2012).
30
Direct Testimony of Carol Szerszen, OPUC Ex. 1 at 44-45.
31
Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997).
32
Direct Testimony of Carol Szerszen, OPUC Ex. 1 at Schedule CAS-7.
PUC Docket No. 39896 Order on Rehearing Page 9 of 44
SOAH Docket No. XXX-XX-XXXX

H. Fuel Reconciliation
Entergy proposed to allocate costs for the fuel reconciliation to customers using a line-
loss study performed in 1997. Entergy conducted a line-loss study for the year ending December
31, 2010, which falls in the middle of the two year fuel reconciliation period—July 2009 through
June 2011—and therefore reflects the actual line losses experienced by the customer classes
during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the
reconciliation period should reflect the current line-loss study performed by Entergy for this case
and recommended approval on a going-forward basis. Fuel factors under P.U.C. SUBST.
R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described
in P.U.C. SUBST. R. 25.236. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel
reconciliation proceeding to include any issue related to the reasonableness of a utility’s fuel
expenses and whether the utility has over- or under-recovered its reasonable fuel expenses.33
Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the
reconciliation period using the current line-losses. The ALJs rejected Cities’ proposed
adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission-
approved line losses that were in effect at the time fuel costs were billed to customers in a fuel
reconciliation.34

The Commission agrees with Cities and reverses the proposal for decision regarding
which line-loss factors should be used in Entergy’s fuel reconciliation. Entergy used the 2010
study line-loss calculations to calculate the demand- and energy-related allocations in its cost of
service analysis supporting its requested base rates. These same currently available line-loss
factors should have been utilized in Entergy’s fuel reconciliation. The Commission finds that
Entergy’s 2010 line-loss factors should be used to calculate Entergy’s fuel reconciliation
over-recovery. As a result, Entergy’s fuel reconciliation over-recovery should be reduced by
$3,981,271. Finding of fact 246A and conclusions of law 19A and 19B are added to reflect the
Commission’s finding that the 2010 line-loss factors be used to reconcile Entergy’s fuel costs.

33
Cities’ Exceptions to the Proposal for Decision at 20-21 (July 23, 2012).
34
PFD at 327-328.
PUC Docket No. 39896 Order on Rehearing Page 10 of 44
SOAH Docket No. XXX-XX-XXXX

I. MISO Transition Expenses
During the Commission’s consideration of the proposal for decision, the parties that
contested the amount of Entergy’s MISO transition expenses and how the transition expenses
should be accounted for reached announced on the record that they had reached an agreement on
these issues.35 Those parties agreed that the MISO transition expenses would not be deferred and
that Entergy’s base rates should include $1.6 million for MISO transition expense.36 The
Commission adopts the agreement of the parties and accordingly modifies finding of fact 251
and deletes finding of fact 252.

J. Purchased-Power Capacity Cost Baseline
The Commission modified the amount of purchased-power capacity expense in the
test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the
change to the proper test-year purchased-power capacity expense.

K. Other Issues
New findings of fact 17A, 17B, 17C, 17D, and 17 E are added to reflect procedural
aspects of the case after issuance of the proposal for decision.

In addition, to reflect corrections recommended by the ALJs, findings of fact 116, 123,
192, 194, and 202 are modified; and new finding of fact 182A is added.

The Commission adopts the following findings of fact and conclusions of law:

II. Findings of Fact

Procedural History
1. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a
retail service area located in southeastern Texas.

35
Open Meeting Tr. at 138 (Aug. 17, 2012).
36
Id.
PUC Docket No. 39896 Order on Rehearing Page 11 of 44
SOAH Docket No. XXX-XX-XXXX

2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
Commission (FERC) regulates ETI’s wholesale electric operations.

3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted test-
year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate
Filing Package for Generating Utilities (RFP) accompanying ETI’s application and
including new riders for recovery of costs related to purchased-power capacity and
renewable energy credit requirements; (3) a request for final reconciliation of ETI’s fuel
and purchased-power costs for the reconciliation period from July 1, 2009 to
June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V
accompanying ETI’s application.

4. The 12-month test-year employed in ETI’s filing ended on June 30, 2011 (test-year).

5. ETI provided notice by publication for four consecutive weeks before the effective date
of the proposed rate change in newspapers having general circulation in each county of
ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of
its customers. Additionally, ETI timely served notice of its statement of intent to change
rates on all municipalities retaining original jurisdiction over its rates and services.

6. The following parties were granted intervenor status in this docket: Office of Public
Utility Counsel; the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe,
Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge
North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah,
Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co.
(Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric
Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores
Texas, LLC, and Sam’s East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility
Commission of Texas (Commission or PUC) was also a participant in this docket.

7. On November 29, 2011, the Commission referred this case to the State Office of
Administrative Hearings (SOAH).
PUC Docket No. 39896 Order on Rehearing Page 12 of 44
SOAH Docket No. XXX-XX-XXXX

8. On December 7, 2011, the Commission issued its order requesting briefing on threshold
legal/policy issues.

9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31
issues to be addressed in this proceeding.

10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order
No. 2, which approved an agreement among the parties to establish a June 30, 2012
effective date for the company’s new rates resulting from this case pursuant to certain
agreed language and consolidate Application of Entergy Texas, Inc. for Authority to Defer
Expenses Related to its Proposed Transition to Membership in the Midwest Independent
System Operator, Docket No. 39741 (pending) into this proceeding. Although it did not
agree, Staff did not oppose the consolidation.

11. On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for
admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and
participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick
D. Chamberlain to appear and participate as counsel for Wal-Mart.

12. On January 19, 2012, the Commission issued a supplemental preliminary order
identifying two additional issues to be addressed in this case and concluding that the
company’s proposed purchased-power capacity rider should not be addressed in this case
and that such costs should be recovered through base rates.

13. ETI timely filed with the Commission petitions for review of the rate ordinances of the
municipalities exercising original jurisdiction within its service territory. All such
appeals were consolidated for determination in this proceeding.

14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues
into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC
Docket No. 39896, Docket No. 40295 (pending).

15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
revenues to approximately $104.8 million over adjusted test-year revenues.

16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.
PUC Docket No. 39896 Order on Rehearing Page 13 of 44
SOAH Docket No. XXX-XX-XXXX

17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30,
2012.

17A. On August 7, 2012, the SOAH ALJs filed a letter with the Commission recommending
changes to the PFD.

17B At the July 27, 2012 open meeting, ETI agreed to extend time to August 31, 2012 to
provide the Commission sufficient time to consider the issues in this proceeding.

17C. The Commission considered the proposal for decision at the August 17, 2012 and August
30, 2012 open meetings.

17D. At the August 30, 2012 open meeting, ETI agreed to extend time to September 14, 2012
to provide the Commission sufficient time to consider the issues in this proceeding.

17E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the
amount of costs for the transition to MISO.

Rate Base
18. Capital additions that were closed to ETI’s plant-in-service between July 1, 2009 and
June 30, 2011, are used and useful in providing service to the public and were prudently
incurred.

19. ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased
when Docket No. 37744 concluded because the asset would have then begun earning a
rate of return as part of rate base.

21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
test-year in the present case, and less the amount of additional insurance proceeds
received by ETI after the conclusion of Docket No. 37744.

22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
remain in rate base, applying a five-year amortization rate beginning August 15, 2010.
PUC Docket No. 39896 Order on Rehearing Page 14 of 44
SOAH Docket No. XXX-XX-XXXX

23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.

24. The company requested in rate base its prepaid pension assets balance of $55,973,545,
which represents the accumulated difference between the Statement of Financial
Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual
contributions made by the company to the pension fund.

25. The prepaid pension assets balance includes $25,311,236 capitalized to construction work
in progress (CWIP).

26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
was insufficient evidence showing that major projects under construction were efficiently
and prudently managed.

27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not
be included in ETI’s rate base.

28. The remainder of the prepaid pension assets balance should be included in ETI’s rate
base.

28A. When items are excluded from rate base, the related ADFIT should also be excluded.
The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded
from rate base is $8,858,933. The adjusted ADFIT for the prepaid pension asset
remaining in Entergy’s rate base should be reduced by $8,858,933.

29. ETI should be permitted to accrue an allowance for funds used during construction on the
portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.

30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48
(FIN 48), “Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of
its uncertain tax positions by evaluating the tax position on its technical merits to
determine whether the position, and the corresponding deduction, is more-likely-than-not
to be sustained by the Internal Revenue Service (IRS) if audited.

31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
PUC Docket No. 39896 Order on Rehearing Page 15 of 44
SOAH Docket No. XXX-XX-XXXX

purposes and record it as a potential liability with interest to better reflect the company’s
financial condition.

32. At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon
tax positions that the company believes will not prevail in the event the positions are
challenged, via an audit, by the IRS.

33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 liability.

34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48
liability.

35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.

36. ETI may never have to pay the IRS the FIN 48 liability.

37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48
liability funds.

38. Until actually paid to the IRS, the FIN 48 liability represents cost-free capital and should
be deducted from rate base.

39. The amount of $4,621,778 (representing ETI’s full FIN 48 liability of $5,916,461 less the
$1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be
added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

40. ETI’s application and proposed tariffs do not include a request for a tracking mechanism
or rider to collect a return on the FIN 48 liability.

40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to
recover on a prospective basis an after–tax return of 8.27% on the amounts paid to the
IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN
48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by
an IRS audit after such amounts are actually paid to the federal government. If ETI
prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider
related to that decision should be credited back to ratepayers.
PUC Docket No. 39896 Order on Rehearing Page 16 of 44
SOAH Docket No. XXX-XX-XXXX

41. Deleted.

42. Investor-owned electric utilities may include a reasonable allowance for cash working
capital in rate base as determined by a lead-lag study conducted in accordance with the
Commission’s rules.

43. Cash working capital represents the amount of working capital, not specifically addressed
in other rate base items, that is necessary to fund the gap between the time expenditures
are made and the time corresponding revenues are received.

44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted
for known and measurable changes, and is consistent with P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii).

45. It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead-
lag study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved
for ETI in this case.

46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7,
2008) and Docket No. 37744, the Commission did not approve ETI’s storm damage
expenses since 1996 and its storm damage reserve balance.

47. ETI established a prima facie case concerning the prudence of its storm damage expenses
incurred since 1996.

48. Adjustments to the storm damage reserve balance proposed by intervenors should be
denied.

49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.

50. ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51. The amount of $9,846,037, representing the value of the average coal inventory
maintained at ETI’s coal-burning facilities, is reasonable, necessary, and should be
included in rate base.
PUC Docket No. 39896 Order on Rehearing Page 17 of 44
SOAH Docket No. XXX-XX-XXXX

52. The Spindletop gas storage facility (Spindletop facility) is used and useful in providing
reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek
generating plants.

53. The Spindletop facility is critical to the economic, reliable operation of the Sabine Station
and Lewis Creek generating plants due to their geographic location in the far western
region of the Entergy system.

54. It is reasonable and appropriate to include ETI’s share of the costs to operate the
Spindletop facility in rate base.

55. Staff recommended updating ETI’s balance amounts for short-term assets to the 13-
month period ending December 2011, which was the most recent information available.
Staff’s proposed adjustments should be incorporated into the calculation of ETI’s rate
base.

56. The following short-term asset amounts should be included in rate base: prepayments at
$8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the
Spindletop facility, represent actual costs incurred to process and close the acquisition,
not mere mark-up costs.

58. ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because
ETI incurred these costs in conjunction with the purchase of a viable asset that benefits
its retail customers.

59. In its application, ETI capitalized into plant in service accounts some of the incentive
payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60. A portion of those capitalized incentive accounts represent payments made by ETI for
incentive compensation tied to financial goals.

61. The portion of ETI’s incentive payments that are capitalized and that are financially-
based should be excluded from ETI’s rate base because the benefits of such payments
inure most immediately and predominantly to ETI’s shareholders, rather than its electric
PUC Docket No. 39896 Order on Rehearing Page 18 of 44
SOAH Docket No. XXX-XX-XXXX

customers. ETI’s capitalized incentive compensation that is financially based is
$335,752.96 and should be removed for rate base.

62. The test-year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the
reasonableness of ETI’s capital costs (including capitalized incentive compensation) for
that prior period was dealt with by the Commission in that proceeding and is not at issue
in this proceeding.

63. In this proceeding, ETI’s capitalized incentive compensation that is financially-based
should be excluded from rate base, but only for incentive costs that ETI capitalized
during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010
(the commencement of the current test-year).

Rate of Return and Cost of Capital
64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable
opportunity to earn a reasonable return on its invested capital.

65. The results of the discounted cash flow model and risk premium approach support a ROE
of 9.80 percent.

65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions
facing utilities.

66. A 9.80 percent ROE is consistent with ETI’s business and regulatory risk.

67. ETI’s proposed 6.74 percent embedded cost of debt is reasonable.

68. The appropriate capital structure for ETI is 50.08 percent long-term debt and
49.92 percent common equity.

69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is
reasonable in light of ETI’s business and regulatory risks.

70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help
ETI attract capital from investors.
PUC Docket No. 39896 Order on Rehearing Page 19 of 44
SOAH Docket No. XXX-XX-XXXX

71. ETI’s overall rate of return should be set as follows:

CAPITAL WEIGHTED AVG
COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL
LONG-TERM DEBT 50.08% 6.74% 3.38%
COMMON EQUITY 49.92% 9.80% 4.89%
TOTAL 100.00% 8.27%

Operating Expenses
72. ETI’s test-year purchased capacity expenses were $245,965,886.

73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its
purchased capacity costs. This request was based on ETI’s projections of its purchased
capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
rate-year).

74. ETI’s purchased capacity expense projections were based on estimates of rate-year
expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments
under third-party capacity contracts; and (c) payments under affiliate contracts.

75. ETI’s projection of its rate-year reserve equalization payments under Schedule MSS-1 is
based on numerous assumptions, including load growths for ETI and its affiliates, future
capacity contracts for ETI and its affiliates, and future values of the generation assets of
ETI and its affiliates.

76. There is substantial uncertainty with regard to ETI’s projection of its rate-year reserve
equalization payments under Schedule MSS-1.

77. ETI’s projection of its rate-year third-party capacity contract payments includes
numerous assumptions, one of which is that every single third-party supplier will perform
at the maximum level under the contract, even though that assumption is inconsistent
with ETI’s historical experience.

78. There is substantial uncertainty with regard to ETI’s projection of its rate-year third-party
capacity-contract payments.

79. ETI’s estimates of its rate-year purchases under affiliate contracts are based on a
mathematical formula set out in Schedule MSS-4.
PUC Docket No. 39896 Order on Rehearing Page 20 of 44
SOAH Docket No. XXX-XX-XXXX

80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments
will be based on ratios and costs that cannot be determined until the month that the
payments are to be made.

81. Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI
WBL Contract) that was not signed until April 11, 2012.

82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the
rate-year than it purchased in the test-year.

84. ETI experienced substantial load growth in the two years before the test-year, and it
continues to project similar load growth in the future.

85. ETI did not meet its burden of proof to demonstrate that a known and measurable
adjustment of $30,809,355 should be made to its test-year purchased capacity expenses.

86. ETI’s purchased capacity expense in this case should be based on the test-year level of
$245,965,886.

87. ETI incurred $1,753,797 of transmission equalization expense during the test-year.

88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization
expense. This request was based on ETI’s projections of its transmission equalization
expenses during the rate-year.

89. The transmission equalization expense that ETI will pay in the rate-year will depend on
future costs and loads for each of the Entergy operating companies.

90. ETI’s projection of its rate-year transmission equalization expenses is uncertain and
speculative because it depends on a number of variables, including future transmission
investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
expenses, and loads of each of the Entergy operating companies.

91. ETI seeks increased transmission equalization expenses for transmission projects that are
not currently used and useful in providing electric service. ETI’s post-test-year
adjustment is based on the assumption that certain planned transmission projects will go
PUC Docket No. 39896 Order on Rehearing Page 21 of 44
SOAH Docket No. XXX-XX-XXXX

into service after the test-year. At the close of the hearing, none of the planned
transmission projects had been fully completed and some were still in the planning phase.

92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
expenses related to projects that are not yet in-service.

93. ETI’s request for a post-test-year adjustment of $8,942,785 for rate-year transmission
equalization expenses should be denied because those expenses are not known and
measurable. ETI’s post-test-year adjustment does not with reasonable certainty reflect
what ETI’s transmission equalization expense will be when rates are in effect.

94. ETI’s transmission equalization expense in this case should be based on the test-year
level of $1,753,797.

95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the
accumulation of recognized allocations of original cost, representing the recovery of
initial investment over the estimated useful life of the asset.

96. Except in the case of the amortization of the general plant deficiency, the use of the
remaining life depreciation method to recover differences between theoretical and actual
depreciation reserves is the most appropriate method and should be continued.

97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line
basis over the remaining, expected useful life of the item or facility.

98. Except as described below, the service lives and net salvage rates proposed by the
company are reasonable, and these service lives and net salvage rates should be used in
calculating depreciation rates for the company’s production, transmission, distribution,
and general plant assets.

99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing
production plant depreciation rates.

100. The retirement (actuarial) rate method, rather than the interim retirement method, should
be used in the development of production plant depreciation rates.

101. Production plant net salvage is reasonably based on the negative five percent net salvage
in existing rates.
PUC Docket No. 39896 Order on Rehearing Page 22 of 44
SOAH Docket No. XXX-XX-XXXX

102. The net salvage rate of negative 10 percent for ETI’s transmission structures and
improvements (FERC Account 352) is the most reasonable of those proposed and should
be adopted.

103. The net salvage rate of negative 20 percent for ETI’s transmission station equipment
(FERC Account 353) is the most reasonable of those proposed and should be adopted.

104. The net salvage rate of negative five percent for ETI’s transmission towers and fixtures
(FERC Account 354) is the most reasonable of those proposed and should be adopted.

105. The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures
(FERC Account 355) is the most reasonable of those proposed and should be adopted.

106. The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors
and devices (FERC Account 356) is the most reasonable of those proposed and should be
adopted.

107. A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures
and improvements (FERC Account 361) are the most reasonable of those proposed and
should be approved.

108. A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles,
towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and
should be approved.

109. A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead
conductors and devices (FERC Account 365) are the most reasonable of those proposed
and should be approved.

110. A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution
underground conductors and devices (FERC Account 367) are the most reasonable of
those proposed and should be approved.

111. A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line
transformers (FERC Account 368) are the most reasonable of those proposed and should
be approved.
PUC Docket No. 39896 Order on Rehearing Page 23 of 44
SOAH Docket No. XXX-XX-XXXX

112. A service life of 26 years and a dispersion curve of L4 for ETI’s distribution overhead
service (FERC Account 369.1) are the most reasonable of those proposed and should be
approved.

113. The net salvage rate of negative five percent for ETI’s distribution structures and
improvements (FERC Account 361) is the most reasonable of those proposed and should
be adopted.

114. The net salvage rate of negative 10 percent for ETI’s distribution station equipment
(FERC Account 362) is the most reasonable of those proposed and should be adopted.

115. The net salvage rate of negative seven percent for ETI’s distribution overhead conductors
and devices (FERC Account 365) is the most reasonable of those proposed and should be
adopted.

116. The net salvage rate of positive five percent for ETI’s distribution line transformers
(FERC Account 368) is the most reasonable of those proposed and should be adopted.

117. The net salvage rate of negative 10 percent for ETI’s distribution overhead services
(FERC Account 369.1) is the most reasonable of those proposed and should be adopted.

118. The net salvage rate of negative 10 percent for ETI’s distribution underground services
(FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119. A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and
improvements (FERC Account 390) are the most reasonable of those proposed and
should be approved.

120. The net salvage rate of negative 10 percent for ETI’s general structures and
improvements (FERC Account 390) is the most reasonable of those proposed and should
be adopted.

121. It is reasonable to convert the $21.3 million deficit that has developed over time in the
reserve for general plant accounts to General Plant Amortization.

122. A ten-year amortization of the deficit in the reserve for general plant accounts is
reasonable and should be adopted.
PUC Docket No. 39896 Order on Rehearing Page 24 of 44
SOAH Docket No. XXX-XX-XXXX

123. FERC pronouncement AR-15 requires amortization over the same life as recommended
based on standard life analysis. A standard life analysis determined that a five-year life
was appropriate for general plant computer equipment (FERC Account 391.2).
Therefore, a five year amortization for this account is reasonable and should be adopted.

124. ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee
headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage
increases set to go into effect after the end of the test-year.

125. The proposed payroll adjustments are reasonable but should be updated to reflect the
most recent available information on headcount levels as proposed by Commission Staff.
In addition to adjusting payroll expense levels, the more recent headcount numbers
should be used to adjust the level of payroll tax expense, benefits expense, and savings
plan expense.

126. Staff has appropriately updated headcount levels to the most recent available data but
errors made by Staff should be corrected. The corrections related to: (a) a double
counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost
percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of
savings plan costs when such costs were already included in the benefits percentage
adjustments; and (d) corrections for full-time equivalents calculations. Staff’s ETI
headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll
reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll
increase by $37,531.

127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128. The compensation packages that ETI offers its employees include a base payroll amount,
annual incentive programs, and long-term incentive programs. The majority of the
compensation is for operational measures, but some is for financial measures.

129. Incentive compensation that is based on financial measures is of more immediate and
predominant benefit to shareholders, whereas incentive compensation based on
operational measures is of more immediate and predominant benefit to ratepayers.
PUC Docket No. 39896 Order on Rehearing Page 25 of 44
SOAH Docket No. XXX-XX-XXXX

130. Incentives to achieve operational measures are necessary and reasonable to provide utility
services but those to achieve financial measures are not.

131. The $5,376,975 that was paid for long term incentive programs was tied to financial
measures and, therefore, should not be included in ETI’s cost of service.

132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
was tied to financial measures and, therefore, should be disallowed.

133. In total, the amount of incentive compensation that should be disallowed is $6,196,037
because it was related to financial measures that are not reasonable and necessary for the
provision of electric service. An additional reduction should be made to account for the
FICA taxes ETI would have paid on the disallowed financially based incentive
compensation.

134. The amount of incentive compensation that should be included in the cost of service is
$7,991,707.

135. To attract and retain highly qualified employees, the Entergy companies provide a total
package of compensation and benefits that is equivalent in scope and cost with what other
comparable companies within the utility business and other industries provide for their
employees.

136. When using a benchmark analysis to compare companies’ levels of compensation, it is
reasonable to view the market level of compensation as a range rather than a precise,
single point.

137. ETI’s base pay levels are at market.

138. ETI’s benefits plan levels are within a reasonable range of market levels.

139. ETI’s level of compensation and benefits expense is reasonable and necessary.

140. ETI provides non-qualified supplemental executive retirement plans for highly
compensated individuals such as key managerial employees and executives that, because
of limitations imposed under the Internal Revenue Code, would otherwise not receive
retirement benefits on their annual compensation over $245,000 per year.
PUC Docket No. 39896 Order on Rehearing Page 26 of 44
SOAH Docket No. XXX-XX-XXXX

141. ETI’s non-qualified supplemental executive retirement plans are discretionary costs
designed to attract, retain, and reward highly compensated employees whose interests are
more closely aligned with those of the shareholders than the customers.

142. ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not
reasonable or necessary to provide utility service to the public, not in the public interest,
and should not be included in ETI’s cost of service.

143. For the employee market in which ETI operates, most peer companies offer moving
assistance. Such assistance is expected by employees, and ETI would be placed at a
competitive disadvantage if it did not offer relocation expenses.

144. ETI’s relocation expenses were reasonable and necessary.

145. The company’s requested operating expenses should be reduced by $40,620 to reflect the
removal of certain executive prerequisites proposed by Staff.

146. Staff properly adjusted the company’s requested interest expense of $68,985 by removing
$25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
2012), leaving a recommended interest expense of $43,047.

147. During the test-year, ETI’s property tax expense equaled $23,708,829.

148. ETI requested an upward pro forma adjustment of $2,592,420, to account for the property
tax expenses ETI estimates it will pay in the rate-year.

149. ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon
the prediction that ETI’s property tax rate will be increased in 2012, a change that is
speculative is not known and measurable.

150. Staff’s recommendation to increase ETI’s test-year property tax expenses by $1,214,688
is based on the historical effective tax rate applied to the known test-year-end plant in
service value, consistent with Commission precedent, and based upon known and
measurable changes.

151. ETI’s test-year property tax burden should be adjusted upward by $1,222,106 for a total
expense of $24,921,022.
PUC Docket No. 39896 Order on Rehearing Page 27 of 44
SOAH Docket No. XXX-XX-XXXX

152. Staff recommended reducing ETI’s advertising, dues, and contributions expenses by
$12,800. The recommendation, which no party contested, should be adopted.

153. The final cost of service should reflect changes to cost of service that affect other
components of the revenue requirement such as the calculation of the Texas state gross
receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
Expenses.

154. The company’s requested Federal income tax expense is reasonable and necessary.

155. ETI’s request for $2,019,000 to be included in its cost of service to account for the
company’s annual decommissioning expenses associated with River Bend is not
reasonable because it is not based upon “the most current information reasonably
available regarding the cost of decommissioning” as required by P.U.C. SUBST.
R. 25.231(b)(1)(F)(i).

156. Based on the most current information reasonably available, the appropriate level of
decommissioning costs to be included in ETI’s cost of service is $1,126,000.

157. ETI’s appropriate total annual self-insurance storm damage reserve expense is
$8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual
expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the
reserve from its current deficit.

158. ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.

159. ETI should continue recording its annual storm damage reserve accrual until modified by
a Commission order.

160. The operating costs of the Spindletop facility are reasonable and necessary.

161. The operating costs of the Spindletop facility paid to PB Energy Storage Services are
eligible fuel expenses.

Affiliate Transactions
162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of
these O&M expenses—$69,098,041—were charged to ETI by ESI. The remaining
affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana,
PUC Docket No. 39896 Order on Rehearing Page 28 of 44
SOAH Docket No. XXX-XX-XXXX

L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.;
Entergy Operations, Inc.; and non-regulated affiliates.

163. ESI follows a number of processes to ensure that affiliate charges are reasonable and
necessary and that ETI and its affiliates are charged the same rate for similar services.
These processes include: (a) the use of service agreements to define the level of service
required and the cost of those services; (b) direct billing of affiliate expenses where
possible; (c) reasonable allocation methodologies for costs that cannot be directly billed;
(d) budgeting processes and controls to provide budgeted costs that are reasonable and
necessary to ensure appropriate levels of service to its customers; and (e) oversight
controls by ETI’s Affiliate Accounting and Allocations Department.

164. Affiliates charged expenses to ETI through 1292 project codes during the test-year.

164A. The $2,086,145 in affiliate transactions related to sales and marketing expenses should be
reallocated using direct assignment. The following amounts should be allocated to all
retail classes in proportion to number of customers: (1) $46,490 for Project
E10PCR56224 – Sales and Marketing – EGSI Texas; (2) $17,013 for Project
F3PCD10049 – Regulated Retail Systems O&M; and (3) $30,167 for Project
F3PPMMALI2 – Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial
Power Service.

165. ETI agreed to remove the following affiliate transactions from its application:
(1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
(2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288;
and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated
with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non
Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the
provision of electric utility service and are not in the public interest.

167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts
Settlement) are not normally-recurring costs and should not be recoverable.
PUC Docket No. 39896 Order on Rehearing Page 29 of 44
SOAH Docket No. XXX-XX-XXXX

168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are
related to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and
Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy
Management for ESI) are research and development costs related to energy efficiency
programs. As such, they should be recovered through the energy efficiency cost recovery
factor rather than base rates.

170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate
transactions were reasonable and necessary, were allowable, were charged to ETI at a
price no higher than was charged by the supplying affiliate to other affiliates, and the rate
charged is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation
171. ETI has one full or partial requirements wholesale customer – East Texas Electric
Cooperative, Inc.

172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set
the wholesale load results in a retail production demand allocation factor of
95.3838 percent.

173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used
by the FERC to allocate between jurisdictions.

174. Using 12CP methodology to allocate production costs between the wholesale and retail
jurisdictions is the best method to reflect cost responsibility and is appropriate based on
ETI’s reliance on capacity purchases.

Class Cost Allocation and Rate Design
175. There is no express statutory authorization for ETI’s proposed Renewable Energy Credits
rider (REC rider).

176. REC rider constitutes improper piecemeal ratemaking and should be rejected.
PUC Docket No. 39896 Order on Rehearing Page 30 of 44
SOAH Docket No. XXX-XX-XXXX

177. ETI’s test-year expense for renewable energy credits, $623,303, is reasonable and
necessary and should be included in base rates.

178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
public rights-of-way to locate its facilities within municipal limits.

179. ETI is an integrated utility system. ETI’s facilities located within municipal limits
benefit all customers, whether the customers are located inside or outside of the
municipal limits.

180. Because all customers benefit from ETI’s rental of municipal right-of-way, municipal
franchise fees should be charged to all customers in ETI’s service area, regardless of
geographic location.

181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA)
§ 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt
hour (kWh) sales, without an adjustment for the MFF rate in the municipality in which a
given kWh sale occurred.

182. The same reasons for allocating and collecting MFF as set out in Finding of Fact
Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts
Taxes. The company’s proposed allocation of these costs to all retail customer classes
based on customer class revenues relative to total revenues is appropriate.

182A. ETI’s proposed gross plant-based allocator is an appropriate method for allocating the
Texas franchise tax.

183. The Average and Excess (A&E) 4CP method for allocating capacity-related production
costs, including reserve equalization payments, to the retail classes is a standard
methodology and the most reasonable methodology.

184. The A&E 4CP method for allocating transmission costs to the retail classes is standard
and the most reasonable methodology.

185. ETI appropriately followed the rate class revenue requirements from its cost of service
study to allocate costs among customer classes. ETI’s revenue allocation properly sets
rates at each class’s cost of service.
PUC Docket No. 39896 Order on Rehearing Page 31 of 44
SOAH Docket No. XXX-XX-XXXX

186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
replacement of a functioning light with a lower-wattage bulb.

187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a
study regarding the feasibility of instituting LED-based rates and, if the study shows that
such rates are feasible, ETI should file proposals for LED-based lighting and traffic
signal rates in its next rate case.

188. An agreement was reached by the parties and approved by the Commission in Docket
No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
ratchet for existing customers in the Large Industrial Power Service (LIPS), Large
Industrial Power Service-Time of Day, General Service, General Service-Time of Day,
Large General Service, and Large General Service-Time of Day rate schedules.

189. ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet
from these rate schedules consistent with the parties’ agreement in Docket No. 37744.

190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI
proposed, is not reasonable.

191. ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
agreement that was adopted by the Commission as just and reasonable in Docket
No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact
No. 192-194.

192. ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read:
DETERMINATION OF BILLING LOAD

The kW of Billing Load will be the greatest of the following:

(A) The Customer’s maximum measured 30-minute
demand during any 30-minute interval of the current billing
month, subject to §§ III, IV and V above; or

(B) 75% of Contract Power as defined in § VII; or

(C) 2,500 kW.
PUC Docket No. 39896 Order on Rehearing Page 32 of 44
SOAH Docket No. XXX-XX-XXXX

193. ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read:
DETERMINATION OF CONTRACT POWER

Unless Company gives customer written notice to the contrary,
Contract Power will be defined as below:

Contract Power - the highest load established under § VI(A) above
during the 12 months ending with the current month. For the
initial 12 months of Customer’s service under the currently
effective contract, the Contract Power shall be the kW specified in
the currently effective contract unless exceeded in any month
during the initial 12-month period.

194. The Large General Service, Large General Service-Time of Day, General Service, and
General Service-Time of Day schedules should be similarly revised to eliminate ETI’s
life-of-contract demand ratchet.

195. In its proposed rate design for the LIPS class, the company took a conservative approach
and increased the current rates by an equal percentage. This minimized customer bill
impacts while maintaining cost causation principles on a rate class basis.

196. It is a reasonable move towards cost of service to add a customer charge of $630 to the
LIPS rate schedule with subsequent increases to be considered in subsequent base rate
cases.

197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy
charges and increase the demand charges as proposed by Staff witness
William B. Abbott.

198. DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent
Pumping Service” (SIPS) for load schedulable at least four weeks in advance, that occurs
in the off-season (October through May), that can be cancelled at any time, and for load
not lasting more than 80 hours in a year. For customers whose loads match these SIPS
characteristics (for example, DOE’s Strategic Petroleum Reserve), the 12-month demand
ratchet provision of Schedule LIPS does not apply to demands set under the provisions of
the SIPS rider. The monthly demand set under the SIPS provisions would be applicable
for billing purposes only in the month in which it occurred. In short, if a customer set a
PUC Docket No. 39896 Order on Rehearing Page 33 of 44
SOAH Docket No. XXX-XX-XXXX

12-month ratchet demand in that month, it would be forgiven and not applicable in the
succeeding 12 months.

199. DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be
adopted. It more closely addresses specific customer characteristics and provides for
cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.

200. Standby Maintenance Service (SMS) is available to customers who have their own
generation equipment and who contract for this service from ETI.

201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance
power to qualifying facilities should recognize system wide costing principles and should
not be discriminatory.

202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
charge equivalent to that of the LIPS rate schedule only for SMS customers not
purchasing supplementary power under another applicable rate; and (b) revising the tariff
as follows:
Distribution Transmission
Charge
(less than 69KV) (69KV and greater)
Billing Load Charge ($/kW):
Standby $2.46 $0.79
Maintenance $2.27 $0.60
Non-Fuel Energy Charge (¢/kWh)
On-Peak 4.245¢ 4.074¢
Off-Peak 0.575¢ 0.552¢

203. ETI’s Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental
charge paid by a customer when ETI installs facilities for that customer that would not
normally be supplied, such as line extensions, transformers, or dual feeds.

204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
Option B, which applies when a customer elects to amortize the directly-assigned
facilities over a shorter term ranging from one to ten years, has a variable monthly
charge. There is also a term charge that applies after the facility has been fully
depreciated.
PUC Docket No. 39896 Order on Rehearing Page 34 of 44
SOAH Docket No. XXX-XX-XXXX

205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.11 percent
per month of the installed cost of all facilities included in the agreement for additional
facilities.

206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and
the Post Term Recovery Charge as follows:

Selected Recovery Term Recovery Term Charge Post Recovery Term Charge
1 9.52% 0.28%
2 5.14% 0.28%
3 3.68% 0.28%
4 2.95% 0.28%
5 2.52% 0.28%
6 2.23% 0.28%
7 2.03% 0.28%
8 1.88% 0.28%
9 1.76% 0.28%
10 1.67% 0.28%

207. The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the
costs of running, operating, and maintaining the directly-assigned facilities.

208. It is reasonable to modify the Large General Service rate schedule by increasing the
demand charge from $8.56 to $11.43; decreasing the energy charge from $.00854 to
$.00458; and reducing the customer charge to $260.00.

209. Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS
customers towards their cost of service by recommending a decrease in the customer
charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is
reasonable and should be adopted.

210. ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer
charge and a consumption-based energy charge. In the months November through April
(winter), the rates are structured as a declining block, in which the price of each unit is
reduced after a defined level of usage. ETI’s proposed increase in the RS customer
charge to $6 per month is reasonable and should be adopted. For the RS summer rate and
PUC Docket No. 39896 Order on Rehearing Page 35 of 44
SOAH Docket No. XXX-XX-XXXX

the first winter block rate, the 6.296¢ per kWh energy charge resulting from the increased
revenue requirement for residential customers is reasonable and should be adopted.

211. ETI’s Schedule RS declining block rate structure is contrary to energy-efficiency efforts
and the Legislature’s goal of reducing both energy demand and energy consumption in
Texas, as stated in PURA § 39.905.

212. Schedule RS winter block rates should be modified consistent with the goal set out in
PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block
differential proposed by ETI and subsequent reductions should be reviewed for
consideration at the occurrence of each rate case filing.

213. Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation
214. ETI incurred $616,248,686 in natural-gas expenses during the reconciliation period,
which is from July 2009 through June 2011.

215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
negotiated operational balancing agreements with various pipeline companies.

216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet
its natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217. ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide
reliable electric service to retail customers.

218. ETI incurred $90,821,317 in coal expenses during the reconciliation period.

219. ETI prudently managed its coal and coal-related contracts during the reconciliation
period.

220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal
burned at the Big Cajun II, Unit 3 facility.

221. ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable
electric service to retail customers.
PUC Docket No. 39896 Order on Rehearing Page 36 of 44
SOAH Docket No. XXX-XX-XXXX

222. ETI incurred $990,041,434 in purchased-energy expenses during the reconciliation
period.

223. The Entergy System’s planning and procurement processes for purchased-power
produced a reasonable mix of purchased resources at a reasonable price.

224. During the reconciliation period, ETI took advantage of opportunities in the fuel and
purchased-power markets to reduce costs and to mitigate against price volatility.

225. ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to
provide reliable electric service to retail customers.

226. ETI provided sufficient contemporaneous documentation to support the reasonableness of
its purchased-power planning and procurement processes and its actual power purchases
during the reconciliation period.

227. The Entergy system sold power off system when the revenues were expected to be more
than the incremental cost of supplying generation for the sale, subject to maintaining
adequate reserves.

228. The System Agreement is the tariff approved by the FERC that provides the basis for the
operation and planning of the Entergy system, including the six operating companies.
The System Agreement governs the wholesale-power transactions among the operating
companies by providing for joint operation and establishing the bases for equalization
among the operating companies, including the costs associated with the construction,
ownership, and operation of the Entergy system facilities.

229. Under the terms of the Entergy System Agreement, ETI was allocated its share of
revenues and expenses from off-system sales.

230. During the reconciliation period, ETI recorded off-system sales revenue in the amount of
$376,671,969 in FERC Account 447 and credited 100 percent of off-system sales
revenues and margins from off-system sales to eligible fuel expenses.

231. ETI properly recorded revenues from off-system sales and credited those revenues to
eligible fuel costs.
PUC Docket No. 39896 Order on Rehearing Page 37 of 44
SOAH Docket No. XXX-XX-XXXX

232. The Entergy system consists of six operating companies, including ETI, which are
planned and operated as a single, integrated electric system under the terms of the System
Agreement.

233. Service schedule MSS-1 of the System Agreement determines how the capability and
ownership costs of reserves for the Entergy system are equalized among the operating
companies. These inter-system “reserve equalization” payments are the result of a
formula rate related to the Entergy system’s reserve capability that is applied on a
monthly basis.

234. Reserve capability under service schedule MSS-1 is capability in excess of the Entergy
system’s actual or planned load built or acquired to ensure the reliable, efficient operation
of the electric system.

235. By approving service schedule MSS-1, the FERC has approved the method by which the
operating companies share the cost of maintaining sufficient reserves to provide
reliability for the Entergy system as a whole.

236. Service schedule MSS-3 of the System Agreement determines the pricing and exchange
of energy among the operating companies. By approving service schedule MSS-3, the
FERC has approved the method by which the operating companies are reimbursed for
energy sold to the exchange energy pool and how that energy is purchased.

237. Service schedule MSS-4 of the System Agreement sets forth the method for determining
the payment for unit power purchases between operating companies. By approving
service schedule MSS-4, the FERC has approved the methodology for pricing
inter-operating company unit power purchases.

238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
horizons. Once the planning process has identified the most economical resources that
can be used to reliably meet the aggregate Entergy system demand, the next step is to
procure the fuel necessary to operate the generating units as planned and acquire
wholesale power from the market.
PUC Docket No. 39896 Order on Rehearing Page 38 of 44
SOAH Docket No. XXX-XX-XXXX

239. Once resources are procured to meet forecasted load, the Entergy system is operated
during the current day using all the resources available to meet the total Entergy system
demand.

240. After current-day operation, the System Agreement prescribes an accounting protocol to
bill the costs of operating the system to the individual operating companies. This
protocol is implemented via the intra-system bill to each operating company on a
monthly basis.

241. ETI purchased power from affiliated operating companies per the terms of service
schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3
to affiliated operating companies are reasonable and necessary, and the FERC has
approved the pricing formula and the obligation to purchase the energy. ETI pays the
same price per megawatt hour for energy under service schedule MSS-3 as does any
other operating company purchasing energy under service schedule MSS-3 during the
same hour.

242. The Spindletop facility is used primarily to ensure gas-supply reliability and guard
against gas-supply curtailments that can occur as a result of extreme weather or other
unusual events.

243. The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can
back down gas-fired generation to take advantage of more economical wholesale power,
or use gas from storage to supplement gas-fired generation when load increases during
the day and thereby avoid more expensive intra-day gas purchases.

244. ETI’s customers received benefits from the Spindletop facility during the reconciliation
period through reliable gas supplies and ETI’s monthly and daily storage activity.

245. ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas
supply for the benefit of customers.

246. ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied
for the purpose of allocating its costs to its wholesale customers and retail customer
classes.
PUC Docket No. 39896 Order on Rehearing Page 39 of 44
SOAH Docket No. XXX-XX-XXXX

246A. ETI’s 2010 line-loss factors should be used to reconcile ETI’s fuel costs. Therefore,
ETI’s fuel reconciliation over-recovery should be reduced by $3,981,271.

247. ETI’s proposed loss factors are reasonable and shall be implemented on a prospective
basis as a result of this final order.

248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the
FERC’s reallocation of rough production equalization costs in FERC Order No. 720-A,
and to treat such costs as eligible fuel expense.

249. Special circumstances exist and it is appropriate for ETI to recover the rough production
cost equalization costs reallocated to ETI as a result of the FERC’s decision in Order
No. 720-A.

Other Issues
250. A deferred accounting of ETI’s Midwest Independent Transmission System Operator
(MISO) transition expenses is not necessary to carry out any requirement of PURA.

251. ETI should include $1.6 million in base rates for MISO transition expense.

252. Deleted.

253. Transmission Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

254. Distribution Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

255. The appropriate amount for ETI’s purchased-power capacity expense to be included in
base rates is $245,965,886.

256. The amount of ETI’s purchased-power capacity expense includes third-party contracts,
legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
amounts for all contracts should be included in the baseline for a purchased-capacity rider
that may be approved in Project No. 39246 is an issue that should be decided in that
project.
PUC Docket No. 39896 Order on Rehearing Page 40 of 44
SOAH Docket No. XXX-XX-XXXX

III. Conclusions of Law
1. ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric
utility” as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.101–.111, and 36.203.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
TEX. GOV’T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act, Tex. Gov’t Code Ann. Chapter 2001.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6. Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded
jurisdiction to the Commission has jurisdiction over the company’s application, which
seeks to change rates for distribution services within each municipality.

7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
municipality’s rate proceeding.

8. ETI has the burden of proving that the rate change it is requesting is just and reasonable
pursuant to PURA § 36.006.

9. In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding
permit ETI a reasonable opportunity to earn a reasonable return on its invested capital
used and useful in providing service to the public in excess of its reasonable and
necessary operating expenses.

10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on
original cost, less depreciation, of property used and useful to ETI in providing service.

11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).
PUC Docket No. 39896 Order on Rehearing Page 41 of 44
SOAH Docket No. XXX-XX-XXXX

12. Including the cash working capital approved in this proceeding in ETI’s rate base is
consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
allowance for cash working capital to be included in rate base.

13. The ROE and overall rate of return authorized in this proceeding are consistent with the
requirements of PURA §§ 36.051 and 36.052.

14. The affiliate expenses approved in this proceeding and included in ETI’s rates meet the
affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.—
Austin 1984, no writ).

15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in
this case is based on the most current information reasonably available regarding the cost
of decommissioning, the balance of funds in the decommissioning trust, anticipated
escalation rates, the anticipated return on the funds in the decommissioning trust, and
other relevant factors.

17. ETI has demonstrated that its eligible fuel expenses during the reconciliation period were
reasonable and necessary expenses incurred to provide reliable electric service to retail
customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted
for the amount of fuel-related revenues collected pursuant to the fuel factor during the
reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants
during the reconciliation period.

19. The reconciliation period level operating and maintenance expenses for the Spindletop
facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision
in a reconciliation proceeding.
PUC Docket No. 39896 Order on Rehearing Page 42 of 44
SOAH Docket No. XXX-XX-XXXX

19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to
include any issue related to the reasonableness of a utility’s fuel expenses and whether
the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use
the new line-loss study to calculate Entergy’s fuel reconciliation and over-recovery.

20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to
recover rough production equalization payments reallocated to ETI by the FERC.

21. ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with
PURA § 36.003.

IV. Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission issues
the following orders:

1. The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent
with this Order.

2. ETI’s application is granted to the extent consistent with this Order.

3. ETI shall file in Tariff Control No. 40742 Compliance Tariff Pursuant to Final Order in
Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates,
Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with
this Order within 20 days of the date of this Order. No later than ten days after the date
of the tariff filings, Staff shall file its comments recommending approval, modification,
or rejection of the individual sheets of the tariff proposal. Responses to the Staff’s
recommendation shall be filed no later than 15 days after the filing of the tariff. The
Commission shall by letter approve, modify, or reject each tariff sheet, effective the date
of the letter.

4. The tariff sheets shall be deemed approved and shall become effective on the expiration
of 20 days from the date of filing, in the absence of written notification of modification or
rejection by the Commission. If any sheets are modified or rejected, ETI shall file
proposed revisions of those sheets in accordance with the Commission’s letter within ten
PUC Docket No. 39896 Order on Rehearing Page 43 of 44
SOAH Docket No. XXX-XX-XXXX

days of the date of that letter, and the review procedure set out above shall apply to the
revised sheets.

5. Copies of all tariff-related filings shall be served on all parties of record.

6. ETI shall prepare and file as part of its next base rate case a study regarding the
feasibility of instituting LED-based rates and, if the study shows that such rates are
feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that
case. If ETI has LED lighting customers taking service, the study shall include detailed
information regarding differences in the cost of serving LED and non-LED lighting
customers. ETI shall provide the results of this study to Cities and interested parties as
soon as practicable, but no later than the filing of its next rate case.

7. All other motions, requests for entry of specific findings of fact and conclusions of law,
and any other requests for general or specific relief, if not expressly granted, are denied.
PUC Docket No. 39896 Order on Rehearing Page 44 of 44
SOAH Docket No. XXX-XX-XXXX

SIGNED AT AUSTIN, TEXAS the ______ day of October 2012.

PUBLIC UTILITY COMMISSION OF TEXAS

______________________________________________
DONNA L. NELSON, CHAIRMAN

______________________________________________
ROLANDO PABLOS, COMMISSIONER

I respectfully dissent regarding the utility- and executive-management-class affiliate
transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect
costs of the management of Entergy’s ultimate parent should not be borne by Texas ratepayers.
Therefore, I would disallow the following: $173,867 for Project No. F3PCCPM001 (Corporate
Performance Management); $372,919 for Project No. F3PCC31255 (Operations-Office of the
CEO); and $74,485 for Project No. F3PPCOO001 (Chief Operating Officer). I join the
Commission in all other respects for this Order.

______________________________________________
KENNETH W. ANDERSON, JR., COMMISSIONER

q:\cadm\orders\final\39000\39896o on reh.docx

37
Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing (Oct. 16, 1997).
 APPENDIX C

District Court's Final Judgment
 DC BK1429S PG132

Filed In 'fh o·
of Travis ~ •strict Cour:·
ounty, Texas
EM OCT 1~ tUlli
CAUSE NO. D-l-GN-13-000121 At (/ .J.q. A
AmaliaRodriguez-Mendoza, c;;~·

ENTERGY TEXAS, INC., § IN THE DISTRICT COURT OF
Plaintiff §
§
v. § TRAVIS COUNTY, TEXAS
§
PUBLIC UTILITY COMMISSION, §
Defendant § 353RD JUDICIAL DISTRICT

ORDER ON ADMINISTRATIVE APPEAL

On July 22, 2014, the Court heard Plaintiffs appeal from Defendant's Order in PUC

Docket No. 39896, SOAH Docket No. XXX-XX-XXXX. The administrative record was admitted

into evidence, and the Court heard oral argument. Entergy, the Cities, and OPUC each asserted

points of error challenging the Commission's order. Having considered the pleadings, the

evidence and the arguments of counsel, the Court makes the following rulings:

l . Entergy's Point of Error No. 1 addressing the use of a current line loss study rather
that a prior-approved line loss study in allocating line loss costs among classes of
customers establishes that the Commission erred in applying the current study in
violation of Commission rules found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a)
and (c)(2)(B). Accordingly, the Court FINDS that the PUC's ruling was arbitrary and
capricious and constitutes an error of law. The Court REVERSES such ruling and
REMANDS this matter to the Commission for further proceedings consistent with
this Court's Order.
2. All other points of error are DENIED, and the Commission' s Order is in all other
respects AFFIRMED.

J
 APPENDIX D

Commission's Final Order in Docket No. 37744
 PUC DOCKET NO. 37744
SOAH DOCKET NO. XXX-XX-XXXX

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION
INC. FOR AUTHORITY TO CHANGE §
RATES AND RECONCILE FUEL § OF TEXAS
COSTS §

ORDER

This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change
rates and reconcile fuel costs. ETI, Commission Staff, the Office of Public Utility Counsel
(OPUC), the Steering Committee of Cities Served by ETI (Cities),1 Texas Industrial Energy
Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and
Sam’s East, Inc. (collectively Wal-Mart), through their duly authorized representatives entered
into and filed a stipulation and settlement agreement that resolves all of the issues in this
proceeding except the issues related to ETI’s proposal for competitive generation service.
Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education
(State Agencies) did not join but do not oppose the stipulation.

The Commission severed the competitive generation service issues into Docket
No. 389512 in Order No. 14.

The Commission adopts the following findings of fact and conclusions of law:

1
Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland,
Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West
Orange.
2
Application of Entergy Texas, Inc. for Approval of Competitive Generation Service Tariff (Issues Severed
From Docket No. 37744), Docket No. 38951.
PUC Docket No. 37744 Order Page 2 of 15
SOAH Docket No. XXX-XX-XXXX

I. Findings of Fact

Procedural History
1. On December 30, 2009, ETI filed an application requesting approval of (1) base rate
tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million,
which includes a total non-fuel retail revenue requirement of $838.3 million (base rate
revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of
proposed tariff schedules presented in the Electric Utility Rate Filing Package for
Generating Utilities (RFP) accompanying ETI’s application; (3) a request for final
reconciliation of ETI’s fuel and purchased power costs for the reconciliation period from
April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP
Schedule V accompanying ETI’s application.

2. The 12-month test year employed in ETI’s filing ended on June 30, 2009.

3. ETI provided notice by publication for four consecutive weeks before the effective date
of the proposed rate change in newspapers having general circulation in each county of
ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of
its customers. Additionally, ETI timely served notice of its statement of intent to change
rates on all municipalities retaining original jurisdiction over its rates and services. ETI
also published one-time supplemental notice by publication in newspapers and by bill
insert.

4. The following parties were granted intervenor status in this docket: OPUC, Cities,
Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a
participant in this docket.

5. On January 4, 2010, the Commission referred this case to the State Office of
Administrative Hearings (SOAH) for processing.

6. On February 19, 2010, the ALJs issued Order No. 3, which approved an agreement
between ETI, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to
(1) establish an interim rate increase of $17.5 million annually above ETI’s then-existing
base rates commencing with service rendered on and after May 1, 2010 subject to
true-up and refund for service rendered prior to September 13, 2010 to the extent final
PUC Docket No. 37744 Order Page 3 of 15
SOAH Docket No. XXX-XX-XXXX

overall rates established by the Commission amounted to less than a $17.5 million rate
increase; (2) extend the jurisdictional deadline by which the Commission must issue a
final order on the Company’s rate request from July 5, 2010 to November 1, 2010;
(3) establish a September 13, 2010 effective date for rates such that, notwithstanding the
extension of the jurisdictional deadline, the final overall rates established by the
Commission would relate back to service rendered on and after September 13, 2010;
(4) require ETI to publish supplemental notice, once in newspapers and by a bill insert,
setting forth the effect of its proposed rate change in terms of the percentage increase in
non-fuel revenues; and (5) establish a procedural schedule and discovery deadlines for
this proceeding. Order No. 3 also granted Mr. Kurt Boehm’s motion for admission
pro hac vice as counsel for Kroger and ETI’s February 3 and February 11, 2010 petitions
for review of cities’ ordinances and motions to consolidate with respect to the rate
decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond,
Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta,
Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty,
Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village,
Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission,
Trinity, and Woodville.

7. On June 14, 2010, the ALJs issued Order No. 6 granting Staff’s June 1, 2010 motion and
severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the ALJs
also granted ETI’s March 12, April 29, and May 17 petitions for review and motions to
consolidate with respect to the rate decisions adopted by the Cities of Anahuac,
Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery,
Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard,
Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and
Woodloch.

3
Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket
No. 38346.
PUC Docket No. 37744 Order Page 4 of 15
SOAH Docket No. XXX-XX-XXXX

8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in
order to facilitate settlement negotiations. The hearing was again convened on
July 15, 2010, at which time the signatories announced their intent to continue settlement
discussions to resolve all issues related to the Company’s application with the exception
of those related to ETI’s proposal for competitive generation service (CGS) and
associated riders.

9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding
issues regarding the Company’s application with the exception of those related to ETI’s
CGS proposal. Under the stipulation, ETI will be allowed to implement base rate tariffs
and riders designed to collect an overall revenue requirement of $1,614.9 million,4 which
includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues
of $599 million plus revenue from riders of $95.9 million). The signatories also
submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate
the severed rate-case expense docket. The interim rates requested in the agreed motion
mirrored the final rates proposed for Commission approval in the stipulation. The agreed
motion further requested that the ALJs consolidate with the instant proceeding Docket
No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the
parties’ pre-filed exhibits into evidence.

10. On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to
ETI’s CGS proposal.

11. On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim
rates for usage on and after August 15, 2010.

12. On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to
ETI’s CGS proposal.

13. On October 5, 2010, the ALJs issued Order No. 13, ordering the consolidation of Docket
No. 38346, related to severed rate-case expense issues, into the instant proceeding,

4
This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices,
the overall revenue requirement figure would be $1,504.0 million.
PUC Docket No. 37744 Order Page 5 of 15
SOAH Docket No. XXX-XX-XXXX

admitting evidence, and returning this docket to the Commission consistent with the
agreed motion filed on August 6, 2010.

14. The Commission considered this Docket at the November 10, 2010 and
December 1, 2010 open meetings.

15. On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS
issues from the settled issues in this docket. The Commission granted the motion at the
December 1, 2010 open meeting and the Commission’s decision was memorialized in
Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket
No. 38951 in Order No. 14.

Description of the stipulation and Settlement Agreement
16. The signatories to the settlement stipulated that ETI should be allowed to implement an
initial overall increase in base-rate revenues of $59 million for usage on and after
August 15, 2010. The signatories further stipulated that they would request approval of
interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely
implementation of this initial rate increase. The signatories further stipulated that ETI
should be allowed to implement an additional overall increase in base-rate revenues of
$9 million on an annualized basis effective for bills rendered on and after May 2, 2011,
the first billing cycle for the revenue month of May.

17. The signatories agreed that ETI’s authorized return on equity shall be 10.125% and its
weighted average cost of capital shall be 8.5209%.

18. The signatories stipulated that the amount of rate increase authorized under finding of
fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and
that this amount constitutes the full and final recovery of all rate-case expenses relating to
Docket No. 37744.

19. The signatories stipulated to the amount of transmission and distribution invested capital
by function as of June 30, 2009 as set out in attachment 1 to the stipulation.
PUC Docket No. 37744 Order Page 6 of 15
SOAH Docket No. XXX-XX-XXXX

20. The signatories stipulated that the Company’s proposed purchased-power recovery rider
will not be approved in this docket, and purchased capacity costs will be included in
base rates.

21. The signatories stipulated that the Company’s proposed transmission cost recovery factor
(TCRF) will not be approved in this docket. The signatories stipulated to the baseline
values as shown in attachment 2 to the stipulation to be used in the Company’s request, if
any, for a TCRF in a separate proceeding.

22. The signatories agreed that ETI’s proposed cost-of-service adjustment rider and formula
rate plan will not be approved in this docket.

23. The signatories stipulated that the Company’s proposed renewable-energy-credit rider
will not be approved in this docket, and the Company’s renewable-energy-credit costs
shall be recovered in base rates. The signatories further stipulated that a transmission
customer that opts out pursuant to P.U.C. SUBST. R. 25.173(j) shall receive a credit that
offsets the amount of renewable-energy-credit costs that are recovered in base rates from
the transmission customer.

24. The signatories agreed that ETI’s proposed remote-communications-link rider should be
approved as filed by the Company.

25. The signatories agreed that ETI’s proposed market-valued-energy-reduction service rider
will not be approved in this docket.

26. The signatories reached the following specific agreements regarding rate design as a part
of the overall resolution of this docket:

a. Rate Schedule IS. Rate Schedule IS will be opened to new business. In the
Company’s next base-rate case, the amount of interruptible credits recoverable
from Texas retail customers shall be limited to an increase of $1 million more
than the amount requested in this docket (or a total of $6.8 million); provided,
however, that in the next rate case, the Company may request an exception to this
limitation upon a showing that the test-year credit amount in excess of the
$6.8 million cap is both cost effective and necessary to meet the Company’s
generation reserve margin requirement. The signatories further agreed that the
PUC Docket No. 37744 Order Page 7 of 15
SOAH Docket No. XXX-XX-XXXX

Company will not offer additional interruptible service if the availability of total
interruptible service supplied by the Company under all interruptible service
riders exceeds 5% of the projected aggregate Company peak demand unless the
additional level of interruptible service offered in excess of the 5% cap is both
cost effective and necessary to meet the Company’s generation reserve margin
requirement. To the extent that the credit amount or participation level exceeds
the limitations described in this paragraph and the Company includes test-year
credits over the $6.8 million credit-amount cap or additional participation in
excess of the 5% participation-level cap in its next rate case, the Company shall
have the burden to prove whether those test-year credits or participation levels
meet the standards established in this paragraph for inclusion in the test year. The
standards in this paragraph are in addition to any requirements in PURA for
inclusion of costs in rates. The signatories further agreed to the Schedule IS
revisions shown on attachment 3 to the stipulation.

b. Rate Schedule IHE. The signatories agreed that no change shall be made to rate
schedule IHE in this docket.

c. Lighting Class Rates. The signatories stipulated that the language under the
paragraph relating to rate group C in rate schedule SHL will be revised to reflect
that, where the Company agrees to install facilities other than its standard street
light fixture and lamp as provided under Rate Group A, a lump sum payment will
be required, based upon the installed cost of all facilities excluding the cost of the
standard street light fixture and lamp, and the customer will be billed under rate
group A.

e. Electric Extension Policy. The signatories agreed to the line-extension terms and
conditions as reflected in attachment 4 to the stipulation.

f. Life-of-Contract Demand Ratchet. The signatories agreed that the
life-of-contract demand ratchet provision in rate schedules Large Industrial Power
Service, Large Industrial Power Service-Time of Day, General Service, General
Service-Time of Day, Large General Service, and Large General Service-Time of
PUC Docket No. 37744 Order Page 8 of 15
SOAH Docket No. XXX-XX-XXXX

Day shall be excluded from rate schedules in ETI’s next rate case. The
signatories further stipulated that the foregoing rate schedules will be revised so
that the life-of-contract demand ratchet provision shall not be applicable to new
customers and shall not exceed the level in effect on August 15, 2010 for existing
customers.

g. Residential Customer Charge. The signatories agreed that the residential
customer charge shall be increased to $5.00.

h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient
funds charge shall be increased to $15.00.

27. The signatories agreed to the class cost allocation set forth in attachment 5 to
the stipulation.

28. The signatories stipulated that the appropriate allocation between ETI’s wholesale and
retail jurisdictions of baseline values and costs to be included in a TCRF is to be
addressed in the proceeding, if any, in which ETI seeks approval of a TCRF.

29. The signatories stipulated that no party waives its right to address in any subsequent
proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales
between ETI and Entergy Gulf States Louisiana, L.L.C.

30. The signatories reached the following specific agreements regarding fuel-related issues as
part of the overall resolution of this docket:

a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of
$3.25 million not associated with any particular issue raised by the signatories.
The disallowance will be allocated pro rata with interest over each month of the
reconciliation period and reflected in the refund in Docket No. 38403.5 The
signatories stipulated that the Company’s fuel costs shall be finally reconciled for
the reconciliation period of April 1, 2007 through June 30, 2009.

b. Rider IPCR. The signatories agreed that ETI’s eligible Rider IPCR costs for the

5
Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order
(Sept. 16, 2010).
PUC Docket No. 37744 Order Page 9 of 15
SOAH Docket No. XXX-XX-XXXX

period April 1, 2007 through the date the rider terminated shall be finally
reconciled with a disallowance of $300,000. The signatories further agreed that
the under-recovered balance of Rider IPCR costs shall be booked as fuel expense
in the month in which the Commission issues an order adopting the stipulation;
provided, however, that the under-recovered balance shall be allocated to
customer classes using A&E4CP.

c. Rough Production Cost Equalization (RPCE) Payments. The signatories agreed
that ETI will credit an additional $18.6 million to Texas fuel-factor customers,
which the signatories stipulated represents the remaining portion of RPCE
payments ETI received in 2007 that were at issue in Docket No. 35269.6 The
RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt
hours at plant for calendar year 2006. For customers in the Large Industrial
Power Service rate class, the credit will be refunded based on the customer’s
actual kWh usage during the billing months of January 2006 through
December 2006. Upon issuance of a final order approving the stipulation, the
RPCEs shall be credited to customers as a separate one-month bill credit in the
same form as the RPCEA Rider last approved in Docket No. 38098.7 ETI agreed
that it will terminate all appeals related to Docket No. 35269.

31. The signatories agreed that ETI will continue its accrual of storm-cost reserves at the
level of $3.65 million annually and that this amount shall be subsumed in the base-rate
revenue increase described in finding of fact 16 above.

32. The signatories agreed that ETI shall maintain River Bend depreciation rates at current
levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at
$2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an
energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of

6
Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 System Agreement
Payments, Docket No. 35269, Order (Jan. 7, 2009).
7
Application of Entergy Texas, Inc. for Authority to Implement New RPCEA Rate, Docket No. 38098,
Order (July 1, 2010).
PUC Docket No. 37744 Order Page 10 of 15
SOAH Docket No. XXX-XX-XXXX

1.71%, resulting in an overall escalation rate of 3.62%, and net investment yields as
follows:
Nuclear-Decommissioning-Trust Projected Returns
Tax-Qualified Non-Tax-Qualified
Investments Investment

2010 5.475% 5.057%
2011 5.837% 5.236%
2012 6.306% 5.567%
2013 6.304% 5.607%
2014 6.481% 5.896%
2015 6.493% 5.909%
2016 6.412% 5.826%
2017 6.412% 5.830%
2018 6.364% 5.790%
2019 6.316% 5.748%
2020 6.268% 5.712%
2021 6.220% 5.670%
2022 2.503% 5.458%
2023 5.817% 5.055%
2024 5.382% 4.628%
2025 5.036% 4.516%
2026-2034 4.920% 4.409%

33. The signatories stipulated that the Company’s depreciation rates for non-River Bend
production plant, transmission, distribution, and general plant will remain at current
levels and the Company will maintain its accounting records on a prospective basis for
purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage,
and cost of removal by FERC account.

Consistency of the Agreement with PURA and the Commission Requirements
34. Considered in light of (1) the pre-filed testimony by the parties entered into evidence and
(2) the additional evidence and testimony admitted during the course of the hearing on
the merits on the Company’s application, the stipulation is the result of compromise from
each signatory, and these efforts, as well as the overall result of the stipulation viewed in
light of the record evidence as a whole, support the reasonableness and benefits of the
terms of the stipulation.
PUC Docket No. 37744 Order Page 11 of 15
SOAH Docket No. XXX-XX-XXXX

35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and
conditions resulting from the stipulation are just and reasonable and consistent with the
public interest.

36. The total level of the Texas retail revenue requirement contemplated by the stipulation
will allow ETI the opportunity to earn a reasonable return over and above its reasonable
and necessary operating expense.

37. The stipulated revenue requirement is consistent with applicable provisions of PURA
chapter 36 and the Commission’s rules.

38. To the extent that affiliate costs are included in the stipulated revenue requirement and
fuel expense, they are reasonable and necessary for each class of affiliate costs presented
in ETI’s application.

39. To the extent that affiliate costs are included in the stipulated revenue requirement and
fuel expense, the price charged to ETI is not higher than the prices charged by the
supplying affiliate for the same item or class of items to its other affiliates or divisions, or
a non-affiliated person within the same market area or having the same market
conditions.

40. The retail revenue requirement in the stipulation does not include any expenses
prohibited from recovery under PURA.

41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ETI
should be adopted consistent with the stipulation.

42. The agreed rate-design provisions and terms and conditions of service included in the
stipulation are just and reasonable.

43. The treatment of rate-case expenses described in the stipulation is reasonable.

44. The Company’s proposed remote-communications-link rider as filed by the Company
is reasonable.

45. The depreciation rates agreed to in the stipulation are just and reasonable.
PUC Docket No. 37744 Order Page 12 of 15
SOAH Docket No. XXX-XX-XXXX

46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production
assets based on the factors agreed to in the stipulation is reasonable.

47. A $3.65 million annual storm cost accrual is reasonable.

48. The class allocation methodologies described in the stipulation are just and reasonable.

49. The fuel and IPCR-related provisions of the stipulation are reasonable.

II. Conclusions of Law
1. ETI is a public utility as that term is defined in PURA § 11.004(1) and an electric utility
as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.001–.111, 36.203, 39.452, and 39.455.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
TEX. GOV’T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA, the Texas
Administrative Procedure Act,8 and Commission rules.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6. This docket contains no remaining contested issues of fact or law.

7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it
addresses; results in just and reasonable rates, terms, and conditions; is supported by a
preponderance of the credible evidence in the record; is consistent with the relevant
provisions of PURA; and is consistent with the public interest.

8. ETI has properly accounted for the amount of fuel and IPCR-related revenues collected
pursuant to the fuel factor and Rider IPCR.

8
TEX. GOV’T CODE ANN. Chapter 2001 (Vernon 2007 and Supp. 2009).
PUC Docket No. 37744 Order Page 13 of 15
SOAH Docket No. XXX-XX-XXXX

9. The revenue requirement, cost allocation, revenue distribution, and rate design
implementing the stipulation result in rates that are just and reasonable, comply with the
ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or
prejudicial.

10. Based on the evidence in this docket, the overall total invested capital through the end of
the test year meets the requirement in PURA § 36.053(a) that electric utility rates be
based on the original cost, less depreciation, of property used by and useful to the utility
in providing service.

11. ETI has met its burden of proof in demonstrating that it is entitled to the level of retail
base rate and rider revenue set out in the stipulation.

12. ETI has met its burden of proof in demonstrating that the rates resulting from the
stipulation are just and reasonable, and consistent with PURA.

III. Ordering Paragraphs
1. ETI’s application seeking authority to change its rates; reconcile its fuel and purchased
power costs for the Reconciliation Period from April 1, 2007 to June 30, 2009; and for
other related relief is approved consistent with the above findings of fact and conclusions
of law.

2. Rates, terms, and conditions consistent with the stipulation are approved.

3. The tariffs and riders consistent with the stipulation are approved for the initial and
second step rate increases.

4. ETI’s request for waivers of RFP instructions (RFP Schedule V) is granted.

5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating
Station consistent with the terms of this Order.

6. Neither the stipulation and settlement agreement nor this Order constitutes the
Commission's agreement with, or consent to, the manner in which ETI, or any entity
affiliated with ETI, has interacted with any decommissioning trust to which ETI or its
ratepayers have made contributions or provided funds. Furthermore, this Order in no
PUC Docket No. 37744 Order Page 14 of 15
SOAH Docket No. XXX-XX-XXXX

way constitutes a waiver or release of any conduct, whether or not such conduct occurred
before the date of this Order, that may constitute a violation of any provision of state law,
including, without limitation, the rules and regulations of this Commission relating to
nuclear decommissioning trust funds; or prevents the Staff of the Commission from
opening an investigation and taking enforcement action relating to violations of such
rules and regulations.

7. Nothing contained in this Order constitutes the consent or approval, explicit or implied,
of any modification, amendment or clarification of any power purchase agreement
between ETI and any other Entergy entity relating to the River Bend Station. Without
limiting the foregoing, nothing contained in this Order shall constitute the consent or
approval of any modification, amendment, or clarification of any power purchase
agreement between ETI and any other Entergy entity relating to the River Bend Station,
which is made to address any concerns raised by the NRC in its Request for Additional
Information regarding the River Bend Station dated March 11, 2010.

8. The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this
Order, reconciled through June 30, 2009, and are approved consistent with the
stipulation.

9. ETI shall adjust its fuel over/under recovery balance consistent with the findings in this
Order.

10. ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions
of law to be effective with the first billing cycle of the billing month immediately
following the effective date of this Order.

11. Because the final approved rates are equal to or higher than the interim rates adopted in
Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary.

12. The interim rates approved in Order No. 12 are herby approved for the initial step rate
increase contemplated by the stipulation, and ETI shall implement the second step rates
for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month
of May.
PUC Docket No. 37744 Order Page 15 of 15
SOAH Docket No. XXX-XX-XXXX

13. Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs
and schedules approved in this docket and a clean copy of the attachments to the
stipulation.

14. The entry of this Order consistent with the stipulation does not indicate the Commission’s
endorsement of any principle or method that may underlie the stipulation. Neither should
entry of this Order be regarded as a precedent as to the appropriateness of any principle
or methodology underlying the stipulation.

15. All other motions, requests for entry of specific findings of fact, conclusions of law, and
ordering paragraphs, and any other requests for general or specific relief, if not expressly
granted in this order, are hereby denied.

SIGNED AT AUSTIN, TEXAS the ______ day of December 2010

PUBLIC UTILITY COMMISSION OF TEXAS

BARRY T. SMITHERMAN, CHAIRMAN

DONNA L. NELSON, COMMISSIONER

KENNETH W. ANDERSON, JR., COMMISSIONER

q:\cadm\orders\final\37000\37744fo.docx
 Page 1 (Pages 1-4)
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· · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1· ·1·
· · · · · · · ·TABLE OF CONTENTS (CONTINUED)
··· ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· · · · · · · · · ·PUC DOCKET NO. 39896
·2·
··· ·3·
·PRESENTATION ON BEHALF OF
·
·3· ··ENTERGY
· TEXAS, INC. (CONTINUED)
···
·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4· ·4·
·
··TEXAS,
· INC., FOR· · · · ··)
·AUTHORITY TO CHANGE RATES )
·5· ···· ··CHRIS E. BARRILLEAUX
··AND
· RECONCILE FUEL COSTS, ) ·5·
· · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
·AND OBTAIN DEFERRED· · · ·)
·6·
··ACCOUNTING
· TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
·
·7· ·6·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
···
·
·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
··· ·7·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
·
·9·
··· ·8·
· · ··SAMUEL C. HADAWAY
·
10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
···
· · · · · · · · · ·HEARING ON THE MERITS
11· ·9·
· · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
···
· · · · · · · ··Wednesday, April 25, 2012
12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
··· 10·
· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
·
13·
··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
·
14· 11·
· · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
···
· · · · · · · · · ··TABLE OF CONTENTS
15· 12·
·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
··· 13·
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· · · · · · ·(Volume 2, Pages i through xxiv)
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·1·
· · · · · · · ·TABLE OF CONTENTS ·1·
· · · · · · · · ··TABLE OF CONTENTS
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·2·
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·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
··· ·4·
·PRESENTATION ON BEHALF OF
·3·
·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ··ENTERGY
· TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
···
·4·
·OPENING STATEMENT ON BEHALF OF ·5·
·
··ENTERGY
· TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ···· ··ROBERT D. SLOAN
·5·
· ·6·
· · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
··OPENING
· STATEMENT ON BEHALF OF ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·6·
·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ·7·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
··· ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·7·
·OPENING STATEMENT ON BEHALF OF ·8·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
··CITIES
· (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ·9·
· · ··H. VERNON PIERCE, JR.
·8·
· ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
··OPENING
· STATEMENT ON BEHALF OF
·9·
·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 10·
· · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
··· ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
10·
·OPENING STATEMENT ON BEHALF OF 11·
·
··OFFICE
· OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· ··MICHAEL P. CONSIDINE
11·
· 12·
· · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
··OPENING
· STATEMENT ON BEHALF OF ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
12·
·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 13·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
··· ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
13·
·OPENING STATEMENT ON BEHALF OF
··THE
· UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 14·
· · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
14·
· ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
··· 15·
·
15·
·PRESENTATION ON BEHALF OF ··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··365
··ENTERGY
· TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 16·
·
16·
· ··PRESENTATION
· ON BEHALF OF
···· ··JOSEPH DOMINO 17·
·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
17·
· · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 18·
· · ··WALTER C. FERGUSON
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
18·
·
··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··103 19·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
· ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
··PRESENTATION
· ON BEHALF OF 20·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
··· 21·
·
21·
· · ··JOSEPH DOMINO ···· ··DANE A. WATSON
···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 22·
· · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
· · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131
23·
· · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 23·
· · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
24·
· · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 24·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
··· ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
· 25·
·

KENNEDY REPORTING SERVICE, INC.
512.474.2233
 Page 51 (Pages 447-450)
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·1·· ·understand your term of human resource costs, to the ·1·· · · ·A· ··It's my rebuttal testimony and exhibits.
·2·· ·extent that there were labor dollars applied to a ·2·· · · ·Q· ··Okay.··Was your direct testimony, rebuttal
·3·· ·project, and my schedule will often have the impact ·3·· ·testimony, and exhibits prepared by you or under your
·4·· ·through the loading of benefits.··And so through that ·4·· ·supervision?
·5·· ·mechanism, I see that, but I couldn't tell you that it ·5·· · · ·A· ··Yes, it was.
·6·· ·had to do with human resource costs in the sense of work ·6·· · · ·Q· ··Do you have any corrections you need to make to
·7·· ·that I would do or anybody on my staff. ·7·· ·your testimony?
·8·· · · ·Q· ··I understand.··But it's in the human resources ·8·· · · ·A· ··No.
·9·· ·class on your exhibit. ·9·· · · ·Q· ··If I were to ask you the same questions today
10·· · · ·A· ··Ma'am, I understand. 10·· ·that were asked in your written testimony, would your
11·· · · ·Q· ··Yes. 11·· ·answers be the same?
12·· · · · · · · · ·MS. KELLEY:··I have no further questions, 12·· · · ·A· ··Yes.
13·· ·and I would offer State Agency Exhibit No. 3. 13·· · · · · · · · ·MR. OLSON:··All right.··Your Honor, at
14·· · · · · · · · ·JUDGE WALSTON:··Any objection? 14·· ·this time, we move for the admission of ETI 32 and 59.
15·· · · · · · · · ·MR. BRITT:··Just with the caveat that it's 15·· · · · · · · · ·JUDGE WALSTON:··Okay.··ETI Exhibits 32 and
16·· ·subject to check and verification. 16·· ·59 are admitted.
17·· · · · · · · · ·JUDGE WALSTON:··Subject to verification, 17·· · · · · · · · ·(Exhibit ETI Nos. 32 and 59 admitted)
18·· ·State's Exhibit 3 is admitted. 18·· · · · · · · · ·MR. OLSON:··All right.··At this time, I
19·· · · · · · · · ·(Exhibit State No. 3 admitted) 19·· ·offer the witness for cross-examination.
20·· · · · · · · · ·JUDGE WALSTON:··Public Utility Counsel? 20·· · · · · · · · ·JUDGE WALSTON:··Cities?
21·· · · · · · · · ·MS. FERRIS:··No questions, Your Honor. 21·· · · · · · · · ·MR. MACK:··No questions.
22·· · · · · · · · ·JUDGE WALSTON:··Okay.··Staff? 22·· · · · · · · · ·JUDGE WALSTON:··TIEC?
23·· · · · · · · · ·MR. SMYTH:··No questions. 23·· · · · · · · · ·MS. GRIFFITHS:··Yes, Your Honor.
24·· · · · · · · · ·JUDGE WALSTON:··Redirect? 24·· ·
25·· · · · · · · · ·MR. BRITT:··No questions, Your Honor. 25·· ·

Page 448 Page 450

·1·· · · · · · · · ·JUDGE WALSTON:··Okay.··Thank you, ·1·· · · · · · · · · · · ·CROSS-EXAMINATION
·2·· ·Mr. Gardner. ·2·· ·BY MS. GRIFFITHS:
·3·· · · · · · · · ·WITNESS GARDNER:··Thank you. ·3·· · · ·Q· ··Good afternoon, Mr. McCulla.··You're here today
·4·· · · · · · · · ·JUDGE WALSTON:··Will you raise your right ·4·· ·for your direct and your rebuttal testimony.··Correct?
·5·· ·hand? ·5·· · · ·A· ··That's correct.
·6·· · · · · · · · ·(Witness McCulla sworn) ·6·· · · ·Q· ··All right.··And what was your title again,
·7·· · · · · · · · ·JUDGE WALSTON:··State your full name. ·7·· ·Mr. McCulla?
·8·· · · · · · · · ·WITNESS McCULLA:··Mark F. McCulla. ·8·· · · ·A· ··Vice president of transmission regulatory
·9·· · · · · · · · ·JUDGE WALSTON:··Thank you. ·9·· ·compliance.
10·· · · · · · · · · · · ·MARK F. McCULLA, 10·· · · ·Q· ··Okay.··And as vice president of transmission
11·· ·having been first duly sworn, testified as follows: 11·· ·and regulatory compliance, you know what MSS-2 means, do
12·· · · · · · · · · · ··DIRECT EXAMINATION 12·· ·you not?
13·· ·BY MR. OLSON: 13·· · · ·A· ··Yes.
14·· · · ·Q· ··Mr. McCulla, you just stated your name.··Please 14·· · · ·Q· ··Okay.··What is MSS-2?
15·· ·state your title and position with the Company. 15·· · · ·A· ··It's schedule that's used for transmission
16·· · · ·A· ··I'm the vice president of transmission 16·· ·facilities, but certain qualifications are equalized
17·· ·regulatory compliance. 17·· ·because they lend themselves to serving the needs of the
18·· · · ·Q· ··Okay.··You have in front of you what has been 18·· ·entire system.
19·· ·marked ETI Exhibit 32.··Do you see that? 19·· · · ·Q· ··Okay.··So MSS-2 is part of the Entergy system
20·· · · ·A· ··I do. 20·· ·agreement which is a FERC-approved schedule.··Correct?
21·· · · ·Q· ··Can you please identify that exhibit? 21·· · · ·A· ··That's correct.
22·· · · ·A· ··It's my direct testimony and exhibits. 22·· · · ·Q· ··All right.··And is it fair to say that what
23·· · · ·Q· ··Okay.··And you also have before you ETI 59. 23·· ·MSS-2 does is it equalizes the costs of transmission
24·· · · ·A· ··I do. 24·· ·investment across the Entergy system for particular
25·· · · ·Q· ··Can you identify that, please? 25·· ·transmission projects that I believe are at 230-kV and

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·1·· ·above?··Is that accurate? ·1·· ·don't know if this is the right word or the right way to
·2·· · · ·A· ··230 and above and other qualifications, tie ·2·· ·phrase it -- but essentially embodied in this number
·3·· ·lines and other things like that.··But generally 230 and ·3·· ·that the Company is requesting as an increase in its
·4·· ·above is correct. ·4·· ·MSS-2 expense.··Is that correct?
·5·· · · ·Q· ··Okay.··And an issue in this case is the amount ·5·· · · ·A· ··Yes, that's correct.
·6·· ·of MSS-2 expense that the Company is entitled to.··Is ·6·· · · ·Q· ··All right.··Now, you have some familiarity with
·7·· ·that fair to say? ·7·· ·the MSS-2 service schedule?
·8·· · · ·A· ··That's one of the issues, yes. ·8·· · · ·A· ··Some familiarity.
·9·· · · ·Q· ··All right.··And the Company is requesting, as ·9·· · · ·Q· ··All right.··Is it accurate that MSS-2 -- that
10·· ·part of its rate request here -- as part of the about 10·· ·there are various inputs to the MSS-2 calculation?··In
11·· ·104 or $10 million -- whatever it is -- rate request -- 11·· ·that I mean that there are various inputs to how much
12·· ·approximately $10.6 million in MSS-2 expense.··Correct? 12·· ·each operating company must pay to figure out what their
13·· · · ·A· ··That's correct. 13·· ·MSS-2 expense is going to be.
14·· · · ·Q· ··And you offer rebuttal testimony on that issue. 14·· · · ·A· ··I wouldn't say I'm very familiar with the
15·· ·Yes? 15·· ·calculation that takes place.··I'm familiar with the
16·· · · ·A· ··Yes, I do. 16·· ·assets -- the transmission assets and what -- what I'm
17·· · · ·Q· ··Okay.··So earlier today -- and I'm not sure if 17·· ·familiar with is whether they're determined to be
18·· ·you were here with -- when this testimony was given, but 18·· ·qualified as equalizable or not.··But as far as the
19·· ·Mr. Lawton with the Cities went over the post test year 19·· ·calculation and how it goes into the rates, I'm not as
20·· ·adjustment that the Company did for MSS-2 expense.··Were 20·· ·familiar with that.
21·· ·you here for that? 21·· · · ·Q· ··Okay.··I understand.··And I don't want to test
22·· · · ·A· ··I was not. 22·· ·your knowledge or give you a test on the FERC schedule,
23·· · · ·Q· ··Okay.··I believe what you have in front of 23·· ·because I counted the pages of the FERC schedule, and
24·· ·you -- it should have been passed out -- is a document 24·· ·it's about a seven-page calculation.
25·· ·that I'm not going to be admitting into the record, but 25·· · · ·A· ··Okay.··Thanks.

Page 452 Page 454

·1·· ·it is labeled at the bottom WP/PAJ-23.1. ·1·· · · ·Q· ··But do you agree that that calculation does
·2·· · · ·A· ··Okay.··I have it in front of me. ·2·· ·look at various variables, and one of those variables
·3·· · · ·Q· ··All right.··And that is a workpaper that is a ·3·· ·will be the -- basically the inter-transmission
·4·· ·backup to Mr. Considine's testimony, because ·4·· ·investment on the system?
·5·· ·Mr. Considine also sponsored that post test year ·5·· · · ·A· ··Correct.··Yes.
·6·· ·adjustment for MSS-2 expense. ·6·· · · ·Q· ··All right.··And another variable will be the
·7·· · · · · · · · ·If you turn to Page 23.2 at the bottom -- ·7·· ·ownership or operating costs of a particular company.
·8·· ·just flip it over. ·8·· ·Correct?
·9·· · · ·A· ··Okay. ·9·· · · ·A· ··The --
10·· · · ·Q· ··All right.··You'll see adjusted total, and 10·· · · ·Q· ··The ownership or operating costs?
11·· ·under that is approximately $10.7 million.··Correct? 11·· · · ·A· ··I'm not sure how that goes into it, but --
12·· · · ·A· ··Yes.··Correct. 12·· · · ·Q· ··Okay.··Fair enough.··Do you know what the term
13·· · · ·Q· ··Okay.··And that correlates to the amount of 13·· ·"responsibility ratio" means?
14·· ·MSS-2 expense that the Company is requesting? 14·· · · ·A· ··I'm not familiar with how it's used.
15·· · · ·A· ··Okay. 15·· · · ·Q· ··Okay.··Do you understand that each particular
16·· · · ·Q· ··Is that accurate? 16·· ·operating company makes -- makes or receives MSS-2 --
17·· · · ·A· ··Correct. 17·· · · ·A· ··Okay.
18·· · · ·Q· ··Okay.··And that is not a test year number, but 18·· · · ·Q· ··-- costs based --
19·· ·it is a projected rate year number for MSS-2 expense. 19·· · · ·A· ··Yes.
20·· ·Correct? 20·· · · ·Q· ··-- on its particular responsibility ratio?
21·· · · ·A· ··That's my understanding.··What my rebuttal 21·· · · ·A· ··Okay.··Yes, I'm familiar with that.
22·· ·testimony was reflecting was the transmission projects 22·· · · ·Q· ··Okay.··So if an operating company has -- I know
23·· ·and their status and expected completion. 23·· ·it's all relative, but a higher responsibility ratio,
24·· · · ·Q· ··Okay.··But you understand that the projects 24·· ·its MSS-2 expense may go up depending upon its actual
25·· ·that you discussed in your rebuttal testimony were -- I 25·· ·costs?

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· · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1· ·1·
· · · · · · · ·TABLE OF CONTENTS (CONTINUED)
··· ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· · · · · · · · · ·PUC DOCKET NO. 39896
·2·
··· ·3·
·PRESENTATION ON BEHALF OF
·
·3· ··ENTERGY
· TEXAS, INC. (CONTINUED)
···
·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4· ·4·
·
··TEXAS,
· INC., FOR· · · · ··)
·AUTHORITY TO CHANGE RATES )
·5· ···· ··CHRIS E. BARRILLEAUX
··AND
· RECONCILE FUEL COSTS, ) ·5·
· · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
·AND OBTAIN DEFERRED· · · ·)
·6·
··ACCOUNTING
· TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
·
·7· ·6·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
···
·
·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
··· ·7·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
·
·9·
··· ·8·
· · ··SAMUEL C. HADAWAY
·
10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
···
· · · · · · · · · ·HEARING ON THE MERITS
11· ·9·
· · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
···
· · · · · · · · ·Thursday, April 26, 2012
12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
··· 10·
· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
·
13·
··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
·
14· 11·
· · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
···
· · · · · · · · · ··TABLE OF CONTENTS
15· 12·
·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
··· 13·
·
· · · ·(Volumes 1 through 3, Pages i through xxviii)
16·
··· 14·
·
·
17· 15·
·
···
·
18· 16·
·
···
·
19· 17·
·
··· 18·
·
·
20·
··· 19·
·
·
21· 20·
·
···
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22· 21·
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23·
··· 23·
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24· 24·
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25· 25·
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Page ii Page iv
·1·
· · · · · · · ·TABLE OF CONTENTS ·1·
· · · · · · · · ··TABLE OF CONTENTS
·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
·3·
·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3·
·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
·OPENING STATEMENT ON BEHALF OF ·4·
·PRESENTATION ON BEHALF OF
··ENTERGY
· TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY
· TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
·5·
·
·5·
·
···· ··ROBERT D. SLOAN
··OPENING
· STATEMENT ON BEHALF OF ·6·
· · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
·OPENING STATEMENT ON BEHALF OF ·7·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
··CITIES
· (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
· ·8·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
··OPENING
· STATEMENT ON BEHALF OF ·9·
· · ··H. VERNON PIERCE, JR.
·9·
·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
·OPENING STATEMENT ON BEHALF OF 10·
· · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
··OFFICE
· OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
11·
·
11·
·
···· ··MICHAEL P. CONSIDINE
··OPENING
· STATEMENT ON BEHALF OF 12·
· · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
·OPENING STATEMENT ON BEHALF OF 13·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
··THE
· UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
· 14·
· · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
··ENTERGY
· TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15·
·
16·
· ··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··365
···· ··JOSEPH DOMINO 16·
·
··PRESENTATION
· ON BEHALF OF
17·
· · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17·
·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18·
· · ··WALTER C. FERGUSON
18·
· ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··103 19·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
· ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
··PRESENTATION
· ON BEHALF OF 20·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
· · ··JOSEPH DOMINO 21·
·
···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON
22·
· · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
· · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23·
· · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
· · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
· · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
· 25·
·

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·1·· ·here showed a cost of $1,100, an increase of $100 over ·1·· · · · · · · · ·MR. VanMIDDLESWORTH:··Objection, as
·2·· ·Year 1 -- Year 1 to Year 3.··Do you see that? ·2·· ·leading.··I move to strike.
·3·· · · ·A· ··Yes. ·3·· · · · · · · · ·JUDGE BURKHALTER:··Sustained.
·4·· · · ·Q· ··Now, this is not rocket science.··Nobody will ·4·· · · ·Q· ··BY MR. WESTERBURG)··Let me ask you this,
·5·· ·be surprised by the simplicity of this.··But if it's ·5·· ·Mr. Cooper:··If you would clarify the record, what are
·6·· ·more, if the increase in capacity is actually greater ·6·· ·the costs based on that appear in this chart?
·7·· ·than $1,100 -- say $1,300 -- because of the increase in ·7·· · · ·A· ··The costs are based on the contracts between
·8·· ·capacity cost in Year 3, then under the chart that's ·8·· ·ETI and the counter-parties and the rates that are
·9·· ·been developed by Mr. VanMiddlesworth, does the revenue ·9·· ·established in those contracts.··So these would be
10·· ·of $1,100 cover the capacity cost? 10·· ·capacity costs associated with those contracts.··Reserve
11·· · · ·A· ··Not at that rate, no. 11·· ·equalization is also a part of the system agreement
12·· · · ·Q· ··All right.··I would like to also ask you -- 12·· ·contract, and those costs will be incurred as part of
13·· ·maybe turn to the chart.··It's a pretty popular item -- 13·· ·the system agreement expense.
14·· ·but I would like to ask you some questions about the 14·· · · ·Q· ··Does the calculation of the reserve
15·· ·Exhibit -- let's see.··I think it's TIEC Exhibit No. 15·· ·equalization have a load growth component?
16·· ·34 -- I think it's 34A.··It's the blow-up version -- 16·· · · ·A· ··No, not really.··The reserve equalization
17·· · · · · · · · ·MR. WESTERBURG:··Is this 34 or 34A?··34A. 17·· ·includes a number of different elements associated with
18·· ·Excuse me.··I need to get my numbering straight for the 18·· ·it.··The two main elements are the amount of capability
19·· ·record here, Your Honor. 19·· ·each company brings to the system's load.··And the other
20·· · · ·Q· ··(BY MR. WESTERBURG)··I'm talking about the 20·· ·main ingredient is each company's responsibility ratio,
21·· ·blown-up version -- Mr. Cooper, you can look at the 21·· ·so the responsibility ratio as a percentage of the
22·· ·actual size document or you can look at the larger 22·· ·system peak that each company shares.··And the extent
23·· ·document, which actually I find easier to look at, too, 23·· ·that a company is short -- in other words, they do not
24·· ·that Mr. VanMiddlesworth provided for us. 24·· ·have enough capability to meet their requirements --
25·· · · ·A· ··I have it. 25·· ·then they would pay their responsibility ratio share of

Page 682 Page 684

·1·· · · ·Q· ··And explain to us what this is.··What is this ·1·· ·the excess from the long companies.
·2·· ·document? ·2·· · · ·Q· ··Now, the responsibility ratio that is the basis
·3·· · · ·A· ··This is a listing of contracts that ETI has ·3·· ·of the reserve equalization on Line 25 --
·4·· ·entered into for the rate year, and it's divided up into ·4·· · · ·A· ··Yes.
·5·· ·third-party contracts and Legacy affiliate contracts, ·5·· · · ·Q· ··-- is that a projected responsibility ratio?
·6·· ·other affiliate contracts.··And then the last line item ·6·· · · ·A· ··Yes, it is.··It's based on the projected loads
·7·· ·is reserve equalization.··These are contracts that have ·7·· ·of all of the system companies during the rate year.
·8·· ·either been in place or will be coming on-line or new ·8·· · · ·Q· ··Okay.··Now, are there any other numbers on this
·9·· ·contracts that have been entered into for the rate year. ·9·· ·chart that are affected by a projected load?
10·· · · ·Q· ··Okay.··And I would like to ask you, Mr. Cooper, 10·· · · ·A· ··No, not that I'm aware of.
11·· ·these are capacity costs associated with those 11·· · · ·Q· ··With respect to the reserve equalization, do
12·· ·contracts.··Is that right? 12·· ·you know what the result would be if, in fact, the
13·· · · ·A· ··Yes, that's correct. 13·· ·projected load you have in this exhibit were held
14·· · · ·Q· ··Now, are the costs that we're looking at here 14·· ·constant from the test year?
15·· ·projections or are they contractually based? 15·· · · ·A· ··If we looked at the responsibility ratios of
16·· · · ·A· ··Well, they are contractually based projections 16·· ·each of the companies during the test year and we
17·· ·of what the costs will be.··So, you know, there are 17·· ·applied it to these contracts and rates, the reserve
18·· ·terms and conditions associated with delivery on these 18·· ·equalization would be about four and a half million
19·· ·contracts that, you know, if someone fails to deliver, 19·· ·dollars less for ETI.
20·· ·there may be penalties associated with the third-party 20·· · · ·Q· ··Now, there was a lot of talk about the EAI WBL,
21·· ·contracts.··But in general, they are contractually 21·· ·and that contract is reflected on Line 19.
22·· ·based. 22·· · · ·A· ··Yes.
23·· · · ·Q· ··Right.··In other words, they are charges that 23·· · · ·Q· ··To clarify for the Judges -- to the extent they
24·· ·the company will have to pay? 24·· ·may need it; they may not -- but for the record, the
25·· · · ·A· ··Yes. 25·· ·discussion about the operating committee minutes for

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·1·· ·what may have been referred to as a new WBL contract, ·1·· · · ·A· ··Yes.
·2·· ·when does that contract that is made the discussion of ·2·· · · ·Q· ··Mr. Cooper, now the chart we're looking at
·3·· ·the operating committee minutes, when does that contract ·3·· ·here, this is a revision.··Is that correct?
·4·· ·begin?··And if you could refer us to the chart. ·4·· · · ·A· ··Yes, it is.
·5·· · · ·A· ··The contract that was approved by the operating ·5·· · · ·Q· ··Okay.··And was the revision for the purpose of
·6·· ·committee in mid-March actually goes into effect in ·6·· ·reflecting the new WBL contract in January 2013?
·7·· ·January of 2013. ·7·· · · ·A· ··Yes, it was.
·8·· · · ·Q· ··Okay.··So what do we have represented for the ·8·· · · ·Q· ··Now, in the lower right-hand corner, the number
·9·· ·EAI WBL on Line 19, prior to January 13? ·9·· ·that is $275,800,000 and some additional dollars, I
10·· · · ·A· ··That's the existing EAI WBL contract. 10·· ·believe that's the total capacity charges that's
11·· · · ·Q· ··Okay.··Do you recall when the case was filed in 11·· ·indicated on the chart.··Does that represent a total of
12·· ·this docket, Mr. Cooper?··I'm just asking. 12·· ·all the charges on this chart?
13·· · · ·A· ··In November. 13·· · · ·A· ··Yes.
14·· · · ·Q· ··Right.··November.··And I see here that the 14·· · · ·Q· ··Okay.··Now, can you tell us whether or not that
15·· ·first date entry or the first month entry for this chart 15·· ·number that appears on your revised RRC-1 is higher or
16·· ·is June 12.··Do you see that? 16·· ·lower than the number that was there prior to the
17·· · · ·A· ··Yes, I do. 17·· ·revision?
18·· · · ·Q· ··Is it your understanding that that's the 18·· · · ·A· ··It's lower by about $400,000.
19·· ·beginning of what we refer to as the rate year? 19·· · · ·Q· ··Now, was that --
20·· · · ·A· ··Yes, that is. 20·· · · · · · · · ·JUDGE ARNOLD:··Mr. Westerburg, you're
21·· · · ·Q· ··So was the company -- and were you, Mr. Cooper, 21·· ·getting into specific numbers.··Are those highly
22·· ·when you prepared this chart, projecting future cost? 22·· ·sensitive?
23·· · · · · · · · ·JUDGE BURKHALTER:··For what time period? 23·· · · · · · · · ·MR. WESTERBURG:··The totals, Your Honor,
24·· · · · · · · · ·MR. WESTERBURG:··Thank you. 24·· ·are not.··But I appreciate the warning.··Thank you.
25·· · · ·Q· ··(BY MR. WESTERBURG)··For the rate year. 25·· · · ·Q· ··(BY MR. WESTERBURG)··And can you tell us,

Page 686 Page 688

·1·· · · ·A· ··The EAI WBL, the contract that existed, that ·1·· ·Mr. Cooper, if that is attributable in part or in whole
·2·· ·was a projection of the MSS-4 costs associated with the ·2·· ·to the new WBL contract?
·3·· ·existing contract, yes. ·3·· · · ·A· ··That's the $400,000?
·4·· · · ·Q· ··How does the projection of the capacity cost ·4·· · · ·Q· ··Yes, the reduction in cost.
·5·· ·for your RRC-1, for the EAI WBL, how does that compare ·5·· · · ·A· ··Yes, that would be attributable to the change
·6·· ·to the projection of cost beginning in January '13 for ·6·· ·in the WBL contract.
·7·· ·the EAI WBL, in terms of the way that it was developed? ·7·· · · ·Q· ··What are the megawatts associated with the new
·8·· · · ·A· ··The way it was developed was similar.··We used ·8·· ·contract, beginning in January 2013?
·9·· ·a similar process to develop that.··The resources that ·9·· · · ·A· ··It's 186 megawatts.
10·· ·make up the new contract do not include two of the 10·· · · ·Q· ··And what were the megawatts associated with the
11·· ·nuclear units that Arkansas has. 11·· ·existing contract that runs through the end of this
12·· · · · · · · · ·So we eliminated those two resources from 12·· ·year?
13·· ·the WBL, and we then changed the megawatt amount, 13·· · · ·A· ··I believe it was 110 megawatts.
14·· ·because the total megawatts that ETI is going to be 14·· · · ·Q· ··As a result of the new WBL, is the company and
15·· ·receiving from this new contract has increased from 15·· ·customers receiving greater megawatts at a lesser cost?
16·· ·110 megawatts to 186 megawatts.··So we applied the new 16·· · · ·A· ··Yes, they are.
17·· ·megawatts and the rates that were the same from the 17·· · · ·Q· ··Are you aware of any -- back up, lay a
18·· ·existing contract, to the resources that are part of the 18·· ·predicate.··Have you reviewed the intervenors' testimony
19·· ·new WBL contract. 19·· ·on the issue of the EAI WBL?
20·· · · ·Q· ··Did the projections prior to January of 2013, 20·· · · ·A· ··Yes, I have.
21·· ·were they based on the MSS-4 rate of the system 21·· · · ·Q· ··Are you aware of any objections to the
22·· ·agreement? 22·· ·projected cost of the existing EAI WBL?
23·· · · ·A· ··Yes. 23·· · · ·A· ··No, I'm not.
24·· · · ·Q· ··The projections after January of 2013, were 24·· · · · · · · · ·JUDGE BURKHALTER:··When you say
25·· ·they based on the MMS-4 of the system agreement? 25·· ·"existing," are you talking about the original one?··I'm

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·1·· ·not sure I'm following you. ·1·· ·operating committee minutes.··Do you recall that?
·2·· · · · · · · · ·MR. WESTERBURG:··I'll ask the witness, ·2·· · · ·A· ··Yes, I do.
·3·· ·Your Honor. ·3·· · · ·Q· ··And my questions will be directed toward the
·4·· · · ·Q· ··(BY MR. WESTERBURG)··Can you clarify for us the ·4·· ·February operating committee minutes.··And you
·5·· ·meaning of "existing"? ·5·· ·understand the distinction?
·6·· · · ·A· ··The existing contract that goes through the end ·6·· · · ·A· ··Yes.
·7·· ·of 2012. ·7·· · · ·Q· ··Are you familiar with the processes of the
·8·· · · ·Q· ··And, Mr. Cooper, is that the contract ·8·· ·operating committee?
·9·· ·associated with the numbers -- well, let me just ask ·9·· · · ·A· ··I'm somewhat familiar with the processes, not
10·· ·you:··What numbers on this chart are associated with 10·· ·intimately familiar.
11·· ·what we refer to as the existing EAI WBL? 11·· · · ·Q· ··Have you had an experience with there being
12·· · · ·A· ··Those would be Line 19, June through December 12·· ·delays of the finality of presentations with operating
13·· ·of 2012. 13·· ·committee minutes?
14·· · · ·Q· ··Now, this MSS-4 tariff, do you know whether 14·· · · ·A· ··Yes.··As I mentioned, it typically takes at
15·· ·that is part of what's referred to as the Energy System 15·· ·least a month to get the minutes from the operating
16·· ·Agreement? 16·· ·committee subsequent to the actual meeting.
17·· · · ·A· ··Yes.··MSS-4 is a schedule in the system 17·· · · ·Q· ··Do you know whether or not the operating
18·· ·agreement. 18·· ·committee sometimes requests changes to those
19·· · · ·Q· ··Does the company have any discretion in the way 19·· ·presentations?
20·· ·it bills under that tariff? 20·· · · ·A· ··No, I do not.
21·· · · ·A· ··No.··That's a FERC-regulated tariff that the 21·· · · ·Q· ··Do you know -- I'm looking for the contract.
22·· ·company really has no discretion in how it bills. 22·· ·And I'm going to refer to the exhibit marked as TIEC
23·· · · ·Q· ··Do you know if there have been changes to that 23·· ·Exhibit No. 21.
24·· ·tariff -- scratch that and start again.··Do you know 24·· · · ·A· ··Yes, I have it.
25·· ·whether there will be changes to that tariff between now 25·· · · ·Q· ··Right now, is this also an exhibit that's made

Page 690 Page 692

·1·· ·and the time that the company implements the new WBL ·1·· ·an exhibit to your rebuttal testimony?
·2·· ·contract in January 2013? ·2·· · · ·A· ··Yes, it is.
·3·· · · ·A· ··No, I'm unaware of any changes. ·3·· · · ·Q· ··And what is it that we're looking at here,
·4·· · · ·Q· ··There was a discussion about the volatility of ·4·· ·Exhibit 21?
·5·· ·fuel cost, Mr. Cooper.··Is it your experience that the ·5·· · · ·A· ··This is the agreement between ETI and EAI for
·6·· ·cost of gas is volatile? ·6·· ·the WBL contract that begins in 2013.
·7·· · · ·A· ··Yes.··The cost of gas, as recently as several ·7·· · · ·Q· ··Do you have any knowledge, Mr. Cooper,
·8·· ·years ago, was $14 a million Btu.··And, you know, in ·8·· ·regarding whether there are or are not negotiations
·9·· ·recent weeks it's been two dollars a million Btu.··It ·9·· ·related to the signing of these kinds of agreements?
10·· ·goes up; it goes down. 10·· · · ·A· ··No, I do not.
11·· · · ·Q· ··Has it been your experience that it has gone up 11·· · · ·Q· ··Let me take you to Page 2 of the agreement.
12·· ·and down over relatively short periods of time? 12·· ·There is a page number in the lower right-hand corner
13·· · · ·A· ··It has gone up and down over short periods of 13·· ·that is 25.
14·· ·time, too. 14·· · · ·A· ··Yes, I'm there.
15·· · · ·Q· ··How does the volatility of gas cost compare to 15·· · · ·Q· ··Now, would you read Section 6.
16·· ·the volatility of cost associated with the resources in 16·· · · ·A· ··Yes.··"Condition Precedent.··This Agreement
17·· ·the new WBL contract? 17·· ·shall be conditioned upon Buyer receiving all regulatory
18·· · · ·A· ··Well, gas historically has been much more 18·· ·approvals required by Buyer for this Agreement no later
19·· ·volatile than coal and nuclear fuel.··Nuclear fuel is 19·· ·than August 1, 2012."
20·· ·typically procured on long-term contracts; coal is also 20·· · · ·Q· ··And who is the buyer here?
21·· ·typically procured on long-term contracts.··And so the 21·· · · ·A· ··That would be Entergy Texas.
22·· ·price of those two fuels has been relatively stable over 22·· · · ·Q· ··Okay.··Do you know whether the operating
23·· ·the past. 23·· ·committee has made any indication of whether this
24·· · · ·Q· ··Now, there was some discussion also, 24·· ·contract will go forward for Entergy Texas if, in fact,
25·· ·Mr. Cooper, about the timing of the production of the 25·· ·it turns out that the Commission did not approve the

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·1·· ·contract? ·1·· ·understanding of what is before the Commission that is
·2·· · · ·A· ··No, I'm not aware. ·2· ·available for the review of the operating committee's
·
·3·· · · ·Q· ··There was a discussion about hedging, ·3·· ·decision regarding the EAI WBL in this case?
·4·· ·Mr. Cooper.··Rather than to try to capture what ·4·· · · ·A· ··The operating committee minutes and the
·5·· ·you said -- and I don't think I'll do a good job of ·5·· ·presentations associated with it and the contract
·6·· ·it -- would you state again your understanding of the ·6·· ·associated with the new WBL.
·7·· ·practice or the opportunities for hedging as they may be ·7·· · · ·Q· ··In Mr. VanMiddlesworth's cross-examination of
·8·· ·exercised by Entergy Services on behalf of the operating ·8·· ·you on that?
·9·· ·companies and the Texas Commission, the PUCT's position, ·9·· · · ·A· ··Yes.
10·· ·your understanding of that. 10·· · · ·Q· ··To clarify a timing issue, if you could look at
11·· · · ·A· ··Yes.··I know that in the State of Louisiana and 11·· ·the exhibit that is the MSS-4 contract.
12·· ·the State of Mississippi, the utilities there practice a 12·· · · ·A· ··Yes, I have it here.
13·· ·gas hedging program where they fix forward a portion of 13·· · · ·Q· ··Now, what is the date at the top of the
14·· ·their projected requirements in order to reduce the 14·· ·contract that the contract is dated?
15·· ·volatility of gas supply costs.··And it was my 15·· · · ·A· ··This agreement is dated as of April 11, 2012.
16·· ·understanding that we have proposed a similar hedging 16·· · · ·Q· ··Okay.··And it will be obvious from the record,
17·· ·program in Texas, and it was denied. 17·· ·but do you recall whether or not the operating
18·· · · ·Q· ··Are you aware of any intervenors proposing 18·· ·committee's decision approving this contract was
19·· ·hedging in this case? 19·· ·provided in this case prior to this date?
20·· · · ·A· ··No. 20·· · · ·A· ··Yes, that's my understanding.
21·· · · ·Q· ··You mentioned your knowledge or your belief 21·· · · ·Q· ··Okay.··Mr. Cooper, with regard to
22·· ·that there was a proposal by the company.··Do you know 22·· ·Mr. VanMiddlesworth's chart up here, is it your
23·· ·whether or not either the Staff or any intervening party 23·· ·understanding that only capacity charges are reflected?
24·· ·has ever proposed hedging for Texas? 24·· ·Is there an energy cost reflected?
25·· · · ·A· ··No, I'm not aware. 25·· · · ·A· ··The only charges that Mr. VanMiddlesworth

Page 694 Page 696
·1·· · · ·Q· ··Back to EAI WBL -- sorry for jumping around -- ·1·· ·reflects are capacity charges, and then he tries to
·2·· ·but there is an existing EAI WBL in place.··Correct? ·2·· ·allocate those across Entergy.··And, you know, as
·3·· · · ·A· ··Yes, that's correct. ·3·· ·associated with these contracts, you know, many of these
·4·· · · ·Q· ··And do you know how long the term is of that ·4·· ·contracts are actually going to provide lower cost
·5·· ·one -- not when it ends.··I know it ends in December. ·5·· ·energy than would be available from existing resources
·6·· ·We saw that. ·6·· ·or if they were just to rely on the resources of the
·7·· · · ·A· ··Yes.··I believe that was a three-year ·7·· ·reserves of the Entergy system.
·8·· ·agreement. ·8·· · · · · · · · ·In addition, these capacity charges assume
·9·· · · ·Q· ··Okay.··Was there an EAI WBL in place under ·9·· ·that they are incremental.··And in the case of ETI being
10·· ·which Texas received or Entergy Texas or its predecessor 10·· ·a short company, we're not even getting ETI up to their
11·· ·received capacity prior to that? 11·· ·capacity needs.··And so, you know, I don't even consider
12·· · · ·A· ··I don't recall. 12·· ·these capacity charges incremental.··They're just, you
13·· · · · · · · · ·(Brief pause) 13·· ·know, trying to bring them up to the level that they
14·· · · · · · · · ·MR. WESTERBURG:··Your Honor, I'm trying to 14·· ·need to be, because they're short on resources.
15·· ·weed out questions, so if you'll bear with me. 15·· · · ·Q· ··Let me ask you about that, Mr. Cooper.··If you
16·· · · · · · · · ·JUDGE BURKHALTER:··Thank you.··I 16·· ·would go back to your RRC-1 --
17·· ·appreciate it. 17·· · · ·A· ··Yes.
18·· · · ·Q· ··(BY MR. WESTERBURG)··Mr. Cooper, I think toward 18·· · · ·Q· ··-- now, are there new third-party contracts
19·· ·the end of Mr. VanMiddlesworth's cross-examination, you 19·· ·that are in place for the rate year that were not in
20·· ·made a reference to all files regarding the EAI WBL as 20·· ·place for the test year?
21·· ·being the basis -- being available for the 21·· · · ·A· ··Yes.
22·· ·Commission's review.··Do you remember your comment on 22·· · · ·Q· ··And which ones are those?
23·· ·files? 23·· · · ·A· ··Well, we have Calpine-Carville and SRMPA.
24·· · · ·A· ··No. 24·· · · ·Q· ··And if you could tell us the line number, just
25·· · · ·Q· ··I may be remembering wrong.··What is your 25·· ·so we --

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·1·· ·has various provisions for required availability rates ·1·· · · ·A· ··I don't know.
·2·· ·and other things that affect what gets actually paid. ·2·· · · ·Q· ··Did ETI experience load growth in the two years
·3·· ·Correct? ·3·· ·between the last test year and this test year?
·4·· · · ·A· ··That's correct, yes. ·4·· · · ·A· ··I don't know.
·5·· · · ·Q· ··And what do you assume for disallowances for ·5·· · · ·Q· ··Were you here for Mr. Domino's testimony the
·6·· ·availability factor adjustments in this? ·6·· ·other day?
·7·· · · ·A· ··We did not assume anything. ·7·· · · ·A· ··No, I wasn't.
·8·· · · ·Q· ··But there have been adjustments in the past ·8·· · · ·Q· ··So this no-load-growth scenario that results in
·9·· ·years for availability, haven't there? ·9·· ·an underrecovery, that's not what ETI is projecting, is
10·· · · ·A· ··Yes, there have, and they have been relatively 10·· ·it?
11·· ·minor. 11·· · · ·A· ··No.
12·· · · ·Q· ··And for the -- well, let's pick another one. 12·· · · ·Q· ··Now let me refer you to Exhibit 19.··I wanted
13·· ·For the ConocoPhillips -- I guess that's the SRW 13·· ·to clarify some things that Mr. Westerburg asked.
14·· ·contract -- that also has various provisions for 14·· ·Exhibit 19A is this sensitive material.··Do you have
15·· ·performance and for reducing the payment based on that. 15·· ·that?
16·· ·Correct? 16·· · · · · · · · ·MR. WESTERBURG:··I'm sorry.··Exhibit 19A,
17·· · · ·A· ··Yes, that's correct. 17·· ·which one is that, so I can look it up?
18·· · · ·Q· ··And in the Line 1, you didn't assume that the 18·· · · · · · · · ·MR. VanMIDDLESWORTH:··That's the March 23,
19·· ·payment would be reduced at all for that? 19·· ·2012 copy of the February 17 operating committee meeting
20·· · · ·A· ··Yes, that's correct. 20·· ·minutes.
21·· · · ·Q· ··Okay.··And we won't know until the actual year 21·· · · · · · · · ·MR. WESTERBURG:··Got it.
22·· ·comes and goes.··Right? 22·· · · · · · · · ·JUDGE BURKHALTER:··And are you intending
23·· · · ·A· ··Yes, sir. 23·· ·to go into highly sensitive?
24·· · · ·Q· ··You talked about lower fuel costs associated 24·· · · · · · · · ·MR. VanMIDDLESWORTH:··I'm not.
25·· ·with some of these contracts.··The fuel costs flow 25·· · · · · · · · ·JUDGE BURKHALTER:··Okay.

Page 706 Page 708

·1·· ·through the fuel factor.··Isn't that right? ·1·· · · ·A· ··Yes, sir, I have it.
·2·· · · ·A· ··Yes, sir. ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··All right.··Now,
·3·· · · ·Q· ··And Entergy receives its actual reasonable fuel ·3·· ·first of all, turning to the page that's marked TH794.
·4·· ·costs from ratepayers -- no more, no less.··Correct? ·4·· ·Do you see that?··Under "Item 3 -- 2013 EAI Wholesale
·5·· · · ·A· ··It's subject to reconciliation in Texas, yes. ·5·· ·Baseload, (Attachment C)"?
·6·· · · ·Q· ··And are you suggesting that you ought to ·6·· · · ·A· ··I'm afraid my pages got messed up here.
·7·· ·overrecover your actual capacity charges if you lower ·7·· · · · · · · · ·MR. VanMIDDLESWORTH:··May I approach the
·8·· ·fuel costs? ·8·· ·witness, Your Honor?
·9·· · · ·A· ··No, I'm not. ·9·· · · · · · · · ·JUDGE BURKHALTER:··Yes.
10·· · · ·Q· ··So you're still believing you should only 10·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··You can look at mine.
11·· ·recover your actual capacity charge? 11·· · · ·A· ··Is that it, 794?
12·· · · ·A· ··I'm suggesting we should recover the costs that 12·· · · ·Q· ··Yes.
13·· ·we incur for our capacity transactions. 13·· · · ·A· ··Okay.
14·· · · ·Q· ··All right.··And even if they reduce fuel costs, 14·· · · ·Q· ··You see Item 3 refers to 2013 EAI wholesale
15·· ·you don't get more than your actual costs.··Right? 15·· ·baseload?··And it says Attachment C?
16·· · · ·A· ··I'm sorry.··I don't understand that question. 16·· · · ·A· ··Yes.
17·· · · ·Q· ··Well, it's probably my fault.··Let me ask about 17·· · · ·Q· ··And then the next line says Charles DeGeorge
18·· ·this chart, ETI Exhibit 7, for you.··You were asked what 18·· ·provided the Committee members with a wholesale baseload
19·· ·would happen if there were no load growth between Year 1 19·· ·sales analysis?
20·· ·and Year 3 here.··Do you recall that? 20·· · · ·A· ··Yes.
21·· · · ·A· ··Yes. 21·· · · ·Q· ··Now, let me ask you to turn to Page 858 of TIEC
22·· · · ·Q· ··Does ETI project load growth between the test 22·· ·Exhibit 19A.
23·· ·year and the rate year? 23·· · · ·A· ··It's stuck in here.
24·· · · ·A· ··Yes, they do. 24·· · · ·Q· ··All right.··Let me show you mine.··I refer you
25·· · · ·Q· ··How much? 25·· ·to Page 858 --

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· · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1· ·1·
· · · · · · · ·TABLE OF CONTENTS (CONTINUED)
··· ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· · · · · · · · · ·PUC DOCKET NO. 39896
·2·
··· ·3·
·PRESENTATION ON BEHALF OF
·
·3· ··ENTERGY
· TEXAS, INC. (CONTINUED)
···
·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4· ·4·
·
··TEXAS,
· INC., FOR· · · · ··)
·AUTHORITY TO CHANGE RATES )
·5· ···· ··CHRIS E. BARRILLEAUX
··AND
· RECONCILE FUEL COSTS, ) ·5·
· · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
·AND OBTAIN DEFERRED· · · ·)
·6·
··ACCOUNTING
· TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
·
·7· ·6·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
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·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
··· ·7·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
·
·9·
··· ·8·
· · ··SAMUEL C. HADAWAY
·
10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
···
· · · · · · · · · ·HEARING ON THE MERITS
11· ·9·
· · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
···
· · · · · · · · ··Friday, April 27, 2012
12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
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· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
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··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
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14· 11·
· · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
···
· · · · · · · · · ··TABLE OF CONTENTS
15· 12·
·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
··· 13·
·
· · · ·(Volumes 1 through 4, Pages i through xxxii)
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·1·
· · · · · · · ·TABLE OF CONTENTS ·1·
· · · · · · · · ··TABLE OF CONTENTS
·2·
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· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
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·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3·
·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
·OPENING STATEMENT ON BEHALF OF ·4·
·PRESENTATION ON BEHALF OF
··ENTERGY
· TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY
· TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
·5·
·
·5·
·
···· ··ROBERT D. SLOAN
··OPENING
· STATEMENT ON BEHALF OF ·6·
· · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
·OPENING STATEMENT ON BEHALF OF ·7·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
··CITIES
· (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
· ·8·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
··OPENING
· STATEMENT ON BEHALF OF ·9·
· · ··H. VERNON PIERCE, JR.
·9·
·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
·OPENING STATEMENT ON BEHALF OF 10·
· · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
··OFFICE
· OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
11·
·
11·
·
···· ··MICHAEL P. CONSIDINE
··OPENING
· STATEMENT ON BEHALF OF 12·
· · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
·OPENING STATEMENT ON BEHALF OF 13·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
··THE
· UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
· 14·
· · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
··ENTERGY
· TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15·
·
16·
· ··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··365
···· ··JOSEPH DOMINO 16·
·
··PRESENTATION
· ON BEHALF OF
17·
· · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17·
·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18·
· · ··WALTER C. FERGUSON
18·
· ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··103 19·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
· ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
··PRESENTATION
· ON BEHALF OF 20·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
· · ··JOSEPH DOMINO 21·
·
···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON
22·
· · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
· · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23·
· · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
· · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
· · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
· 25·
·

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·1·· ·subject to the prior ruling on objections to ETI Exhibit ·1·· ·sorry -- other -- let me rephrase that.··Too many MSSs.
·2·· ·No. 39, it is admitted. ·2·· · · · · · · · ·You also support the system agreement
·3·· · · · · · · · ·(Exhibit ETI No. 39 admitted) ·3·· ·costs in the fuel reconciliation period to the extent
·4·· · · · · · · · ·MR. WESTERBURG:··Your Honor, ETI tenders ·4·· ·they're included there?
·5·· ·the witness for cross. ·5·· · · ·A· ··Yes, I support the other service schedule
·6·· · · · · · · · ·JUDGE WALSTON:··All right.··Cities? ·6·· ·costs, whether they're in the fuel part or in base rates
·7·· · · · · · · · ·MR. LAWTON:··Yes, Your Honor.··May I ·7·· ·in this case.
·8·· ·begin? ·8·· · · ·Q· ··But to be clear, you support the test year
·9·· · · · · · · · ·JUDGE WALSTON:··Yes. ·9·· ·costs, whatever they were, about 1.7 million.··Correct?
10·· · · · · · · · ·MR. LAWTON:··Thank you. 10·· · · ·A· ··Are we talking about my direct testimony or are
11·· · · · · · · · · · · ·CROSS-EXAMINATION 11·· ·we talking about my rebuttal testimony in this?
12·· ·BY MR. LAWTON: 12·· · · ·Q· ··It's my understanding you're only here for
13·· · · ·Q· ··Good morning, Mr. Cicio.··How are you, sir? 13·· ·direct today.
14·· · · ·A· ··Good morning, Mr. Lawton.··Just fine. 14·· · · ·A· ··Okay.··In this particular case, Mr. Considine
15·· · · ·Q· ··Okay.··Start off with Page 3, Line 20 of your 15·· ·supported the pro forma to the test year MSS-2 costs in
16·· ·testimony, which is, I think -- ETI Exhibit 39, Is it? 16·· ·this case.
17·· · · ·A· ··Page 3 -- 17·· · · ·Q· ··Okay.··He supported a 9 million-dollar pro
18·· · · ·Q· ··Line 20. 18·· ·forma in MSS-2 costs.··Correct?
19·· · · ·A· ··-- Line 20.··Okay. 19·· · · ·A· ··The total was 10.7 million for the pro forma,
20·· · · ·Q· ··Okay.··Now, I want to understand the purpose of 20·· ·as I recall.
21·· ·your testimony and exactly what you do. 21·· · · ·Q· ··And when I asked him about the basis for that
22·· · · · · · · · ·The first thing I see there is you support 22·· ·9 million-dollar adjustment the other day, Mr. Considine
23·· ·the costs and revenues associated with ETI's 23·· ·told me he got it from, I think, your group.
24·· ·participation in the Entergy service agreement during 24·· · · ·A· ··Okay.··That's what he testified.··I haven't
25·· ·the test year, July 1, 2010 to June 30, 2011.··Correct? 25·· ·read Mr. Considine's testimony.

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·1·· · · ·A· ··It's the Entergy system agreement, yes. ·1·· · · ·Q· ··He got it from some accounting group that does
·2·· · · ·Q· ··Okay.··And so when you say you support the ·2·· ·this work, MSS-2.··Would that be your group or can you
·3·· ·costs and revenues associated with the service ·3·· ·think of somebody else?
·4·· ·agreement, what costs and revenues are you talking ·4·· · · ·A· ··He got that information from a combination of
·5·· ·about? ·5·· ·sources.··I think it was looked at by my group as well.
·6·· · · ·A· ··I think I go through and list those in my ·6·· · · ·Q· ··Well, I'm wondering, who do I ask questions
·7·· ·testimony, but generally speaking, it's the MSS-1 ·7·· ·about the 10.6 million calculation?
·8·· ·service -- Schedule MSS-1, MSS-2, MSS-3, MSS-5 and I ·8·· · · · · · · · ·In this direct case, I've asked
·9·· ·think that's it -- and MSS-4.··I think I forgot that. ·9·· ·Mr. Considine about it, and now I'm asking you about it.
10·· · · ·Q· ··Okay.··And if we -- and we're going to focus a 10·· ·And you don't testify to the 10.6 million.··Who in this
11·· ·bit today on what's called MSS-2. 11·· ·case testifies to the 10.6 million of MSS-2 costs the
12·· · · · · · · · ·So would you tell us what MSS-2 is? 12·· ·company is requesting in this direct case?
13·· · · ·A· ··Generally speaking, MSS-2 is the service 13·· · · · · · · · ·Who does it?··Who do I ask?
14·· ·schedule by which certain transmissions costs are 14·· · · ·A· ··It depends on what component of the
15·· ·equalized among the operating companies, and it's the 15·· ·calculations you're talking about.··The investment, I
16·· ·ownership costs of those transmission assets. 16·· ·believe, was sponsored -- or was supported by
17·· · · ·Q· ··And as I understand it, you support the test 17·· ·Mr. McCulla's organization.··The calculation was done in
18·· ·year cost of MSS-2? 18·· ·another group, but, you know, my group reviewed that.
19·· · · ·A· ··In my testimony, I support the test year cost 19·· ·So I feel comfortable talking about the calculation.
20·· ·of MSS-2. 20·· · · ·Q· ··Okay.··You're comfortable talking about how we
21·· · · ·Q· ··And exactly what is the amount of those costs 21·· ·get to 10.6 million?
22·· ·in the test year? 22·· · · ·A· ··Generally speaking, I can generally talk about
23·· · · ·A· ··I believe the test year costs are $1.7 million. 23·· ·it, yes.··But it came from Mr. Considine's thing, but I
24·· · · ·Q· ··And you also support the MSS-2 costs in the 24·· ·can talk about it.
25·· ·reconciliation period, or the other MSS costs?··I'm 25·· · · ·Q· ··Okay.··Fair enough.··Now, if we turn to your

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·1·· · · ·Q· ··Under the system agreement, the operating ·1·· · · · · · · · ·admitted)
·2·· ·companies that we've talked about are to equalize their ·2·· · · ·Q· ··(BY MR. LAWTON)··What I want to focus on,
·3·· ·cost of transmission.··Is that correct? ·3·· ·Mr. Cicio, is last page of Cities 28.··Are you there,
·4·· · · ·A· ··Of certain transmission.··It's not all ·4·· ·sir?··It's a table.··Do you see that table?
·5·· ·transmission.··There are certain guidelines within the ·5·· · · ·A· ··Yes, I see the table.
·6·· ·service schedule that govern what transmissions are ·6·· · · ·Q· ··This is the response to Cities 3-3 g.··Correct?
·7·· ·equalized. ·7·· · · ·A· ··That's correct.
·8·· · · ·Q· ··And generally speaking, would you agree that ·8·· · · ·Q· ··Now, what we have here on this table on the
·9·· ·it's all transmission assets at 230 kV and above? ·9·· ·left-hand side is the year from 2006 to 2011, along with
10·· · · ·A· ··I think that's generally the case. 10·· ·a grand total.··Do you see that?
11·· · · ·Q· ··Okay.··So if a utility has a lot of 11·· · · ·A· ··Yes, I see that.
12·· ·transmission relative to the other operating companies 12·· · · ·Q· ··And then across the top of the table, we have
13·· ·and its responsibility ratio reflects it, it may get 13·· ·EAI.··That would be the Arkansas company --
14·· ·paid MSS-2 dollars -- correct -- from the other 14·· · · ·A· ··That's correct.
15·· ·operating companies? 15·· · · ·Q· ··-- and EGSI.··Which company is that, the
16·· · · ·A· ··I'm not sure I would characterize it exactly 16·· ·Louisiana Texas -- I mean, Louisiana Gulf States?
17·· ·that way. 17·· · · ·A· ··That is both companies, ETI and EGSL.··That was
18·· · · ·Q· ··Okay.··Well, would you agree with this 18·· ·prior to the jurisdictional separation of those two
19·· ·statement:··Some of the operating companies are paid on 19·· ·companies.
20·· ·a monthly basis for transmission and others pay the 20·· · · ·Q· ··Fair enough.··And then you have -- and so what
21·· ·cost? 21·· ·happened is on January 1st, 2008, Texas and Louisiana
22·· · · ·A· ··And there are long companies and there are 22·· ·separated.··Correct?
23·· ·short companies, as it relates to equalizable 23·· · · ·A· ··I think that's the case.
24·· ·transmission investment. 24·· · · ·Q· ··Okay.··And then the next company is ELL.··Which
25·· · · ·Q· ··Okay.··I've put some -- had Ms. Mayhall put 25·· ·one is that?··That's another operating company?

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·1·· ·some exhibits in front of you, and the first one I want ·1·· · · ·A· ··That's Entergy Louisiana.
·2·· ·to look at is what has been marked as Cities Exhibit 28. ·2·· · · ·Q· ··And EGSL, that's the Louisiana version that
·3·· · · ·A· ··I have it.··Yes, I have it.··Okay.··Cities ·3·· ·separated.··Correct?
·4·· ·Exhibit 28 is the response to Cities 3-3? ·4·· · · ·A· ··Right.··That's the Louisiana portion of what
·5·· · · ·Q· ··Yes.··You're getting ahead of me, sir. ·5·· ·used to be EGSI.
·6·· · · ·A· ··Okay. ·6·· · · ·Q· ··And EMI would be the Mississippi company I
·7·· · · ·Q· ··Would you agree that Cities Exhibit 28 is a ·7·· ·forgot before.··Right?
·8·· ·discovery response to Cities 3-3? ·8·· · · ·A· ··Entergy Mississippi, correct.
·9·· · · ·A· ··Yes, I would agree with that. ·9·· · · ·Q· ··And ENOI, that would be the New Orleans
10·· · · ·Q· ··And would you agree with me that you are the 10·· ·operations?
11·· ·sponsoring witness for Subparts g. and h.? 11·· · · ·A· ··That would be Entergy New Orleans, Inc.
12·· · · ·A· ··I am the sponsoring witness for g. and h. 12·· · · ·Q· ··And ETI at the far right would be the company
13·· · · ·Q· ··And you've seen this document before, haven't 13·· ·we're here about today, Entergy Texas, Inc.··Correct?
14·· ·you, sir? 14·· · · ·A· ··That's correct.
15·· · · ·A· ··I have seen it. 15·· · · ·Q· ··And let's look at ETI for a second starting in
16·· · · ·Q· ··Okay.··And it's true and correct to the best of 16·· ·2008.··You have a number that says a negative
17·· ·your knowledge.··Correct? 17·· ·$2,660,494.··Do you see that?
18·· · · ·A· ··That's correct. 18·· · · ·A· ··Yes, I do.
19·· · · · · · · · ·MR. LAWTON:··Your Honor, I would offer, at 19·· · · ·Q· ··And what does that number mean?
20·· ·this time, Cities 28. 20·· · · ·A· ··That means for the year -- calendar year
21·· · · · · · · · ·JUDGE WALSTON:··Any objection? 21·· ·2008 that Entergy Texas received MSS-2 payments in the
22·· · · · · · · · ·MR. WESTERBURG:··No, Your Honor. 22·· ·amount of $2.6 million.
23·· · · · · · · · ·JUDGE WALSTON:··Cities Exhibit 28 is 23·· · · ·Q· ··So the other operating companies had to pay
24·· ·admitted. 24·· ·Entergy Texas transmission dollars for equalization in
25·· · · · · · · · ·(Exhibit Cities··No. 28 marked and 25·· ·2008.··Correct?

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·1·· · · ·A· ··On a net basis -- net for the year. ·1·· · · ·Q· ··Okay.··Well, I just want to make sure what it
·2·· · · ·Q· ··On a net basis? ·2·· ·is because we said the test year was 1.7.··I'm trying to
·3·· · · ·A· ··Month-to-month it could have been different. ·3·· ·distinguish it.
·4·· · · ·Q· ··Okay.··Well, if we look -- let's stay on ·4·· · · ·A· ··Okay.
·5·· ·2008 for a moment.··Okay? ·5·· · · ·Q· ··Now, if we go to the bottom of that graph,
·6·· · · · · · · · ·If we look across all the 2008 numbers and ·6·· ·below it, you -- it looks like what appears to be the
·7·· ·if we were to add, for example, the EAI number for 2008, ·7·· ·test year numbers.··Is that correct, sir?
·8·· ·that's a negative 1.4 million.··Do you see that? ·8·· · · ·A· ··That's what it looks like, yes.
·9·· · · ·A· ··Yes. ·9·· · · ·Q· ··It says -- its starts off July 2010-June 6th --
10·· · · ·Q· ··And that means they got paid.··Correct? 10·· ·June 2011.··Correct?
11·· · · ·A· ··Again; for the year, yes. 11·· · · ·A· ··That's right.
12·· · · ·Q· ··Right.··And then we see the ELL number is 12·· · · ·Q· ··Okay.··And so these are the actual numbers in
13·· ·something like 7.8 million for 2008.··Do you see that? 13·· ·the test year.··Right?
14·· · · ·A· ··Yes, I do. 14·· · · ·A· ··These are the actual amounts recorded for MSS-2
15·· · · ·Q· ··And they were paid 7.8 million.··Right? 15·· ·during the test year.
16·· · · ·A· ··Yes. 16·· · · ·Q· ··And Entergy Texas ended up paying the other
17·· · · ·Q· ··And EGSL had to pay.··It's a positive number. 17·· ·operating companies roughly 1.7 million.··Correct?
18·· ·That means they had to pay some money.··Correct? 18·· · · ·A· ··Yes.··They paid 1.7 million on a net basis for
19·· · · ·A· ··That's right. 19·· ·the year.
20·· · · ·Q· ··If we added the numbers across in any year, 20·· · · ·Q· ··On a net basis.··And if we added the test year
21·· ·would they equal zero? 21·· ·numbers across, it would, again, equal zero on a system
22·· · · ·A· ··They should equal zero. 22·· ·basis.··Right?
23·· · · ·Q· ··And the reason they equal zero is basically the 23·· · · ·A· ··That's correct.
24·· ·short companies have to pay the long companies. 24·· · · ·Q· ··Fair enough.··And it's that 1.7 million --
25·· ·Correct? 25·· ·1,753,797 that you sponsor?

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·1·· · · ·A· ··It's a system, so we're equalizing the cost ·1·· · · ·A· ··Yes, that's what I sponsor in my testimony.
·2·· ·among the system.··So for the system, it would equal -- ·2·· · · ·Q· ··Fair enough.··But to be clear -- just go back
·3·· ·should equal zero. ·3·· ·there a second -- what you're asking for in this case --
·4·· · · ·Q· ··Fair enough.··Now, in -- if we look at ETI, we ·4·· ·I'm sorry.
·5·· ·see in 2000 -- I think it's 2010, we have a positive ·5·· · · · · · · · ·What the company is asking for in this
·6·· ·number of 559,000.··Do you see that? ·6·· ·case is roughly not the 1.7 million test year number.
·7·· · · ·A· ··Yes, I do. ·7·· ·They're asking for a number of 10.6 million.··Correct?
·8·· · · ·Q· ··That means on the year, Entergy Texas, Inc., ·8·· · · ·A· ··They're asking for 10.6 million because, you
·9·· ·had to pay money to the operating companies -- other ·9·· ·know, the way the calculation works, if there's added
10·· ·operating companies.··Correct? 10·· ·investment across the companies, which you see here --
11·· · · ·A· ··That's correct. 11·· ·there are changes in transmission investment year to
12·· · · ·Q· ··Okay.··And then in the following year, 2011, 12·· ·year, and so as those transmission projects are put in
13·· ·they had to pay -- "they" being ETI, Entergy Texas -- 13·· ·service, the balance will shift between the different
14·· ·had to pay roughly 1.3 million.··Correct? 14·· ·companies, depending on their transmission
15·· · · ·A· ··That's correct. 15·· ·responsibility relative to their investment.
16·· · · ·Q· ··But on a grand total basis, you just added 16·· · · ·Q· ··Fair enough.··Now, sir, I've had -- I want to
17·· ·those numbers up and said, on a net basis, Entergy 17·· ·go through that calculation for a moment so we all
18·· ·Texas, Inc., got paid 1.7 million.··Correct? 18·· ·understand how it's done.
19·· · · ·A· ··I think if you added up Entergy -- add all the 19·· · · · · · · · ·I've had a two-page demonstrative put in
20·· ·years for Entergy Texas, they would have received 20·· ·front of you, and the first page is just a. through w.
21·· ·1.7 million. 21·· ·You'll see those lines.··And the second page is a sheet
22·· · · ·Q· ··Fair enough. 22·· ·that has a bunch of numbers.··Okay, sir?··Do you see
23·· · · ·A· ··We're just saying for four years, you know, 23·· ·that?
24·· ·they got a net payment.··It's not -- that's just a 24·· · · ·A· ··I have this in front of me, yes.
25·· ·total. 25·· · · ·Q· ··And I just wanted you to assist us on how this

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·1·· · · ·Q· ··Okay.··Fair enough.··Fair enough. ·1·· · · · · · · · ·MR. LAWTON:··Thank you.
·2·· · · · · · · · ·Now, you said, when we started this ·2·· · · ·Q· ··(BY MR. LAWTON)··What's the rate year, sir, in
·3·· ·examination this morning, that you could talk about the ·3·· ·this case?··Do you know?
·4·· ·$10.6 million request. ·4·· · · ·A· ··I believe it begins June of '12 and ends May of
·5·· · · · · · · · ·JUDGE WALSTON:··Can I ask one clarifying ·5·· ·'13.
·6·· ·question just to make sure I'm clear? ·6·· · · ·Q· ··So June 2012 to May 2013.··That's your rate
·7·· · · · · · · · ·MR. LAWTON:··Yes, sir. ·7·· ·year, and you would agree that's a forecast period.
·8·· · · · · · · · ·JUDGE WALSTON:··You said some were removed ·8·· ·Correct?
·9·· ·due to an adjustment.··Is that -- do I understand some ·9·· · · ·A· ··I believe that's -- I'm not exactly sure that
10·· ·assets were included that should not have been included 10·· ·those are the 12 months, but I believe it's generally --
11·· ·and then removed, or why were they removed?··I didn't 11·· · · ·Q· ··I think you got it right.
12·· ·follow that. 12·· · · ·A· ··Okay.
13·· · · · · · · · ·THE WITNESS:··Each month we -- being my 13·· · · ·Q· ··I think it's right.
14·· ·group -- receives the equalizable transmission 14·· · · ·A· ··Okay.
15·· ·investment from the transmission organization, who, I'm 15·· · · ·Q· ··So your 10.6 dollar-million estimate in this
16·· ·assuming, get it from the property accounting records. 16·· ·case is based upon MSS-2 costs for this time period,
17·· · · · · · · · ·So they look at the investment in 17·· ·June 2012 to May 2013.··Correct, sir?
18·· ·transmission month to month, and, say, based on the 18·· · · ·A· ··It's based on the expected investment, the
19·· ·rules of MSS-2, what should be determined to be 19·· ·changes in responsibility ratio for that 12-month
20·· ·equalizable investment. 20·· ·period.
21·· · · · · · · · ·They review that as they provide it, and 21·· · · ·Q· ··Okay.··And do you have Cities Exhibit 39 there,
22·· ·in that particular month, there was an adjustment where 22·· ·sir?··That's the demonstrative with all the numbers.
23·· ·they said that the investment that was there the month 23·· · · ·A· ··Yes, I have that in front of me.
24·· ·before -- a portion of that was no longer equalizable 24·· · · ·Q· ··Okay.··For that time period that we just
25·· ·and shouldn't have been equalizable.··So it was adjusted 25·· ·discussed, June 2012 to May 2013, you had to get an

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·1·· ·out.··The investment is still there.··It's just not ·1·· ·estimate of all the plant costs on Lines a. through d.
·2·· ·determined to be equalizable investment. ·2·· ·Correct?
·3·· · · · · · · · ·JUDGE BURKHALTER:··Meaning it's not 230 kV ·3·· · · ·A· ··That's correct.··We would had to have a point
·4·· ·or above? ·4·· ·of view on the expected transmission investment.
·5·· · · · · · · · ·THE WITNESS:··Generally, yes, that's ·5·· · · ·Q· ··Somebody had to forecast all that stuff.
·6·· ·correct. ·6·· ·Right?
·7·· · · ·Q· ··(BY MR. LAWTON)··Now, sir -- ·7·· · · ·A· ··They had to forecast, or they looked at what
·8·· · · · · · · · ·MR. LAWTON:··I'm sorry.··I don't want to ·8·· ·projects were already being built that they thought were
·9·· ·interrupt again. ·9·· ·going to be completed, so a forecast based on existing
10·· · · · · · · · ·JUDGE WALSTON:··Okay. 10·· ·projects and forecasted projects.
11·· · · ·Q· ··(BY MR. LAWTON)··Now, the company has, in fact, 11·· · · ·Q· ··Okay.··And then if we look under the category
12·· ·forecast a 10.6 million-dollar number for this MSS-2 12·· ·cost of capital; debt ratio, bond costs, all the way
13·· ·category.··Correct? 13·· ·down to Item e., did you get a forecast for all those
14·· · · ·A· ··It's 10.696, I think. 14·· ·numbers?
15·· · · ·Q· ··You've got more decimal places than I, sir. 15·· · · ·A· ··I don't think those numbers were updated for
16·· · · · · · · · ·But this $10.6 million is roughly a 16·· ·that period.
17·· ·9 million-dollar increase, and it's included in the 17·· · · ·Q· ··They weren't?
18·· ·111 million request the company originally made.··Right? 18·· · · ·A· ··I don't -- I don't know, to be honest.
19·· · · ·A· ··It's a -- yes.··The $10.69 million is the rate 19·· · · ·Q· ··You don't know?
20·· ·year -- expected rate year MSS-2 expense. 20·· · · ·A· ··No, I don't.
21·· · · ·Q· ··All right.··Fair enough.··Now, go back, for a 21·· · · ·Q· ··Who knows?
22·· ·moment, to the demonstrative for Cities, Exhibit 39. 22·· · · ·A· ··Somebody that -- the gentlemen or gentleman
23·· · · · · · · · ·MR. LAWTON:··Your Honor, may I use this a 23·· ·that reviewed that.··I don't -- I don't know personally.
24·· ·second? 24·· · · ·Q· ··But I thought you reviewed it.
25·· · · · · · · · ·JUDGE WALSTON:··Yes. 25·· · · ·A· ··I reviewed it, but I don't remember whether

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·1·· ·those changed or not.··I just don't remember that. ·1·· · · ·Q· ··When they did the load forecast for Entergy
·2·· · · ·Q· ··Let's go to the tax rate.··Do you think that ·2·· ·Texas, did they have an increase in load for Entergy
·3·· ·changed? ·3·· ·Texas, sir?··Do you know?
·4·· · · ·A· ··I don't -- the factors I'm not sure of. ·4·· · · ·A· ··I don't know.
·5·· · · ·Q· ··Okay.··Well, would that include the factors ·5·· · · ·Q· ··Is the -- okay.
·6·· ·under O&M expenses, too? ·6·· · · · · · · · ·The last area that I want to ask you about
·7·· · · ·A· ··Everything from cost of capital through, you ·7·· ·is I think on your -- I have passed out this morning --
·8·· ·know, the net investment ratio.··Those numbers, I just ·8·· ·is copy of Cities Exhibit 7.··It's part of 10-K.··It's
·9·· ·don't know if the financial factors were updated. ·9·· ·already into the record.··I just wanted to ask you a
10·· · · ·Q· ··Is there somebody in this case I can ask about 10·· ·little bit about the 10-K.
11·· ·it? 11·· · · ·A· ··Okay.
12·· · · ·A· ··I don't know, Mr. Lawton. 12·· · · ·Q· ··Go to Page 364 of the 10-K, sir.
13·· · · ·Q· ··Okay.··What about all the other numbers, net 13·· · · ·A· ··Okay.··I'm there.
14·· ·investment ratio, and all that, was that -- 14·· · · ·Q· ··Under "Other income statement variances" -- do
15·· · · ·A· ··Those are calculations, so those are embedded 15·· ·you see that in bold?
16·· ·in -- if you update, you know, the net transmission 16·· · · ·A· ··Yes, I see that.
17·· ·investment, then you update, you know, the ratio -- that 17·· · · ·Q· ··Go to the first bullet point and read that to
18·· ·ratio anyway. 18·· ·yourself.
19·· · · ·Q· ··Would you agree with me, sir -- we went through 19·· · · ·A· ··To myself?
20·· ·this -- that the cost of capital and all these O&M 20·· · · ·Q· ··Yes.
21·· ·factors are important parts of the calculation as well? 21·· · · · · · · · ·(Brief pause)
22·· · · ·A· ··Yes.··They're important parts of the 22·· · · ·A· ··Okay.··I've read it.
23·· ·calculation, but they don't typically vary a great deal. 23·· · · ·Q· ··(BY MR. LAWTON)··All right.··What I understand
24·· ·I mean, the significant change that generated the 24·· ·the 10-K -- the company, Entergy Corp., is reporting
25·· ·10.6 million was the change in the investment. 25·· ·that Entergy Texas, Inc., had some billing adjustments

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·1·· · · ·Q· ··Well, let's talk about the load responsibility ·1·· ·to make in its MSS-2 expenditures.··Is that a fair
·2·· ·ratio.··Isn't that line -- what line is that, sir? ·2·· ·characterization creation of that statement?
·3·· · · ·A· ··On the demonstrative exhibit, it's Line s. ·3·· · · ·A· ··As it reads here, there was a transmission -- a
·4·· · · ·Q· ··Line s.··And isn't that load responsibility ·4·· ·change of 2011 -- down to year 2011 over calendar year
·5·· ·ratio based upon the forecast of loads in your example ·5·· ·2010.··There was a variance in transmission expenses of
·6·· ·here in your estimate? ·6·· ·roughly 8 and a half million dollars.
·7·· · · ·A· ··Are we talking about the rate year? ·7·· · · ·Q· ··Okay.··Would those be -- that 8 and a half
·8·· · · ·Q· ··Yes, sir.··Did somebody forecast the load ·8·· ·million referred to MSS-2 payments?
·9·· ·responsibility for the rate year to get 10.6 million? ·9·· · · ·A· ··The 8 and a half million appears to be due to a
10·· · · ·A· ··Yes, they updated -- that they did update, but 10·· ·change in the MSS-2 expenses from 2011 to 2010, a
11·· ·it's a very small percentage.··I mean, basically out of 11·· ·portion of that, and it's not a large portion of that,
12·· ·10.6, you know, that was less than 15 percent of the 12·· ·was related to that 16-year period from 1996 to 2011,
13·· ·adjustment. 13·· ·the billing adjustment for that period.
14·· · · ·Q· ··Based on your calculations.··Correct? 14·· · · ·Q· ··Okay.··So would it fair to say that the
15·· · · ·A· ··Based on my calculations.··Correct. 15·· ·company, Entergy Texas, Inc., or one of the groups
16·· · · ·Q· ··In rebuttal testimony, and we're going to talk 16·· ·there, did an audit for that time period, 1996 to 2011?
17·· ·about it at another time.··Right? 17·· ·Fair?
18·· · · ·A· ··It was calculated, you know, under my 18·· · · ·A· ··There was a review of the MSS-2 balances for
19·· ·supervision, and it's included in my rebuttal testimony. 19·· ·that period, 1996 to 2011, that resulted in a change in
20·· · · ·Q· ··Okay. 20·· ·the MSS-2 payments for -- over that 16-year period, and
21·· · · ·A· ··It's a very small percentage of the total. 21·· ·when you look at 2011 versus 2010, the variance is 8 and
22·· · · ·Q· ··Who did the load forecast, sir? 22·· ·a half million dollars for that period, but only a
23·· · · ·A· ··I believe the load forecast was generated out 23·· ·small -- less than half of that really related to that
24·· ·of one of the groups in our system planning 24·· ·adjustment.
25·· ·organization. 25·· · · · · · · · ·It could be other changes in transmission

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·1·· ·know whether he's also appeared for cross-examination in ·1·· ·Attachment 5 of the inter-system bill.
·2·· ·this proceeding? ·2·· · · ·Q· ··And has the company provided the inter-system
·3·· · · ·A· ··Yes, he's already appeared. ·3·· ·bill for a period of time in this case?
·4·· · · ·Q· ··And, now, what does -- does Mr. Considine ·4·· · · ·A· ··I believe in Cities 5-1, it's provided these
·5·· ·support the pro forma for MSS-2? ·5·· ·attachments, I believe, through February of 2011 --
·6·· · · ·A· ··Mr. Considine also supports the pro forma for ·6·· ·2012.··I'm sorry.
·7·· ·MSS-2. ·7·· · · ·Q· ··And that is an attachment to 5-1?
·8·· · · ·Q· ··And what is the nature of his support for that? ·8·· · · ·A· ··Yes.
·9·· · · ·A· ··Mr. Considine looks -- took all the changes to ·9·· · · ·Q· ··And I think that is Cities Exhibit 29, so let's
10·· ·the test year that were perceived to be known and 10·· ·turn to that.
11·· ·measurable changes to the test year and adjusted the 11·· · · ·A· ··Okay.
12·· ·test year expenses by those known and measurable 12·· · · ·Q· ··Now, would we find Page 2 of Cities Exhibit 39
13·· ·adjustments. 13·· ·in the documents attached to -- or in the attachments to
14·· · · ·Q· ··Do you know whether Mr. Considine has already 14·· ·Cities Exhibit 29?
15·· ·appeared for cross-examination in this proceeding? 15·· · · ·A· ··Attachment 5 is -- which is the second page of
16·· · · ·A· ··Yes, he has already appeared. 16·· ·the Cities exhibit, is found as an attachment to Cities
17·· · · ·Q· ··I would like to turn to Mr. Lawton's 17·· ·5-1.
18·· ·demonstrable exhibit. 18·· · · ·Q· ··Right.··And, I mean, this -- what I'm talking
19·· · · · · · · · ·MR. WESTERBURG:··Was that Exhibit 37? 19·· ·about is the very specific month that -- could we turn
20·· · · · · · · · ·JUDGE WALSTON:··39. 20·· ·to that?
21·· · · · · · · · ·MR. WESTERBURG:··39.··Excuse me. 21·· · · · · · · · ·JUDGE WALSTON:··Which page are we turning
22·· ·Exhibit 39. 22·· ·to?
23·· · · ·Q· ··(BY MR. WESTERBURG)··Mr. Lawton took you 23·· · · · · · · · ·MR. WESTERBURG:··What I'm trying to do,
24·· ·through a discussion of the numbers and the columns and 24·· ·Your Honor, is find, in Cities Exhibit 29, 5-1, which is
25·· ·the lines that appear on Page 2 here.··You recall that? 25·· ·a number of Attachment 5 to the inter-system bill.··I'm

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·1·· · · ·A· ··Yes, I do. ·1·· ·trying to find this specific page that is Page 2 of
·2·· · · ·Q· ··Do you have a sense, or do you have an opinion, ·2·· ·Cities 39.··So I'm dealing with both 39 and 29.
·3·· ·Mr. Cicio, about -- with respect to the number in the ·3·· · · ·A· ··If you go to Page 22 of Cities 5-1, you'll find
·4·· ·bottom right-hand corner, which on Exhibit 39, it shows ·4·· ·the July 2011 MSS-2 calculation, which is the same page
·5·· ·an MSS-2 payment for ETI -- with respect to that number, ·5·· ·as -- second page of the Cities demonstrative exhibit.
·6·· ·do you know, or would you have an opinion as to which ·6·· · · ·Q· ··(BY MR. WESTERBURG)··Okay.··Thank you,
·7·· ·numbers or groups of numbers change more than others to ·7·· ·Mr. Cicio.··And can you verify whether all of the
·8·· ·affect that number? ·8·· ·attachments to Cities 5-1, the -- sounds strange, but
·9·· · · ·A· ··I mean, the majority of this calculation is -- ·9·· ·I'm referring to them as the Attachment 5s -- with an
10·· ·a large percent of the calculation turns on the change 10·· ·"S" on the end of it.
11·· ·in total investment and net transmission investment. 11·· · · ·A· ··Okay.
12·· ·Generally speaking, the rest of the components, the cost 12·· · · ·Q· ··All of those are historical.··Is that correct?
13·· ·rates, the responsibility ratios don't change typically, 13·· · · ·A· ··Yes, these are historical periods.··I think the
14·· ·you know, much year over year. 14·· ·last month is February of 2012.
15·· · · ·Q· ··And, now, this document we're looking at, at 15·· · · ·Q· ··And does that mean that the information
16·· ·Page 2 of exhibit -- Cities Exhibit 39, this same form 16·· ·contained on these Attachment 5s reflect actual data and
17·· ·of document -- well, let me ask you, is -- this is a 17·· ·recordings return?
18·· ·page in an attachment to what's referred to as the 18·· · · ·A· ··These are based on the actual inter-system
19·· ·inter-system bill.··Is that correct? 19·· ·bills for those representative months.
20·· · · ·A· ··Yes, that's correct. 20·· · · ·Q· ··Okay.··And can we turn to the very last page of
21·· · · ·Q· ··And just for the sake of the way the transcript 21·· ·Attachment 5, which would be Page 29?
22·· ·might read, what page is this to the inter-system bill 22·· · · ·A· ··Yes, I'm there.
23·· ·in terms of -- you know, what part of the inter-system 23·· · · ·Q· ··And what is this?
24·· ·bill would this be a page of? 24·· · · ·A· ··This is the Attachment 5 for February of 2012.
25·· · · ·A· ··This is -- the MSS-2 calculation is found on 25·· · · ·Q· ··Just -- do you know why -- we're sitting here

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·1·· ·today in April.··Do you know why we don't have March ·1·· · · ·Q· ··Now, there was also discussion with Mr. Lawton
·2·· ·attached to attachment -- Cities Exhibit 29? ·2·· ·about an adjustment to MSS-2.··Do you recall that?
·3·· · · ·A· ··Yes.··The inter-system bill is prepared twice a ·3·· · · ·A· ··Yes, I do.
·4·· ·month.··It's prepared on the second work day of a month, ·4·· · · ·Q· ··Now, does -- the adjustment that's been
·5·· ·and the actual bill is rendered about 30 days after the ·5·· ·discussed, does that play a part in the increase in the
·6·· ·conclusion of the preceding month.··So the actual March ·6·· ·MSS-2 expense from the test year to what we see here on
·7·· ·bill was actually prepared this week -- was issued this ·7·· ·Page 29 of Exhibit 29?
·8·· ·week.··And so it's not yet -- it will be provided once ·8·· · · ·A· ··By -- what you're saying is, "does it play a
·9·· ·it was complete, which is, I think, mid-week or early ·9·· ·part."··To the extent there were changes in the
10·· ·part of this week. 10·· ·investment balance resulting from that review from '96
11·· · · ·Q· ··Okay.··So February was the latest available? 11·· ·to 2011, this calculation is based on cumulative
12·· · · ·A· ··Yes, February was the latest available. 12·· ·balances of transmission investment.
13·· · · ·Q· ··Okay.··And what's the number in the lower 13·· · · · · · · · ·So to the extent there was any change, it
14·· ·right-hand corner under payments for ETI for February, 14·· ·would have had some effect on those balances, but the
15·· ·which is Page 29? 15·· ·majority of this has been -- has occurred post that
16·· · · ·A· ··For February of 2012, ETI had an MSS-2 payment 16·· ·adjustment -- the change in transmission investment, the
17·· ·of $698,289.82. 17·· ·majority of which has been just new investment that's
18·· · · ·Q· ··And those are based on -- that is based on 18·· ·been put in service.
19·· ·actual investment and transmission of the operating 19·· · · ·Q· ··Maybe this is a cleaner question.··Does the
20·· ·companies.··Is that right? 20·· ·February Attachment 5 on Page 29 reflect the adjustment
21·· · · ·A· ··That's correct. 21·· ·and equalizable investment that you discussed with
22·· · · ·Q· ··There's no projections on this page? 22·· ·Mr. Lawton?
23·· · · ·A· ··There are no projections on this page. 23·· · · ·A· ··Does it reflect the equalizable --
24·· · · ·Q· ··Do you know, Mr. Cicio, what -- or if you have 24·· · · ·Q· ··The adjustment in equalizable investment you
25·· ·it, I think it's a simple calculation. 25·· ·discussed with Mr. Lawton.

Page 784 Page 786

·1·· · · · · · · · ·Do you know what, you know, 12 times ·1·· · · ·A· ··It reflects the balance -- the changes in the
·2·· ·698,000 would be? ·2·· ·balances.
·3·· · · ·A· ··No, I don't have a calculator on me, but if I ·3·· · · ·Q· ··Well, let me ask for clarification.··What was
·4·· ·rounded it to 700,000, it would be about $8.4 million. ·4·· ·the adjustment?··What was adjusted?
·5·· · · ·Q· ··8.4.··And what was the amount of test year ·5·· · · ·A· ··What was adjusted during that -- from '96 to
·6·· ·MSS-2 expenses? ·6·· ·2011, there were changes in the investment balances
·7·· · · ·A· ··The test year amount was 1.7 million. ·7·· ·across the different companies.
·8·· · · ·Q· ··Do you know whether the MSS-2 payments, as ·8·· · · ·Q· ··The equalizable investment?
·9·· ·reflected in this Cities 29 since the test year, have ·9·· · · ·A· ··The equalizable investment.
10·· ·been increasing or decreasing? 10·· · · ·Q· ··Okay.··Are those changes reflected in Page 29
11·· · · ·A· ··To get to -- I mean, if I looked at the test 11·· ·of Exhibit 29?
12·· ·year payments and receipts -- and since the test year, 12·· · · ·A· ··Yes.··Yes, they are reflected.
13·· ·they've been all payments, and they've been increasing 13·· · · ·Q· ··Do you know whether those changes will continue
14·· ·since the end of the test year. 14·· ·to be reflected going forward in the MSS-2 payments?
15·· · · · · · · · ·I mean, I'm going back, you know, since 15·· · · ·A· ··It's a cumulative balance, so to the extent
16·· ·the test year.··I think there was a slight dip in the -- 16·· ·those changes in -- those assets are still part of the
17·· ·in the month of January, it went from 620 to 596, but 17·· ·net investment, yes, they will continue to be included.
18·· ·generally above the test year monthly levels. 18·· · · ·Q· ··Mr. Lawton asked you about certain operating
19·· · · ·Q· ··And do you know why that has occurred? 19·· ·companies leaving the system agreement or having given
20·· · · ·A· ··There's been, as we talked about, you know, a 20·· ·notice to leave the system agreement.··Do you recall
21·· ·major factor in the change in how the payments and 21·· ·that?
22·· ·receipts for MSS-2 are generated by transmission 22·· · · ·A· ··Yes, I do.
23·· ·investment across the system.··And so there's been a 23·· · · ·Q· ··And those operating companies are Entergy
24·· ·fair amount of transmission investment built and placed 24·· ·Mississippi and Entergy Arkansas?
25·· ·in service across the system during this period. 25·· · · ·A· ··That's correct.

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·1·· ·Do you see that? ·1·· ·projects that are in service or in service early or
·2·· · · ·A· ··Yes.··I think it's Line s. on the -- ·2·· ·projected to be in service, and there's a construction
·3·· · · ·Q· ··And that's what you just explained.··Correct? ·3·· ·amount associated with each of those projects.··So
·4·· · · ·A· ··I explained coincident peak.··Responsibility ·4·· ·they're measurable by that aspect of it.
·5·· ·ratio is the average of the 12 -- preceding 12 months. ·5·· · · ·Q· ··What value does ETI receive for its MSS-2
·6·· · · ·Q· ··Twelve months what, coincident peak? ·6·· ·payments?
·7·· · · ·A· ··Twelve months coincident peak. ·7·· · · ·A· ··What ETI receives as a benefit from its MSS-2
·8·· · · ·Q· ··Okay.··Now, is there any other calculation on ·8·· ·payments is the ability to have resources available to
·9·· ·this page that reflects the concept of load, other than ·9·· ·them through the use of the system's bulk electric power
10·· ·responsibility ratio? 10·· ·system.··So if there are resources that are in a
11·· · · ·A· ··No, there's not. 11·· ·different area outside of Texas, by use of that system,
12·· · · ·Q· ··Now, I think Mr. Lawton established that for 12·· ·they have available to them purchased power
13·· ·the purpose of the projections into the rate year of 13·· ·opportunities, other generation from the system that
14·· ·MSS-2, there needed to be a projection of the 14·· ·would benefit customers in terms of lower fuel costs.
15·· ·responsibility ratio.··Is that correct? 15·· · · · · · · · ·So it's part of the coordinated dispatch
16·· · · ·A· ··Yes, that's correct. 16·· ·of the system.··So if you have a coordinated dispatch,
17·· · · ·Q· ··Does that mean that the -- there was a 17·· ·you have to rely on a system to move that power.··That
18·· ·projection of load in order to make that calculation? 18·· ·would be the bulk electric power system.
19·· · · ·A· ··For purposes of the rate year calculation, 19·· · · · · · · · ·MR. WESTERBURG:··I believe I'm finished.
20·· ·there was a forecasted load, which generated a forecast 20·· ·Can I have a 60-second break?
21·· ·of responsibility ratios that was included as part of 21·· · · · · · · · ·JUDGE WALSTON:··Yeah.
22·· ·that. 22·· · · · · · · · ·(Brief pause)
23·· · · ·Q· ··Okay.··Have you made a calculation of what the 23·· · · · · · · · ·MR. WESTERBURG:··No more questions, Your
24·· ·rate year MSS-2 cost would be if you held the load and 24·· ·Honor.
25·· ·responsibility ratio constant from the test year? 25·· · · · · · · · ·JUDGE WALSTON:··Do the Cities have

Page 792 Page 794
·1·· · · ·A· ··Yes, I have. ·1·· ·recross?
·2·· · · ·Q· ··And what is that? ·2·· · · · · · · · ·MR. LAWTON:··Just a bit, Your Honor.
·3·· · · ·A· ··That number was 86 percent of the total.··I ·3·· ·Thank you.
·4·· ·think the adjustment was around $9.4 million, I believe. ·4·· · · · · · · · · · ··RECROSS-EXAMINATION
·5·· · · ·Q· ··That's what the adjustment would be in the rate ·5·· ·BY MR. LAWTON:
·6·· ·year if you held it? ·6·· · · ·Q· ··Mr. Cicio, counsel asked you about your
·7·· · · ·A· ··Yes, the total.··I think the adjustment is ·7·· ·testimony I crossed you about regarding your support for
·8·· ·7-something. ·8·· ·the test year.··You support the test year number.
·9·· · · ·Q· ··Excuse me.··Thank you.··And you address that in ·9·· ·Correct?
10·· ·your rebuttal? 10·· · · ·A· ··That's correct.
11·· · · ·A· ··It's all -- yeah, the actual numbers are 11·· · · ·Q· ··And he also asked you that -- whether you
12·· ·contained in my rebuttal testimony. 12·· ·supported the 9 million pro forma.··Correct?··And you
13·· · · ·Q· ··What is your opinion of whether the rate year 13·· ·do.··Right?
14·· ·change in transmission investment is known? 14·· · · ·A· ··Yes, I support the calculation.
15·· · · ·A· ··I relied on Mr. McCulla's assessment of the 15·· · · ·Q· ··Right.··And you've reviewed the calculations,
16·· ·known and measurable aspect of the MSS-2 -- MSS-2 inputs 16·· ·but you didn't do the calculations?
17·· ·of transmission investment that -- Mr. McCulla believes 17·· · · ·A· ··I have looked at the calculations, that's
18·· ·those are known and measurable changes, then they were 18·· ·correct.
19·· ·known and measurable changes and they were included in 19·· · · ·Q· ··Okay.··And you still don't know who did all the
20·· ·the pro forma adjustment. 20·· ·calculations for the load forecast.··Correct?
21·· · · ·Q· ··My next question for you I think you just 21·· · · ·A· ··I don't know the specific individual.
22·· ·answered, but what is your opinion of whether the change 22·· · · ·Q· ··Okay.··And then you also said that
23·· ·in investment -- excuse me -- the change in the 23·· ·Mr. Considine also supports the 9 million pro forma.
24·· ·investment dollars is measurable? 24·· ·Correct?
25·· · · ·A· ··They are measurable if they were based on 25·· · · ·A· ··Yes, that's correct.

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· · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1· ·1·
· · · · · · · ·TABLE OF CONTENTS (CONTINUED)
··· ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· · · · · · · · · ·PUC DOCKET NO. 39896
·2·
··· ·3·
·PRESENTATION ON BEHALF OF
·
·3· ··ENTERGY
· TEXAS, INC. (CONTINUED)
···
·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4· ·4·
·
··TEXAS,
· INC., FOR· · · · ··)
·AUTHORITY TO CHANGE RATES )
·5· ···· ··CHRIS E. BARRILLEAUX
··AND
· RECONCILE FUEL COSTS, ) ·5·
· · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
·AND OBTAIN DEFERRED· · · ·)
·6·
··ACCOUNTING
· TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
·
·7· ·6·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
···
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·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
··· ·7·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
·
·9·
··· ·8·
· · ··SAMUEL C. HADAWAY
·
10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
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· · · · · · · · · ·HEARING ON THE MERITS
11· ·9·
· · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
···
· · · · · · · · ··Wednesday, May 2, 2012
12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
··· 10·
· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
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13·
··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
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14· 11·
· · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
···
· · · · · · · · · ··TABLE OF CONTENTS
15· 12·
·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
··· 13·
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· · · ·(Volumes 1 through 7, Pages i through xlviii)
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·1·
· · · · · · · · · · ·TABLE OF CONTENTS ·1·
· · · · · · · · ··TABLE OF CONTENTS
·2·
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· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
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·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3·
·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
·OPENING STATEMENT ON BEHALF OF ·4·
·PRESENTATION ON BEHALF OF
··ENTERGY
· TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY
· TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
·5·
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·5·
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···· ··ROBERT D. SLOAN
··OPENING
· STATEMENT ON BEHALF OF ·6·
· · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
·OPENING STATEMENT ON BEHALF OF ·7·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
··CITIES
· (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
· ·8·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
··OPENING
· STATEMENT ON BEHALF OF ·9·
· · ··H. VERNON PIERCE, JR.
·9·
·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
·OPENING STATEMENT ON BEHALF OF 10·
· · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
··OFFICE
· OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
11·
·
11·
·
···· ··MICHAEL P. CONSIDINE
··OPENING
· STATEMENT ON BEHALF OF 12·
· · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
·OPENING STATEMENT ON BEHALF OF 13·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
··THE
· UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
· 14·
· · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
··ENTERGY
· TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15·
·
16·
· ··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··365
···· ··JOSEPH DOMINO 16·
·
··PRESENTATION
· ON BEHALF OF
17·
· · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17·
·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18·
· · ··WALTER C. FERGUSON
18·
· ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··103 19·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
· ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
··PRESENTATION
· ON BEHALF OF 20·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
· · ··JOSEPH DOMINO 21·
·
···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON
22·
· · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
· · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23·
· · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
· · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
· · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
· 25·
·

KENNEDY REPORTING SERVICE, INC.
512.474.2233
 Page 11 (Pages 1538-1541)
Page 1538 Page 1540
·1·· · · · · · · · ·MR. VanMIDDLESWORTH:··Yes. ·1·· ·generation.··So that would be in addition to the
·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Do you see the chart ·2·· ·twenty-nine eighty-nine and the thirty-three seventeen
·3·· ·at the bottom of Page 22? ·3·· ·megawatt numbers purchased.
·4·· · · ·A· ··Yes. ·4·· · · ·Q· ··Okay.··So do you know about what the overall
·5·· · · ·Q· ··Okay.··What does that tell you about the amount ·5·· ·growth in the overall generation is from year-to-year?
·6·· ·of capacity that Entergy is purchasing in what they call ·6·· · · ·A· ··So if we take the purchases plus the owned
·7·· ·the "rate year" versus the test year? ·7·· ·capacity and compare the two, the test year and the rate
·8·· · · ·A· ··That chart shows that as far as purchased ·8·· ·year, it's about a 7.8 percent change in overall
·9·· ·capacity is concerned that the Company anticipates that ·9·· ·capacity.
10·· ·it will need additional capacity or, roughly, if you 10·· · · ·Q· ··By the way, for the rate year, you mentioned
11·· ·take it on average, the test year number, 35,863, is 11·· ·something about the timing of the rate year.··What has
12·· ·about 2,989 megawatts per month, and the rate year would 12·· ·Entergy used for the rate year?
13·· ·go up to 39,807 which suggests an average amount of 13·· · · ·A· ··So the rate year that Entergy uses is the
14·· ·purchases of 3,317 megawatts per month. 14·· ·period -- I might get this wrong.··Let me look --
15·· · · ·Q· ··Can you give me the -- so the numbers you have 15·· ·June 2012 through May 2013.
16·· ·here are megawatt month numbers and you just converted 16·· · · ·Q· ··And I guess that was what they used in their
17·· ·them to annual megawatt numbers? 17·· ·filing?
18·· · · ·A· ··Yes. 18·· · · ·A· ··That's correct.
19·· · · ·Q· ··Can you give me the test year and rate year 19·· · · ·Q· ··And since then, do you know if there's been any
20·· ·megawatts again, please? 20·· ·agreement about the implementation of rates in this
21·· · · ·A· ··2,989 test year; 3,317 rate year. 21·· ·case?
22·· · · ·Q· ··And is that just third-party purchases, or does 22·· · · ·A· ··My understanding is that rates would become
23·· ·that include the effect of all the purchases? 23·· ·effective on June 30th.··So that effectively moves the
24·· · · ·A· ··That's all the purchases.··So it's third-party, 24·· ·rate year up a month -- or back a month.
25·· ·affiliate and MSS-1. 25·· · · ·Q· ··All right.

Page 1539 Page 1541
·1·· · · ·Q· ··And what are the MSS-1? ·1·· · · · · · · · ·Now, you mentioned the importance of unit
·2·· · · ·A· ··The MSS-1 is the reserve equalization payments. ·2·· ·costs.··The 300-plus megawatts of additional purchases,
·3·· ·So the Company takes service from the system.··So to the ·3·· ·what does that go to?··I'm talking about the 300-plus
·4·· ·extent that the Company's owned resources or purchased ·4·· ·megawatts of the difference between the test year and
·5·· ·power resources are less than its obligation, then it ·5·· ·rate year.
·6·· ·will purchase capacity from the other operating ·6·· · · ·A· ··The utility will purchase additional capacity
·7·· ·companies. ·7·· ·mainly because it anticipates serving additional load.
·8·· · · ·Q· ··Is that firm or interruptible capacity? ·8·· · · ·Q· ··It would make sense to purchase additional
·9·· · · ·A· ··It's firm -- the system provides service to the ·9·· ·capacity if you didn't and to have more capacity if you
10·· ·Company and those system resources are network 10·· ·weren't planning on serving more load?
11·· ·resources; therefore, the power is considered firm. 11·· · · ·A· ··No.
12·· · · ·Q· ··Is it -- but does each company operate 12·· · · ·Q· ··Do you know whether that load is wholesale load
13·· ·separately, or is the system generation operated as a 13·· ·or retail load?
14·· ·system? 14·· · · ·A· ··I do not.
15·· · · ·A· ··The system agreement is what basically ties all 15·· · · ·Q· ··Does that matter for purposes of the unit cost
16·· ·six operating companies together as a single unit for 16·· ·analysis?
17·· ·planning and operational purposes.··So for all things in 17·· · · ·A· ··No.
18·· ·effect, it's the system that's providing the service. 18·· · · ·Q· ··Why not?
19·· · · ·Q· ··So, if you show that there's, I think, a little 19·· · · ·A· ··Because initially we're determining the
20·· ·more than 300 megawatts difference in purchases -- 20·· ·Company's overall revenue requirement which includes
21·· · · ·A· ··Yes. 21·· ·retail and wholesale.··Ultimately, once you've
22·· · · ·Q· ··-- is there any difference in the -- I guess 22·· ·established what that number is, then you've got to
23·· ·purchases aren't all of their generation capacity.··They 23·· ·separate the retail and the wholesale to set rates in
24·· ·have -- what else do they have? 24·· ·this case.
25·· · · ·A· ··ETI has about 1200 megawatts of owned 25·· · · ·Q· ··So we've seen the number -- the proposed rate

KENNEDY REPORTING SERVICE, INC.
512.474.2233
 Page 1 (Pages 1-4)
Page i Page iii
· · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1· ·1·
· · · · · · · ·TABLE OF CONTENTS (CONTINUED)
··· ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
· · · · · · · · · ·PUC DOCKET NO. 39896
·2·
··· ·3·
·PRESENTATION ON BEHALF OF
·
·3· ··ENTERGY
· TEXAS, INC. (CONTINUED)
···
·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4· ·4·
·
··TEXAS,
· INC., FOR· · · · ··)
·AUTHORITY TO CHANGE RATES )
·5· ···· ··CHRIS E. BARRILLEAUX
··AND
· RECONCILE FUEL COSTS, ) ·5·
· · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
·AND OBTAIN DEFERRED· · · ·)
·6·
··ACCOUNTING
· TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
·
·7· ·6·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
···
·
·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
··· ·7·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
·
·9·
··· ·8·
· · ··SAMUEL C. HADAWAY
·
10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
···
· · · · · · · · · ·HEARING ON THE MERITS
11· ·9·
· · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
···
· · · · · · · · ··Thursday, May 3, 2012
12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
··· 10·
· · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
·
13·
··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
·
14· 11·
· · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
···
· · · · · · · · · ··TABLE OF CONTENTS
15· 12·
·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
··· 13·
·
· · · · ·(Volumes 1 through 8, Pages i through l)
16·
··· 14·
·
·
17· 15·
·
···
·
18· 16·
·
···
·
19· 17·
·
··· 18·
·
·
20·
··· 19·
·
·
21· 20·
·
···
·
22· 21·
·
··· 22·
·
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23·
··· 23·
·
·
24· 24·
·
···
·
25· 25·
·

Page ii Page iv
·1·
· · · · · · · · · · ·TABLE OF CONTENTS ·1·
· · · · · · · · ··TABLE OF CONTENTS
·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2·
· · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
·3·
·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3·
·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
·OPENING STATEMENT ON BEHALF OF ·4·
·PRESENTATION ON BEHALF OF
··ENTERGY
· TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY
· TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
·5·
·
·5·
·
···· ··ROBERT D. SLOAN
··OPENING
· STATEMENT ON BEHALF OF ·6·
· · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
·OPENING STATEMENT ON BEHALF OF ·7·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
··CITIES
· (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
· ·8·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
··OPENING
· STATEMENT ON BEHALF OF ·9·
· · ··H. VERNON PIERCE, JR.
·9·
·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
·OPENING STATEMENT ON BEHALF OF 10·
· · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
··OFFICE
· OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
11·
·
11·
·
···· ··MICHAEL P. CONSIDINE
··OPENING
· STATEMENT ON BEHALF OF 12·
· · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
·OPENING STATEMENT ON BEHALF OF 13·
· · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
··THE
· UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
· 14·
· · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
··ENTERGY
· TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15·
·
16·
· ··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··365
···· ··JOSEPH DOMINO 16·
·
··PRESENTATION
· ON BEHALF OF
17·
· · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17·
·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18·
· · ··WALTER C. FERGUSON
18·
· ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
··AFTERNOON
· SESSION· · · · · · · · · · · · · · · · · ··103 19·
· · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
· ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
··PRESENTATION
· ON BEHALF OF 20·
· · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
· · ··JOSEPH DOMINO 21·
·
···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON
22·
· · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
· · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23·
· · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
· · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24·
· · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
· · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
· 25·
·

KENNEDY REPORTING SERVICE, INC.
512.474.2233
 Page 43 (Pages 1938-1941)
Page 1938 Page 1940

·1·· ·Frontier is a contract that is already in place.··It was ·1·· · · · · · · · ·And for those reasons, this company could
·2·· ·in place during the test year.··All that remains to be ·2·· ·not procure in a manner that was consistent with our
·3·· ·done is to ensure that the costs, because those costs ·3·· ·general planning principles, as described by Mr. Cooper.
·4·· ·stepped up during the test year as well as the capacity ·4·· ·And so for those reasons, we're now put in the position
·5·· ·stepped up during the test year, that those costs are ·5·· ·of having to sort of make up.··It would be almost like
·6·· ·adequately adjusted for in the adjusted test year. ·6·· ·if you missed a few mortgage payments, you still have to
·7·· · · · · · · · ·Another example is the Calpine contract. ·7·· ·make those mortgage payments up.··And that's kind of
·8·· ·The Calpine contract does not increase the capacity of ·8·· ·where -- the position we are in today, trying to
·9·· ·the Entergy system.··That is a contract that is already ·9·· ·rebalance the company's portfolio in a way that's
10·· ·in place.··What will happen at the end of this month, 10·· ·consistent with those planning principles.
11·· ·that contract will be allocated differently to reflect 11·· · · ·Q· ··And can you explain -- do you have an idea of
12·· ·the fact that overhang of retail competition has been 12·· ·when the company on its current track would catch up and
13·· ·removed and now we are allocating modern and highly 13·· ·no longer become a short company?
14·· ·efficient, flexible generation to Entergy Texas; and 14·· · · ·A· ··No.··That -- that's a question --
15·· ·that allocation is consistent with those criteria that 15·· · · ·Q· ··But we're not there now?
16·· ·Mr. Cooper talked about in his testimony. 16·· · · ·A· ··No, we certainly are not.
17·· · · · · · · · ·And so for those reasons, no, I don't 17·· · · ·Q· ··You had mentioned that the Calpine contract was
18·· ·believe that that example is consistent. 18·· ·not brought for serving new load.··Does it nonetheless
19·· · · ·Q· ··And you mentioned in your answer -- and this 19·· ·provide benefits to customers?
20·· ·also came up, I think, from Mr. Lawton -- that ETI is 20·· · · ·A· ··Yes, sir, it does.··The Calpine contract -- and
21·· ·short.··Can you explain -- 21·· ·that's the contract, as I mentioned, is already
22·· · · · · · · · ·MS. FERRIS:··Your Honor, I object.··This 22·· ·providing service to the system.··It's currently not
23·· ·is beyond the scope of my cross-examination. 23·· ·allocated to ETI.··However, I believe it's -- at the end
24·· · · · · · · · ·JUDGE WALSTON:··Well, but there was also 24·· ·of this month, it will begin providing service to
25·· ·other cross before the lunch break. 25·· ·Entergy Texas customers, a very attractive contract.··It

Page 1939 Page 1941

·1·· · · · · · · · ·MS. FERRIS:··Okay.··You're -- I'm sorry. ·1·· ·has an attractive heat rate, a 7500 heat rate; and the
·2·· · · · · · · · ·JUDGE WALSTON:··Right.··Yeah. ·2·· ·cost of that contract, given, for instance, the fact
·3·· · · · · · · · ·MR. NEINAST:··I agree. ·3·· ·that it also displaces MSS-1 capacity, gas prices would
·4·· · · · · · · · ·JUDGE WALSTON:··No problem. ·4·· ·probably have to drop below a dollar per MMBtu for that
·5·· · · · · · · · ·MR. NEINAST:··It is beyond hers. ·5·· ·contract not to be economic.··In other words, at gas
·6·· · · · · · · · ·MS. FERRIS:··Sorry about that. ·6·· ·prices today, the fuel savings alone from that contract
·7·· · · ·Q· ··(BY MR. NEINAST)··Mr. Lawton had asked you, I ·7·· ·pay for that contract over multiple times.
·8·· ·believe -- I believe it was Mr. Lawton -- about the ·8·· · · ·Q· ··And that benefits ETI's customers?
·9·· ·company being short, and you had started to talk about ·9·· · · ·A· ··Yes, sir, it does.
10·· ·why the company is short and it's been there -- can you 10·· · · ·Q· ··You might -- let me ask the question again; and
11·· ·go into more detail?··Why is the company short?··What is 11·· ·if you've already answered this question, then, please,
12·· ·it doing about it? 12·· ·you don't need to go any further into it.
13·· · · ·A· ··Yeah, and, you know, primarily, what -- what 13·· · · · · · · · ·But what I had written down, based on the
14·· ·happened is, we were required to go to retail 14·· ·cross-examination, was some discussion you had with
15·· ·competition; and that requirement began in 1999 with 15·· ·Mr. VanMiddlesworth, and, I think, Mr. Lawton, asking
16·· ·the -- with the -- if I recall correctly, the objective 16·· ·you about whether the post-test year PPA costs can be
17·· ·to go to retail competition in 2002.··However, for a 17·· ·known and measurable?
18·· ·number of reasons, we were not able to do that, and so 18·· · · ·A· ··Yes, sir.
19·· ·we had this sort of constant overhang that we're going 19·· · · ·Q· ··Can you explain why the costs for those
20·· ·to go to retail competition by such-and-such date. 20·· ·contracts can be known and measurable?
21·· ·Constantly a moving target.··You really can't go out and 21·· · · ·A· ··I'll try.
22·· ·procure long-term cash capacity.··You really can't go 22·· · · · · · · · ·The costs in question here -- and I sort
23·· ·out and build a new highly efficient, modern generating 23·· ·of ticked off a number of these.··One of them is the
24·· ·plant in a world where your customers could be severed 24·· ·Frontier contract.··That Frontier contract has probably
25·· ·by someone else in the very near future. 25·· ·been in place -- I don't -- close to a decade, perhaps.

KENNEDY REPORTING SERVICE, INC.
512.474.2233
 Page 44 (Pages 1942-1945)
Page 1942 Page 1944

·1·· ·Not long after the plant was completed, we began ·1·· ·is, one of the routine sort of adjustments that are made
·2·· ·contracting for it. ·2·· ·are, for instance, merit increases for employees.··And
·3·· · · · · · · · ·What we're talking about here is that ·3·· ·so that's measured -- a known and measurable change.
·4·· ·contract stepping up from -- I believe it's ·4·· ·The fact of the matter is, the day after that
·5·· ·150 megawatts up to 300 megawatts.··And so all that ·5·· ·implementation of that merit increase or the acceptance
·6·· ·needs to be done is to recognize those additional costs ·6·· ·of that as a known and measurable change, an employee
·7·· ·because that step-up occurs in the -- in the midst of ·7·· ·could resign from the company; and, therefore, the costs
·8·· ·the test year.··It doesn't occur through the entire test ·8·· ·would deviate.··But, in general, those cost changes are
·9·· ·year, so it doesn't fully recognize the cost of that ·9·· ·known, they are measurable, and those little deviations
10·· ·contract.··That contract is needed to serve load today, 10·· ·are just not that much a significant part of the
11·· ·and because we have quite a bit of experiences, we have 11·· ·outcome.
12·· ·a good understanding of what the costs are today and 12·· · · ·Q· ··And, finally, on this purchased power topic,
13·· ·what the costs will be in the future. 13·· ·you'd discussed the Frontier contract, the Calpine
14·· · · · · · · · ·Similarly, Calpine, we have -- that is a 14·· ·contract.··I think there's another, the SRMPA?
15·· ·contract that we have some experience with as well.··The 15·· · · ·A· ··Yes, sir.
16·· ·capacity costs are well known.··It's based upon our 16·· · · ·Q· ··Was there anything about that contract that --
17·· ·experience and based upon a negotiated contract.··I 17·· · · ·A· ··With the SR --
18·· ·understand that there could be instances, as indicated 18·· · · ·Q· ··-- makes it not known and measurable?
19·· ·by Mr. VanMiddlesworth, that there could be some 19·· · · ·A· ··Well, the SRMPA has a very straightforward $3
20·· ·deviations from the actual payments made.··But, you 20·· ·per kW a month stated rate.··So it's very easy to
21·· ·know, the history there is those are very, very small 21·· ·calculate what those known and measurable costs are.
22·· ·deviations from the actual contracted costs. 22·· · · ·Q· ··My next topic -- almost done -- is MSS-1.··You
23·· · · · · · · · ·When we negotiate those contracts, our 23·· ·were asked some questions by -- I think it was
24·· ·intent is to get the full benefit of that capacity. 24·· ·Mr. VanMiddlesworth.··Generally, I mean, to cut to the
25·· ·Those provisions are generally intended to enforce and 25·· ·chase, there was discussion of maintaining test year

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·1·· ·make sure that we get the full benefits of that ·1·· ·loads by taking into account rate year costs.··In the
·2·· ·capacity.··The counterparties intend to get the full ·2·· ·course of that discuss -- and Mr. VanMiddlesworth was
·3·· ·benefit of those capacity costs.··They want to make sure ·3·· ·asking you for some analyses in doing different things
·4·· ·that in the event they do have an outage or need to take ·4·· ·with Entergy Arkansas.··I remember that.
·5·· ·the unit off-line, that it's done in a way that's ·5·· · · ·A· ··Yes, sir.
·6·· ·consistent so they can continue to get paid their full ·6·· · · ·Q· ··But in the course of that discussion, you said
·7·· ·capacity. ·7·· ·something about an analysis by Mr. Cooper that involved
·8·· · · · · · · · ·So, for those reasons, we have a need -- ·8·· ·4.5 million.··What was that -- what was that?
·9·· ·we know what those costs are.··They are measurable, and ·9·· · · ·A· ··Yes, sir.··That is extremely relevant.
10·· ·I think that is consistent with the known and measurable 10·· · · · · · · · ·The situation that was being described by
11·· ·standard. 11·· ·Mr. VanMiddlesworth is what if EAI had higher load,
12·· · · ·Q· ··Well, and also you mentioned inconsistencies 12·· ·would that result -- in the test -- in the rate year,
13·· ·among contracts.··If a contract -- go back to some -- 13·· ·what if they had higher load?··What if ETI had higher
14·· ·not the contract we're talking about here, but some 14·· ·load?··What if they had lower load?
15·· ·contract that's already in base rates. 15·· · · · · · · · ·Mr. Cooper examined that very situation.
16·· · · · · · · · ·Once it's in base rates, does that mean 16·· ·What he did is he locked in the responsibility ratios,
17·· ·there are no inconsistencies in the costs going forward, 17·· ·and what I mean by that is the actual load that was in
18·· ·or those fluctuate so it's not absolutely without doubt 18·· ·the test year was locked in via those responsibility
19·· ·known that it is fixed and never going to change during 19·· ·ratios.··And then he measured for that rate year, what
20·· ·its life? 20·· ·would have been the difference in cost for MSS-1 if
21·· · · ·A· ··Well, while those fluctuations are rather 21·· ·nothing changed with regard to those -- that load
22·· ·small, the fact is, even those contracts in base rates 22·· ·growth.··No operating company deviated whatsoever.··They
23·· ·can fluctuate.··It's just that there's not any real 23·· ·actually used the test year load.··The result of that
24·· ·significant deviation from that. 24·· ·was approximately $4.5 million reduction in our MSS-1
25·· · · · · · · · ·And another example of this, in my mind 25·· ·cost as a result of locking in those loads.

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·1·· · · · · · · · ·MR. NEINAST:··No further questions. ·1·· · · · · · · · · · ·RECROSS-EXAMINATION
·2·· · · · · · · · · ··CLARIFYING EXAMINATION ·2·· ·BY MR. LAWTON:
·3·· ·BY JUDGE WALSTON: ·3·· · · ·Q· ··Mr. May, you would agree that the company has
·4·· · · ·Q· ··Okay.··I want to ask a couple of clarifying ·4·· ·had load growth over the past number of years?
·5·· ·questions, if I can, and I may just show my lack of ·5·· · · ·A· ··Yes, sometimes --
·6·· ·understanding. ·6·· · · ·Q· ··Some years --
·7·· · · · · · · · ·But if I understood your testimony, the ·7·· · · ·A· ··-- load growth, sometimes no.
·8·· ·new purchased power contracts are being -- or have been ·8·· · · ·Q· ··Okay.··And you would agree that the -- between
·9·· ·entered into to account for the shortage of capacity. ·9·· ·the test year and the rate year, the company is
10·· ·Correct? 10·· ·projecting load to grow?
11·· · · ·A· ··Yes, sir. 11·· · · ·A· ··Yes, sir.
12·· · · ·Q· ··Okay.··And not for load growth.··Correct? 12·· · · ·Q· ··Okay.··And if load growth occurs and the
13·· · · ·A· ··Yes.··In this case, the needs that are driven 13·· ·company does not buy any additional capability, what
14·· ·by the allocation -- for instance, Calpine.··That is a 14·· ·happens?··Does it become more short?
15·· ·contract that already exists on the system.··What is 15·· · · ·A· ··That would depend upon what happens with the
16·· ·happening right now, none of that comes to ETI.··But 16·· ·other operating companies.
17·· ·what will happen is, 50 percent of that will be 17·· · · ·Q· ··Fair enough.··All else equal, to use one of
18·· ·allocated to ETI.··The other 50 percent will be to 18·· ·Mr. VanMiddlesworth's phrases.
19·· ·Entergy Gulf States Louisiana.··That is essentially 19·· · · ·A· ··To the extent that load grows and we do not add
20·· ·recognizing the fact that this company now has some 20·· ·capacity, it is an accurate statement that the company
21·· ·resolution less uncertainty about what its future is, 21·· ·will become more short.
22·· ·and so it's allocating long-term contracts to meet its 22·· · · ·Q· ··Okay.··So we know that load grows from year to
23·· ·needs. 23·· ·year, or it's projected.··Correct?
24·· · · ·Q· ··But what I was leading up to is that capacity 24·· · · ·A· ··Certainly a possibility.
25·· ·is added, then the MSS-1 costs would go down? 25·· · · ·Q· ··All right.··And is some of the purchased power

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·1·· · · ·A· ··Yes, sir. ·1·· ·here in this case being purchased to replace contracts
·2·· · · ·Q· ··Okay. ·2·· ·that are dropping off in the test year, or do you know?
·3·· · · ·A· ··It is a very straightforward calculation. ·3·· · · ·A· ··That direct relationship, I can't speak to.
·4·· · · ·Q· ··Okay.··And actually, that's all I want to know. ·4·· · · ·Q· ··That's something I'd ask Mr. Cooper?
·5·· · · · · · · · ·But just can you tell me, just in ballpark ·5·· · · ·A· ··You certainly can.··But certainly, it's a fact
·6·· ·amounts, is the increase and the decrease, is that a ·6·· ·that there are changes in the overall makeup.
·7·· ·wash or is one more or less? ·7·· · · ·Q· ··Fair enough.
·8·· · · ·A· ··It depends on the contract, sir.··For instance, ·8·· · · · · · · · ·MR. LAWTON:··Your Honor, I pass the
·9·· ·the Calpine contract is priced higher than MSS-1.··Now, ·9·· ·witness.··Thank you.
10·· ·when you look at our rate year MSS-1 calculation, it 10·· · · · · · · · ·Thank you, Mr. May.
11·· ·includes all that that you just identified there.··All 11·· · · · · · · · ·JUDGE WALSTON:··TIEC?
12·· ·of that capacity results, and that's what's reflected in 12·· · · · · · · · ·MR. VanMIDDLESWORTH:··Yes.
13·· ·our rate year, lower MSS-1 cost. 13·· · · · · · · · · · ··RECROSS-EXAMINATION
14·· · · · · · · · ·And in the case of Calpine, it has higher 14·· ·BY MR. VanMIDDLESWORTH:
15·· ·cost per kW than MSS-1 costs would be.··So the net cost 15·· · · ·Q· ··Following up on Judge Walston's questions, ETI
16·· ·of that contract -- net after the fact that MSS-1 goes 16·· ·in this filing shows that it's projecting to purchase
17·· ·down -- is still a positive value.··That's reflected in 17·· ·about 600 megawatts more capacity in the rate year,
18·· ·our rate year clause. 18·· ·third-party purchases, than in the test year.··Is that
19·· · · · · · · · ·In the case of SRMPA, this is a contract. 19·· ·right?
20·· · · ·Q· ··You've gone beyond my -- I got the answer that 20·· · · ·A· ··Let me think about that for a moment.··How much
21·· ·I wanted. 21·· ·is the number again?
22·· · · ·A· ··Thank you. 22·· · · ·Q· ··About 600 megawatts.
23·· · · ·Q· ··But I appreciate it. 23·· · · ·A· ··It's probably approaching 600.
24·· · · · · · · · ·JUDGE WALSTON:··Okay.··Further cross? 24·· · · ·Q· ··Okay.··And ETI is also projecting to purchase
25·· · · · · · · · ·MR. LAWTON:··I do.··Thank you, Your Honor. 25·· ·about 300 megawatts less of MSS-1 capacity in the rate

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·1·· ·year than in the test year.··Correct? ·1·· ·including MSS-1, ETI is proposing to add about
·2·· · · ·A· ··I can't tell you the specific amount, sir. ·2·· ·300 megawatts more in the rate year than in the test
·3·· · · ·Q· ··You don't know? ·3·· ·year.··Right?
·4·· · · ·A· ··I don't have that document in front of me. ·4·· · · ·A· ··If you put that in an exhibit, I can confirm
·5·· · · ·Q· ··Okay.··You know it's a lot less than the amount ·5·· ·that.··I don't know the number precisely.
·6·· ·of purchased capacity? ·6·· · · ·Q· ··Okay.··We can -- that's a -- we could get that
·7·· · · ·A· ··Absolutely, for the very reasons we discussed. ·7·· ·from, I think, H-12 in the rate filing, couldn't we?
·8·· · · ·Q· ··Oh, and those -- ·8·· · · ·A· ··I'm sorry.
·9·· · · ·A· ··Those reasons being that as you add capacity, ·9·· · · ·Q· ··We could do that calculation from H-12?··I'm
10·· ·that the MSS-1 amounts would be reduced. 10·· ·not going to make you do the calculation.··I think it's
11·· · · ·Q· ··Right.··But why wouldn't they be reduced by the 11·· ·in the record.
12·· ·same amount of the capacity you're adding? 12·· · · ·A· ··Okay.
13·· · · ·A· ··There would be a number of reasons why that 13·· · · ·Q· ··You don't have any reason to disagree?
14·· ·would be.··One of the primary reasons would be the fact 14·· · · ·A· ··No.··I believe that's right.··The company will
15·· ·that the system has other changes.··There are capacity 15·· ·be adding capacity.··Correct.
16·· ·being acquired on the other operating companies as well. 16·· · · ·Q· ··All right.··And when you add -- when a company
17·· ·We will be acquiring capacity at Arkansas and 17·· ·adds capacity, they need -- if a company is planning on
18·· ·Mississippi, I believe.··Those will likely occur this 18·· ·experiencing load growth, it needs to add a little more
19·· ·year. 19·· ·in capacity than the estimated load growth.··Right?
20·· · · ·Q· ··And you're saying the capacity acquired by 20·· ·Talking about reserve margins.
21·· ·Arkansas and Mississippi means that the MSS-1 won't 21·· · · ·A· ··If the -- okay.··I'm sorry.
22·· ·decrease as much as the purchased capacity for ETI? 22·· · · · · · · · ·To the extent that you have a hundred
23·· · · ·A· ··All things being relative. 23·· ·megawatts of load growth, planning principles would
24·· · · ·Q· ··All right.··And so you -- do you dispute that 24·· ·suggest, if the company was perfectly balanced in the
25·· ·ETI projects, when you add all the purchased capacity, 25·· ·first place, that they should add, for instance, 115.

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·1·· ·purchased -- all the purchased capacity, third party, ·1·· · · ·Q· ··Right.··And the 115 is the reserve --
·2·· ·and we sometimes -- by the way, when we talk -- when you ·2·· · · ·A· ··Reserve margin.
·3·· ·use the term "short," you're not talking about all ·3·· · · ·Q· ··And that's built into your rates.··I mean,
·4·· ·purchased capacity as we use the term for the purchased ·4·· ·everybody that buys a megawatt from you is buying -- is
·5·· ·power rider.··Right?··You're talking about a subset of ·5·· ·paying for the reserve margin as a part of the rate?
·6·· ·that. ·6·· · · ·A· ··Theoretically.
·7·· · · ·A· ··I'm not sure I understand the question.··I'm ·7·· · · ·Q· ··All right.
·8·· ·sorry. ·8·· · · ·A· ··It should include that.
·9·· · · ·Q· ··When you say they're short, when ETI is short, ·9·· · · ·Q· ··All right.··So 300 megawatts of additional
10·· ·don't you mean that if you look at just the purchased 10·· ·purchased capacity would serve a little less than
11·· ·power and the legacy contracts and the other affiliate 11·· ·that -- I'm not going to -- can't do the math right
12·· ·contracts, that that -- and you don't look at MSS-1, you 12·· ·here -- of actual load growth?
13·· ·just look at the stuff either owned or purchased 13·· · · ·A· ··You know, I'm not sure I can agree with that
14·· ·directly by ETI, that that's not sufficient to meet 14·· ·without seeing the facts.
15·· ·their load? 15·· · · ·Q· ··Okay.··Well, you may be able to do that.··If
16·· · · ·A· ··That's correct. 16·· ·somebody said, "Phillip May, I need -- we're going to
17·· · · ·Q· ··And then you have to add -- and then the way 17·· ·have a hundred megawatts of load growth next year, and
18·· ·that ETI becomes not short anymore is it purchases 18·· ·we need the capacities -- you need to get capacity to
19·· ·MSS-1. 19·· ·meet that," how many megawatts capacity would you need,
20·· · · ·A· ··Yes, I think that's a reasonably accurate 20·· ·more or less, to do that?
21·· ·statement. 21·· · · ·A· ··Depends on a number of factors.··But if this
22·· · · ·Q· ··Okay.··I think sometimes the record -- it's 22·· ·were a standalone company, it would probably add
23·· ·probably partially my fault.··Sometimes the record has 23·· ·20 percent more than that hundred.
24·· ·gotten a little fuzzy about what that means. 24·· · · ·Q· ··Okay.··A little -- and that's the reserve
25·· · · · · · · · ·Now, but all in, all purchased capacity, 25·· ·margin?

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·1·· · · ·A· ··Yes. ·1·· ·attractive.
·2·· · · ·Q· ··Okay.··Now, you've previously taken the ·2·· · · ·Q· ··But the fallback proposal did not deal with
·3·· ·position that it was appropriate in looking at the rate ·3·· ·load growth or load shrinkage or whatever happened.··It
·4·· ·year purchased power to take load growth into account to ·4·· ·just stuck with the test year sales?
·5·· ·make sure that ETI doesn't over-recover, haven't you? ·5·· · · ·A· ··Yes, sir, the fallback proposal is consistent
·6·· · · ·A· ··Are you referring to the incremental capacity ·6·· ·with the current ratemaking in the PUCT.
·7·· ·rider testimony? ·7·· · · ·Q· ··Well, I was just --
·8·· · · ·Q· ··No.··I'm referring to actually the position you ·8·· · · · · · · · ·MR. VanMIDDLESWORTH:··I'm going to take
·9·· ·originally filed in this case. ·9·· ·issue with that and move to strike the volunteering that
10·· · · ·A· ··Which was with regard to a capacity rider. 10·· ·its current -- consistent with current practice at the
11·· ·Correct? 11·· ·PUC.
12·· · · ·Q· ··I'm just -- and in that -- in your initial 12·· · · · · · · · ·MR. NEINAST:··I object.··He opened up the
13·· ·proposal, it was your position that the -- you should 13·· ·question by going back to the exhibit.
14·· ·take load growth into account, revenue growth into 14·· · · · · · · · ·MR. VanMIDDLESWORTH:··My question was
15·· ·account, in addition to costs. 15·· ·simply, is this what you proposed?··His answer was --
16·· · · ·A· ··Yes.··In my original testimony, I indicated 16·· ·I'm not sure if he said yes, but then he said, "And
17·· ·that we would true that capacity up.··The only way to do 17·· ·that's consistent with PUCT practice."
18·· ·that is to consider load growth. 18·· · · · · · · · ·MR. NEINAST:··But it --
19·· · · ·Q· ··And you indicated that if revenues collected 19·· · · · · · · · ·JUDGE WALSTON:··I think his answer -- you
20·· ·from the rider, which is how you proposed it, were 20·· ·asked another question about, well, what you're doing
21·· ·increased due to sales, then that would automatically be 21·· ·now in base rates, and he was responding to the base
22·· ·reflected in updates to the rider via over or under 22·· ·rate question.
23·· ·recovery? 23·· · · · · · · · ·MR. VanMIDDLESWORTH:··Oh, okay.
24·· · · ·A· ··Yes, sir, that would be part of the 24·· · · · · · · · ·JUDGE WALSTON:··Yeah.
25·· ·reconciliation process. 25·· · · · · · · · ·MR. VanMIDDLESWORTH:··Let me withdraw my

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·1·· · · ·Q· ··So this problem we've talked about here under ·1·· ·motion to strike.
·2·· ·the purchased power rider, as you proposed it, if this ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Are you aware of any
·3·· ·hypothetical utility was adding -- ·3·· ·prior PUC decision where the PUC has said, "We're going
·4·· · · ·A· ··Yes, sir. ·4·· ·to look out two years past the test year and estimate
·5·· · · ·Q· ··-- a hundred dollars to meet an expected ·5·· ·purchased power costs and then apply those to test year
·6·· ·10 percent load -- ·6·· ·billing determinants"?··Any other PUC case ever in
·7·· · · ·A· ··Yes, sir. ·7·· ·Texas?
·8·· · · ·Q· ··-- increase on TIEC Exhibit 23 and that's what ·8·· · · ·A· ··Well, I think a number of these cases have been
·9·· ·they had -- ·9·· ·settled, so that would be hard to say.
10·· · · ·A· ··Yes, sir. 10·· · · ·Q· ··Are you aware of any PUC decision?
11·· · · ·Q· ··-- then there would be no over or under 11·· · · ·A· ··I -- I can't recall any specific PUCT finding
12·· ·recovery because it would be trued up? 12·· ·on that.
13·· · · ·A· ··That's right. 13·· · · ·Q· ··I mean, this -- we're treading new ground.
14·· · · ·Q· ··But when the Commission rejected your purchased 14·· ·This -- what you proposed here has never been done by
15·· ·capacity rider in this case, your position after that 15·· ·this commission, has it?
16·· ·was, "Well, just take the purchased capacity costs and 16·· · · ·A· ··I don't agree.
17·· ·apply it to test year sales"? 17·· · · ·Q· ··Okay.··Then tell me when this commission has
18·· · · ·A· ··Well, I think our position was kind of an 18·· ·ordered the use of test year -- or of rate year
19·· ·either/or.··We represented that had we not had a 19·· ·purchased capacity and test year sales numbers.
20·· ·capacity -- if we did not get a capacity rider, then you 20·· · · ·A· ··In my mind, this is really not different than a
21·· ·would use these for base rates. 21·· ·merit increase adjustment.··It's known; it's measurable.
22·· · · ·Q· ··Right.··Right.··And I'm showing that the 22·· ·Sure, it extends beyond the test year, but in this case,
23·· ·initial proposal dealt with this, and you thought that 23·· ·the capacity that this company must add is not being
24·· ·was a reasonable thing to do. 24·· ·added because we have some great load growth
25·· · · ·A· ··I think the initial proposal is still very 25·· ·expectation.

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·1·· · · ·Q· ··I'm just asking -- ·1·· ·contract was in place, that there were never ever two
·2·· · · ·A· ··And I'm answering the question, sir. ·2·· ·months that had the same capacity payment from ETI to
·3·· · · · · · · · ·JUDGE WALSTON:··I think you went beyond ·3·· ·Frontier?
·4·· ·his question. ·4·· · · ·A· ··I don't have that data in front of me, but I
·5·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Yeah.··My question, ·5·· ·don't believe that there are huge variations in the
·6·· ·sir, is, tell me the case where there's a PUC decision ·6·· ·capacity cost.··Now, it is a shaped product --
·7·· ·that says, "We will look two years out for purchased ·7·· · · ·Q· ··My question --
·8·· ·capacity and come up with a projection of that and apply ·8·· · · · · · · · ·JUDGE WALSTON:··Okay.
·9·· ·it to test year sales."··Tell me the case. ·9·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Can you answer my
10·· · · ·A· ··Sir, I can't point to specific language in a 10·· ·question?
11·· ·PUCT finding. 11·· · · · · · · · ·JUDGE WALSTON:··Try and just answer his
12·· · · ·Q· ··Can you point to any language about purchased 12·· ·question as concisely as you can.
13·· ·power capacity that does that? 13·· · · · · · · · ·WITNESS MAY:··I'm sorry.
14·· · · ·A· ··No. 14·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··We won't badger each
15·· · · · · · · · ·MR. NEINAST:··Objection, badgering the 15·· ·other.
16·· ·witness. 16·· · · · · · · · ·Do you -- isn't it a fact that for the
17·· · · · · · · · ·JUDGE WALSTON:··I don't know that he's 17·· ·entire ten months that contract was in place, there were
18·· ·badgering, but I think he's already told you before he 18·· ·no two months that had the same capacity payment from
19·· ·doesn't know -- 19·· ·ETI, if you know?
20·· · · · · · · · ·MR. VanMIDDLESWORTH:··Okay. 20·· · · ·A· ··I don't have the contract in front of me,
21·· · · · · · · · ·JUDGE WALSTON:··-- a finding or a case. 21·· ·but --
22·· ·So it's repetitive, if nothing else. 22·· · · ·Q· ··I'm just asking you --
23·· · · · · · · · ·MR. VanMIDDLESWORTH:··I haven't had an 23·· · · ·A· ··-- on a dollar basis, I would suspect that
24·· ·objection levied against me in years, Your Honor.··I 24·· ·that's correct.
25·· ·thought the witness was badgering me. 25·· · · ·Q· ··All right.··And, in fact, weren't there

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·1·· · · · · · · · ·(Laughter) ·1·· ·adjustments made for availability during the test year
·2·· · · · · · · · ·MR. NEINAST:··But you asked the question. ·2·· ·for --
·3·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Let me go to another ·3·· · · ·A· ··I suspect --
·4·· ·subject. ·4·· · · ·Q· ··-- the Frontier contract?
·5·· · · · · · · · ·You mentioned a Frontier contract, and it ·5·· · · ·A· ··Yes, sir.··I suspect there could have been.
·6·· ·was actually in place during the test year? ·6·· · · ·Q· ··And, in fact, weren't there months where the
·7·· · · ·A· ··Yes. ·7·· ·payments under the Frontier contract were about half of
·8·· · · ·Q· ··And that it was at a lower megawatt level. ·8·· ·the full contract amount?
·9·· ·Right? ·9·· · · ·A· ··I'm not familiar with that, but it is a shaped
10·· · · ·A· ··Yes.··It straddled the test year, so there was 10·· ·product.
11·· ·an increase in the capacity and the cost that was in the 11·· · · ·Q· ··Yes.
12·· ·midst of the test year. 12·· · · ·A· ··And that may be driving that.
13·· · · ·Q· ··Okay.··And I'm going to try to avoid asking you 13·· · · ·Q· ··Yes.··So in some months, all other things being
14·· ·anything that's highly sensitive.··We know there's a 14·· ·equal, even if they performed completely --
15·· ·Frontier contract. 15·· · · ·A· ··Yes, sir.
16·· · · ·A· ··Yes, sir. 16·· · · ·Q· ··-- there would be higher capacity costs than
17·· · · ·Q· ··I think we may know the megawatts, but I'm not 17·· ·others?
18·· ·sure.··So I'm going to try to avoid that. 18·· · · ·A· ··Yes, sir.
19·· · · · · · · · ·But for the first ten months of the test 19·· · · ·Q· ··But, in fact, for the Frontier contract, in the
20·· ·year, the Frontier contract was in one level, and then 20·· ·test year, there were months when -- I mean, if that
21·· ·it went to another level. 21·· ·were the case, there were a number of months that had
22·· · · ·A· ··Yes, sir. 22·· ·the same percentage applicable.··Right?··June, July,
23·· · · ·Q· ··Now, you talked about the stability of that 23·· ·August, September all have the same?
24·· ·contract, but isn't it the fact -- a fact that for the 24·· · · ·A· ··Yes, sir.
25·· ·first ten months of the test year, when that Frontier 25·· · · ·Q· ··And so everybody knows what we're talking about

KENNEDY REPORTING SERVICE, INC.
512.474.2233
II II
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, §
INC. FOR AUTHORITY TO CHANGE § BEFORE THE STATE OFFICE
RA TES, RECONCILE FUEL COSTS, § OF
AND OBTAIN DEFERRED § ADMINISTRATIVE HEARINGS
ACCOUNTING TRFATMENT §

DIRECT TESTIMONY AND EXHIBITS

OF

MARK E. GARRETT

ON BEHALF OF

CITIES SERVED BY ENTERGY TEXAS, INC.

MARCH 27, 2012

Mark Garrett
Garrett Group, LLC
Oklahoma City, Oklahoma
Blank Page
 TABLE OF CONTENTS

Section I. Witness Identification ........................................................................................... 3

Section II. Purpose of Testimony ............................................................................................ 4

Section III. Rate Base Adjustments

A. FIN 48 Tax Adjustment .................................................................................. 5
B. Prepaid Pension Costs in Rate Base ............................................................... 7
C. Rita Regulatory Asset .................................................................................... 11

Section IV. Payroll and Benefits Expense Adjustments

A. ET! Payroll Adjustment ............................................................................... 12
B. ESI Payroll Adjustment ................................................................................ 19
C. Lewis Creek and Sabine Payroll Adjustments ........................................... 23
D. Above-Market Payroll Cost Adjustments ................................................... 25
E. Incentive Compensation Adjustment ........................................................... 27
F. Supplemental Executive Retirement Compensation .................................. 54
G. Above-Market Benefit Costs Adjustment .................................................. 58
H. Ad Valorem Tax Expense Adjustment ....................................................... 60

Section V. MISO Transition Expense Adjustment ............................................................ 61

Section VI. River Bend Decommissioning Expense Adjustment ....................................... 64

Exhibit MG-1 Qualifications of Mark E. Garrett ......................................................... Attached

Exhibit MG-2 Garrett Adjustment Workpapers .......................................................... Attached

Direct Testimony of Mark E. Garrett Page 2 of 58
Docket No. 39896
Blank Page
 SECTION I. WITNESS IDENTIFICATION

1 Q: PLEASE STATE YOUR NAME AND OCCUPATION.

2 A: My name is Mark Garrett and I am the President of Garrett Group, LLC, a firm

3 specializing in public utility regulation, litigation and consulting services.

4

5 Q: WOULD YOU PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND

6 AND YOUR PROFESSIONAL EXPERIENCE RELATED TO UTILITY

7 REGULATION?

8 A: I am an attorney and a certified public accountant. I work as a consultant in the area of

9 public utility regulation. I received my bachelor's degree from the University of

10 Oklahoma and completed post graduate hours at Stephen F. Austin State University and

11 at the University of Texas at Arlington and Pan American. I received my juris doctorate

12 degree from Oklahoma City University Law School and was admitted to the Oklahoma

13 Bar in 1997. I am a Certified Public Accountant licensed in the States of Texas and

14 Oklahoma with a background in public accounting, private industry, and utility

15 regulation. In public accounting, as a staff auditor for a firm in Dallas, I primarily

16 audited financial institutions in the State of Texas. In private industry, as controller for a

17 mid-sized ($300 million) corporation in Dallas, I managed the Company's accounting

18 function, including general ledger, accounts payable, financial reporting, audits, tax

19 returns, budgets, projections, and supervision of accounting personnel. In utility

20 regulation, I served as an auditor in the Public Utility Division of the Oklahoma

21 Corporation Commission from 1991 to 1995. In that position, I managed the audits of

Direct Testimony of Mark E. Garrett Page 3 of65
Docket No. 39896
 l major gas and electric utility companies in Oklahoma. Since leaving the Commission, I

2 have worked on various rate cases and other regulatory proceedings on behalf of

3 industrial interveners, gas pipelines and the Attorney General of Oklahoma.

4

5 Q: HAVE YOUR QUALIFICATIONS BEEN ACCEPTED IN PROCEEDINGS

6 DEALING WITH COST-OF-SERVICE AND OTHER RATEMAKING ISSUES?

7 A: Yes, they have. A more complete description of my qualifications and a list of the

8 proceedings in which I have been involved are included at the end of my testimony.

9

10 Q: ON WHOSE BEHALF ARE YOU APPEARING IN THESE PROCEEDINGS?

11 A: I am appearing on behalf of Certain Cities Served by Entergy Texas, Inc. ("Cities"). 1

SECTION II. PURPOSE OF TESTIMONY

12 Q: WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?

13 A: The purpose of my testimony is to address various revenue requirement issues identified

14 in the Company's rate case application and to provide the Commission with

15 recommendations for the resolution of these issues. I address several rate base issues,

16 including the Company's Prepaid Pension Asset, the Rita Regulatory Asset, Uncertain

17 Tax Positions, and several operating expense issues, including Payroll Expense,

18 Incentive Compensation, Employee Benefits Expense, Supplemental Executive

1
Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville,
Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches,
Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.
Direct Testimony of Mark E. Garrett Page 4 of 65
Docket No. 39896
 l Retirement Expense, Ad Valorem Tax Expense, MISO Transition Costs and River Bend

2 Decommissioning Costs. In total, my recommended adjustments reduce the Company's

3 requested revenue requirement increase by approximately $34.835 million.

SECTION III. A. FIN 48 TAX ADJUSTMENT

4 Q: HAVE YOU REVIEWED ETI'S PROPOSED FIN 48 ADJUSTMENT TO

5 ACCUMULATED DEFERRED FEDERAL INCOME TAX ("AD FIT")?

6 A: Yes. In June 2006, the Financial Accounting Standards Board issued Financial

7 Interpretation 48, ("FIN 48"), Accounting for Uncertainty in Income Taxes, which

8 requires companies with uncertain tax positions to remove these amounts from the

9 ADFIT balance and record them as a separate liability, for financial accounting

10 purposes. FIN 48 became effective January 1, 2007.

11

12 Q: HAS THE COMMISSION CONSIDERED THE RATEMAKING TREATMENT

13 OF THE FIN 48 PRONOUNCEMENT IN THE PAST?

14 A: Yes. In Docket No. 35717, the Commission found that the subject utility, Oncor, should

15 include its FIN 48 amounts in ADFIT as a rate base deduction, stating: "Oncor may not

16 have to pay the IRS the FIN 48 deductions of $96,972,460; and therefore they should be

17 added back into the ADFIT for ratemaking purposes." 2 This ruling (1) reflects the fact

18 that the eventual treatment of these deductions is not currently known and (2) that in the

2
Order on Rehearing, Docket 35717, page 18 at 60.

Direct Testimony of Mark E. Garrett Page 5 of65
Docket No. 39896
 1 meantime, the utility does have the use of the cost free capital from the deferred taxes

2 associated with these deductions at its disposal.

3

4 Q: IS THE COMPANY'S TREATMENT OF ITS FIN 48 ADJUSTMENTS

5 CONSISTENT WITH THE COMMISSION'S RULING IN DOCKET NO. 35717?

6 A: No. The Company's FIN 48 adjustments remove $5,916,461 from ADFIT balance that

7 should be included for ratemaking purposes. 3 In response to Cities RFI 19-6, the

8 Company states:

9 "Because the Company removed all ADIT related to FIN48 uncertain tax
10 positions from test year end ADIT balances, there would be no change to
11 rate base. Please see the Company's response to Cities 4-21 (d) for the
12 amounts removed from test year end ADIT."

13 Q: SHOULD THE COMMISSION'S RULING IN DOCKET NO. 35717 APPLY IN

14 THIS CASE?

15 A: Yes. The FIN 48 adjustments do reflect actual tax benefits from deductions taken by the

16 utility on its tax return, and the utility does have the use of these additional funds even if

17 the IRS were to reject the deductions, which may or may not ever happen. For

18 ratemaking purposes, rate base should reflect the actual amount of cost free capital in the

19 ADFIT accounts at test year end.

3
See AJ 10 for accounts 282901 and 282903 and the Highly Sensitive response to Cities 4-21.

Direct Testimony of Mark E. Garrett Page 6 of65
Docket No. 39896
 1 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE

2 COMP ANY'S FIN 48 ADJUSTMENT?

3 A: Consistent with the Commission's ruling in Docket No. 35717, I recommend that the

4 Company's ADFIT balance be increased by $5,916,461 to reinstate the FIN 48 amounts

5 removed by the Company. 4 This adjustment is set forth at Exhibit MG-2.1.

SECTION III. B. PREPAID PENSION ASSET IN RATE BASE

6 Q: PLEASE DESCRIBE THE COMPANY'S UNFUNDED PENSION BALANCE.

7 A: The Company included in pro forma rate base an item entitled Unfunded Pension

8 Balance. The amount requested in this account is supposed to represent the accumulated

9 difference between the Statement of Financial Accounting Standards ("SF AS") No. 87

10 calculated pension costs each year and the actual contributions made by the Company to

11 the pension fund. 5 The balance requested in rates is $55.9 million. 6

12

13 Q: WHAT IS THE ISSUE WITH RESPECT TO A PENSION ASSET IN RATE

14 BASE?

15 A: In general terms, a portion of the balance in Account 253.012, Unfunded Pension Plans

16 actually represents the accumulated difference between the SF AS 87 calculated pension

17 costs each year and actual contributions made by the Company to the pension fund.

4
This amount could be reduced by attributable IRS cash deposits identified by the Company in rebuttal testimony.
5
The Company incorrectly referred to this item as a PURA Section 36.065(b) reserve account. PURA Section
36.065(b) allows a utility to record the difference between the SF AS No. 87 pension cost established in a rate case
and the actual SFAS No. 87 cost experienced during the rate-effective period. The balance here is the difference in
SF AS 87 costs and contributions.
6
See ETl response to Cities' 13-21.
Direct Testimony of Mark E. Garrett Page 7 of 65
Docket No. 39896
 1 When there is a debit balance in the account, as is the case here, the Company has been

2 contributing more to the fund than its SF AS 87 calculated cost levels. 7

3

4 Q: ARE THESE CONTRIBUTIONS MANDATORY?

5 A: No. Schedule G-2.1 shows the payments to the fund have significantly exceeded the

6 required minimum contributions levels.

7

8 Q: HAS THIS COMMISSION ADDRESSED THIS ISSUE IN A PREVIOUS CASE?

9 A: Yes. The Commission addressed this issue in an AEP Texas Central Company rate case,

10 PUC Docket No. 33309. The Commission determined in that case that the excess

11 contributions to the pension fund, net of CWIP, resulted in lower future pension expense

12 levels for ratepayers. In effect, the Commission allowed the inclusion of a net pension

13 asset in rate base, because it provided a benefit to ratepayers.

14

15 Q: DOES THE BENEFIT RECEIVED BY RATE PAYERS EQUAL THE INCREASE

16 IN RATES FROM INCLUDING EXCESS PENSION FUNDING IN RATE BASE?

17 A: No. ETI's pension fund earns a much lower return on plan assets than ETI's requested

18 pretax return on rate base. The requested return on rate base is 11.5%, but the average

19 actual return on pension plan assets over the 5-year period since ETI became a separate

20 company, and the period over which substantially all of the prepaid pension buildup

7
See ETI response to Cities' 13-16.

Direct Testimony of Mark E. Garrett Page 8 of65
Docket No. 39896
 1 occurred, is only 1.37%. 8 Thus, if this asset were included in rate base, ratepayers would

2 pay a substantial premium for the slight pension cost savings ETI' s excess contributions

3 may have achieved. From a ratemaking perspective, it would be inappropriate for the

4 Company to receive a greater benefit, through earning a full rate base return on the

5 excess contributions, than the benefit ratepayers receive through lower pension costs that

6 result from the pension fund returns. 9 In short, it would be inappropriate for the

7 Company to earn an 11.5% return on contributions that have only produced a 1.37%

8 benefit to ratepayers.

9

10 Q: HOW ARE PREPAID PENSION ASSETS TREATED IN OTHER STATES?

11 A: At least one state, Virginia, has included a prepaid pension balance in rate base and

12 Texas has included a portion of a prepaid balance in rate base (which was the prepaid

13 pension balance less CWIP in the AEP TCC case). West Virginia, on the other hand, in

14 a recent decision, entirely excluded a requested prepaid pension balance. 10 In Oklahoma,

15 the commission addressed this issue in four separate decisions, and in each decision

16 excluded the prepaid pension balance from rate base and provided a cost of debt carrying

17 charge on the balance. 11 In effect, the Oklahoma commission provided a return on the

18 balance because ratepayers had received a benefit from the excess contributions in the

8
The annual returns for 2007 through 2011 are the actual returns divided by the average of the beginning and
ending balance. The average of these amounts is 1.37%. See Exhibit MG2.2.
9
For example, in Oklahoma, the commission allows a cost-of-money return (rather than a full rate base return) on
excess pension contributions ifthe utility can show that ratepayers benefited from the excess contributions. In
those cases, the utility's long term debt rate was representative of, though lower than, the actual returns received in
the pension fund.
10
See Commission Order on March 30, 2011 in Case No. 10-0699-E-42T.

Direct Testimony of Mark E. Garrett Page 9 of65
Docket No. 39896
 1 form of lower annual pension costs. In those cases, the actual pension fund returns were

2 much more similar to a long-term debt return than to a full rate base return.

3

4 Q: WHAT ADJUSTMENT ARE YOU PROPOSING?

5 A: I propose to remove the entire prepaid pension asset from rate base, because the

6 Company has not justified its inclusion in any way. This adjustment reduces pro forma

7 rate base by $36,382,803, which is the net amount of the prepaid balance less

8 accumulated deferred income tax (55,973,543 - 19,590,740 = 36,382,803)_12 I also

9 recommend that the Commission increase operating expense by $498,284, to provide a

10 1.3 7% return on the net balance. The adjustment calculations are set forth at Exhibit

11 MG-2.2.

12 In the alternative, if the Commission decides to follow its prior ruling in the AEP

13 TCC case, Docket No. 33309, the necessary reduction to pro forrna rate base would be

14 $25,311,236, which is the portion of the prepaid pension balance associated with

15 CWIP. 13

11
ONG rate case Cause No. PUD 91-1190; OG&E rate case Cause No. PUD 05-151; AEP PSO rate case Cause No.
PUD 06-285; AEP PSO Cause No. PUD 08-144.
12
See ETI RFI response to Cities' 13-21.
13
The Company's expense ratio for pensions is 55.78% and the capitalization ratio is 44.22%. See ETI W/P AJ20.

Direct Testimony of Mark E. Garrett Page 10 of65
Docket No. 39896
 SECTION III. C. RITA REGULATORY ASSET

1 Q: WHAT IS THE ISSUE WITH RESPECT TO THE RITA REGULATORY

2 ASSET?

3 A: In this application the Company seeks to include a Rita Regulatory Asset in the amount

4 of $26,229,627. 14 This balance represents the unrecovered insurance proceeds from the

5 Rita storm loss. The Company seeks rate base treatment of the regulatory asset balance

6 along with a 5-year amortization of the balance in rates. The problem with the

7 Company's recommended treatment in this case is that the Rita balance was presented in

8 the Company's last rate case, Docket No. 37744, as a regulatory asset with a 5-year

9 amortization of the balance and no party in that case opposed the recovery of those costs

10 through rates. This means that, even though the last rate case settled, since no party

11 opposed the Company's inclusion in rates of the Rita regulatory costs, the Company

12 should have been amortizing the Rita regulatory balance since the last case, which would

13 mean that 22.5 months of the 60 month amortization would be complete by the time new

14 rates go into effect from this case. 15 From a ratemaking perspective, the appropriate

15 balance for rate treatment at this point would be $10,714,557, 16 which is the original

16 balance of $26,229,627, less $9,836,110, 22.5 months of the 5-year amortization, less

17 $5,678,960, which is the difference between insurance proceeds estimated in Docket No.

18 37744 and actual receipts. These calculations are set forth at MG-2.3

14
See Sch. P, P. 19, L. 23.
15
New rates from Docket No. 37744 went into effect on August 15, 2010 and new rates from this case will go into
effect on June 30, 2012.
16
This is the balance that Mr. Pous will include in the storm reserve.

Direct Testimony of Mark E. Garrett Page 11 of65
Docket No. 39896
 1 Q: WHAT DOES CITIES RECOMMEND WITH RESPECT TO THE RITA

2 REGULATORY ASSET?

3 A: The recommended rate treatment of the Rita regulatory asset going forward is being

4 addressed in the testimony of Cities' witness, Mr. Jacob Pous, who recommends that the

5 Rita regulatory asset balance be added to and amortized in the storm reserve. In light of

6 this alternate recovery methodology for the Rita regulatory asset balance I am

7 recommending that the entire balance be removed from pro forma rate base and the

8 amortization expense be removed from pro forma cost of service. This results in a

9 reduction to the requested rate base of $26,229,627 and a reduction to the requested cost

10 of service of$5,245,925. These adjustments are set forth at Exhibit MG 2.3.

SECTION IV. A. ETI PAYROLL ADJUSTMENT

11 Q: PLEASE DESCRIBE ETI'S PROPOSED PAYROLL ADJUSTMENT.

12 A: ETI's payroll adjustment contains three components: (1) a decrease of $648,362 for a

13 reduction in the number of ETI employees during the test year, estimated by multiplying

14 the effective number of employees who left the Company by an average annual salary

15 amount; (2) an increase of $350,047 to recognize test year pay raises for both bargaining

16 and non-bargaining employees; 17 and (3) an increase of $628,947 for post-test year pay

17 raises for both bargaining and non-bargaining employees, calculated by multiplying total

18 payroll expense by the nominal rate of the pay raise. The post-test year raises for

19 bargaining employees occurred in early August 2011, just over one month after test year

Direct Testimony of Mark E. Garrett Page 12 of65
Docket No. 39896
 1 end. The post-test year raises for non-bargaining employees are scheduled to occur in

2 April 2012, nine months after test year end. The combination of these three adjustments

3 results in a net requested increase to ETI payroll expense of $330,632. 18

4

5 Q: DO YOU AGREE WITH THE COMP ANY'S PROPOSED ADJUSTMENT TO

6 ETI PAYROLL EXPENSE?

7 A: I agree with the first two components of the Company's proposed adjustment, where the

8 Company attempts to reflect workforce reductions and pay raises that occur during the

9 test year. And, in the third component, I agree with the post-test year raises for

10 bargaining employees that occurred shortly after test year end. However, I do not agree

11 with the Company's adjustment which attempts to reflect the effects of pay raises that

12 are expected to occur up to nine months after test year end. From a ratemaking

13 perspective, there are several problems with the Company's proposed recognition of

14 these post-test year raises.

15

16 Q: WHAT ARE THE PROBLEMS YOU SEE WITH THE COMP ANY'S

17 PROPOSED APPROACH?

18 A: First, the Company's method of calculating the impact of the pay raise is based on the

19 flawed assumption that a pay raise that occurs nine months after test year end would

20 increase test year payroll expense by the same amount as the pay raise. This assumption,

17
The Company awarded bargaining employees an effective 0.72% pay raise on 3/20/11 and non-bargaining
employees an effective 1.50% pay raise on 4/1/11.
18
See Workpaper AJ22.12.

Direct Testimony of Mark E. Garrett Page 13 of65
Docket No. 39896
 however, fails to consider other events occurring during the same period that could

2 decrease payroll levels by the same, or even greater, amounts. For example, workforce

3 reductions could have a greater impact on payroll expense than pay raises. In addition,

4 other more subtle changes may also decrease payroll levels. Even with a stable overall

5 workforce level, employees are being added to and removed from the payroll registers

6 on a fairly regular basis. Since retiring employees are generally paid higher salaries than

7 new employees, payroll expense levels can decrease significantly if higher paid

8 employees leave the company and are replaced with employees paid at lower

9 compensation levels. These potential reductions in payroll expense can more than offset

10 the anticipated increase from an annual raise. As a consequence, even if the

11 Commission were inclined to accept an adjustment for pay raises that occur up to nine

12 months outside the test year, the Company's proposed adjustment is inappropriate

13 because it fails to show that net payroll expense levels actually increased by the amount

14 of the pay raises.

15

16 Q: IF THE COMMISSION WERE INCLINED TO ACCEPT AN INCREASE FOR

17 PAY RAISES THAT OCCUR UP TO NINE MONTHS OUTSIDE THE TEST

18 YEAR, HOW WOULD THE IMP ACT OF THESE RAISES BE PROPERLY

19 MEASURED FOR RATEMAKING PURPOSES?

20 A: In my experience, payroll levels generally do not increase by the nominal amount of a

21 pay raise. In other words, a 3.5% pay raise typically does not result in a 3.5% increase in

22 overall payroll costs. To calculate the effective impact of a pay raise, it is necessary to

Direct Testimony of Mark E. Garrett Page 14 of65
Docket No. 39896
 1 annualize the Company's actual payroll cost levels after the raise was awarded. This

2 approach takes the guess-work out of estimating the impact of a pay raise. The

3 Company's approach of merely taking the amount of the nominal pay raise increase and

4 applying it to overall payroll expense is not an accurate method for estimating the impact

5 of a pay raise and should not be used for ratemaking purposes. In this case, it would be

6 necessary to annualize the April 2012 payroll levels in order to effectively realize the

7 April 2012 pay raise for non-bargaining employees.

8

9 Q: EVEN IF THE AD.JUSTMENT WAS APPROPRJATEL Y BASED ON A PROPER

10 ANNUALIZATION OF PAYROLL LEVELS AT APRIL 2012, WOULD THE

11 RECOGNITION OF THESE POST TEST YEAR RAISES BE APPROPRIATE

12 FROM A RATEMAKING PERSPECTIVE?

13 A: No. From a ratemaking perspective, it is generally considered inappropriate to go

14 beyond the test year to recognize an isolated increase in one expense item, such as

15 payroll, without also recognizing other potential offsetting decreases, such as higher

16 revenue levels from load growth. The Company's proposed isolated recognition of pay

17 raises that occur nine months after test year end, without offsetting adjustments, amounts

18 to a piecemeal ratemaking approach for payroll costs and, in my opinion, should be

19 rejected by this Commission. The Company makes no attempt to update its Revenue, or

20 Accumulated Depreciation, or Accumulated Deferred Income Tax balances to a nine-

21 month post-test year level, each of which would more than offset the proposed increase

22 from the April 2012 raises. In my opinion, it is inappropriate to recognize an increase in

Direct Testimony of Mark E. Garrett Page 15 of65
Docket No. 39896
 1 one item nme months after test year end, while ignoring other obvious decreases.

2 Jurisdictions with which I am familiar typically require that if one item is updated to a

3 point in time substantially after test year end, then all items must be updated to that later

4 date as well. An isolated increase in one expense item is not allowed.

5

6 Q: ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD NOT

7 INCLUDE THE APRIL 2012 PAY RAISES IN RATES?

8 A: Yes. According to Mr. Gardner's testimony, the Company's total payroll costs for 2011,

9 including both base pay and incentives, was I 0% above market. 19 Most of these above-

10 market payroll costs relate to the Company's incentives. The Company's incentive

11 levels are 63% above-market and the Company's base pay levels are 2% above market,

12 resulting in total above-market level of 10% for base pay and incentives. 20 The above-

13 market incentive pay is addressed in detail later in this testimony. However, the

14 Company's above-market base pay is relevant to mention here as well. Because the

15 Company's 2011 base pay is already 2% above market, an additional 2% pay raise

16 increase in April 2012 will only further exacerbate the problem.

19
See Table 5 at page 26 of Mr. Gardner's Direct Testimony.
20
See ETI response to Cities' RFI 18-S(b ).

Direct Testimony of Mark E. Garrett Page 16 of65
Docket No. 39896
 l Q: IF THE COMMISSION FINDS IT APPROPRIATE TO RECOGNIZE THE

2 COMP ANY'S POST TEST YEAR PAY RAISES IN APRIL 2012, WHAT OTHER

3 ADJUSTMENTS SHOULD THE COMMISSION ALSO RECOGNIZE?

4 A: If the Commission decides to recognize the April 2012 post-test year pay raises, I believe

5 the Commission should, at a minimum, consider offsetting the post-test year pay raise

6 increases with the overall productivity improvements that should occur over the same

7 period of time. These productivity improvements must be considered in forward-looking

8 adjustments to payroll costs, such as the Company's proposed pay raise increases. It

9 would be inappropriate for the Company to recognize the incremental increases to

10 payroll associated with post-test year pay raises payroll and not consider the mitigating

11 effects of increased productivity.

12

13 Q: WHAT IS PRODUCTIVITY GROWTH AND WHY IS IT IMPORTANT IN THIS

14 CASE?

15 A: In economic terms, increased productivity is the ability to produce more with less input.

16 Productivity is measured by comparing the amount of goods and service produced with

17 the inputs used in the production of a product. Specifically, labor productivity is the

18 ratio of the output of goods and service to the labor hours devoted to the production of

19 the output. The Bureau of Labor Statistics ("BLS") reports significant growth in labor

20 productivity over the past few years.

Direct Testimony of Mark E. Garrett Page 17 of 65
Docket No. 39896
 1 Q: WHY IS IT IMPORTANT TO RECOGNIZE PRODUCTIVITY GROWTH IN

2 THIS SITUATION?

3 A: Labor productivity is important here because of the forward-looking impacts of the post-

4 test year pay raises. An accurate projection of post-test year labor costs must give some

5 recognition to the expectation of increased productivity.

6

7 Q: WHAT AMOUNT OF PRODUCTIVITY GROWTH COULD BE EXPECTED

8 FOR THE COMPANY?

9 A: Based on projected productivity growth statistics, a reasonable productivity adjustment

10 would reduce labor cost by about 2.1 %. The BLS reported "business sector"

11 productivity growth of .4% for 2011, 4% for 2010, and 2.3% for 2009. This results in a

12 3-year average productivity growth of about 2.2%. The past 2-year average is 2.1 %. A

13 productivity offset of 2.1 % would recognize the fact that the Company should be

14 expected to achieve the same type of productivity gains that the business sector achieves

15 on average.

16

17 Q: HOW WOULD A PRODUCTIVITY ADJUSTMENT IMP ACT THE

18 COMP ANY'S PROPOSED INCREASE FOR APRIL 2012 P AYRAISES?

19 A: The Company's projected labor cost increases of 2% would be more than offset with a

20 2.1 % annual productivity factor.

Direct Testimony of Mark E. Garrett Page 18 of65
Docket No. 39896
 1 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE

2 COMPANY'S PAYROLL EXPENSE?

3 A: I recommend the Commission: (1) accept the Company's adjustment to decrease payroll

4 expense for workforce reductions in the test year; (2) accept the Company's adjustment

5 to increase payroll expense for pay raises awarded in March and April 2011 for

6 bargaining and non-bargaining employees respectively; (3) accept the Company's

7 adjustment to increase payroll for pay raises awarded in August 2011 for bargaining

8 employees; and (4) reject the Company's adjustment to increase payroll expense for pay

9 raises awarded in April 2012 for non-bargaining employees.

10

11 Q: PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL

12 EXPENSE.

13 A: My recommended adjustment reverses the Company's proposed increase for April 2012

14 pay raises in the amount of $316,989 and associated payroll-related expense of $41,081,

15 for a total adjustment of $358,071. The calculations supporting Cities' recommended

16 ETI payroll adjustment is set forth at Exhibit MG-2.4.

SECTION IV. B. ESI PAYROLL ADJUSTMENT

17 Q: HAVE YOU REVIEWED THE COMP ANY'S PROPOSED ADJUSTMENT FOR

18 ESI PAYROLL EXPENSE?

19 A: Yes. Like the ETI payroll adjustment, the ESI payroll adjustment contains three

20 components: (1) a decrease of $243 ,416 for a reduction in the number of ESI employees

Direct Testimony of Mark E. Garrett Page 19 of65
Docket No. 39896
 1 during the test year, estimated by multiplying the effective number of employees who

2 left the Company by an average annual salary amount; (2) an increase of $466,666 to

3 recognize test year pay raises for non-bargaining employees; 21 and (3) an increase of

4 $622,221 for post-test year pay raises for non-bargaining employees, calculated by

5 multiplying total payroll expense by the nominal rate of the pay raise. The post-test year

6 pay raises for ESI employees are scheduled to occur in April, nine months after test year

7 end. The combination of all three of these adjustments results in a net requested increase
22
8 in ESI payroll expense allocated to ETI of $845,471.

9

10 Q: DO YOU AGREE WITH THE ESI PAYROLL ADJUSTMENT?

11 A: Not entirely. I agree with the first two components of the adjustment that occur during

12 the test year-the test year workforce reductions and the test year pay raises-but I do

13 not agree with the third component of the adjustment that inappropriately increases

14 payroll expense for pay raises expected to occur nine months after test year end. Not

15 only does this proposed adjustment fall far outside the test year, it also improperly

16 calculates the impact of these raises by merely multiplying labor costs times the nominal

17 percentage of the raise.

21
The Company awarded bargaining employees an effective .72% pay raise on 3/20/11 and non-bargaining
employees an effective 1.50% pay raise on 4/1/11.
22
See Workpaper AJ22.23.

Direct Testimony of Mark E. Garrett Page 20 of65
Docket No. 39896
 1 Q: EVEN IF THE ADJUSTMENT WAS APPROPRIATELY BASED ON A PROPER

2 ANNUALIZATION OF PAYROLL LEVELS AT APRIL 2012, WOULD THE

3 RECOGNITION OF THESE POST TEST YEAR RAISES BE APPROPRIATE

4 FROM A RA TEMAKING PERSPECTIVE?

5 A: No. From a ratemaking perspective, it is inappropriate to go beyond the test year to

6 recognize an isolated increase in one expense item, such as payroll, without also

7 recognizing other potential offsetting decreases, such as higher revenue levels from load

8 growth. As I testified with respect to the Company's proposed ETI Payroll adjustment,

9 the proposed adjustments to ESI payroll expense also recognize pay raises that occur

10 nine months after test year end without offsetting adjustments. This amounts to

11 piecemeal ratemaking for payroll costs and should be rejected by this Commission.

12 Because the Company makes no attempt to update Revenue, or Accumulated

13 Depreciation or Accumulated Deferred Income Tax balances to the nine-month post-test

14 year level, it is inappropriate to recognize an increase in a single isolated item.

15

16 Q: ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD NOT

17 INCLUDE THE APRIL 2012 PAY RAISES IN RATES?

18 A: Yes. As discussed in the previous section of this testimony, Mr. Gardner's testimony

19 and responses to Cities' RFis indicate that the Company's 2011 base pay levels are 2%

20 above market. 23 With the Company's 2011 base pay levels already 2% above-market, an

23
See ETI response to Cities' RFI l 8-8(b ).

Direct Testimony of Mark E. Garrett Page 21 of65
Docket No. 39896
 1 additional 2% increase for pay raises in April 2012 would only further exacerbate the

2 problem.

3

4 Q: IF THE COMMISSION FINDS IT APPROPRIATE TO RECOGNIZE THE

5 COMPANY'S POST TEST YEAR PAY RAISES, IN APRIL 2012, WHAT

6 OTHER ADJUSTMENTS SHOULD THE COMMISSION ALSO RECOGNIZE?

7 A: If the Commission should decide to recognize the April 2012 post-test year pay raises, I

8 believe the Commission should offset the 2% pay raises with a 2.1 % productivity

9 adjustment, which, according to the BLS, is the two-year average productivity factor for

10 the business sector.

11

12 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE

13 COMPANY'S PAYROLL EXPENSE?

14 A: I recommend the Commission: (1) accept the Company's adjustment to decrease payroll

15 expense for workforce reductions in the test year; (2) accept the Company's adjustment

16 to increase payroll expense for pay raises awarded in April 2011 (during the test year);

17 and (3) reject the Company's adjustment to increase payroll expense for post-test year

18 pay raises awarded in April 2012.

19

20 Q: PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL

21 EXPENSE.

22 A: My recommended adjustment reverses the Company's proposed increase for April 2012

Direct Testimony of Mark E. Garrett Page 22 of65
Docket No. 39896
 1 pay raises in the amount of $622,220, and associated payroll-related expense in the

2 amount of $80,640, for a total adjustment of $702,861. The calculations supporting

3 Cities' recommended ESI payroll adjustment is set forth at Exhibit MG-2.7.

SECTION IV. C. SABINE AND LEWIS CREEK PAYROLL ADJUSTMENT

4 Q: HAVE YOU REVIEWED THE COMP ANY'S PROPOSED ADJUSTMENTS FOR

5 SABINE AND LEWIS CREEK PAYROLL EXPENSE?

6 A: Yes. Like the ETI and ESI payroll adjustment, the Sabine and Lewis Creek payroll

7 adjustment contains three components: (1) an increase for employees added during the

8 test year; (2) an increase to recognize test year pay raises for both bargaining and non-

9 bargaining employees; and (3) an increase for post-test year pay raises for both

10 bargaining and non-bargaining employees, calculated by multiplying total payroll

11 expense by the nominal rate of the pay raise. The post-test year raises for bargaining

12 employees occurred in early August 2011, just over one month after test year end. The

13 post-test year raises for non-bargaining employees are scheduled to occur in April 2012,
24
14 nine months after test year end.

15

16 Q: DO YOU AGREE WITH THE COMP ANY'S PROPOSED SABINE AND LEWIS

17 CREEK PAYROLL ADJUSTMENTS?

18 A: No. As with the ETI and ESI adjustments, I agree with the first two components of the

19 Company's proposed adjustment, where the Company attempts to reflect workforce

24
See Workpapers AJ22.15 and AJ22.18.
Direct Testimony of Mark E. Garrett Page 23 of65
Docket No. 39896
 1 additions and pay raises that occur during the test year. And, I also agree with the post-

2 test year raises for bargaining employees that occurred shortly after test year end.

3 However, I do not agree with the component of the Company's adjustment that attempts

4 to reflect the effects of pay raises that are expected to occur up to nine months after test

5 year end. From a ratemaking perspective it is inappropriate to go that far beyond the test

6 year to recognize an isolated increase in one expense item without also recognizing

7 offsetting decreases in other items, such as revenue, accumulated depreciation and

8 accumulated deferred income taxes. Also, pay raises projected that far beyond the test

9 year should be offset with an appropriate corresponding productivity adjustment.

10

11 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE

12 COMPANY'S PAYROLL EXPENSE?

13 A: I recommend the Commission: (1) accept the Company's adjustment to increase payroll

14 expense for workforce additions in the test year; (2) accept the Company's adjustment to

15 increase payroll expense for pay raises awarded in April 2011 (during the test year) and

16 in August 2011 shortly after test year end; and (3) reject the Company's adjustment to

17 increase payroll expense for post-test year pay raises awarded in April 2012, nine

18 months after test year end.

19

20 Q: PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL

21 EXPENSE.

22 A: For Sabine, my recommended adjustment reverses the Company's proposed increase for

Direct Testimony of Mark E. Garrett Page 24 of65
Docket No. 39896
 l April 2012 pay raises in the amount of $81,894 and associated payroll-related expense in

2 the amount of $10,613, for a total adjustment of $92,507. For Lewis Creek, my

3 recommended adjustment reverses the Company's proposed increase for April 2012 pay

4 raises in the amount of $28,659 and associated payroll-related expense in the amount of

5 $3,713, for a total adjustment of $32,372. The calculations supporting Cities'

6 recommended Sabine and Lewis Creek payroll adjustments are set forth at Exhibit MG-

7 2.5 and MG 2.6.

SECTION IV. D. ABOVE-MARKET BASE PAY COMPENSATION

8 Q: WHAT IS THE ISSUE REGARDING THE COMPANY'S ABOVE-MARKET

9 BASE PAY LEVELS?

10 A: According to Mr. Gardner's testimony, the Company's total payroll costs for 2011,

11 including both base pay and incentives, is 10% above market. 25 Most of these above-

12 market payroll costs relate to the Company's incentives. The Company's incentive

13 levels are 63% above-market, and the Company's base pay levels are 2% above market,

14 resulting in total above-market level of 10% for both components. 26 The Company's

15 incentive compensation is addressed in another section of this testimony. In this section,

16 I address the Company's above-market base pay compensation.

25
See Table 5 at page 26 of Mr. Gardner's Direct Testimony.
Direct Testimony of Mark E. Garrett Page 25 of65
Docket No. 39896
 1 Q: ARE YOU PROPOSING AN ADJUSTMENT TO THE BASE PAY LEVEL

2 REQUESTED IN RATES?
,,
.) A: Yes. From a ratemaking perspective, ratepayers are only required to pay the necessary

4 costs of providing utility service. Although the Company is certainly free to pay its

5 employees at above-market wage levels if it so chooses, ratepayers should only be asked

6 to pay market-based costs for utility services the Company provides. Based upon the

7 Company's own calculation, its base pay wage levels are above market. This is

8 particularly inappropriate when ratepayers are experiencing, arguably, the worst

9 economy in the past 30 to 35 years and quite possibly the worst economy since the

10 great depression. In light of this economic downturn, it would be particularly unfair to

11 ask captive ratepayers to pay above-market wages for utility services. As a result, I am

12 recommending a 2% adjustment to the payroll expense included in pro forma rates, to

13 bring the Company's base pay down to a market-based level.

14

15 Q: IF THE COMMISSION ADOPTS YOUR ADJUSTMENT, WILL IT RESULT IN

16 A 2% PAYROLL REDUCTION?

17 A: No, certainly not. The Company alone decides how much it pays its employees; the

18 Commission, on the other hand, decides how much of that cost should be collected from

19 ratepayers. The Company will continue to pay its employees whatever it believes is

20 appropriate. Ratepayers, however, should bear only the necessary market-based price

21 for employee pay.

26
See ETI response to Cities' RFI l 8-8(b ).
Direct Testimony of Mark E. Garrett Page 26 of65
Docket No. 39896
 Q: HOW IS YOUR PROPOSED ADJUSTMENT CALCULATED?

2 A: The adjustment is calculated by multiplying base pay wages in operating expense by

3 2%. 27 This results in an adjustment of $989,370, 28 which can be seen at Exhibit MG2.8.

SECTION IV. E. ETI INCENTIVE COMPENSATION

4 Q: HAVE YOU REVIEWED THE LEVEL OF INCENTIVE COMPENSATION

5 EXPENSE INCLUDED IN THE COMPANY'S COST OF SERVICE?

6 A: Yes. The Company seeks to include $14, 187, 744 in cost of service for incentive

7 compensation expense. This includes 100% of ETI and ESI annual incentive plan

8 compensation, 100% of ETI and ESI long-term incentive compensation, and 100% of

9 ETI and ESI equity ownership incentive compensation. The Company makes no

10 adjustment to remove any of its test year incentive expense from cost of service, even

11 though it admits that at least 35% of the annual incentive plans and 100% of the long-

12 term plans are tied to the type of financial performance measures that the Commission

13 has routinely excluded in the past. 29 The Company's proposed inclusion of financial-

14 based incentive compensation is supported in the testimony of Jay C. Hartzell, who

15 asserts that incentive programs tied to cost controls, profitability and stock price help

16 companies attract, motivate and retain talented employees. The Company asserts that

17 without financial-based incentives, employees would not be motivated to look after the

27
The actual percentage is 1.8%. See, ETI response to Cities' RFI l 8-8(b ).
28
Base pay payroll expense for ETI and ESI = $54.965 million times 1.8%. = $989,370. (See, TIEC 9-1 and Cities'
l 8-8(b)).
29
Please see Testimony of Jay C. Hartzell, PhD at page 9 for the admission, and Gardner Exhibit KGG-4 for the
percentage.

Direct Testimony of Mark E. Garrett Page 27 of65
Docket No. 39896
 1 financial health of the company. 30 The inclusion of financial-based incentives is also

2 supported in the testimony of Kevin G. Gardner, who asserts that the incentives are part

3 of a total package of compensation and benefits that is reasonable when compared with

4 other companies. 31 ETI's test year incentive expense levels and the amounts included in

5 cost of service are set forth in the table below:

Table 1: Total Incentive Compensation Expense in Cost of Service

Amount Included in
Incentive Compensation Programs I Test Year Expense
Cost of Service
Management Incentive Plan $4,749,198 $4,749,198
Exempt Incentive Plan $1,858,337 $1,858,337
Team Share Incentive Plan $153,447 $153,447
Team Share for Bargaining Employees $384,877 $384,877
Executive Annual Incentive Plan $1,483,447 $1,483,447
ML6 Operational Plan 181,462 181,462
Long-Term Incentive Plans $815,608 $815,608
Equity Ownership Plans $4,561,367 $4,561,367

Total Incentive Compensation $14,187,744 $14,187,744

6 Q. WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE

7 COMPANY'S INCENTIVE COMPENSATION EXPENSE?

8 A. For incentive compensation expense, the general rule followed in most states is that

9 incentive payments related to the financial performance of the company are excluded for

10 ratemaking purposes. Under this rule, most short-term incentive expense and virtually

30
Direct Testimony of Jay C. Hartzell, PhD at page 7, lines 9-17.
31
Direct Testimony of Kevin G. Gardner at pages 5-30.

Direct Testimony of Mark E. Garrett Page 28 of65
Docket No. 39896
 1 all long-term incentive expense for executives is excluded. In my opinion, this rule

2 should be applied to ETI's incentive plans.

3

4 Q: WHAT IS THE GENERAL RATIONALE FOR EXCLUDING INCENTIVE

5 COMPENSATION TIED TO FINANCIAL PERFORMANCE?

6 A: When incentive compensation costs associated with financial performance are excluded

7 from rates, the rationale is generally based on one or more of the following reasons:

8 (1) Payment is uncertain. Often, payment of incentive compensation is conditioned
9 upon meeting some predetermined financial goal such as achieving a certain
10 increase in earnings, reaching a targeted stock price or meeting budget objectives.
11 If the predetermined goals are not met, the incentive payment is not made, or
12 payment is made at some lesser amount. Therefore, there is no certainty from
13 year to year what the level of the payment may be or whether the payment will be
14 made at all. It is generally considered inappropriate to set rates to recover a
15 tentative level of expense 32

16 (2) Many of the factors that significantly impact earnings are outside the control
17 of most company employees and have limited value to customers. For
18 example, an unusually hot summer can easily trigger an incentive payment based
19 on company earnings for an electric utility. Obviously, weather conditions are
20 outside the control of utility employees and customers receive no benefit from
21 the higher utility bills that result from an unusually hot summer. Similarly,
22 company earnings may increase, thus triggering incentive payments, as a result of
23 customer growth, which commonly occurs without significant influence from
24 company personnel. In fairness, since shareholders enjoy the benefits of
25 customer growth between rate cases, shareholders should also bear the cost of
26 any incentive payments such growth may trigger. Finally, utility earnings may
27 increase substantially if the utility is able to successfully argue for a higher ROE
28 in a rate case proceeding. However, utility efforts to maximize ROE in a rate
29 proceeding have little to do with improving overall employee performance across
30 the company. If utility employee efforts are geared toward securing an
32
This general rationale for excluding financial-based incentives is on point in this case. At page 28, lines 8-14, of
his Direct Testimony, Mr. Gardner admits that actual payments for financial incentives may be considerably less
than the targeted level. For example, the actual payouts under the Performance Unit Programs were only 57% of
the targeted level in 2010 and a mere 10% of the target level in 2011.

Direct Testimony of Mark E. Garrett Page 29 of65
Docket No. 39896
 1 unreasonably high ROE in a rate proceeding, the incentive mechanism actually
2 would work to the detriment of the utility customers.

3 (3) Earnings-based incentive plans can discourage conservation. When incentive
4 payments are based on earnings, employees may not be as supportive of
5 conservation programs designed to reduce usage if they perceive these programs
6 could adversely impact incentive payment levels. To the extent earnings-based
7 incentive plans discourage conservation and demand-side management programs,
8 these plans would not be in the public interest. This point is especially important
9 in light of the growing focus on energy efficiency at both the national and state
10 level. 33

11 (4) The utility and its stockholders assume none of the financial risks associated
12 with incentive payments. Ratepayers assume the risk that the amounts collected
13 through rates for incentive payments will instead be retained by the utility
14 whenever targeted increases are not reached. Employees assume the risk that the
15 incentive payments will not be made in a given year. However, the utility and its
16 stockholders assume no risk associated with these payments. Instead, the
17 company's only responsibility is to decide who gets the money, the stockholders
18 or the employees.

19 (5) Incentive payments based on financial performance measures should be
20 made out of increased earnings. Whatever the targets or goals may be that
21 trigger an incentive payment, when the plan is based in whole or in part on
22 financial performance measures there is always a financial benefit to the
23 company that comes from achieving these objectives. This financial benefit
24 should provide ample funds from which to make the payment. If not, the
25 incentive plan was poorly conceived in the first place. As such, employees
26 should be compensated out of the increased earnings, and not through rates.

27 (6) Incentive payments embedded in rates shelter the utility against the risk of
28 earnings erosion through attrition. When utilities are allowed to embed
29 amounts for incentive payments in rates that money is available to the utility not
30 only to pay the incentive payment when financial performance goals are met but
31 also to supplement earnings in those years when the company does not perform
32 well. In those years when financial performance measures are met, the increased
33 earnings of the company provide ample additional funds from which to make the
34 incentive payments to employees, and the incentive payment amount embedded
35 in rates is not needed. In those years when financial performance measures are
36 not met and the incentive payments are not made, the amount embedded in rates
33
This general rationale for excluding financial-based incentives is particularly important in Texas, since the
Commission's rules specifically disallow expenses that would promote increased consumption of electricity. See
§25 .231 (b )(2)(F).

Direct Testimony of Mark E. Garrett Page 30 of65
Docket No. 39896
 1 for incentive payments acts as a financial hedge to shelter the poor financial
2 performance of the company.

3 Even though regulators often exclude incentive compensation payments based on one or

4 more of the reasons outlined above, this does not mean that regulated companies should

5 not offer incentive compensation packages. To the contrary, incentive plans that

6 motivate employees to achieve increased efficiencies (i.e., cost control) should be

7 encouraged. However, since the utility retains the savings generated from these

8 increased efficiencies between rate cases, payment to the employees for these plans

9 should be made from a portion of the savings these plans help achieve. Thus, incentive

10 compensation plans designed to enhance financial performance need not be subsidized

11 by ratepayers.

12

13 Q. HOW IS INCENTIVE COMPENSATION TREATED FOR RATEMAKING

14 PURPOSES IN TEXAS?

15 A. My understanding is that the Commission generally excludes the portion of incentive

16 payments designed to increase the financial position of the utility. For example, in PUC

17 Docket No. 28840, 34 the Commission disallowed sixty-six percent (66%) of AEP-Texas

18 Central's test year incentive payments in the amount of $4.2 million -- the portion of the

19 utility's incentive payments that was based on financial performance measures. 35

34
Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840; SOAH Docket
No. XXX-XX-XXXX, Final Order(August 15, 2005).

Direct Testimony of Mark E. Garrett Page 31of65
Docket No. 39896
 1 Q: HOW IS INCENTIVE COMPENSATION TREATED IN OTHER STATES?

2 A: The results of an Incentive Survey of 24 Western States 36 taken by the Garrett Group in

3 2007, and updated in 2009 and again in 2011, show that most states follow guidelines

4 similar to those described above for Texas, where incentive pay associated with financial

5 performance is not allowed in rates. Some states disallow incentive pay using other

6 criteria. None of the jurisdictions surveyed allow full recovery of incentive

7 compensation through rates as a general rule. The results of the survey are set forth

8 below.

States that closely follow the Financial Performance rule

9 Arizona The commission deals with incentive compensation plans on a case by
10 case basis. It first compares overall compensation to the state norm, then
11 asks if the costs are prudent and reasonable. The commission leans
12 toward disallowing programs which benefit only the shareholder even if
13 total compensation is comparable to the state norm. Staffs position is that
14 unless a plan is tied to performance issues it is unnecessary for the
15 provision of service and that shareholders should pay for plans tied to
16 financial measures. In practice, the costs of annual incentive plans are
17 often shared 50/50 between ratepayers and shareholders. 37

18 Arkansas Excludes 100% of the long-term, equity-based plans. Short-term
19 incentive plans are evaluated to determine if they are based on financial
20 or operational measures. Operational-based plans are allowed. 50% of
21 plans containing financial measures are disallowed. Any plans based
22 solely on the discretion of the company are seen as having no direct
23 benefit to ratepayers and are disallowed 100%. Settlements in recent
24 cases have upheld this treatment. 38

35
See ALJ's Proposal for Decision at page 113 in PUC Docket No. 28840, SOAH Docket No. XXX-XX-XXXX, issued
July I, 2004. The PFD with respect to the treatment of incentive compensation was adopted by the Commission in
its Final Order.
36
The survey does not cover Nebraska because the state does not regulate investor-owned electric utilities.
37
See e.g., APS 2008 rate case, Decision 70360, Southwest Gas 2008 rate case, Decision 70665 and UNS Gas 2008
rate case, Decision 70011.
38
Entergy Arkansas, 06-101-U, Order No. 10.
Direct Testimony of Mark E. Garrett Page 32 of65
Docket No. 39896
 1 California Incentive funding is an issue that is typically litigated. In CPUC Decision
2 00-02-046, the commission established that utilities could recover 50% of
3 the regular employee's incentive compensation costs in rates. In
4 California's latest litigated rate case, the commission decided that
5 Edison's non-executive plans and 50% of the short-term executive plans
6 would be funded in rates and that 100% of the executive long-term stock
7 plans would be disallowed. 39

8 Colorado Regular employee programs are judged based on ratepayer verses
9 stockholder benefit ratio. Plans with metrics for goals benefiting
10 ratepayers but dependent on an earnings-per-share trigger are considered
11 to benefit shareholders and opposed by staff. Staff's approach is set forth
12 most recently, in 1OAL-963G by staff witness Kahl. The settlement in
13 that case removed the dollar amount opposed by Kahl. All executive
14 incentives are excluded from rates and typically no longer sought in
15 company filings.

16 Hawaii Hawaii does not allow incentive compensation to be included in rates. In
17 Docket No. 6531 the commission agreed that bonus awards tied to
18 company income and earnings benefit stockholders, not ratepayers. The
19 commission further states, "... we believe that a utility employee,
20 especially at the executive level, should perform at an optimum level
21 without additional compensation. Ratepayers should not be burdened
40
22 with additional costs for expected levels of service. "

23 Idaho The commission's policy for evaluating incentive compensation plans
24 involves determining who benefits, the customer or the company. This
25 treatment has been refined in the recent Idaho Power rate case for plans
26 which benefit the customer but require a financial trigger to be paid. For
27 these plans the commission reduced the percentage allowed in rates. The
28 commission also now does not include any executive compensation in
41
29 rates.

30 Kansas Plans based solely on financial goals are not allowed. For executive
31 incentive programs, the Commission also disallows 100% of plans based
32 on financial measures and 50% for plans using a balance of financial and
33 operational measures. The Commission has allowed in rates non-
39
Southern California Edison (Application#: 07-11-011, Decision#: 09-03-025).
40
Hawaii's policy is set forth in Docket No. 6531 in the October 17, 1991 Order No. 11317. Prior Dockets in which
the commission disallowed incentive compensation include No. 3216, No. 4215, No. 4588 and No. 5114.
41
The Commission's focus on customer benefit is reflected in the direct testimony of Staff witness Leckie, and in
the final order for the recent IPC General Rate Case IPC-E-08-10. For earlier examples of the basic policy, see
Idaho Power Company Rate Case IPC-E-05-28, Corrected Motion for Approval of Stipulation 3/1/06, 6e, p. 4;
Idaho Power Company IPC-05-28, Order No. 30035, p. 4/10.
Direct Testimony of Mark E. Garrett Page 33 of 65
Docket No. 39896
 1 executive annual incentive programs that have no focus on profitability or
. 42
2 earmng

3 Louisiana Traditionally incentive compensation for upper level management and
4 officers is excluded, while costs for lower level managers and employees
5 are allowed. The criteria used to evaluate plan design consider whether
6 the goals of each plan directly benefit ratepayers or shareholders. Stock
7 based compensation plans at ail levels are excluded.

8 Minnesota Minnesota distinguishes between incentive plans tied to financial triggers
9 (such as a threshold ROE), and plans tied to criteria benefitting the
10 ratepayer. Plans based on goals which benefit ratepayers are allowed in
11 rates, but their costs are capped at 25% of base salaries. 43 The portions of
12 these plans that are allowed into rates are tracked and must be returned to
13 ratepayers if they are not paid to employees. Executive plans are largely
44
14 not allowed.

15 Missouri Missouri's treatment disallows incentives tied to goals benefitting
16 primarily the stockholders (e.g. tied to earnings per share) while allowing
17 plans with customer-specific goals (e.g. safety). Plans must also be
18 reasonable. The Commission also allows only the amounts actually paid,
19 not those accrued. The same criteria are used for executive pians and few
20 are allowed. 45

21 Nevada The commission excludes 100% of the long-term plans and all short-term
22 plans directly related to financial performance. 46

42
In the litigated 2010 KCP&L rate case (10-KCPE-415-RTS) the Commission also stated that relying on peer
group statistics "can result in a continuing upward spiral [instead] the Commission must examine the elements of
incentive packages, and the behavior they in cent." The Commission held that a focus on profitability or earning
might incent employee behavior "detrimental to customers."
43
This general policy is demonstrated in recent orders in the Minnesota Power and Ottertail rate cases: E002/GR-
09-l l 51 and E002/GR-10-239 respectively.
44
Minnesota's general policy is demonstrated in recent orders in the Minnesota Power and Ottertail rate cases:
E002/GR-09-l 15 l and E002/GR- l 0-239 respectively. See also Minnesota Power General Rate Case
E002/GR/05/l 428.
45
See, e.g., in the latest Missouri American rate case (WR-2010-0131), not only were plans based on financial
goals disallowed, but incentive payments based on customer satisfaction were disallowed due to the unreasonably
small sample size used to establish a positive rating (a phone survey of927 of roughly 450,000 customers). The
commission also removed incentive payments tied to lobbying and charitable activity. In the most recent case
processed, the Ameren UE rate case, the company did not seek even short-term incentive compensation tied to
earnings, providing further indication that staff's practice of disallowing financial performance based incentives is
accepted by the companies. All incentive compensation adjustments were made not only to expense charges, but to
construction charges as well. See also recent Kansas City Power and Light and Empire Electric District orders on
the commission's website.
46
See, for example, the PUCN's final order in Docket 11-06006.
Direct Testimony of Mark E. Garrett Page 34 of65
Docket No. 39896
 1 New Mexico The commission does not favor incentive compensation plans that are tied
2 to financial goals and tends to allow in rates those based on operational
3 goals. This standard is applied to all levels of utility employees and tends
4 to eliminate the greater portion of executive plans. 47

5 Oklahoma The commission excludes incentive payments tied to financial
6 performance. From a practical perspective this means that all executive
7 stock plans are excluded and some portion of the annual cash plan for all
8 employees. Since the commission has not been able to determine in
9 recent cases the precise portion of the annual plans tied to financial
10 measures, the commission has excluded 50% of the annual plans. 100%
11 of the executive stock plans are excluded. 48

12 Oregon The commission's general policy is to evaluate plans based on whether
13 they benefit the customers or the company. Customer-based plans
14 involving reliability, response speed, etc. are called "merit" (operational)
15 plans. Company-based plans which track increases to the bottom line,
16 ROE, etc. are called "performance" (financial) plans. 50% of the cost of
17 merit plans is disallowed and 75% of the performance plans is disallowed.
18 100% of officer bonuses are disallowed. 49

19 S. Dakota The commission's general policy is to disallow the portion of incentive
20 plans that are based on the company's financial performance. 5 Current °
21 treatment also includes disallowing both executive and non-executive
22 management incentive compensation. There are no incentive
23 compensation plans for union employees. Several utilities have whole
24 incentive programs that hinge on whether or not the company earns a
25 certain return. These financial prerequisites cause the whole plans to be
26 excluded from rates.

27 Texas The general rule is that incentive payments designed to improve the
28 financial performance of the utility are excluded. For example, in PUC
29 Docket No. 28840, 51 the commission disallowed sixty-six percent (66%)
47
See Docket 07-00077-UT.
48
See e.g., AEP-PSO Cause No. PUD 06-285; OG&E Cause No. PUD 05-151; and ONG Cause No. PUD 04-610.
49
A recent order reflecting this policy can be found in Docket UE 197, Order No. 09-020.
50
In Docket No. EL 08-030 the settlement excluded bonuses related to "stockholder-benefitting financial goals."
The settlement in Xcel rate case Docket No. EL09-009 removed payments based on financial performance
indicators. In the settlement agreement signed July 7, 2010 in the Black Hills Power rate case Docket No. EL09-
018 the Staff Memorandum states, "The settlement removes financial based incentive payments that were included
in the capitalized labor costs for plant. Shareholders are the overwhelming beneficiaries of incentive plans that
promote the financial performance of the Company and therefore should be responsible for the cost of such
compensation."
51
Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840; SOAH Docket
No. XXX-XX-XXXX, Final Order (August 15, 2005).
Direct Testimony of Mark E. Garrett Page 35 of65
Docket No. 39896
 1 of AEP-Texas Central's test year incentive payments in the amount of
2 $4.2 million. This was the portion of the utility's incentive payments that
3 were based on financial performance measures. 52

4 Utah The commission's general policy is to allow in rates the parts of a plan
5 that are tied to ratepayer benefit and disallow the parts tied to financial
6 goals. Equity-based incentive compensation is excluded from rates. 53

7 Washington Incentive plans are evaluated on a case by case basis. Incentives tied to
8 operational efficiency or other measures which benefit ratepayers are
9 allowed in rates and incentives based on return on earnings or other
10 measures that benefit the shareholders are disallowed. 54

11 Wyoming Employee incentive compensation plans are evaluated on a case by case
12 basis, distinguishing between employee programs that benefit the
13 ratepayer or the stockholders and requiring the benefitting party to pay.
14 Executive incentive compensation plans are all excluded from rates.

States that use another approach

15 Alaska Incentive compensation is not an issue in rate cases in Alaska. There is
16 no relevant regulation or policy.

17 Iowa Incentive compensation is not typically an issue because few rate cases
18 are litigated in this jurisdiction. Mid-America has an incentive
19 compensation plan but hasn't filed a rate case in many years. For the
20 state's other utilities, it has been a long time since they have filed a rate
21 case or had a rate increase. The standing treatment is to consider
22 incentive compensation plans on a case by case basis and to evaluate
23 whether they are reasonably and prudently incurred. Both of the investor
24 owned utilities in Iowa are under rate freezes until 2013 and 2014.
25
26 Montana Montana has no specific treatment directive and considers the issue on a
27 case by case basis. In a recent North Western Energy rate case, as part of
28 a stipulation agreement, the company took a portion of its incentive
52
See ALJ's Proposal for Decision at page 113 in PUC Docket No. 28840, SOAH Docket No. XXX-XX-XXXX, issued
July 1, 2004. The PFD with respect to the treatment of incentive compensation was adopted by the Commission in
its Final Order.
53
The recent final order in Docket 09-035-23 follows this general policy as does the order in Docket 07-35-93. See
also Missouri Corp. Rate Case Docket 97-035-01, pp. 10-12; US West Communications Rate Case Docket 95-049-
05.
54
See the Order in Pacific Power and Light Docket 061546.

Direct Testimony of Mark E. Garrett Page 36 of65
Docket No. 39896
 1 compensation out of rates, but reserved the right to propose that it be
2 included in a later filing.
3
4 N. Dakota Historically, North Dakota has followed the general policy that the
5 portion of incentive compensation that relates to shareholder earnings is
6 disallowed and the rest is included. Recently the commission chose to
7 consider overall compensation and determine whether it was reasonable
8 as compared to the market. 55 Executive incentive compensation is not
9 allowed in rates, and is typically not sought by the company.

10 Q: HOW IS INCENTIVE COMPENSATION TREATED IN THE OTHER STATES

11 WHERE YOU HA VE PERSONAL EXPERIENCE?

12 A: The states in which I routinely practice all follow the majority rule that incentive

13 expense associated with financial performance is excluded from rates. As a practical

14 matter, this means that some portion of all incentive plans are excluded in these

15 jurisdictions, as set forth in the summary below:

16 In Arizona, the commission follows the same rule - that costs associated with

17 financial performance are excluded. In practice, this means that the costs of long-term

18 plans are excluded altogether and the costs of the short term annual cash plans are shared

19 50/50 between shareholders and ratepayers. As examples, see APS 2008 rate case,

20 Decision 70360, Southwest Gas 2008 rate case, Decision 70665 and UNS Gas 2008 rate

21 case, Decision 70011.

22 In Arkansas, incentive payments tied to financial performance measures that

23 benefit only the company such as stock-based plans and EPS measures are assigned

55
Other than Xcel, the utilities in North Dakota (Otter Tail and MDU) are highly diversified now (with mostly
unregulated operations, e.g. MDU 90%). This allows utility executives to draw on the unregulated components for
their compensation.

Direct Testimony of Mark E. Garrett Page 37 of65
Docket No. 39896
 1 l 00% to the shareholders while measures that benefit both the company and its

2 customers are shared 50/50.

3 In Nevada, in the 2008 Nevada Power rate case, the commission excluded 100%

4 of the long-term plan for executives and key employees of the company, based on the

5 fact that these costs mainly benefit shareholders. 56 In Nevada Power's recent 2011 rate

6 case, Docket No. 11-06006, the Company voluntarily excluded the costs of its long-term

7 plan. With respect to short-term incentives, the commission excludes all plans directly

8 related to financial performance.

9 In Oklahoma, the commission also excludes incentive payments tied to financial

10 performance. From a practical perspective this means that all executive stock plans are

11 excluded and some portion of the annual cash plan for all employees. Since the

12 commission has not determined in recent years the precise portion of the annual plans

13 tied to financial measures, the commission has excluded 50% of the expense. All of the

14 long-term plan costs are routinely excluded. 57

15 In Utah, costs associated with financial performance are excluded. The rule is

16 followed so closely that the utility typically no longer submits the cost of its long term

17 incentive plan for rate case recovery.

56
See Draft Order issued June 17, 2009 in Docket No. 08-12002, at page 138.
57
See, e.g., AEP-PSO Cause No. PUD 06-285; OG&E Cause No. PUD 05-151; and ONG Cause No. PUD 04-610.

Direct Testimony of Mark E. Garrett Page 38 of65
Docket No. 39896
 1 Q: WHY IS THE DISTINCTION BETWEEN FINANCIAL PERFORMANCE

2 MEASURES AND OPERATIONAL MEASURES IMPORTANT FOR

3 INCENTIVE COMPENSATION ANALYSIS?

4 A: When incentive compensation payments are based on financial performance measures,

5 the compensation agreement between shareholders and employees could be loosely

6 stated in this manner: "if you will help increase shareholder earnings, we will pay you a

7 bonus." The intended beneficiaries to this agreement are the shareholders and the

8 employees. Ratepayers have no stake in this agreement; therefore, they should bear none

9 of the costs that result from such an agreement. If, instead, the agreement were stated in

10 this manner: "if you will help increase reliability and quality of service to the customers,

11 we will pay you a bonus," then, ratepayers would have a stake in the agreement, and

12 could share in a portion of the costs. However, so long as some portion of the incentive

13 plan is designed to increase earnings, that portion of the plan should be funded out of the

14 increased earnings the plan helps produce.

15

16 Q: HOW MUCH OF THE COMPANY'S INCENTIVE COMPENSATION IS TIED

17 TO FINANCIAL PERFORMANCE?

18 A: The Company estimates that 35% of the annual incentive plan payments are related to

19 financial performance measures. This percentage is a weighted average percentage that

20 includes: (1) all payments tied to Financial and Cost Control measures; and (2) one- third

21 of the payments tied to a combination of Cost Control, Safety and Operational

Direct Testimony of Mark E. Garrett Page 39 of65
Docket No. 39896
 58
l measures. The Company also indicates that 100% of the equity-based long-term

2 incentive plans and 100% of the stock option plans are related to financial

3 performance. 59

4

5 Q: WHAT TYPES OF INCENTIVES ARE PROVIDED TO COMPANY

6 EXECUTIVES?

7 A: Under the Company's plan, executives are provided three types of incentive

8 compensation: (1) the Executive Annual Incentive Plan; (2) the Long-Term Cash

9 Incentive plan; and (3) the Equity Ownership Plan, which provides stock options and

10 other stock-based awards to executives and other employees of the Company.

11

12 Q: DO YOU RECOMMEND THE INCLUSION OF THE EXECUTIVE INCENTIVE

13 EXPENSE IN RATES?

14 A: Generally, incentive compensation payments to officers, executives and key employees

15 of a utility company are excluded for ratemaking purposes, and I agree with this

16 treatment. Executive stock-based compensation in particular is excluded in most

17 jurisdictions because stock-based compensation is, on its face, tied to financial

18 performance. Since officers of any corporation have a duty of loyalty to the corporation

19 itself and not to the customers of the company, these individuals typically put the

20 interests of the company first. Undoubtedly, the interests of the company and the

58
This percentage is derived from Exhibit KGG-4 and is the weighted average of payments tied to financial and
cost control measures. However, because Exhibit KGG-4 has been identified by the Company as a highly sensitive
exhibit the exact derivation of this percentage is not provided in this "public" testimony, but is available for review.

Direct Testimony of Mark E. Garrett Page 40 of65
Docket No. 39896
 1 interests of the customer are not always the same, and at times, can be quite divergent.

2 This natural divergence of interests creates a situation where not every cost associated

3 with executive compensation is presumed to be a necessary cost of providing utility

4 service.

5 It has been my experience that some utilities no longer seek recovery of

6 executive long-term incentive compensation, since long-term executive incentive plans,

7 such as stock option plans, are specifically designed to tie executive compensation to the

8 financial performance of the company to further align the interests of the executives with

9 those of the shareholders. Since the compensation of the employee is tied over a long

10 period of time to the company's stock price, it creates an incentive for the employee to

11 make business decisions from the perspective of long-term shareholders. This

12 intentional alignment of employee and shareholder interests means the costs of these

13 plans should be borne solely by the shareholders. It would be inappropriate to require

14 ratepayers to bear the costs of incentive plans designed to encourage utility executives to

15 put the interest of the shareholders first, especially when the interest of the shareholder is

16 directly bolstered by increases in utility rates.

17 While many regulators are inclined to exclude all executive bonuses, incentive

18 compensation and supplemental benefits from utility rates, my recommendation in this

19 testimony merely follows the Texas rule which excludes incentives tied to financial

20 performance measures - effectively eliminating most of the executive incentives.

59
See ETI responses to Cities' RFI 10-9(k) and Cities' RFI 10-lO(k).
Direct Testimony of Mark E. Garrett Page 41 of65
Docket No. 39896
 1 Q: IS YOUR RECOMMENDATION TO EXCLUDE ALL EQUITY INCENTIVE

2 COMPENSATION CONSISTENT WITH THE TREATMENT OF INCENTIVES

3 IN THE OTHER STATES WHERE YOU REGULARLY PRACTICE?

4 A: Yes. Oklahoma, Nevada and Utah all follow the same general rule that excludes

5 incentive compensation tied to financial performance measures. This means that long-

6 term equity incentive plans are all excluded. For example, in Oklahoma, in each of the

7 most recently litigated rate cases for the three major utilities in that state, the commission

8 has excluded 100% of the utilities' long-term incentive compensation plans. Likewise,

9 in Nevada, the commission excluded 100% of the long-term incentive compensation

10 plan costs in Nevada Power's 2008 rate case. In the Company's 2011 rate case, the

11 utility voluntarily excluded the long-term incentive costs. In Utah, PacifiCorp also

12 voluntarily removes all costs associated with its long-term incentive compensation

13 plans. 60 The table below sets forth the most recent treatment of long-term incentive

14 compensation for the major utilities in these jurisdictions.

60
In PacifiCorp's last two general rate case, Docket No. 07-035-93 and Docket No. 08-035-38, the Company did
not seek recovery of its long-term executive compensation plans.

Direct Testimony of Mark E. Garrett Page 42 of65
Docket No. 39896
 TABLE: 2

LONG-TERM INCENTIVE TREATMENT IN OKLAHOMA, NEV ADA AND UTAH

Utility Company Amount Excluded Docket Number

AEP/PSO 100% Excluded Cause Nos. PUD 06-285;08-144
Oklahoma Gas & Electric 100% Excluded Cause No. PUD 05-151
Oklahoma Natural Gas 100% Excluded Cause No. PUD 04-610
Nevada Power l 00% Excluded Docket No. 08-12002; 11-06006
PacifiCorp I 00% Excluded Docket No. 08-035-38

1 Q: HOW IS EQUITY INCENTIVE COMPENSATION TREATED IN OTHER

2 STATES?

3 A: As shown in the Garrett Group's Incentive Survey, most states follow guidelines similar

4 to those described above for Texas, Oklahoma, Nevada and Utah, that disallow incentive

5 pay associated with financial performance. As a result, equity-based incentives typically

6 are not allowed in most states. A synopsis of the survey results from each state was

7 included earlier in this section of testimony, with the treatment of executive incentives in

8 each state underlined. According to the survey, the following western states exclude all

9 or virtually all executive incentive pay: Oregon, California, Nevada, Idaho, Utah, South

10 Dakota, Oklahoma, Wyoming, North Dakota, Missouri, Arkansas, Louisiana and

11 Minnesota. Other states, like Washington, Missouri and Texas, apply the financial

12 performance rule, which has the effect of excluding executive incentives, especially

13 stock-based awards.

Direct Testimony of Mark E. Garrett Page 43 of65
Docket No. 39896
 1 Q: WHEN UTILITIES DO SEEK TO INCLUDE EXECUTIVE STOCK

2 COMPENSATION IN RATES, WHAT RATIONALE IS GENERALLY

3 PROVIDED?

4 A: Generally, utilities argue that executive incentives are part of an overall compensation

5 package that is designed to attract and retain qualified personnel. Generally, the

6 rationale is that some other utilities may offer incentive plans to their executives, thus a

7 company runs the risk of not being able to compete for key personnel if it does not offer

8 a comparable plan. 61

9

10 Q: IS THIS ARGUMENT PLAUSIBLE?

11 A: No. The common problem with the Company's "total compensation package" argument

12 is that when an incentive payment is based on achieving financial performance goals

13 there should be a financial benefit to the company that comes from achieving these

14 goals. This financial benefit should provide ample additional funds from which to make

15 the incentive payments. If not, the plan was poorly conceived. Thus, a utility is not

16 placed at a competitive disadvantage when incentive payments tied to financial

17 performance are not collected through rates, because the funding for these payments is

18 available from the additional earnings the incentive plans help achieve.

19 Further, when utilities, such as ETI, compete with other utilities for qualified

20 executives, and the executive incentive compensation plans of the other utilities are not

21 being recovered through rates, ETI is not at a disadvantage when its equity incentive

61
See, for example, the Direct Testimony of Jay C. Hartzell at page 7, lines 10-13.
Direct Testimony of Mark E. Garrett Page 44 of65
Docket No. 39896
 1 compensation is excluded as well. Since most states exclude equity incentive pay as a

2 matter of course, and many others exclude equity incentives as a practical matter, ETI

3 would actually be given an unfair advantage if its equity plans were included in rates.

4 The fact that other utilities may offer equity incentive plans is not relevant; what is

5 relevant is the fact that other utilities typically are not recovering the costs of these plans

6 in rates. The Nevada Commission articulated this important ratemaking concept in its

7 order disallowing Nevada Power's long-term incentive plan in the Company's 2008

8 general rate case.

9 Therefore the Commission accepts BCP's and SNHG's recommendations
10 to disallow recovery of expenses associated with LTIP. Both parties
11 provide a valid argument that this type of incentive plan is mainly for the
12 benefit of shareholders. Further, both BCP and SNHG provide examples
13 of numerous other jurisdictions that do not allow the recovery of these
14 costs and, therefore, disallowance in this instance wouid not place NPC in
15 a competitive disadvantage. 62 (Emphasis added).

16 Q: IS THERE OTHER EVIDENCE THAT THE COMPANY WILL NOT BE

17 DISADVANTAGED BY A DISALLOWANCE OF INCENTIVE EXPENSE?

18 A: Yes. According to Mr. Gardner, the Company's total payroll costs for 2011, including

19 both base pay and incentives, was 10% above market. 63 Most of these above-market

20 payroll costs relate to the Company's incentives. The Company's incentive levels are

21 63% above-market and the Company's base pay levels are 2% above market, resulting in

22 a total above-market level of 10% for both base pay and incentives. 64 The above-market

62
See Final Order in Docket 08-12002 at paragraph 549. NPC did not seek recovery of its LTIP in the 2011 rate
case, Docket No. 11-06006.
63
See Table 5 at page 26 of Mr. Gardner's Direct Testimony.
64
See ETI response to Cities' RFI l 8-8(b ).

Direct Testimony of Mark E. Garrett Page 45 of65
Docket No. 39896
 1 base pay is addressed earlier in this testimony. The Company's 63% above-market

2 incentive pay, however, is relevant in this section of testimony. Cities' adjustment,

3 proposed below, to reduce incentive compensation levels associated with financial based

4 incentives (3 5% of the short term cash incentives and 100% for long term equity-based

5 incentives), only reduces the Company's overall incentive compensation by 59%, which

6 is less than the 63% that the incentives are above-market.

7

8 Q: WHAT ADJUSTMENT DO YOU PROPOSE WITH RESPECT TO THE

9 COMPANY'S INCENTIVE COMPENSATION COSTS?

10 A: My proposed adjustment removes 35% of the annual incentive plan costs. This is the

11 weighted-average portion of the Company's plan that is tied to financial performance,

12 according to the Company. My adjustment also removes 100% of (1) the Long-Term

13 Incentive plan and (2) the Stock Option awards. These plans are clearly based entirely

14 upon the financial performance of the Company. Stock options are financial-based on

15 their face, and the Company admits that the Long-Term awards are based on financial

16 performance. 65

65
See ETI responses to Cities' RFI I0-9(k) and Cities' RFI 10-lO(k).

Direct Testimony of Mark E. Garrett Page 46 of65
Docket No. 39896
 1 Q: DOES THE AMOUNT YOU IDENTIFIED IN THE ANNUAL PLANS AS

2 ASSOCIATED WITH FINANCIAL PERFORMANCE DIFFER FROM THE

3 AMOUNT IDENTIFIED BY THE COMP ANY?

4 A: Yes. The Company identified 14.1 % costs in the annual incentive plans as associated

5 with financial performance. 66 The Company divided the plans into four categories: (1)

6 financial performance goals; (2) cost control goals; (3) operational goals; and (4) safety

7 goals. 67 The Company included only category (1 ), financial performance goals, in the

8 14.1 % tied to financial performance. 68 This category includes goals tied solely to

9 increasing shareholder wealth such as earnings per share, shareholder returns, and stock

10 price. 69 The Company did not include category (2), cost control goals, as goals tied to

11 financial performance, but does acknowledge that this category should be included based

12 on prior Commission orders. 70

13

14 Q: WHAT DID YOU DO TO ARRIVE AT YOUR CALCULATED 35% FOR

15 FINANCIAL PERFORMANCE COMPONENT OF THE ANNUAL INCENTIVE

16 PLANS?

17 A: To arrive at 35%, I included costs in category (2), cost control goals, as related to

18 financial performance. I also included one-third of the costs in category (5), which

19 included a combination of cost control, safety and operational goals. When categories

20 (1) and (2) and one-third (1/3) of category (5) are combined, the amount related to

66
Direct Testimony of Kevin G. Gardner at page 30, line 7.
67
Highly Confidential Exhibit KGG-4, page I of 1.
68
Calculated from the information on Highly Confidential Exhibit KGG-4.

Direct Testimony of Mark E. Garrett Page 47 of 65
Docket No. 39896
1 financial performance is 35%. I included the category (2), cost control goals, as related

2 to financial performance because, in my experience, this is the typical treatment for cost

3 control measures. Since the Company retains all of the savings generated from cost

4 cutting measures between rate cases, it should pay the related incentives out of the

5 savings these cost cutting measures generate. Moreover, this treatment is consistent with

6 the regulatory treatment used by this Commission in the past on this issue. 71

7

8 Q: HOW WAS YOUR ADJUSTMENT DEVELOPED?

9 A: The following table shows the amount of Cities' proposed adjustment for incentives:

69
From the Description of Goals box at the bottom of page l of Highly Confidential Exhibit KGG-4.
70
See Direct Testimony of Jay C. Hartzell, PhD, at page 9, lines 9-13.
71
See Id. at page 8, lines 9-13 and footnote 1.

Direct Testimony of Mark E. Garrett Page 48 of65
Docket No. 39896
 Table 3: Cities' Incentive Compensation Adjustment

Amount % Tied to
CITIES'
Incentive Compensation Plans Included in Financial
Adjustment
Cost of Service Performance
Management Incentive Plan $4,749,198 35% $1,862,219
Exempt Incentive Plan $1,858,337 35% $650,418
Team Share Incentive Plan $153,447 35% $53,706
Team Share - Bargaining Employees $384,877 35% $134,707
Executive Annual Incentive Plan $1,483,447 35% $519,206
Long-Term Incentive Plans $815,608 100% $815,608 I
Equity Ownership Plans $4,561,367 100% $4,561,367

CITIES' Adjustment $14,187,774 $8,397,2321
I I

1 Q: ARE THERE OTHER REASONS THE COMMISSION COULD CONSIDER A

2 LARGER ADJUSTMENT TO INCENTIVE PAY?

3 A: Yes. The Company's "allowable" incentive payments, m effect, those not tied to

4 financial goals, are tied primarily to operational goals, made up of "reliability, customer

5 service, capacity factor and community relations." In the test year, the Company made

6 substantial incentive payments based on employees achieving some perceived acceptable

7 level with respect to these goals. However, these payments seem inconsistent with

8 Entergy's ratings in the annual J.D. Power's Report on Customer Satisfaction for

9 Residential customers. 71 The J.D. Power and Associates Reports are widely recognized

10 and unbiased. The J.D. Power's report ranks utilities based on customer satisfaction. The

11 Entergy companies did not fare well, with Entergy Arkansas and Entergy Louisiana

12 ranking below average and Entergy New Orleans ranking 124th out of the 125 utilities

Direct Testimony of Mark E. Garrett Page 49 of65
Docket No. 39896
 1 ranked in the 2011 report. Entergy Texas ranked only slightly above average. The poor

2 showing of the Entergy companies in general in an independent, objective customer

3 satisfaction evaluation report brings into question whether ratepayers should be required

4 to pay any of the "allowable" ETI incentives that are based on customer service and

5 community relations.

6

7 Q: IS THERE EVIDENCE THAT THE ANNUAL INCENTIVE PLANS ACTUALLY

8 MAY BE TIED TO FINANCIAL PERFORMANCE AT LEVELS HIGHER THAN

9 THE 35% DIRECTLY RELATED TO STOCK PRICE GOALS AND COST

10 CONTROL GOALS?

11 A: Yes. Each Entergy business unit designs its incentive targets based on goals that include

12 both financial-performance and operational goals such as spending level goals, cost

13 constraint goals, reliability goals, safety goals and customer service goals. However, the

14 Company still uses the EAM (Entergy Achievement Multiplier) to arrive at the amount

15 to be funded each year. In the past, the EAM was a composite of the Company's

16 earnings per share increase and operating cash flows, and was used as a performance

17 target. Now, the EAM operates as a funding mechanism for all plans to ensure that

18 adequate additional funds exist to pay the incentives, and as a performance target for

19 certain executives. 73 This indicates that all incentive payments are directly dependent on

20 the financial success of the Company each year. For ratemaking purposes, this means

21 that the entire amount of incentive payments could be viewed as tied to financial

72
J.D. Power and Associates 2011 Electric Utility Residential Customer Satisfaction Study.
Direct Testimony of Mark E. Garrett Page 50 of65
Docket No. 39896
 I performance and disallowed on this basis. 74 If that were the case, the adjustment

2 necessary to remove the entire amount of incentive payments from the cost of service

3 would be $14,187,744.

4

5 Q: HOW SHOULD THE COMMISSION TREAT INCENTIVE COMPENSATION

6 IN THIS CASE?

7 A: At a minimum, the Commission should continue to follow the rule observed in Texas

8 and in most other jurisdictions, by disallowing for ratemaking purposes all incentive

9 payments associated with financial performance goals. This approach would exclude

10 the portion of annual incentive costs associated with stock price and cost control goals -

11 as well as the costs of the long-term incentive plan and the stock option plans. In light of

12 the overwhelming trend against including financial-based incentives in rates, and

13 considering the current national economic downturn and the economic shortfalls being

14 experienced in Texas in particular, I believe the Commission should continue to follow

15 the approach to incentive compensation that protects ratepayers against even the

16 appearance of being forced to pay costs designed to increase shareholder wealth. A

17 policy that includes incentive payments based on financial performance in rates, as

18 proposed by the Company, has the effect of forcing ratepayers to become captive

19 contributors to the financial prosperity of one company. Cities' proposed adjustment

73
See Direct Testimony of Kevin G. Gardner at page 17-18.
74
In Oklahoma, the Commission disallowed l 00% of the ONEOK, Inc. incentives for regular employees, because,
although many of the goals were purportedly customer-related goals, actual funding of the incentive payments
depended on the financial success of the company each year. See Cause Nos. PUD 91-1190 and PUD 2004-610.

Direct Testimony of Mark E. Garrett Page 51 of65
Docket No. 39896
 decreases pro forma operating expense by $8,397,232, and is set forth at Exhibit MG-

2 2.10.

3 In the alternative, the Commission could consider a larger adjustment based on

4 the fact the Company's performance with respect to operational goals, such as customer

5 service and customer satisfaction, should not be included in rates if the Company's

6 performance in these areas is clearly below average. Based on the assessment of an

7 independent third party in the J.D. Power report, the Company's performance in

8 customer satisfaction is below average and, thus, the Commission may determine that a

9 larger disallowance of incentive compensation is appropriate.

10

11 Q: ARE YOU PROPOSING ANY OTHER ADJUSTMENTS FOR INCENTIVE

12 COSTS?

13 A: Yes. Disallowed incentive costs should not just be removed from operating expense but

14 should also be removed from rate base as well. When a cost is disallowed for

15 ratemaking purposes it must be removed from both operating expense and rate base.

16 Since a significant portion of the Company's incentive payments are capitalized each

17 year into the plant accounts, these amounts are included in pro forma rate base where

18 they will earn a return and be recovered through depreciation rates if not adjusted in this

19 case. Thus, it is necessary to reduce the amount of incentives capitalized in rate base by

20 the same percentage disallowed in operating expense. In effect, capitalized annual

21 incentives should be reduced by 35% and capitalized stock-based incentives should be

22 reduced by 100%.

Direct Testimony of Mark E. Garrett Page 52 of65
Docket No. 39896
 1 Q: HAVE YOU BEEN ABLE TO QUANTIFY THIS ADJUSTMENT?

2 A: Yes. In response to Cities' 10th Set of RFis, the Company provided the amounts

3 capitalized for each incentive plan from 2008 through the end of the test year. For my

4 proposed adjustment, I included capitalized incentives from 2008 through the beginning

5 of the test year but did not include incentive capitalized during the test year, as test year

6 incentives may still be recorded in the CWIP accounts and not included in pro forma rate

7 base in this case.

8 Cities' proposed adjustment decreases proforma rate base by $9,835,111 and is

9 set forth at Exhibit MG-2.10. This adjustment removes 35% of the annual incentives in

10 rate base and 100% of the equity-based incentives, from the 2007 inception of ETI

11 forward excluding the test year.

12

13 Q: ARE YOU PROPOSING ANY OTHER ADJUSTMENTS FOR INCENTIVE

14 COSTS?

15 A: Yes. Accumulated deferred federal income tax (ADFIT) associated with disallowed

16 long-term incentive plans should be removed from rate base. This means that rate base

17 should be reduced by a net $694,730 debit balance in ADFIT accounts associated with

18 the Company's long-term incentive and stock option plans. The calculations for this

19 adjustment are set forth at Exhibit MG2. l 0.

Direct Testimony of Mark E. Garrett Page 53 of65
Docket No. 39896
 SECTION IV. F. SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS

1 Q: PLEASE DESCRIBE THE COMPANY'S SUPPLEMENTAL EXECUTIVE

2 RETIREMENT PLANS.

3 A: The Company provides supplemental retirement benefits to highly compensated employees

4 of the Company. These supplemental retirement plans for highly compensated individuals

5 are provided because benefits under the general retirement plans are subject to certain

6 limitations under the Internal Revenue Code (the "Code"). As such, these types of plans are

7 often referred to as non-qualified plans. Benefits payable under these non-qualified plans

8 are typically equivalent to the amounts that would have been paid but for the limitations

9 imposed by the Code. In general, the limitations imposed by the Code allow for the

75
10 computation of benefits on annual compensation levels of up to $245,000 for the year.

11 Retirement benefits on compensation levels in excess of the $245,000 limitation are paid

12 through supplemental plans. Supplemental retirement plans for highly compensated

13 employees are designed to provide benefits in addition to the benefits provided under the

14 general pension plans of the company.

15 The Company has three non-qualified retirement plans for highly compensated

16 employees:

17 1) Pension Equalization Plan;
18 2) System Executive Retirement Plan; and
19 3) Supplemental Retirement Plan.

75
The limits are $225,000 for 2007, $230,000 for 2008 and $245,000 for 2009.

Direct Testimony of Mark E. Garrett Page 54 of65
Docket No. 39896
 1 The first plan covers all employees with compensation levels above the $245,000 limitation

2 under the internal revenue code. The other two plans are supplemental plans for executives

3 only. Benefits are paid out of the general funds of the Company.

4

5 Q: WHAT AMOUNTS WERE INCLUDED IN PROFORMA OPERATING EXPENSE

6 FOR THE EXECUTIVE PENSION PLAN?

7 A: The amount of non-qualified supplemental retirement plan costs included in the filed cost-

8 of-service was $2, 114,931. Of this amount, direct ETI costs were $721,643 and the amount

9 allocated from ESI was $1,393,288. 76

10

11 Q: WHAT DO YOU RECOMMEND FOR THE SUPPLEMENTAL EXECUTIVE

12 RETIREMENT PLAN COSTS?

13 A: I recommend that shareholders pay for the costs of the supplemental executive

14 retirement plans. This means that ratepayers will pay for all of the executive benefits

15 included in the Company's regular pension plans, and that shareholders pay for the

16 additional executive benefits included in the supplemental plan. For ratemaking

17 purposes, shareholders should bear the additional costs associated with supplemental

18 benefits to highly compensated executives, since these costs are not necessary for the

19 provision of utility service, but are instead discretionary costs of the shareholders

20 designed to attract, retain and reward highly compensated employees. However, because

21 officers of any corporation have a duty of loyalty to the corporation, these individuals

76
See ETI responses to Cities' RFI 12-47.
Direct Testimony of Mark E. Garrett Page 55 of 65
Docket No. 39896
 1 will put the interests of the company first. This creates a situation where not every cost

2 associated with executive compensation is presumed to be a cost appropriately passed on

3 to ratepayers. Many regulators are inclined to exclude executive bonuses, incentive

4 compensation and supplemental benefits from utility rates, understanding that these costs

5 would be better borne by the utility shareholders. 77

6

7 Q: HOW IS SERP TREATED IN OTHER STATES?

8 A: Although I have not conducted a comprehensive study of SERP treatment in other states,

9 I know that SERP is disallowed in the states of Oregon, 78 Idaho 79 and Arizona. 80

10 Moreover, in Nevada, the commission disallowed all SERP expense in Docket Nos. 01-

11 10001 and 03-10001, and in Docket Nos. 06-l 1022and 08-12002, the Nevada

12 Commission disallowed a portion of SERP costs.

77
For example, this Commission excluded SERP costs in PSO's last rate case, PUD 200600285.
78
See Oregon Public Utilities Commission, Order No. 01-787, September 7, 2001, page 44.
The Commission has not allowed recovery of SERP expenses in other utility rate cases.
PacifiCorp has not persuaded us that it is necessary to pay SERP to hire and retain
executive officers. The SERP costs are not allowed."
79
See Idaho Public Utilities Commission Order No. 32196 issued February 28, 2011 in Rocky Mountain Power's
rate case, Case No. Pac-E-10-07:

The Commission finds Staffs argument persuasive and finds it reasonable to disallow Company
recovery of SERP costs of $2.6 million (total Company) in this case. The Company has not
demonstrated that the costs are related to providing services to southeast Idaho. The responsibility
for generous severance benefits for executives, we find, is the responsibility of the Company and
its shareholders, not Idaho customers.
80
The Arizona Corporation Commission has issued several decisions in which it denied rate recovery for SERP
expenses. See 258 PUR 4th 353 (2007) Re Arizona Public Service Company, 247 PUR 4th 243 (2006), In Re
Southwest Gas Corp., 2008 WL 2332953 (Arizona Corp Commission Decision 70360, May 27, 2008), In the
Matter of the Application of UNS Electric, and 2007 WL 4731250 (Arizona Corp Commission Decision 70011,
November 27, 2007) Re UNS Gas, Inc.

Direct Testimony of Mark E. Garrett Page 56 of65
Docket No. 39896
 1 In Oklahoma, the Commission disallowed 100% of AEP/PSO's SERP expense in

2 PSO's 2006 rate case, Cause No. PUD 200600285:

3 q. Employee Benefits-Supplemental Executive Retirement Plan
4 ("SERP").
5
6 PSO included $596,081 as Supplemental Executive Retirement Plan
7 ("SERP") in its cost-of-service. The Commission adopts OIEC's
8 proposal to remove the SERP Expense from the revenue requirement in
9 this proceeding. The Commission adopts OIEC's recommendation that
I0 ratepayers pay for all of the executive benefits included in PSO's regular
11 pension plans and that shareholders pay for the additional executive
12 benefits included in the supplemental plan.

13 Again, in PSO's 2008 rate case, Cause No. PUD 200800144, the Oklahoma commission

14 disallowed 100% of the Company's SERP expense.

15 11. Supplemental Executive Retirement Plan ("SERP")

16 The AG and OIEC recommend reductions to reflect the elimination of
17 SERP expense from PSO' s cost of service. Staff proposed no adjustment
18 to PSO's recommendation. SERP is AEP's non-qualified defined benefit
19 retirement plan that allows PSO argued allows AEP the flexibility to
20 attract and retain key employees and provides benefits that cannot be
21 provided under AEP's qualified defined benefit plans. PSO stated that
22 the combined plans, of which SERP is a part, allow employees to
23 accumulate an appropriate level of replacement income upon retirement.
24 According to PSO, SERP plans and other benefits are part of a market
25 competitive benefits program for the utility industry and large employers
26 in general. The Commission finds that the SERP expenses do not provide
27 a benefit to the ratepayers of PSO and therefore adopts the
28 recommendation of the AG and OIEC to deny recovery of these costs
29 from PSO's ratepayers.

Direct Testimony of Mark E. Garrett Page 57 of65
Docket No. 39896
 I Q: WHAT IS THE AMOUNT OF YOUR ADJUSTMENT?

2 A: Cities' proposed adjustment, in the amount of $2,114,931, removes the costs of the non-

3 qualified retirement plans from cost of service. The adjustment is set forth at Exhibit

4 MG-2.11.

SECTION IV. G. ABOVE-MARKET EMPLOYEE BENEFITS

5 Q: WHAT IS THE ISSUE WITH RESPECT TO ABOVE-MARKET EMPLOYEE

6 BENEFITS?

7 A: This section of my testimony addresses the above-market value of the Company's

8 employee benefit plans. At page 41 of his direct testimony, Mr. Gardner admits that the

9 value of the Company's employee benefit plans is 14% above market when compared to

10 a peer group of Fortune 500 companies.

11

12 Q: HA VE YOU PROPOSED AN ADJUSTMENT TO THE BASE PAY LEVEL

13 REQUESTED IN RATES?

14 A: Yes. From a ratemaking perspective, ratepayers are only required to pay the necessary

15 costs of providing utility service. Although the Company is free to pay its employees

16 above-market wages and above-market benefits, ratepayers should only be asked to pay

17 market-based prices for employee costs. For purposes of this adjustment, the calculation

18 of market-based wages is based the Company's own calculation. Because ratepayers

19 are experiencing the effects of perhaps the most severe financial downturn in the past 30

20 to 35 years, it would be particularly unfair at this time to ask captive ratepayers to pay

Direct Testimony of Mark E. Garrett Page 58 of65
Docket No. 39896
1 above-market wages for utility services. As a result, I am recommending a 14%

2 adjustment to the employee benefits expense included in proforma rates.

3

4 Q: HOW IS YOUR ADJUSTMENT CALCULATED?

5 A: The adjustment, calculated in the table below, removes 14% of the Company's identified

6 employee benefits expense. The adjustment can be seen at Exhibit MG 2.9.

Table 4: Cities' Employee Benefits Adjustment81

Total Amount in
Employee Benefit Plans ETI ESI Cost of Service
Medical I Dental 4,476,874 2,504,140 5,981,014
LTD 131,273 58,058 189,331
Life 142,636 79,328 221,964
Retirement Plans 7,324,753 5,711,755 13,036,508
Executive F'"etirement Plans 721,643 1,393,288 0

Totals 12,797,179 9,746,569 20,426,817

Above Market Percentage 14%

CITIES' Adjustment $2,860,034

81
The information in this table is from ETI's response to Cities' RFI 18-l(d)(vii).

Direct Testimony of Mark E. Garrett Page 59 of65
Docket No. 39896
 SECTION IV. H. ADV ALOREM TAX EXPENSE

1 Q: WHAT IS THE COMPANY PROPOSING AS AN AD VALOREM TAX

2 EXPENSE ADJUSTMENT?

3 A: The Company is proposing a 10. 81 % increase in property tax expense based on a

4 weighted average projected increase in net plant and net operating income for 2011. 82

5 The Company asserts that both net plant and net income are drivers in determining a

6 company's calculation for property tax assessment purposes. 83 The Company gives its

7 projected net plant increase a 20% weighting and its projected net income increase an

8 80% weighting and then adds an additional 1% for "Annual Tax Rate Creep." 84 The

9 Company's 10.81 % projected increase in property tax valuation results in an adjustment

10 of $2,592,417 to test year property tax expense.

11

12 Q: DO YOU AGREEE WITH THE COMP ANY'S PROPOSED ADJUSTMENT?

13 A: No. The Company's proposed adjustment is based on estimates and seems unreasonably

14 high when compared to actual valuation increase over the last couple of years. The

15 Company provided actual valuation increases for 2010 and 2011 in Chart 1 at page 8 of

16 Patricia Galbraith's direct testimony. These actual valuation increases were 7.0% in

17 2010 and 4.2% in 2011, much less than the Company's predicted 10.81% increase for

18 2012.

82
See AJ25, Adjustment to Property Tax Expense.
83
See Direct Testimony of P. Galbraith at page 7, line 16.
84
See AJ25, Adjustment to Property Tax Expense.

Direct Testimony of Mark E. Garrett Page 60 of65
Docket No. 39896
 1 Q: WHAT ADJUSTMENT WOULD YOU RECOMMEND FOR PROPERTY TAX

2 EXPENSE?

3 A: I would recommend a more conservative approach when estimating tax increases. Since

4 actual valuation increases have averaged about 5.6% over the last two year period, I

5 would recommend an increase in that range for ratemaking purposes. Since property tax

6 is typically assessed on the appraised value of property located within the jurisdiction of

7 the taxing authority, 85 I recommend an adjustment based upon the Company's estimated

8 percentage increase in net plant for 2011, which is 3.73%. 86 With a 1% "Tax Rate

9 Creep" added, this results in a 4.73% increase, which is much closer to the Company's

10 actual average valuation increase of 5.6%. A 4.73% increase in property tax expense

11 results in an increase to test year property tax expense of $1.1 million. Using a 4.73%

12 increase instead of the Company's recommended 10.81 % increase results in an

13 adjustment to pro forma cost of service of $1,457,975. This adjustment can be seen at

14 Exhibit MG2.13.

SECTIONV. MISO TRANSITION EXPENSE ADJUSTMENT

15 Q: WHAT IS THE ISSUE REGARDING MISO TRANSITION EXPENSE?

16 A: In this case, the Company is requesting deferred accounting treatment for its MISO

17 transition costs. 87 The Company is also proposing a pro forma adjustment to include its

18 estimated MISO transition costs in rates in the event its requested deferred accounting

85
See P. Galbraith Direct Testimony at page 6, line 16.
86
See AJ25.
87
See the Direct Testimony and the Supplemental Testimony of Mr. Jay A. Lewis.

Direct Testimony of Mark E. Garrett Page 61 of 65
Docket No. 39896
 1 treatment is not approved. Cities oppose the Company's requested deferred accounting

2 for the MISO transitions costs in the testimony of Mr. James Brazell. In my testimony, I

3 address the Company's pro forma adjustment to recover MISO transition costs in the

4 event the deferred treatment is not approved.

5

6 Q: WHAT IS THE COMPANY PROPOSING FOR A PROFORMA ADJUSTMENT

7 TO RECOVER ESTIMATED MISO TRANSITION COSTS?

8 A: The Company's adjustment increases cost of service by $4 million annually to recover a

9 3-year amortization of estimated MISO transition costs of $12 million. 88

10

11 Q: DO YOU AGREE WITH THE COMP ANY'S PROPOSED ADJUSTMENT IN

12 THE EVENT DEFERRED ACCOUNTING IS NOT APPROVED FOR MISO

13 TRANSITION COSTS?

14 A: No. The Company's requested $4 million annual expense level is inconsistent with the

15 Company's own projections of anticipated cost levels provided in response to Cities' 6-

16 3. The test year level for these expenses was $916,535. 89 The actual expenses incurred

17 m 2011, January through November, were only $2.513 million. 90 Annualized, this

18 would be $2.742 million. For 2013, the Company is expecting to incur an expense level

88
See adjustment AJl 6.23L. The Company also removes test year expense of $9 l 6K so that the amount included
in pro forma expense is $4 million.
89
See AJl 6L is ETI Workpapers.
90
This amount appears in ETI's response to Cities' 6-3(b), Confidential Attachment 2. Attachment 2 is not being
provided as an exhibit to this testimony because of its confidential designation. Cities, however, is using the
$2,513 ,932 total from Attachment 2 with permission of the Company.

Direct Testimony of Mark E. Garrett Page 62 of65
Docket No. 39896
 1 of $2.587 million, 91 which is considerably less than the pro forma level of $4 million.

2 The projected 2012 level of $8.9 million is higher than $4 million, but the 2012 is an

3 estimated level and is not consistent with actual 2011 results, and, 2012 will be half-over

4 by the time new rates go into effect. In my opinion, the actual 2011 level of about $2. 7

5 million or the expected 2013 level of about $2.6 million would be the outside range of

6 what the Commission would use for setting prospective rates. However, these levels, on

7 a going forward basis, are not sufficiently known and measurable to include for

8 ratemaking purposes. It is unknown at this point whether the move to MISO will even

9 be approved by this or other commissions and whether the Company will continue to

10 incur costs toward a MISO transition. Consequently, we are left with only the test year

11 level as the level to include in rates.

12

13 Q: HOW IS YOUR ADJUSTMENT CALCULATED?

14 A: My recommendation to reduce the Company's requested level of $4 million to the actual

15 test year level of $916,535 results in an adjustment of $3,083,462. This adjustment can

16 be seen at Exhibit MG2.14.

91
This amount appears in ETI's responses to Cities' 6-3(a)and (c), Confidential Attachment 1. Attachment l is not
being provided as an exhibit to this testimony because of its confidential designation. Cities, however, is using the
$2,587,943 total from Attachment 1 with permission of the Company.

Direct Testimony of Mark E. Garrett Page 63 of65
Docket No. 39896
 SECTION VI. RIVER BEND DECOMMISSIONING EXPENSE

1 Q: WHAT IS THE ISSUE REGARDING THE RIVER BEND DECOMMISSIONING

2 EXPENSE?

3 A: In its application, the Company has included River Bend decommissioning costs in the

4 amount of $2,019,000. This level is based on an agreement of the parties in the

5 Company's 2009 rate case, Docket No. 37744. 92 In this case, the Company was

6 requested to provide the annual decommissioning expense responsibility for Texas retail

7 customers required for River Bend 70% calculated using the most current Texas

8 Jurisdictional decommissioning fund balance and assuming the escalation rates agreed to

9 in the settlement of Docket No. 37744. The Company was also asked to provide the

10 most current fund balance sheet for the total fund balance, the calculation of the annual

11 decommissioning expense, the proposed funding term, and any other assumptions

12 supporting ETis calculation. In response, the Company provided the annual

13 decommissioning revenue requirement based on the Texas retail trust fund liquidation

14 values as of December 31, 2011, the assumed nuclear cost escalation rate of 3.625%

15 agreed to in the settlement of Docket No. 37744, and the projected trust fund earnings

16 rates and the NRC minimum cost estimate utilized in the decommissioning revenue

17 requirement approved in Docket No. 37744. This annual revenue requirement is

18 $1,126,000.

92
See Order signed 12/13/10 in Docket No. 37744 at paragraph 32, and ETI responses to Cities' 10-20 and 10-22.

Direct Testimony of Mark E. Garrett Page 64 of65
Docket No. 39896
 1 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THIS ISSUE?

2 A: Chapter 25 of the Substantive Rules Applicable to Electric Providers at §25 .231 (b)(F)(i)

3 provides that the annual cost of decommissioning for ratemaking purposes must be

4 determined in each rate case and expressly included in the cost of service established by

5 the commission's order. The amount expressly established in this case should be the

6 Company's calculated annual decommissioning revenue requirement of $1,126,000.

7 Also, an adjustment of $893,000 to the pro forma cost of service is needed to reflect the

8 difference between the requested level for decommissioning costs of $2,019,000 and

9 recommended level of $1, 126,000. This adjustment is included at Exhibit MG 2.12.

10

11 Q: DOES THIS CONCLUDE YOUR TESTIMONY?

12 A: Yes. It does.

Direct Testimony of Mark E. Garrett Page 65 of65
Docket No. 39896
Blank Page
II II
SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, §
INC. FOR AUTHORITY TO CHANGE § BEFORE THE STATE OFFICE
RATES, RECONCILE FUEL COSTS, § OF
AND OBTAIN DEFERRED § ADMINISTRATIVE HEARINGS
ACCOUNTING TREATMENT §

DIRECT TESTIMONY AND EXHIBITS

OF

DR. DENNIS W. GOINS

ON BEHALF OF

CITIES SERVED BY ENTERGY TEXAS, INC.

MARCH 27, 2012

REDACTED PUBLIC VERSION
Blank Page
 TABLE OF CONTENTS

Page
INTRODUCTION AND QUALIFICATIONS .................................................................. 1

CONCLUSIONS •••••••••••••••••••••••••••••••••••.••••••••••••••••..••..•••••.•••••••••••••••••••••...•••••••••••..•••• 4

RECOMMENDATIONS ••••••••••••••••••••••••••••••••••••.••••.•.•.••••••••••••••••••••••••......••••••••...••••••• 8

WHOLESALE JURISDICTION ALLOCATION .••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 10

PURCHASED POWER CAPA CITY COSTS ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 13

MSS-2 COSTS ••••••••••••••••••••••••••••••••••••••.•...••••••••••••••••••..••..•...••.•••••••••••••••••••••••••..... 19

STREET LIGHTING AND TRAFFIC SIGNAL RATES •••••••••••••.•••••••••••......•.•••••••••••••• 21

EXHIBITS

APPENDIX: QUALIFICATIONS

Docket No. 39896
Dennis W. Goins - Direct
Page i
Blank Page
 SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, INC. § BEFORE THE
FOR AUTHORITY TO CHANGE RATES, § STATE OFFICE OF
RECONCILE FUEL COSTS, AND OBTAIN § ADlVUNISTRATJVE HEARINGS
DEFERRED ACCOUNTING §

DIRECT TESTIMONY OF
DENNIS W. GOINS
ON BEHALF OF
CITIES

INTRODUCTION AND QUALIFICATIONS

2 Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
3 ADDRESS.

4 A. My name is Dennis W. Goins. I operate Potomac Management Group, an
5 economics and management consulting firm. My business address is 5801
6 Westchester Street, Alexandria, Virginia 22310.

7 Q. PLEASE DESCRIBE YOUR EDUCATIONAL AND
8 PROFESSIONAL BACKGROUND.

9 A. I received a Ph.D. degree in economics and a Master of Economics degree
10 from North Carolina State University. I also earned a B.A. degree with
11 honors in economics from Wake Forest University. Following graduate
12 school I worked as a staff economist at the North Carolina Utilities
13 Commission (NCUC). During my tenure at the NCUC, I testified in
14 numerous cases involving electric, gas, and telephone utilities on such
15 issues as cost of service, rate design, intercorporate transactions, and load
16 forecasting. While at the NCUC I also served as a member of the
17 Ratcmaking Task Force in the national Electric Utility Rate Design Study

Docket No. 39896
Dennis W. Goins - Direct
Page 1
 sponsored by the Electric Power Research Institute (EPRI) and the
2 National Association of Regulatory Utility Commissioners (NARUC).
3 Since leaving the NCUC, I have worked as an economic and
4 management consultant to firms and organizations in the private and
5 public sectors. My assignments focus primarily on market structure,
6 policy, planning, and pricing issues involving firms that operate in energy
7 markets. For example, I have conducted detailed analyses of product
8 pricing, cost of service, rate design, and interutility planning, operations,
9 and pricing issues; prepared analyses related to utility mergers,
10 transmission access and pricing, and the emergence of competitive
11 markets; evaluated and developed regulatory incentive mechanisms
12 applicable to utility operations; and assisted clients in analyzing and
13 negotiating interchange agreements and power and fuel supply contracts. I
14 have also assisted clients on electric power market restructuring issues in
15 Arkansas, New Jersey, New York, South Carolina, Texas, and Virginia.
16 I have submitted testimony and affidavits and provided technical
17 assistance in nearly 200 proceedings before state and federal agencies as
18 an expert in competitive market issues, regulatory policy, utility planning
19 and operating practices, cost of service, and rate design. These agencies
20 include the Federal Energy Regulatory Commission (FERC), the
21 Government Accountability Office, state courts in Iowa, Montana, and
22 West Virginia, and regulatory agencies in Alabama, Arizona, Arkansas,
23 Colorado, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Kansas,
24 Kentucky, Louisiana, Maine, Maryland, Massachusetts, Minnesota,
25 Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio,
26 Oklahoma, South Carolina, Texas, Utah, Vermont, Virginia, West
27 Virginia, Wyoming, and the District of Columbia. Additional details of
28 my educational and professional background are presented in the
29 Appendix.

Docket No. 39896
Dennis W. Goins - Direct
Page 2
 Q. ON WHOSE BEHALF ARE YOU APPEARING IN THIS
2 PROCEEDING?

3 A. I am appearing on behalf of the Cities of Anahuac, Beaumont, Bridge City,
4 Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery,
5 Navasota, Nederland, Oak Ridge North, Orange, Pinc Forest, Pinehurst,
6 Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake,
7 Splendora, Vidor, and West Orange (collectively, the Cities).

8 Q. WHAT ASSIGNMENT WERE YOU GIVEN WHEN YOU WERE
9 RETAINED?

10 A. I was asked to undertake two primary tasks:
11 1. Review the application, testimony, and exhibits filed by Entergy
12 Texas, Inc. (ETI) to adjust its base rates, reconcile fuel costs, and
13 obtain deferred accounting. In particular, I was asked to focus on
14 issues related to ETI's proposed treatment of demand-related
15 production costs associated with serving wholesale customers,
16 recovery of purchased power and transmission capacity costs, and
17 the design of street lighting and traffic signal rates.
18 2. Evaluate the reasonableness of ETI's proposals, and recommend
19 necessary changes.

20 Q. WHAT INFORMATION DID YOU REVIEW IN CONDUCTING
21 YOUR EVALUATION?

22 A. I reviewed ETI' s filing, testimony, exhibits, and responses to requests for
23 information. I also reviewed selected testimony and Commission orders in
24 prior ETI rate cases related to issues that I address in my testimony. I also
25 reviewed street lighting and traffic signal rates offered by selected utilities
26 other than ETI. Finally, I reviewed information found on web sites
27 operated by ETI's parent company, Entergy, Inc., FERC, the Commission,
28 and other selected state regulatory commissions.

Docket No. 39896
Dennis W. Goins - Direct
Page3
 CONCLUSIONS

2 Q. WHAT CONCLUSIONS HAVE YOU REACHED?

3 A. On the basis of my review and evaluation, I have concluded the following:
4 1. During the test year in this case (July 20 IO-June 2011 ), ETI
5 provided electric service to retail customers in Texas, as well as
6 three wholesale customers-including East Texas Electric
7 Cooperative (ETEC)-under service agreements and rates
8 approved by FERC. 1 ETEC-a partial requirements customer-
9 will be ETI's only wholesale customer during the forward-looking
10 rate year (June 2012-May 2013).
11 2. Because ETI does not own sufficient capacity to serve its Texas
12 retail and ETEC wholesale loads, it must rely on purchased
13 capacity. The principal sources of ETI's purchased capacity
14 resources are:
15 II System capacity purchases from EOCs with surplus capacity
16 that is billed under Service Schedule MSS- I of the Entergy
17 System Agreement (ESA). Because Schedule MSS-1 is
18 designed to share the cost of system reserve capacity among
19 the EOCs, MSS-1 transactions are referred to as Reserve
20 Equalization.
21 11 Unit power purchases from EOCs under Service Schedule
22 MSS-4 of the ESA. Several of these purchases are related to
23 purchased power agreements arising from the JSP. 2 For

1
In addition to ETI, the other regulated Entergy Operating Companies (EOCs) are Entergy Gulf
States Louisiana, LLC (EGSL), Entergy Arkansas, Inc. (EAI), Entergy Louisiana (ELL), Entergy
Mississippi (EMI), and Entergy New Orleans, Inc. (ENOI). ETI's and EGSL's predecessor was
Entergy Gulf States, Inc. (EGSI), which was split into two vertically integrated utilities-ETI and
EGSL-~as a result of the Jurisdictional Separation Plan (JSP) that became effective December 31,
2007.
2
Under the JSP, all of EGSI's transmission and distribution assets and gas-fired generating plants
were assigned to ETI and EGSL on a situs basis. ETI also got an undivided 42.5-percent share in
EGSI's 70-percent ownership interest in Nelson 6 and a 42-percent ownership interest in Big

Docket No. 39896
Dennis W. Goins - Direct
Page 4
 example, as a result of the JSP, ETI has a life-of-unit
2 purchased power agreement for 42.5 percent of the 70 percent
3 of EGSL's River Bend nuclear station subject to retail
4 regulation. ETI refers to these purchases as Legacy Affiliate
5 Contracts. In addition, ETI makes unit power purchases from
6 EOCs that are unrelated to the JSP. ETI refers to these
7 affiliate purchases as Other Affiliate Contracts 3
8 II Third-party purchases from firms not affiliated with ETI or
9 other Entergy companies-for example, ETEC. Two of the
10 third-party contracts-the 10-year, 485-MW Carville contract
11 and the 25-year, 225-MW purchase power agreement with
12 Sam Rayburn Municipal Power Agency (SRMPA)-were not
13 in place during the test year, but will be in place during the
14 rate year. 4
15 3. ETI estimated its cost of servmg Wholesale customers m a
16 jurisdictional separation study that split ETI' s cost of service
17 between the Texas Retail and the Wholesale jurisdictions. In this
18 jurisdictional study, ETI assigned demand-related (fixed)
19 production costs to each jurisdiction using the average and excess,
20 4 coincident peak (AED4CP) allocation method-the same method
21 that ETI used in its class cost-of-service study to assign demand-
22 related production cost responsibility to each retail customer class.
23 4. ETI (and its predecessors) has historically recovered purchased
24 power capacity costs in base rates. However, in this case, ETI
25 initially proposed recovering $276.2 million in rate year FERC
26 Account 555 purchased power expense-including MSS-1 and

Cajun 2, Unit 3---two coal units in Louisiana. EGSL became the owner of EGSI's remaining
generating plants--including the River Bend nuclear plant.
3
See the direct testimony of ETI witness Robert R. Cooper (Cooper Direct) at 21: 1-8 and Exhibit
RRC-1 (HS). (ETI updated and revised Exhibit RRC-1 (HS) on March 16, 2012.)
4
Ibid. at 21 :10-22:14.

Docket No. 39896
Dennis W. Goins - Direct
Page S
 MSS-4 capacity payments-through a new purchased power
2 recovery rider instead of base rates. 5 As a result of a Commission
3 ruling following ETI's filing, recovery of ETI's purchased power
4 capacity costs (PPCC) is restricted to base rates at present, and
5 ETI' s proposed purchased power recovery rider will not be
6 considered in this case.
7 5. In this case ETI proposed adjusting test-year PPCC to reflect
8 known and measurable changes (primarily the expiration of some
9 test-year contracts and the commencement of two new purchase
10 power agreements). To reflect these changes, ETI recommends
11 setting its adjusted test-year PPCC equal to its forecast rate year
12 PPCC ($276.2 million), which will be recovered in base rates.
13 Including rate-year PPCC in base rates set using historical adjusted
14 test-year billing determinants ensures overrecovery of ETI's PPCC
15 if its load grows relative to test-year levels-that is, if rate-year
16 billing determinants are expected to be greater than test-year billing
17 determinants. ETI made no adjustment to its rate-year PPCC to
18 prevent this likely overrecovery.
19 6. ETI has proposed a similar approach to recover transmission costs
20 associated with payments under Service Schedule MSS-2.
21 Specifically, ETI adjusted its test-year MSS-2 costs (approximately
22 $1.84 million) to reflect a nearly - increase in rate-year
23 MSS-2 costs (almost ETI's MSS-2 test-year
24 adjustment ignores Entergy' s announced divestiture/merger of its
25 transmission assets into ITC Holdings Corp. (ITC) in 2013. In

5
On March 16, 2012, ETI updated and revised Exhibit RRC-1 (HS) to reflect the impacts ofrecent
changes in the EAI WBL contract on ETI's rate-year costs for Other Affiliate Contracts and
Reserve Equalization. The updated PPCC shown in Exhibit RRC-1 (HS-revised) is $275.8
million. Because ETI has not yet updated and revised witness Cooper's direct testimony, I use the
$276.2 million shown in ETI's original filing and Exhibit RRC-1 when referring to ETI's rate-year
PPCC in my testimony. However, Cities rec01mnended adjustments to ETI's rate-year PPCC that I
present later include ETI's PPCC adjustments shown in Exhibit RRC-1 (HS-revised).

Docket No. 39896
Dennis W. Goins - Direct
Page 6
 effect, ETI's rate-year estimate assumes that the divestiture/merger
2 will have no effect on either the level of or method of recovering
3 (via Schedule MSS-2 of the ESA) such costs. In addition, ETI
4 again ignored the effects of load growth when it set rate-year MSS-
5 2 costs as adjusted test-year MSS-2 costs recovered in base rates.
6 That is, by ignoring load growth in setting both PPCC and MSS-2
7 costs that will be recovered in base rates, ETI almost certainly
8 ensured that it will overrecover both types of costs going forward.
9 7. ETI's principal rate schedules for street lighting and traffic signal
10 customers are Schedules SHL and TSS, respectively. Schedule
11 SHL applies to lighting for public streets, roads, and thoroughfares
12 in cities and in subdivisions with an incorporated homeowners
13 association. Schedule SHL sets fixed monthly charges for standard
14 and nonstandard fixture and lamps that ETI installs and maintains
15 (Rate Groups A and C). ETI also offers a fixed kWh rate for
16 lighting facilities that the customer owns and maintains (Rate
17 Groups D and E). Schedule TSS is a fixed kWh rate with a
18 monthly customer charge per delivery point applicable to
19 customer-owned and -maintained traffic signals. Both proposed
20 rates do not reflect the lower cost of operating and maintaining
21 lighting facilities using energy-efficient light-emitting diode (LED)
22 bulbs. Moreover, Schedule SHL includes a provision that
23 penalizes a customer that replaces a high-wattage bulb with a more
24 energy-efficient LED bulb.

Docket No. 39896
Dennis W. Goins - Direct
Page 7
 RECOMMENDATIONS

2 Q. WHAT DO YOU RECOMMEND ON THE BASIS OF THESE
3 CONCLUSIONS?

4 A. I recommend that the Commission take the following actions regarding the
5 major issues discussed in my testimony:
6 1. Reject the AED4CP method used in ETI' s jurisdictional separation
7 study to assign demand-related production costs to its Texas retail
8 and wholesale jurisdictions. Instead, the Commission should
9 require ETI to assign these costs to the wholesale jurisdiction using
10 the 12 coincident peak (12CP) method to allocate demand-related
11 production costs. This approach is consistent not only with the
12 cost-of-service approach FERC typically uses to allocate demand-
13 related production costs reflected in wholesale rate schedules, but
14 also with the assignment of MSS-1 costs (as well as MSS-2
15 transmission costs) to ETI under the ESA. I have calculated test-
16 year 12CP allocation factors for the Texas Retail (94.6208 percent)
17 and Wholesale (5.3792 percent) jurisdictions, and provided them to
18 Cities witness Karl Nalepa for inclusion in his jurisdictional
19 separation study.
20 2. Reject ETI's adjusted test-year purchased power capacity costs
21 ($276.2 million). Instead, ETI should be allowed to recover no
22 more than approximately $241.3 million in PPCC. This
23 approximately $35 million reduction in ETI's proposed rate-year
24 PPCC estimate reflects the following three adjustments:
25 111 - reduction in costs for Legacy Affiliate Contracts
26 to reflect more current pricing data.
27 Ill reduction in costs for Other Affiliate Contracts
28 and Reserve Equalization to reflect more recent contract

Docket No. 39896
Dennis W. Goins - Direct
Page 8
 pncmg data and Cities recommended adjustment m costs
2 related to the EAI WBL contract. 6
3 111111 reduction to reflect the effects of load growth on
4 rate-year PPCC costs that ETI will recover going forward.
5 3. Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained
6 in MSS-2 costs relative to test-year
7 costs, plus complete uncertainty regarding the magnitude of ETI's
8 post-2012 MSS-2 costs under Entergy's proposed
9 divestiture/merger deal with ITC in 2013, make ETI's projected
10 rate-year MSS-2 costs speculative at best. I recommend setting
11 ETI's adjusted test-year MSS-2 costs no higher t h a n - -
12 or
13 value reflects ETI's actual 2011 MSS-2 costs plus a
14 to reflect the effects of load growth.
15 4. Require ETI to modify Schedules SHL (Rate Groups A and C) and
16 TSS to include a minimum 25 percent reduction in monthly fixed
17 charges applicable to street and traffic lighting fixtures that use
18 LED technology. Energy charges in Schedule SHL (Rate Groups
19 D and E) should also be reduced by 25 percent for LED customers.
20 This reduction should partially reflect the lower cost of operating
21 and maintaining energy-efficient LED fixtures. In addition, the
22 Commission should require ETI to eliminate the $50 fee applicable
23 to Rate Groups A and C under Schedule SHL when an existing
24 light is replaced with a more efficient light with lower wattage (for
25 example, an LED bulb). Eliminating this fee will remove a
26 disincentive for customers to adopt LED fixtures as conservation
27 measures.

6
EAI WBL denotes capacity entitlements in several of EAI's baseload generating units that EAI
sells at wholesale. Justification for Cities recommended EAI WBL rate-year cost adjustment is
provided in the direct testimony of Cities witness Karl Nalepa.

Docket No. 39896
Dennis W. Goins - Direct
Page 9
 WHOLESALE JURISDICTION ALLOCATION

2 Q. DID ETI SERVE ANY WHOLESALE CUSTOMERS DURING THE
3 TEST YEAR?

4 A. Yes. ETI provided partial requirements service to 3 wholesale customers
5 during the test year. However, during the rate year, ETI projects that
6 ETEC will be its only partial requirements wholesale customer.

7 Q. DOES ETI OWN SUFFICIENT GENERATING CAPACITY TO
8 SERVE ITS RETAIL AND WHOLESALE CUSTOMERS?

9 A. No. ETI is a short EOC-that is, its owned capacity and firm purchases
10 are insufficient to meet its capability responsibility under the ESA. As a
11 result, ETI must rely on additional capacity purchases to meet this
12 shortfall.

13 Q. IN ITS FILING, DID ETI ESTIMATE ITS COST OF SERVING
14 WHOLESALE CUSTOMERS?

15 A. Yes. ETI conducted a jurisdictional separation study to determine its cost
16 of serving customers in its Texas Retail and Wholesale jurisdictions. As
17 part of this separation study, ETI used the AED4CP method to allocate
18 demand-related production costs. ETI also used the AED4CP method to
19 allocate demand-related production costs in its retail class cost-of-service
20 study.

21 Q. IS THE AED4CP THE MOST APPROPRIATE METHOD TO
22 ALLOCATE THESE COSTS BETWEEN JURISDICTIONS?

23 A. No. In my opinion, the 12CP allocation method would be preferable. The
24 12CP approach is consistent with the cost-of-service approach FERC
25 typically uses to allocate demand-related production costs reflected in
26 wholesale rate schedules. Moreover, the ESA uses a 12CP method to

Docket No. 39896
Dennis W. Goins - Direct
Page 10
 derive each EOC's load responsibility ratio, which is then used to derive
2 each EOC's share of monthly MSS-1 and MSS-2 charges. Finally, in
3 reviewing monthly data reflected in ETI's rate-year PPCC shown in
4 Exhibit RRC-1, I noticed that estimated PPCC by month are relatively
5 stable-that is, total projected PPCC do not vary significantly by month.
6 ETI's heavy reliance on capacity purchases to serve load (both retail and
7 wholesale), and the relative stability of projected monthly PPCC costs
8 imply that the 12CP method should properly split ETI's demand-related
9 production costs between the Texas Retail and Wholesale jurisdictions.

10 Q. IN DOCKET NO. 37744, DID YOU TESTIFY THAT THE AED4CP
11 METHOD WOULD BE REASONABLE TO USE IN ETl'S
12 JURISDICTIONAL SEPARATION STUDY?

13 A. Yes. Although I recommended the 12CP method, I noted that the
14 AED4CP method would also be reasonable to use in ETI's jurisdictional
15 separation study. However, in this case, ETI's reliance on capacity
16 purchases is even greater that it was during test- and rate-years that ETI
17 used in Docket No. 37744. Moreover, in my opinion, for the reasons I
18 cited earlier, the 12CP allocation method is preferable to the AED4CP
19 method proposed by ETI, and should be used to assign ETI' s demand-
20 related production costs to jurisdictions.

21 Q. DID YOU CALCULATE JURISDICTIONAL 12CP ALLOCATION
22 FACTORS IN THIS CASE?

23 A. Yes. I calculated test-year 12CP allocation factors for the Texas Retail
24 and Wholesale jurisdictions. I provided the 12CP factors to Cities witness
25 Karl Nalepa for inclusion in his jurisdictional separation study. As shown
26 in Exhibit DWG-1 and Table 1 below, the 12CP allocation factor for the
27 Wholesale jurisdiction is about 5.38 percent versus 4.62 percent under
28 ETI' s recommended AED4CP method.

Docket No. 39896
Dennis W. Goins - Direct
Page 11
 Table 1. Jurisdictional Separation

Demand-Related Production
Cost Allocation Factor
Jurisdiction AED4CP 12CP

TX Retail 95.3838% 94.6208%

Wholesale 4.6162% 5.3792%

Total 100.0000% 100.0000%

Source: Schedule P-7.2 and Exhibit DWG-1.

2 Q. WHAT LOADS DID YOU USE IN CALCULATING THE 12CP
3 WHOLESALE ALLOCATION FACTOR THAT YOU PROVIDED
4 WITNESS NALEPA FOR USE IN HIS JURISDICTIONAL
5 SEPARATION ANALYSIS?

6 A. I used a loss-adjusted 150 MW (ETEC's monthly billing MW) as a proxy
7 for the 12 monthly CPs. The 150 MW is indicative of ETI's capacity
8 obligations to ETEC, and reflects known and measurable changes
9 compared to test-year wholesale CPs (which would include CPs for
10 wholesale customers that ETI no longer serves).

11 Q. SHOULD THE COMMISSION REQUIRE ETI TO USE THE 12CP
12 METHOD TO ASSIGN DEMAND-RELATED PRODUCTION
13 COSTS TO JURISDICTIONS?

14 A. Yes. The l 2CP method best reflects how ETI incurs demand-related
15 production costs to serve Texas Retail and Wholesale customers.

Docket No. 39896
Dennis W. Goins - Direct
Page 12
 PURCHASED POWER CAPACITY COSTS

2 Q. DOES ETI CURRENTLY HAVE ENOUGH CAPACITY
3 RESOURCES TO SERVE ITS RETAIL AND WHOLESALE
4 CUSTOMERS?

5 A. No. Under Schedule MSS-1, an EOC with fewer capacity resources than
6 its capacity responsibility must buy capacity from other EOCs whose
7 capacity resources exceed their capacity obligations. This capacity deficit
8 situation is commonly referred to as a short position, in contrast to a long
9 position involving a capacity surplus. Even with major increases in
10 purchased capacity, ETI expects to be short more than - during the
11 rate year. 7

12 Q. WHAT TYPES OF PURCHASES DOES ETI PLAN TO USE TO
13 MEET THIS CAPACITY SHORTFALL?

14 A. ETI plans to use four principal categories of purchases:
15 1111 Schedule MSS-1 purchases (Reserve Equalization) from other
16 EOCs with surplus capacity.
17 1111 Schedule MSS-4 purchases related to purchased power
18 agreements arising from the JSP (Legacy Affiliate Contracts).
19 1111 Schedule MSS-4 unit power purchases unrelated to the JSP
20 (Other Affiliate Contracts).
21 1111 Third-party purchases from companies not affiliated with ETI
22 or other Entergy companies.
23 ETI witness Robert R. Cooper discusses these categories of purchases in
24 his direct testimony, and presents rate-year estimates of ETI' s purchases in
25 each category in Exhibit RRC-1 (Highly Sensitive).

7
See ETI's responses to Cities 2-1.d (RRC-1 Workpaper MSS-1 111215_HSPM) and TIEC 1-
17 (HS).

Docket No. 39896
Dennis W. Goins - Direct
Page 13
 Q. ARE ETI'S RA TE-YEAR PPCC SIGNIFICANTLY HIGHER THAN
2 ITS TEST-YEAR PPCC?

3 A. Yes. ETI's projected rate-year PPCC ($276.2 million) exceed test-year
4 PPCC by a b o u t - . My review of these costs indicates that third-
5 party purchases are the principal driver of the increase-growing more
6 than - from to

7 Q. HOW HAS ETI TRADITIONALLY RECOVERED PURCHASED
8 POWER CAPACITY COSTS?

9 A. ETI has traditionally recovered these costs in base rates smce the
10 Commission's current fuel rule excludes purchased power demand or
11 capacity costs from eligible and reconcilable fuel expenses absent a
12 finding of special circumstances. 9

13 Q. IN THIS CASE, DID ETI INITIALLY PROPOSE TO CONTINUE
14 RECOVERING PPCC IN BASE RATES?

15 A. No. ETI proposed recovering PPCC in a purchased power recovery rider.
16 However, the Commission issued a ruling indicating that ETI's proposed
17 rider would not be considered in this case because of the ongoing
18 rulemaking in Project No. 39246 to consider the issue of how PPCC
19 should be recovered. As a result, ETI will continue to recover PPCC
20 approved by the Commission in base rates.

21 Q. WHY IS IT IMPORTANT TO ENSURE THAT THE LEVEL OF
22 PPCC INCLUDED IN BASE RATES IS REASONABLE AND NOT
23 SIGNIFICANTLY OVERSTATED?

24 A. Purchased power capacity costs included in base rates are not subject to
25 true-up and reconciliation. If the level of PPCC included in base rates is

8
See ETI's response to Cities 2-1.a.iii-iv (including Addendum 1).
9
PUC Subst. R. 25.236(a)(4).

Docket No. 39896
Dennis W. Goins - Direct
Page 14
 significantly overstated, ratepayers will simply pay for costs that ETI never
2 incurs. The level of PPCC included in base rates must strike a balance
3 between giving ETI a reasonable opportunity to recover prudent capacity
4 costs that it incurs going forward, and protecting ratepayers from giving a
5 windfall to ETI.

6 Q. DID ETI ADJUST ITS TEST-YEAR PPCC?

7 A. Yes. ETI recommends adjusting test-year PPCC for known and
8 measurable changes (including the expiration of some test-year contracts
9 and the start of two new post-test-year purchase power agreements). To
10 reflect these changes, ETI set adjusted test-year PPCC equal to rate-year
11 PPCC ($276.2 million).

12 Q. DOES ETl'S ADJUSTED TEST-YEAR PPCC RAISE ANY
13 CONCERNS?

14 A. Yes. ETI's estimate raises two major concerns:
15 1111 ETI did not modify the level of adjusted test-year PPCC it
16 proposes to include in base rates for the going-forward effects
17 of load growth on PPCC recovery. This oversight ensures that
18 ETI will overrecover its adjusted test-year PPCC if load
19 growth results in base rate billing determinants greater than
20 test-year billing determinants used to set base rates in this
21 case.
22 1111 ETI developed rate-year cost estimates for Legacy Affiliate
23 and Other Affiliate transactions using the September 2010-
24 August 2011 average cost per MW for each affiliate contract.
25 More recent average cost (price proxy) data for ETI's affiliate
26 transactions are available, and should be used to reflect known
27 and measurable cost changes.

Docket No. 39896
Dennis W. Goins - Direct
Page 15
 Q. PLEASE EXPLAIN THE LOAD GROWTH ISSUE AND WHY IT
2 SHOULD BE REFLECTED IN THE LEVEL OF PPCC INCLUDED
3 IN BASE RATES IN THIS CASE.

4 A. A simple example illustrates the problem. Assume Utility X files a rate
5 case in which its test-year billing units and PPCC are 100 units and $500,
6 respectively (see Table 2 below). Also assume that Utility X's projected
7 rate-year PPCC is $1,000, which it asks the regulator to include in base
8 rates set in the current rate case instead of $500 in test-year PPCC that
9 Utility X actually incurred. Finally, assume the regulator allows Utility X
10 to include rate-year PPCC in base rates instead of test-year PPCC. As a
11 result, the level of PPCC included in base rates set in the current rate case
12 is $10 per billing unit (that is, $1,000 in rate-year PPCC, divided by 100
13 test-year billing units).
14 Now move forward to the rate year when rates set in the rate case are in
15 effect. Assume that Utility X was correct in the rate case-its rate-year
16 PPCC turns out to be $1,000 exactly as it had projected. However, Utility
17 X's rate-year billing units have grown to 200 units-not 100 units that it
18 sold in the test year. As a result of this load growth, Utility X will recover
19 $2,000 of PPCC during the rate year ($10 per billing unit in base rates,
20 times 200 rate-year billing units)-or twice the level of PPCC that it
21 actually incurs in the rate year, and twice the amount the regulator
22 assumed would occur when approving base rates in the rate case to recover
23 projected rate-year PPCC.

Docket No. 39896
Dennis W. Goins - Direct
Page 16
 Table 2. Effect of Load Growth on PPCC Recovery

Line Item Test Yr Rate Yr Comment

1 Billing Units 100 200

2 Actual PPCC $500

3 Projected PPCC $1,000

4 Base Rate PPCC $1,000 Rate-Yr PPCC included in Base Rates

5 PPCC/Billing Unit in Base Rates $10 Line 4 I 100 Test-Yr billing units

6 Actual PPCC Recovered $2,000 Line 5 * 200 Rate-Yr billing units

2 ETI's proposed adjusted test-year PPCC creates the same problem,
3 because ETI is implicitly asking the Commission to ignore load growth
4 and set base rates in this case using rate-year PPCC and test-year billing
5 units. Using test-year billing determinants to set rates to recover ETI's
6 rate-year PPCC guarantees that ETI will overrecover its estimated rate-
7 year PPCC if rate-year billing units exceed test-year billing units-that is,
8 if ETI' s load grows.

9 Q. DOES ETI EXPECT ITS LOAD TO GROW FROM THE TEST
10 YEAR THROUGH THE RATE YEAR?

11 A. Yes. ETI expects a steady growth in both energy sales and peak load in
12 the next few years. 10

13 Q. HA VE YOU MODIFIED ETI'S ESTIMATED RA TE-YEAR PPCC
14 TO REFLECT YOUR CONCERNS REGARDING THE LOAD
15 GROWTH AND AFFILIATE TRANSACTION PRICING ISSUES?

16 A. Yes. I first adjusted the average cost per MW (proxy price) used to
17 develop the rate-year cost of Legacy Affiliate and Other Affiliate
18 (excluding EAI WBL) transactions. Specifically, I used transaction cost
19 data from November 2010-0ctobcr 2011 (instead of September 2010-
20 August 2010 data that ETI used) to develop the transaction proxy prices

10
See ETI's response to Cities 2-2 (HS).

Docket No. 39896
Dennis W. Goins - Direct
Page 17
 and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for
2 the EAI WBL contract and Reserve Equalization to reflect the adjustment
3 recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate-
4 year total PPCC estimate to reflect the effects of load growth. The
5 resulting adjusted test-year PPCC by transaction category is shown in
6 Exhibit DWG-2. 11 As shown in this exhibit, ETI's adjusted test-year
7 PPCC should be set no higher than $241.3 million-or $35 million less
8 than ETI's original request. As I noted earlier, this $35 million reduction
9 in ETI's proposed rate-year PPCC estimate reflects the following three
10 adjustments:
11 II - reduction in costs for Legacy Affiliate Contracts
12 to reflect more current pricing data.
13 II reduction in costs for Other Affiliate Contracts
14 and Reserve Equalization to reflect more recent contract
15 pricing data and Cities recommended adjustment in costs
16 related to the Cities recommended SO-percent reduction m
17 adjusted test-year costs for the EAI WBL contract.
18 II reduction to reflect the effects of load growth.

19 Q. HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT
20 YOU APPLIED TO YOUR PPCC ESTIMATE?

21 A. The development of my recommended load growth
22 adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of
23 ETI's firm load (energy sales and peak demand) from 2011 through 2014.
24 I then calculated the growth in ETI' s energy sales and peak demands over
25 different intervals (Exhibit DWG-3, page 1). On the basis of this review, I
26 s e l e c t e d - as a reasonable estimate of the likely growth in ETI's
27 energy and demand billing determinants from the test year to the rate year.

11
Results shown in Exhibit DWG-2 are presented in a format similar to that used by ETI's witness
Robert Cooper in Exhibit RRC-1 (HS-revised).

Docket No. 39896
Dennis W. Goins - Direct
Page 18
 I next estimated ETT's rate-year energy billing units, and derived an
2 average cost per billing unit (Exhibit DWG-3, page 2) for the estimated
3 rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of
4 this average rate-year PPCC and ETI's test-year kWh billing units equals
5 the adjusted test-year PPCC that ETI should be allowed to include in base
6 rates.

7 Q. IS YOUR RECOMMENDED $241.3 MILLION IN ADJUSTED
8 TEST-YEAR PPCC A REASONABLE AND FAIR ESTIMATE OF
9 COSTS THAT ETI IS LIKELY TO INCUR IN THE RATE YEAR?

10 A. Yes. My estimate mitigates two problems that cause ETI to overstate its
11 rate-year PPCC-its failure to adjust rate-year projections to reflect load
12 growth, and the use of dated transaction price proxies. In addition, my
13 estimate reflects witness Nalepa's recommended cost adjustments related
14 to the EAI WBL contract.

15 MSS-2 COSTS

16 Q. WHAT ARE MSS-2 COSTS?

17 A. Under the ESA's Service Schedule MSS-2, the EOCs share cost
18 responsibility for the Entergy transmission system much like they share
19 cost responsibility for generating resources under Service Schedule MSS-
20 1. Each month an EOC receives a payment or bill for System transmission
21 costs based on the EOC's level of transmission investment relative to total
22 System transmission investments, its load responsibility ratio, and the
23 average cost of total System investments.

Docket No. 39896
Dennis W. Goins - Direct
Page 19
 Q. WHAT LEVEL OF MSS-2 COSTS HAS ETI PROPOSED TO
2 INCLUDE IN BASE RATES IN THIS CASE?

3 A. ETI has proposed including almost of rate-year MSS-2 costs
4 in base rates.

5 Q. IS ETI'S PROPOSED LEVEL OF MSS-2 COSTS SIGNIFICANTLY
6 GREATER THAN ITS TEST-YEAR MSS-2 COSTS?

7 A. Yes. ETI' s projected rate-year MSS-2 costs are more than
8 actual test-year MSS-2 costs ($1.8 million).

9 Q. DID ETI PROVIDE DETAILS REGARDING WHY ITS RATE-
10 YEAR MSS-2 COSTS ARE EXPECTED TO GROW SO MUCH?

11 A. No. ETI provided workpapers supporting its rate-year MSS-2 cost
12 projection, 12 but did not provide details explaining the
13

14 Q. DID ETI ADJUST ITS PROJECTED RA TE-YEAR MSS-2 COSTS
15 TO REFLECT CHANGES IN BILLING AND TRANSMISSION
16 INVESTMENTS THAT MAY ARISE WHEN THE
17 DIVESTITURE/MERGER OF ENTERGY'S TRANSMISSION
18 ASSETS INTO ITC IS COMPLETED IN 2013?

19 A. No. ETI's MSS-2 cost projections assume business-as-usual even though
20 Entergy will no longer be sole owner of transmission assets used to deliver
21 power and energy to its EOCs following the proposed divestiture/merger.
22 This calls into question the future applicability of Service Schedule MSS-2
23 to the EOCs, and the reasonableness of ETI's MSS-2 rate-year
24 projection-a conclusion indirectly supported by ETI. For example,
25 during his deposition, ETI witness Phillip May acknowledged that if the
26 divestiture/merger takes place as planned, ETI's MSS-2 costs would be

Docket No. 39896
Dennis W. Goins - Direct
Page 20
 zero. 13 In general, the pending divestiture/merger makes ETI's MSS-2 cost
2 projections problematic.

3 Q. IS THERE AN ADDITIONAL PROBLEM WITH ETI'S ADJUSTED
4 TEST-YEAR MSS-2 COSTS?

5 A. Ycs. Including ETI's MSS-2 rate-year costs in base rates creates the same
6 problem that I discussed with respect to ETI's rate-year PPCC.
7 Specifically, using base rates that reflect test-year billing determinants to
8 recover projected rate-year MSS-2 costs guarantees ovcrrecovery if rate-
9 year billing units exceed test-year billing units-that is, if ETI's load
10 grows.

11 Q. HOW SHOULD ETl'S RATE-YEAR MSS-2 COSTS BE ADJUSTED
12 TO ADDRESS THESE ISSUES?

13 A. I recommend a 2-step approach:
14 II Because of the pending divestiture/merger of Entergy' s
15 transmission assets, limit MSS-2 costs included in base rates
16 to no more than actual MSS-2 costs incurred in the most
17 recent 12 months. This modification also addresses the
18 of ETI's MSS-2 costs.
19 II Adjust the modified post-test year MSS-2 cost estimate for
20 load growth in a manner similar to the approach I used in
21 adjusting rate-year purchased power capacity costs.

12
See ETI's response to Cities 5-3.a.
13
See the transcript of the March 6, 2012, deposition of ETI witness Phillip R. May at 43: 10.

Docket No. 39896
Dennis W. Goins - Direct
Page 21
 Q. HA VE YOU DEVELOPED AN ADJUSTED TEST-YEAR
2 ESTIMATE OF MSS-2 COSTS THAT SHOULD BE INCLUDED IN
3 BASE RATES?

4 A. Yes. As shown in Exhibit DWG-4, the level of adjusted test-year MSS-2
5 costs included in base rates should not exceed $4.1 million. This value
6 reflects ETI's actual annual MSS-2 costs through December 2011, and a
7 load growth adjustment.

8 STREET LIGHTING AND
9 TRAFFIC SIGNAL RATES

10 Q. DID YOU REVIEW ETI'S STREET LIGHTING AND TRAFFIC
11 SIGNAL RATES?

12 A. Yes. ETI's principal rate schedule for street lighting customers is
13 Schedule SHL, while Schedule TSS is the principal rate schedule for ETI's
14 traffic lighting customers that own and maintain their lighting facilities.

15 Q. IS SERVICE UNDER SCHEDULE SHL UNIFORM FOR ALL
16 STREET LIGHTING CUSTOMERS?

17 A. No. The rate includes four categories of service (Rate Groups A, C, D,
18 and E). Rate Group A includes ETI's standard fixture and lamps mounted
19 on existing standard wood poles that ETI installs and maintains. If a
20 customer wants nonstandard lighting facilities (those not provided in Rate
21 Group A), the customer is assigned to Rate Group C and required to
22 prepay ETI for the incremental cost of the nonstandard facilities. Lighting
23 facilities that are customer-owned and customer-maintained are assigned
24 to Rate Group D, while incidental lighting services (for example,
25 underpass lighting) are assigned to Rate Group E.

Docket No. 39896
Dennis W. Goins - Direct
Page 22
 Q. DO CHARGES VARY BY CATEGORY OF SERVICE IN
2 SCHEDULE SHL?

3 A. Yes. Customers in Rate Groups A and C pay a fixed monthly charge per
4 lighting fixture, while customers in Rate Groups D and E pay a fixed (and
5 identical) energy charge per kWh. Each customer's monthly bill also
6 includes charges for ETI's fixed fuel factor (Schedule FF) and applicable
7 riders applied to monthly kWh per fixture.

8 Q. WHAT TYPES OF CHARGES ARE APPLICABLE UNDER
9 SCHEDULE TSS?

10 A. Traffic signal customers pay a fixed monthly charge ($3 .20 proposed) per
11 point of delivery, plus a fixed kWh rate and all applicable rider charges.

12 Q. DO ETI'S LIGHTING RATES INCORPORATE ANY SPECIAL
13 SERVICE OR PRICING PROVISIONS FOR NEW ENERGY-
14 EFFICIENT LIGHTING TECHNOLOGIES-FOR EXAMPLE,
15 LED FIXTURES?

16 A. No. The basic structure and pricing provisions of the SHL and TSS rates
17 have been in place for years. The rates were designed for lighting fixtures
18 that use older, less energy-efficient bulb technology.

19 Q. DID ETI CONDUCT A DETAILED COST ANALYSIS IN
20 DEVELOPING PROPOSED CHARGES FOR STREET LIGHTING
21 AND TRAFFIC SIGNAL CUSTOMERS?

22 A. I have seen no evidence that ETI conducted such an analysis. Moreover,
23 in this case, ETI did not conduct any analyses to estimate the cost
24 differential of serving street lighting and traffic signal customers that use
25 energy-efficient LED fixtures.

Docket No. 39896
Dennis W. Goins - Direct
Page 23
 Q. HOW DID ETI ADJUST PROPOSED PRICES IN ITS LIGHTING
2 RATES IN THIS CASE?

3 A. ETI applied a unifonn percentage increase to the kWh and fixed charges in
4 Schedule SHL. In Schedule TSS, ETI left the fixed monthly charge per
5 delivery point unchanged, but reduced the kWh charge to reflect its
6 proposal to recover PPCC through a rider. (This latter change will be
7 reversed to reflect the Commission's ruling in this case regarding recovery
8 of PPCC in base rates.)

9 Q. WHY ARE LED FIXTURES AN ATTRACTIVE LIGHTING
10 OPTION FOR MUNICIPALITIES?

11 A. The cost of street and traffic lighting services can be significant for many
12 cities and towns. As government agencies face increasing pressure to
13 control budgets, municipalities are increasingly looking at energy-efficient
14 lighting options such as LED fixtures to provide an ongoing, long-term
15 reduction in operating costs. LED fixtures use significantly less energy
16 than incandescent and most other lighting options, last longer, and may
17 require less maintenance (for example, fewer bulb replacements).

18 Q. HA VE ANY OF THE CITIES ADOPTED LED LIGHTING AS A
19 WAY TO REDUCE THEIR OPERATING COSTS?

20 A. Yes. Counsel has informed me that at least one of the Cities has an
21 ongoing program to replace incandescent fixtures with LED options, and
22 several others are actively considering moving to LED lighting.

23 Q. WOULD WIDESPREAD ADOPTION OF LED LIGHTING RATES
24 HELP REDUCE ENERGY CONSUMPTION IN TEXAS?

25 A. Yes. Such rates would encourage municipalities to adopt energy-efficient
26 LED options, and help offset the high front-end cost of LED lights.

Docket No. 39896
Dennis W. Goins - Direct
Page 24
 Q. HAVE MOST UTILITIES IMPLEMENTED LIGHTING RATES
2 THAT REFLECT THE LOWER COST OF OPERATING LED
3 FIXTURES?

4 A. No. I reviewed street lighting and traffic signal rates offered by a number
5 of utilities. Although some of them have implemented LED rates, most
6 utilities have not updated their rates to reflect the lower operating and
7 maintenance cost of serving energy-efficient LED fixtures.

8 Q. DOES ANY UTILITY IN TEXAS HAVE AN LED LIGHTING
9 OPTION?

10 A. Yes. In 2010 the Commission approved a street and traffic signal rate for
11 El Paso Electric (Docket No. 37690) that included separate charges for
12 LED traffic signals. (See Exhibit DWG-5.) The fixed monthly rate for
13 LED signals is generally less than one-third the comparable rate for
14 incandescent signals.

15 Q. SHOULD THE COMMISSION REQUIRE ETI TO INCLUDE AN
16 LED OPTION IN ITS SHL AND TSS RATES?

17 A. Yes. ETI should offer an LED option in these rates to encourage energy
18 efficiency investments and promote conservation. To facilitate these
19 goals, the Commission should require ETI to modify monthly fixed
20 charges in Schedule SHL (Rate Groups A and C) and TSS to reflect a 25-
21 percent discount for LED installations. The discounted Rate Group A
22 fixed charges (if applicable) in Schedule SHL should be applied according
23 to the estimated monthly kWh consumption of the installed LED fixture.
24 In addition, I recommended reducing by 25 percent the Schedule SHL
25 kWh charges applicable to LED customers assigned to Rate Groups D and
26 E to reflect the lower cost of operating and maintaining LED fixtures. In
27 the future, ETI should be required to provide detailed information

Docket No. 39896
Dennis W. Goins - Direct
Page 25
 regarding differences in the cost of serving LED and non-LED lighting
2 customers.

3 Q. HAVE YOU IDENTIFIED ANY OTHER CHANGES THAT
4 SHOULD BE MADE IN ETl'S PROPOSED LIGHTING RATES?

5 A. Yes. The Commission should require ETI to eliminate the service
6 condition applicable to Rate Groups A and C in Schedule SHL that
7 charges a $50 fee for any replacement of a functioning light with a lower-
8 wattage bulb. This fee actively discourages customers from adopting more
9 energy-efficient lighting technologies (for example, LED devices), and is
10 not supported in ETI' s filing. The Commission should get rid of this
11 barrier to conservation and efficiency improvements.

12 Q. DOES THIS COMPLETE YOUR DIRECT TESTIMONY?

13 A. Yes.

Docket No. 39896
Dennis W. Goins - Direct
Page 26
 Exhibit DWG-1
Page 1 of 1

Jurisdictional Separation: Demand-Related Production Costs - 12CP

12CP kW 12CP
Class of Service at Plant Factor
(a) (b) (c)

Residential 1,240,632 43.4768%
Small General Service 57,554 2.0169%
General Service 531, 108 18.6122%
Large General Service 212, 129 7.4339%
Large Industrial Power Service 654,652 22.9417%
Roadway Lighting 1,633 0.0572%
Non-Roadway Lighting 2,345 0.0822%
Total Texas Retail 2,700,053 94.6208%

Wholesale For Resale 153,498 5.3792%
Wheeling 0 0.0000%
Total Texas Wholesale 153,498 5.3792%

Total ETI 2,853,551 100.0000%

Source: Schedule P-7.2, pages 21-22, and ETl's response to TIEC 1-38 Highly Sensitive.
Blank Page
Exhibit DWG-2
Redacted

Highly Sensitive
Blank Page
Exhibit DWG-3
Redacted

Highly Sensitive
Blank Page
Exhibit DWG-4
Redacted

Highly Sensitive
Blank Page
 EXHIBIT DWG-5

EL PASO ELECTRIC'S SCHEDULE NO. 08- GOVERNMENT STREET
LIGHTING AND SIGNAL SERVICE RATE
Blank Page
 EL PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

APPLICABILITY

This rate is availabie to any village, town, city, county, state of Texas and Federal
facilities for Mercury Vapor and High Pressure Sodium Vapor street light, freeway lighting
and for traffic signal lights.

TERRITORY

Texas Service Area

MONTHLY RATE

Street Lights

MERCURY VAPOR-OVERHEAD SYSTEM-COMPANY OWNED
35 FOOT MOUNTING HEIGHT - WOOD POLE ·k
-
Total Per Lamp
Wattage Charge
175W - 7,000 Lumen Single
,__________~-·
195 $15.22
250W - 11,000 Lumen Single 275 $18.26
-
400W - 20,000 Lumen Single 460 $21.66
400W - 20,000 Lumen Double 920 $35.i9

HIGH PRESSURE SODIUM VAPOR - DOWNTOWN EL PASO AREA- COMPANY
OWNED STEEL BASE STANDARD AND LUM1NA1RE
Total Per Lamp
Wattage Charge
1,000W -119,500 Lumen Overhead System 1,102 $54.81
1,000W - 119,500 Lumen Underground System 1,102 $89.45

H1GH PRESSURE SODIUM VAPOR- DOWNTOWN EL PASO AREA- COMPANY
OWNED STEEL BASE STANDARD AND LUM!NAIRE
Total Per Lamp
Wattage Charge
450W - 50,000 Lumen Overhead System 485 $47.87

* Refer to Mercury Vapor Closed to New Installations and Conversiin/Replacement of
Existing Installations section of the tariff. • UB!.IC UTILITY COMMISSION Of TEXAS
. . ·· . ··· APPROVED

JUL 3D'10 DOCKET

CONTROL#.
Section Number_ _ __,_1_ _ _ __ Revision Number 20 ----
SheetNumber~~~--'-7-~~~­ Effective for consumQt!on on or
Page~~~-~~-l~o_f~8~~~- after July 1, 2010
 El PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

MERCURY VAPOR - OVERHEAD SYSTEM - COMPANY OWNED
30 FOOT MOUNTING HEIGHT-STEEL POLE*
Total Per Lamp
~·
Wattage Charge
400W - 20,000 Lumen Single 460 $33.46
400W - 20,000 Lumen Double 920 $46.99

MERCURY VAPOR - NON-COMPANY OWNED SYSTEMS
-
INTERSTATE OR FREEWAY LIGHTING*
Total Per Lamp
Wattage Charge
250W - i 1,000 Lumen - Wall Mounted 292 $8.78
400W - 20,000 Lumen - 40 Foot Maximum Mounting Height 460 $12.08
1_,000W - 60,000 Lumen - 50 Foot Maximum Mounting Heigb_t__ 1, 102 $31.67

MERCURY VAPOR - NON-COMPANY OWNED - WOOD POLE
UNDERGROUND OR OVERHEAD RESIDENTIAL SERViCE "
--
Total Per Lamp
Wattaoe Charqe
175W - 7,000 Lumen - 35 Foot Maximum Mounting Height 195 $6.68

* Refer to Mercury Vapor Closed to New Installations and Conversion/Replacement of
Existing Installations section of the tariff.

HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED SYSTEMS
INTERSTATE OR FREEWAY LIGHTING
-
Total Per Lamp
Wattaqe Charqe
150W - 16,000 Lumen - Wall Mounted 193 $7.00
250W - 23,200 Lumen - Waif ~ounted 313 $9.42
250W • 23,200 Lumen - 40 Foot Maximum Mountinq Heiqht 313 $9.42
400'{1! - 50,000 Lumen - 50 Foot Maximum MountinQ Heiqht 485 $12.95
400W - 50,000 Lumen - Tower Structure 150 Foot-Climbing 485 $13.67
Maximum Mounting Height
10 Luminaires per Tower PUB' !C UTiLJTY Cb;\:'.\ 1'.~S'.SlGN C , TEX.AS
P~Ff ';1
Rate per fixture
JUL 3 o~rn [)( f:'/'.7
..._~n; .. l 'Z 7
;.JI 690
CONTflOLil

Section Number 1 ~~~---~~~~
Revision Number 20
~~-------=--~~~~-

Sheet Number 7~~~~~~~~~
Effective for consumption on or
Page~~~~~~=2~o~f8,,,__~~~- after July 1, 201 O
 EL PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

400W - 50,000 Lumen - Tower Structure 150 Foot-Lowering 485 $12.79
Maximum Mounting Height
10 Luminaires per Tower
Rate per fixture
>---- -
116W - Obstruction Lights Incandescent 40 Foot Maximum 116 $4.47
Mounting Height
116W -150 Foot Tower ..116 $5.35

HIGH PRESSURE SODIUM VAPOR-NON-COMPANY OWNED SYSTEMS
LARGE ARTERIAL LIGHTING
Total Per Lamp
Wattage Charg~
150W-16,000 Lumen Wall Mounted 193 $7.11
250W - 23,?00 Lumen Wall Mounted 313 $10.24
250W -23,200 Lumen 40 FT Maximum Mounting Height 313 $10.24
~OW - 50,000 Lumen 50 FT Maximum Mounting Height 485 $14.73

HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED
WOOD/STEEL POLE UG OR OH STANDARD RESIDENTIAL SERVICE
Total Per Lamp
Wattage Charge
1 OOW - 8,500 Lumen - 30 Foot Maximum Mounting Height 124 -
$5.32
150W - 14,400 Lumen - 30 Foot Maximum Mounting Height 193 $6.21
250W - 23,200 Lumen - 30 Foot Maximum Mounting Height 313 $9.59

HIGH PRESSURE SODIUM VAPOR - OVERHEAD - NON-COMPANY OWNED
FIXTURE- COMPANY OWNED EXISTING WOOD POLE
(DISTRIBUTION OR STREET LIGHT CF or Dl
Total Per Lamp
WattaQe Charge
1 OOW - 8,500 Lumen - 35 Foot Maximum Mounting Heii:iht 124 $7.43
· 150W - 14~190 Lumen - 35 Foot Maximum Mounting Height 193 $8.99
250W - 23,200 Lumen - 35 Foot Maximum Mounting Height 313 $11.41
250W - 23,200 Lumen - Double 35 Foot Maximum Mounting 626 $18.65
Heiqht
450W - 50,QOO Lumen - 50 Foot Maximum Mounting Height 485 $14.06

37690
Section Number 1
~~~~~~~~-
Revision Number OONJmt #
Sheet Numb e r~~~--'-7~~~~~ Effective for consumption on or
Page~~~~~~~3~o~f~8~~~~ after July 1, 2010
 EL PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

OVERHEAD SYSTEM - HIGH PRESSURE SODIUM VAPOR
COMPANY OWNED - WOOD POLE
-
Total Perla~
'
Wattage Charg_E?
1 OOW - 8,500 Lumen - 35 Foot Maximum Mounting Height 124 $15.20
150W - 14,400 Lumen - 35 Foot Maximum Mountinq Heiqht i93 $16.49
250W - 23,200 Lumen - 35 Foot fV1axlmum Mounting Height 313 $19.18
400W - 50,000 Lumen - 50 Foot Maximum Mountinq Heiqht 485 $27.02

ORNAMENTAL HIGH PRESSURE SODIUM VAPOR -
NON-COMPANY OWNED, OPERATED AND MAINTAINED
-· Total Per Lamp
Wattage Charge
?OW - 5,300 Lumen 82 $1.67
150W -1_4,400 Lumen 193 $3.04
175W- 14,400 Lumen
250W - 16,000 Lumen
210
295
$6.65
$3.94 j
HIGH PRESSURE SODIUM VAPOR-
ROADWAY ILLUMINATION- NON COMPANY OWNED
Total Per Lamp
Watta_qe Cha roe
100W- HPS 124 $2.04
150W- HPS 193 $5.02
250W-HPS
>----·
313 $5.08
400W- HPS 485 $13.48
l"iJ!:>UG UTiUTY COMMi0,~1;;'

MONTHLY RA TE
JUL 3 0 ' 1'0 DOCKET 3 769 Q
Traffic Signal Lights
.----~~-~~~,~~~·
INCANDESCENT TRAFFIC SfGNALS
Wattage of on y
Type and Hours Incandescent Rate
Of 0 eration Lam Per Unit
24 Hours 61 $1.24
24 Hours 61 - - ' - - '$1.24
----'

Section Number 1
~--....._~~~~
Revision Number_ ____,,2=0_ _ _ __
Sheet Number 7
~-~--'--~~~~
Effective for consumption on or
Page~-~~-~~4~o~f8;..._~~~- after July 1. 2010
 EL PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
ANO SIGNAL SERVICE RATE

~Lame Head 24 Hours 103 $2.09
3 Lamp Head 18 Hours Normal, 6 Hours Flashing 103 $2.09
5 Lamp Head 24 Hours 133 $2.72
4 Lamp Head 18 Hours Normal, 6 Hours Flashing 103 $2.09
3 Lamp Head 24 Hours 133 $2.72
3 Lame Head 18 Hours Normal, 6 Hours Flashinq 133 $2.72
4 Lamp Head 24 Hours 133 $2.72
~J-ame Head 18 Hours Normal, 6 Hours Flashing 133 $2.72
2 Unit Walk Light 24 Hours 61 $1.24
2 Unit Walk Lh::iht 24 Hours 103 $2.09
2 Unit Walk Light 18 Hours Normal, 6 Hours Flashinq 103 $2.09
- ~

1 Unit Flashing 24 Hours 103 $2.09 '
1 Unit Flashing 24 Hours 133 $2.72
2 Unit Flashinq 24 Hours 103 $2.09
2 Unit School Flashers 351 Annual Burning Hours ·>-~
103 - $2.09
2 Unit School Flashers 790 Annual Burninq Hours 133 $2.72
30 Watt Controller 24 Hours 30 $0.61 --
1 100 Watt Controller 24 Hours ··-~..I ..
100 $2.60

LIGHT-EMITTING DIODE ("LED") TRAFFIC SIGNALS
~· -
Wattage of
High- Monthly
Type and Hours Efficiency Rate
Type of Unit Of Operation LED Lamp Per Unit
3 Lamp Head 18 Hours Normal, 6 Hours Flashing 14 $0.34
5 Lamp Head 24 Hours 14 $0.6
4 Lamp Head 18 Hours Normal, 6 Hours Flashinq 14 $0.~
3 Lamp Head 24 Hours 14 $0.3
3 Lamp Head 18 Hours Normal, 6 Hours Flashing 14 $0.~
4 Lamp Head 24 Hours 14 $0.69;; --·
4 Lamp Head 18 Hours Normal, 6 Hours Flashing 14 $0.6~) .~,·
2 Unit Walk Liqht 24 Hours 9 $0.2$b
2 Unit Walk Light 18 Hours Normal, 6 Hours Flashing 9 $0 23'.5 ~::
......... 1••

i Unit Flashing 24 Hours 14 $0.18>,:: 1 ;,
2 Unit Flashing 24 Hours 14 $0.352
2 Unit School Flashers 351 Annual Burning Hours 14 $0.28::.:1
2 Unit School Flashers 790 Annual Burning Hours 14 $0.28 :s
4 Unit School Flashers 351 Annual Burning Hours -- 14 $0.69 ';:'
4 Unit School Flashers 790 Annua! Burning Hours 14 $0.69 -

Section Number 1 Revision Number_ _~2_0_ _ _ _ __
~~--~-~--
Sheet Number_ _ ___.;.?_ _ _ __ Effective for consumption on or
Page~~---~~5~o~f~8----~~- after July 1, 2010
 PU8UC UTlUT' Q;:: TEXfJ

EL PASO ELECTRIC COMPANY
1

SCHEDULE NO. 08
JUL 3 0 10 DOCl\\:T 3 7690
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

MONTHLY RATE PER UNIT

Street lights and traffic signal lights that do not operate under any of the preceding
conditions will be billed under the rate with the closest operating conditions.

MERCURY VAPOR CLOSED TO NEW INSTALLATIONS AND
CONVERSION/REPLACEMENT OF EXISTING INSTALLATIONS

Mercury Vapor lamp categories are closed to new installations. The Company wit!
continue to maintain existing Mercury Vapor installations and will, at the Company's
option, install High Pressure Sodium Vapor ballasts in place of defective non-repairable
Mercury Vapor ballasts. Customers with existing fixtures which are defective and must
be replaced will have the option to convert its service to high pressure sodium vapor
lamps or may cancel service at no cost.

Mercury Vapor Fixture Replacement Schedule

For Company owned lights, when existing mercury vapor fixtures require replacement,
the Company will make such replacements with comparable high pressure sodrum vapor
lighi1ng at no cost, as specified below:
Mercury Vapor - Overhead System - Company Owned,
35 Foot Mounting Height - Wood Pol~----~----~
r Existing Mercury Vapor Lighting: High Pressure Sodium Vapor Replacement:
Wattaqe Lu mens kWh Wattage Lu mens kWh
195 7,000 70 124 8,500 44
275 1 i ,000 98 193 14,400 69
460 20,000 164 313 23,200 112
920 20,0000 328 313* 23,200 112

Mercury Vapor - Overhead System - Company Owned,

Existing Mercury Vapor Lighting:
-
. ht Stee I Poe
30 F00t M oun fmg He1g I
High Pressure Sodium Vapor Replacement:
Wattage Lu mens kWh Wattage Lu mens kWh
460 20,000 164 313 23,200 112
920 20,0000 328 313* 23,200 112 ·--
*O=Double - Mercury Vapor with double lamps on a single pole will be converted to two
separate poles with a Single High Pressure Sodium Vapor lamp each.

For Non-Company owned lights, upon the request of the Customer, the Company will
convert or replace facilities with the high pressure sodium vapor lighting options listed
below, at an amount equal to all applicable costs of such conversion or replacement.

Section Number 1
~~~----~~~~~
Revision Number_ _~2~0_ _ _ _ __
SheetNumber~~~~~7~~~-~ Effective for consumption on or
Page_~~~~~-6""--"o~f=8~--~ after July 1, 2010
 EL PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

Mercury vaeor - Non-Company 0 wned Systems -Interstate or Freewav L"lg ht mg
I
Existing M~ury Vaeor Lighting: High Pressure Sodium Vapor Replacement:
Wattage Lu mens kWh Wattage Lu mens kWh
292 11,000 104 193 16,000 69 ~

460 20,000 164 313 23,200 112
1102 60,000 393 485 45,000 173

lacement:
kWh
44
At the time of the replacement, the Customer wlll be billed at the applicable rate charge
and associated kWh usage for the high pressure sodium vapor replacement lighting.

Mercury Vapor Fixture Conversion Or Replacement Of Existing Facilities

Upon the request of the Customer, the Company will convert or replace existing
Company owned mercury vapor lighting to applicable Company offered street lighting
options other than those indicated above.

Upon the request of and payment by the Customer, the Company will convert existing
Company owned facilities (size or type of luminaire) to a different applicable Company
offered size or type of luminaire at an amount equal to ail applicable costs less the
salvage value of the existing facilities. (./')
-5 0
GI
!-
0'
Upon the request of and payment by the Customer, the Company will replace existing ~!... ....0
c:i f'-..
Company owned lighting facilities at an amount equal to all applicable costs less the ;;;:;;;: !'t'\
C)
salvage value of the existing facilities. Installation of new facilities requested by the ('/iD
Customer will be performed pursuant to the applicable Schedule and lamp category f!'2 ~~ l-

,,~~~
u.1
described above. ~---"'
..... .,~ ~ 0__,
CS~~
11· Cl ~
FIXED FUEL FACTOR r::<
:::i
_!
0
c:::> tiC
The above rates are subject to the provisions of the Company's Tariff Schedule No. 98 § ;:--- I-
entitled Fixed Fuel Factor. S.1! 0 z.
s """'
--'
0
0
ENERGY EFFICIENCY COST RECOVERY FACTOR fr ::::=>
~

The above rates are subject to the provisions of the Company's Tariff Schedule No. 97,
entitled Energy Efficiency Cost Recovery Factor.

Section Number____1-'------- Revision Number~-~~~--~~ 20
Sheet Number~---"'--~-~--
7 Effective for consumption on or
Pa ge_ _ _ _~--7~o_f_8_ _~~- after July 1, 2010
 EL PASO ELECTRIC COMPANY

SCHEDULE NO. 08
GOVERNMENTAL STREET LIGHTING
AND SIGNAL SERVICE RATE

MILITARY BASE DISCOUNT RECOVERY FACTOR

The above rates are subject to the provisions of the Company's Tariff Schedule No. 96,
entitled Military Base Discount Recovery Factor.

TERMS OF PAYMENT

The due date of the bill for utility service shall not be less than sixteen (16) days after
issuance. A bill becomes delinquent if not received at the Company by the due date.

TERMS AND CONDITIONS

The Company's Rules and Regulations apply to service under this rate schedule.

Specific terms are as covered in various written agreements.

JUL 3 0 '10 DOC!3} ' 3)666,313 / ,.J,= 230 KV 0.5774% 0.945178 0.945741 -0.1%

5 System Average 6.4111%

Source: Schedule P-7.2. Fixed Fuel
Factor
ANDREWS 111 Congress Avenue, Suite 1700
Austin, Texas 78701
A'rTORNEYS KU RT H. . LLP 512.320.9200 Phone
512.320.9292 Fax
andrewskurth.com

Meghan Griffiths
512~320.9214 Phone
512.320.9292 Fax ··
meghangrlffilhs@andrewskurth.com

April 30, 2012

Tracie Lowrey
Public Utility Commission of Texas
1701 N. Congress Ave.
Austin, Texas 78701

Re: PUC Docket No. 39896, SOAH Docket No. XXX-XX-XXXX, Application of Entergy
Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain
Deferred Accounting - TIEC Errata to the Direct Testimony of Jeffry Pollock

Dear Ms. Lowrey:

Texas Industrial Energy Consumers submits the attached errata to the Direct Testimony of
Jeffry Pollock, which includes the revisions listed below, Please note that two pages of Mr.
Pollock's testimony that are affected by the errata contain highly sensitive information. Corrected
versions of the pages with highly sensitive information are attached separately and filed pursuant
to the protective order in this docket. However, it should be noted that the highly sensitive
information contained on those pages is not affected by the errata.

Errata

• Page 9, lines 4-5

• Page 22, Table 1

• Page 23, line 2

• Page 25, lines 13-15

• Page 27, lines 6, 7, 12

• Page 39 - line 4
SOAH Docket No. XXX-XX-XXXX
• Page 42, lines 17-18 PUC Docket No. 39896
ENTERGY TEXAS, INC. RATE CASE
• Page 48, Table 4 TIEC Exhibit No. \__D

AUS:653507.I 1
Austin Beijing Dallas Houston London New York Research TrianQ(e Park The Woodlands Washinqton. DC
 \,.' ~-··
'
"
J

Tracie Lowrey
April 30, 2012
Page2

• Page 106, Exhibit JP-1

Verytruly yours,

cc: All parties of record

AUS:653507.I 2
.,

Jeffry Pollock
Direct Testimony
ERRATA- Page 9

1 For all of these reasons, the Commission should reject any post-test year

2 adjustments that use Rate Year projections for Test Year costs as ET! has done. If

3 the Commission were to make such post-test year adjustments, however, the proper

4 adjusted amount of purchased power capacity costs is $238.51 million or $6.651 per

5 kW-Month, which is a reduction of $37.735 million from ETl's request. 1 The $37.735

6 million reduction is based on re-pricing Test Year capacity purchases under the

7 known PP As.

8 • Transmission Equalization Payments

9 ETl's proposed post-test year adjustment to transmission equalization

1O payments should be rejected because ETI has failed to demonstrate that the

11 requested pro-forma adjustment is known and measurable. Transmission

12 equalization payments are a function of three variables: inter-transmission

13 investment, ownership costs and responsibility ratios. Estimating these variables is

14 susceptible to a host of uncertainties, such as the timing of new transmission

15 investment, the cost of money, operating expenses, taxes and load growth, which

16 determines the responsibility ratios. Further complicating the analysis is that such

17 estimates require specific assumptions not on.ly for ETI, but for all Entergy Operating

18 Companies. Should the Commission decide that a pro-forma adjustment is

19 appropriate, a reasonable approach would be to annualize the average monthly

20 transmission equalization payments incurred by ETI from January through June 2011

1
Ail amounts are stated on a Total Company basis.

1. Introduction, Qualifications
And Summary

J. POLLOCK
IN CO RPO RATEO

3
 ·,

Jeffry Pollock
Direct Testimony
ERRATA· Page 22

1 Q HAVE YOU ANALYZED ETl'S PROPOSAL TO RECOVER PURCHASED POWER

2 CAPACITY COSTS IN BASE RATES?

3 A Yes. ETI is proposing to recover $276 million of "adjusted test yaar" purchased

4 power capacity.costs in base rates.•

5 Q HOW WAS THE $276 MILLION DERIVED?

6 A ET! projected its capacity purchases under PPAs that would be in place during the

7 Rate Year (june 2012-May 2013). It then substituted these Rate Year expenses for

8 the Test Year expenses in determining ETl's overall cost of service in this

9 proceeding.

10 Q. ARE ETi'S RATE YEAR PURCHASES BASED ON THE SAME ASSUMPTiONS

11 AS ITS TEST YEAR POWER PURCHASES?

12 A No. For example, the projected quantity of capacity purchases is clearly different in

13 the Rate Year than during the Test Year as shown in the table below.

··• ·. _{:J~~'\!!),f.1~~fl!~l~;I~0tt~t~ft~;'-~i{.i
Purchase Test Rate
Year Year
Third Party Purchases 5,884 12,834
Affiliate Purchases 21,670 21,711
MSS-1 Payments 8,309 5,262
Total 35,863 39,807

8
Direct Testimony of Robert R. Cooper at 20. Another ETI witness, Mr. Considine, stated that the
amount of purchased power capacity costs ETI is seeking 1D recover are the costs that were removed
from the Test Year. However, $246.6 million of costs were removed from the Test Year (Considine at
26 and Adjustment No. 24). This testimony is contradicted by Mr. Cooper's testimony.
2. Revenue Requirement Issues

J. POLLOCK
!NCORPORATEO

4
 ... -,
_.,

Jeffry Pollock
Direct Testimony
E~TA-Page23

1 As can be seen, ETl's Rate_ Year purchases (39,807 MW-Months) would be riearly

2 11 % higher than the corresponding Test Year purchases (35,863 MW-Months).

3 Q WHY ARE RATE YEAR PURCHASES HIGHER THAN TEST YEAR PURCHASES?

4 A Rate year purchases reflect the fact that ETI is projecting to serve additional load

5 during the Rate Year. As discussed later, most of the $30 million spread between

6 Rate Year ($276 million) and Test Year ($245 million) purchased power capacity

7 costs is due to additional capacity purchases. These additional purchases are

8 primarily related to meeting future loads, while maintaining an appropriate reserve

9 margin.

10 Q DID ETI MAKE ANY OTHER ADJUSTMENTS TO RATE YEAR PURCHASED

11 POWER CAPACITY COSTS?

12 A No. ETI did not recognize additional revenues from post-test year load growth.

13 Thus, ETl's post-test year adjustment fajls to recognize all attendant effects. Further,

14 rates would be set using Rate Year costs and Test Year sales. Thus, this approach

15 would clearly violate the Matching Principle as previously discussed.

16 Q SHOULD ETl'S RATE YEAR PURCHASED POWER CAPACITY COSTS BE USED

17 TO SET RATES IN THIS PROCEEDING?

18 A No. ETl's use of Rate Year expenses is not consistent with accepted ratemaking

19 practices or this Commission's rules. For all of these reasons, ETl's proposed post-

20 test year adjustments should be rejected. Rates should be set using actual Test

21 Year expenses.

2. Revenue Requirement Issues

J. POLLOCK
INCORPORATEO

5
 ._.

Jeffry Pollock
Direct Testimony
ERRATA·Page25

1 quantified Test Year per-untt costs (column 3) by dividing the· Te.st Year costs

2 (column 1) by the corresponding amount of Test Year capacity purchases (column

3 2). Pro-forma adjustments were made solely to recognize changes in per-unit

4 capacity costs associated with known P.PAs. The pro-forma untt costs are based on

5 analysis of all known PPAs (column 4).

6 Q HOW DID YOU QUANTIFY THE PRO-FORMA ADJUSTMENTS?

7 A First, I categorized ETl's PPAs into three separate groups:

8 • Tnird-Party Purchases (line 3);
9 • Affiliate Purchases (line 4); and
10 • Reserve Equalization Payments (line 5).

11 I then applied the unit costs of the known PPAs (column 4) to Test Year capacity

12 purchases (column 2). This resulted in adjusted Test Year purchased power

13 capacity costs of about $250 million (line 6). This is slightly higher than ETl's actual

14 Test Year costs and about $26 million below ETl's proposed adjusted Test Year

15 expense ($276 million- $250 million).

16 Q SHOULD ANY FURTHER ADJUSTMENTS BE MADE TO TEST YEAR

17 PURCHASED POWER CAPACITY COSTS?

18 A Yes. It is currently known that the EAl-WBL PPA will expire at the end of 2012. To

19 ensure that rates reflect ETl's going-forward costs, Test Year expenses should be

20 adjusted to recognize this known change.

2. Revenue Requirement Issues

J.POLLOCK
!NCORPORATEO

6
' ..

Contains Highly Sensitive Information Jeffry Pollock
Direct Testimony
ERRATA· Page 27

-
1 whether this agreement is prudent. Until such time as the Commission has

2 determined a new EAl-WBL PPA is prudent, no post-test year adjustment associated

3 with such a potential contract should be made in setting base rates. 10

4 Q PLEASE SUMMARIZE YOUR RECOMMENDATION ON ETi'S ADJUSTED TEST

5 YEAR OF PURCHASED POWER CAPACITY COSTS.

6 A Test Year adjusted purchased power capacity costs should be set at $238.51 million,

7 or $6.651 per kW-Month ($238.51 million + 35,863 MW-Months + 1,000) on a Total

8 Company basis. This is based on Test Year capacity purchases, and it reflects

g changes in the per-unit costs under all known PPAs. It also reflects the expiration of·

10 the EAl-WBL PPA, which is currently scheduled to occur during the Rate Year. The

11 $238.51 million represents a $37.735 million reduction in ETl's proposed adjusted

12 Test Year expense.

13 Transmission Equalization Payments

14 Q WHAT ARE TRANSMISSION EQUALIZATION PAYMENTS?

15 A The Entergy System Agreement (ESA) requires that all Entergy Operating.

16 Companies equalize certain transmission costs. The equalization process is

10
However, if an adjustment is to be made, It should not exceed $5.944 million, which is derived as
follows:
.Line:_ "-' .·...,·: ,,··.'::.·. ·: D'$ilc~ipti()ni\•'.':;:.::.•:. '"-'•'''"':''' .@filQiif' .: ·. ,.,,<·· ·,
:;:·:·.:·l'li:!tlriiJ;l~':,~:r,.;·;..,:;,. ;:.,
1 Demand Charge Differential Between ...Qerived from ETl's Responses
the Original and New EAl-WBL To TIEC 5-1 (Addendum 1).
Anreements Iner kW-fvbnth\
2 EAl-WBL Purchases Removed 746 Exhibit JP-2, line 2.
(MW-11/onths\
3 Adjustment (Millions) $5.944 Line 1 x Line 2.

This ooutd result in adjusted Test Year purchased power cai;acity costs of $242.080 millbn, which is a reductbn
of $34.162 milrlOn from ETl's request
2. Revenue Requirement Issues

J.POLLOCK
INCORPORATEO

7
 Jeffry Pollock
Direct Testimony
ERRATA - Page 39

1 the deficient accounts-will require a $1.3 million increase In the annual accruals_ to

2 achieve full recovery over the remaining lives of the surplus accounts. Thus, the net

3 impact of my recommended adjustments to ETl's Test Year depreciation expense

4 would be $0.794 million, as shown in the following table.

Amount
($ in Millions)
Function
Accruals Adjusted
As Filed Accruals Difference
General - Depreclable Accounts $1,605 $2,946 $ 1,341
General -Amortization Accounts $5,947 $5,947 $ 0
Deficient Reserve Amortization $2,135 $ 0 ($2,135)
General Plant Total $9,687 $8,893 ($ 794)

5 Q PLEASE SUMMARIZE YOUR RECOMMENDED DEPRECIATION EXPENSE.

6 A The Commission should reject ETl's proposal to increase production depreciation
7 rates at this time given that the production depreciation reserve has a considerable

8 surplus. The Commission should also reject ETl's proposed general plant "catch-up•

9 adjustment because the deficiency can largely be cured by reallocating the reserve

10 from the surplus to the deficit genera1 plant accounts. This recommendation reduces

11 ETl's proposed depreciation expense by $1.950 million ($1, 156,000 + $794,000) on

12 a Total Company basis.

13 Property Tax Expense

14 Q IS ETI PROPOSING TO ADJUST PROPERTY TAX EXPENSES?

15 A Yes. ETI is proposing a $2.6 million pro-fonma adjustment to Test Year expense.

2. Revenue Requirement Issues

J.POLLOCK
!NCOftPOftATEO

8
.,

Contains Highly Sensitive Information Jeffry Pollock
Direct Testimony
ERRATA· Page 42

1 Entergy, the parent of ETI, should be disallowed on the basis that it benefrts only

2. shareholders not customers. As discussed later, ~t least $6.2 million of expense was

3 incurred to achieve financial objectives and should be disallowed. This includes

4 incentive compensation associated with affiliate (i.e., Entergy Services, Inc.)

5 .. expenses.

6 Q WHAT INCENTIVE COMPENSATION PLANS DOES ETI OFFER ITS

7 EMPLOYEES?

8 A ETI and ESI have two primary types of incentive compensation plans:

9 1. Annual; and
1O 2. Long-Term.

11 These plans and proposed Test Year expenses are listed on Exhibit JP-7.

12 Q WHAT ARE THE ANNUAL INCENTIVE COMPENSATION PLANS?

13 A There are various annual incentive compensation plans including the Management

14 Incentive Plan, Exempt Incentive Plan, Teamsharing Incentive Plan, Teamsharing

15 Selected Bargaining Units Incentive Plan and Operational Incentive Plan. In

16 addition, there is also an Executive Annual Incentive Plan ("EAIP") for Entergy

17 Company officers.

18 Q WHAT PERFORMANCE GOALS TRIGGER ADDITIONAL PAYOUTS UNDER THE

19 ANNUAL PLANS?

20 A In general, the payouts under the Annual plans are based on cost control,

21 operational and safety measures. In addition, of the ESI portion of the EAIP is

22 related to financial measures such as earnings per share (EPS) and stock price.2°

"" Exhibit KGG-4 (Highly Sensitive).
2. Revenue Requirement Issues

J. POLLOCK
INCORPORATEO

9
 Jeffry Pollock
Direct Testimony
ERRATA - Page 48

~~,~~~:_,,~~;~!(~~,.~-~~i.~~.~~tWtillflf~,. -~- '~i~~l1i:::·~~~j~tt~.[~~N~.
38663 Informational Project Relating To Filings By Entergy
Texas At The Louisiana Public Service Commission
Relating To The Entergy System Agreement And
Possible Successor Arrangements
38708 Project To Investigate The Entergy SuGCSssor
Arrangement
37344 Information Related To The Entergy Regional State
·Committee
37338 Commission Review Of Wholesale Market Issues
Relating To Entergy Texas, Inc.

1 Q WHY ELSE SHOULD ETl'S PROPOSED DEFERRED ACCOUNTING REQUEST

2 BE DENIED? .

3 A The projected transition costs are not material. ETI is currently projecting to incur

4 $17 million of transition costs.28 This equates to only $5.8 million per year, which Is

5 only 1% of ETI's Test Year operating revenues. Even at this level, the MISO

6 transition costs are easily subsumed in the normal variation in ETl's year-to-year

7 expenses._ as shown In Exhibit JP-8.

8 Q PLEASE EXPLAIN EXHIBIT JP-8.

9 A Exhibit JP-8 measures the year-to-year variation in operating expenses booked to

1o those FERG Accounts In which ETI Is proposing to record the MISO transition costs.

11 The year-to-year varlatlon is calculated for 3 separate time periods:

12 1. Calendar year 2009 versus year 2008;
13 2. Calendar year 201 O versus year 2009; and
14 3. Docket No. 39896 versus Docket No. 37744.

2
' Supplemental Direct Testimony of Jay Lewis at 5.

2. Revenue Requirement Issues

J.POLLOCK
!NCO!tPORATEO

10
.,

ExhibitJP-i ERRATA

ENTERGY TEXAS, INC.
Derivation of Test Year Adjusted
Purchased Power Capacity Costs
Year Ended June 30, 2011

Amount Unit Cost
Test Year (MW· ($/kW-Month) Cost
Line Descri[!tion Cost Months) Actual Pro .. Forma ($000)
(1) (2) (3) (4) SS)

1 ETI Proposed Expense $276,242

2 Test Year Actual Expense 245,433

Pro·Forma Adjustments (a)
'3 Third Party Purchases $30,939 5,884 $5.258 $5.381 723
4 Affiliate Purchases 189,032 21,670 8.723 8.656 (1,462)
5 Reserve Equalization 25,461 8,309 3.064 3.659 4,944
6 Total $245,433 35,863 $6.844 $6.940 249,638
Adjust Unit Cost
for Expiration of the
7 EAl·WBL Contract (b) (11,132)

8 Test Year Adjusted 238,507

9 Adjustment to ETl's Proposal ($37,735)

(a) Column 5 =(Column 4 ·Column 3) x Column 2.
(b) Exhibit JP-2.

11
 DOCKET NO. Joi 9/Jf
APPLICATION OF ENTERGY § BEFORE THE
GULF STATES, INC. FOR § PUBLIC UTILITY COMMISSION I"-)
DETERMINATION OF HURRICANE § OF TEXAS =
c..-:>
C".;M
RECONSTRUCTION COSTS § <-
c::: "'
,,
• I
" c•.n c'"''"t
' " ,,~
,,
-ry
' ..;... .,'
., ~

r;y

APPLICATION OF ENTERGY GULF STATES, INC.

FOR DETERMINATION OF

HURRICANE RECONSTRUCTION COSTS

JULY 5, 2006

Hurr Recon Costs 1-001

1
I
 This page intentionally left blank.

Hurr Recon Costs 1-002

2
 ENTERGY GULF STATES, INC.
HURRICANE RECONSTRUCTION COSTS CASE
EXECUTIVE SUMMARY OVERVIEW
Entergy Gulf States, Inc. ("EGSI" or the "Company") requests a
determination by the Commission that its EGSI Texas retail-jurisdictional
Hurricane Rita reconstruction costs of $393,236,384 were reasonable and
necessary to enable EGSI to restore electric service to its Texas customers. With
this determination, EGSI requests entry of a Commission order: (a) determining
that such costs are eligible for recovery and securitization; (b) authorizing the
Company to recover carrying costs; and (c) approving the manner in which
hurricane reconstruction costs will be functionalized and allocated in a subsequent
proceeding.

EGSI proves up the reasonableness and necessity of the $393.2 million by
showing that, on a Total Company basis (that is, EGSI Texas and EGSI Louisiana
combined), EGSI incurred $561.0 million in Hurricane Rita reconstruction costs
based on the following functional cost classes:

Class (Type) of Cost Texas Retail Costs Total Company Costs
Transmission $36.7 million $80.6 million
Generation $5.1 million $11.9 million
Other Plant/Suooort $1.1 million $2.4 million
Distribution-Texas $350.3 million $355.6 million
Distribution-Louisiana -0- $110.4 million
Total $393.2 million $561.0 million

Sorted another way, the $393.2 million (Texas Retail) and the $561.0 million (Total
Company) include the following categories of costs within the functional cost
classes:

Cost Category Texas Retail Costs Total Company Costs
Non-Enterav Contractors $307.2 million $428.3 million
EGSI Employee Expenses $13.7 million $19.3 million
EGSI Labor $9.4 million $15.6 million
Materials $36.2 million $55.1 million
Other Costs/Telecommunications/ $18.1 million $28.1 million
Transportation
Affiliate Charges (ES I/Loaned $8.6 million $14.5 million
Resources
Total $393.2 million $561.0 million

1

Hurr Recon Costs 1-003

3
 Eleven witnesses support the Company's case. Their proof includes:
detailed explanations of why and how the costs were incurred; the extraordinary
scope of damage; cost controls, including oversight of contractors; reliance on pre-
existing competitively-bid or negotiated contracts where possible; the need for
quick and safe restoration; benchmarks comparing EGSI Texas' restoration efforts
to other utilities; the cost recording, accounting, and review process; an
independent third-party financial audit of the costs; affiliate cost proof discussion;
potential insurance and grant payments; and a financial ratings agencies
perspective.
Because of the 150-day processing timeline established by House Bill 163
for this case, and its unique nature, EGSI requests that the Commission hear this
case directly.
The Commission's decision in this case concerning EGSl's reasonable and
necessary costs associated with Hurricane Rita will define for the future the level
of urgency a utility should employ in restoring service after a major weather event.
The Commission should strive to create an incentive for Texas utilities to follow
EGSl's example in taking all actions reasonably available to restore service as
quickly as possible for the benefit of customers and the regional economy.

2

Hurr Recon Costs 1-004

4
~---- -- - .......---

DOCKET NO.

APPLICATION OF ENTERGY § BEFORE THE
GULF STATES, INC. FOR § PUBLIC UTILITY COMMISSION
DETERMINATION OF HURRICANE § OF TEXAS
RECONSTRUCTION COSTS §

APPLICATION OF ENTERGY GULF STATES, INC. FOR DETERMINATION OF
HURRICANE RECONSTRUCTION COSTS

TO THE HONORABLE PUBLIC UTILITY COMMISSION OF TEXAS:

I. EXECUTIVE SUMMARY
Entergy Gulf States, Inc. ("EGSI or the "Company") requests a determination by the

Public Utility Commission of Texas ("Commission") that its EGSI Texas retail-

jurisdictional Hurricane Rita reconstruction costs of $393,236,384, through March 31,

2006, were reasonable and necessary to enable EGSI to restore electric service to its

Texas customers. With this determination, EGSI requests entry of a Commission order:

(a) determining such costs are eligible for recovery and securitization; (b) authorizing

the Company to recover carrying costs; and (c) approving the manner in which

hurricane reconstruction costs will be functionalized and allocated in a subsequent

proceeding.

Hurricane Rita was the most severe natural disaster ever to hit EGSl's service

area in southeast Texas and southwest Louisiana. The storm severely damaged

distribution and transmission facilities in Texas as well as causing damage to a majority

of EGSl's generation resources. At the storm's peak, over 75% of the customers in

EGSl's Texas service area were without service. Working with neighboring utilities,

EGSI undertook significant efforts to restore service to its customers, managing to

restore service to all customers who could receive service within 21 days. The costs of

Hurr Recon Costs 1-005

5
EGSl's reconstruction for both its Texas and Louisiana jurisdictions totaled almost $561

million through March 31, 2006. Of this amount, $393.2 million was incurred in Texas

retail-jurisdictional costs for the same time period.

EGSI files this Application as authorized by House Bill 163, which the Texas

Legislature passed and the Governor signed into law in May 2006. House Bill 163

states that EGSI is entitled to recover hurricane reconstruction costs consistent with the

Bill. The Bill provides a detailed, specific definition of the term "hurricane reconstruction

costs." Summarized, the "hurricane reconstruction costs" that EGSI is entitled to

recover are: the reasonable and necessary costs, whether expensed, charged to the

storm reserve, or capitalized, that EGSI incurred due to its own activities or activities

conducted on its behalf by others, in connection with the restoration of service

associated with electric power outages affecting EGSl's customers as a result of

Hurricane Rita. The Bill states that these costs include costs for "mobilization, staging,

and construction, reconstruction, replacement, or repair of electric generation,

transmission, distribution, or general plant facilities." House Bill 163 also states that the

hurricane reconstruction costs may include carrying charges, and that EGSI is enabled,

through the Bill, to use securitization financing to obtain timely recovery of the

reconstruction costs. EGSI requests the recovery of carrying costs on its Hurricane

Rita expenditures and, in a future proceeding after the total Hurricane Rita

reconstruction costs are determined in this docket, will request a securitization financing

order to recover those costs.

EGSl's request for a determination of its Texas retail Hurricane Rita

reconstruction costs incurred includes testimony and supporting exhibits sponsored by

2

Hurr Recon Costs 1-006

6
eleven witnesses. As is typical in cost-related applications filed by EGSI before the

Commission, the majority of EGSl's witnesses focus on and support the Total Company

costs: in this case, that is, the $561 million Total Company figure. The reason for this

approach is that EGSl's books and records are maintained on a Total Company basis.

The costs are recorded for the single legal entity - EGSI - rather than its two distinct

internal functional operations - EGSI Texas and EGSI Louisiana. EGSI also presents

witnesses who explain how to derive the Texas retail costs (the $393.2 million) from the

Total Company $561 million Hurricane Rita costs.

Because of the 150-day processing timeline established by House Bill 163 for

this case, and its unique nature, EGSI also requests that the Commission hear this case

directly.

A. Summary of Reconstruction Costs

At a summary level, the costs in this case are presented both by "class" of cost

and by "category" of cost. In this Application, a class of cost is a distinct operational or

functional grouping: transmission, generation, distribution, and "other plant/support." A

"category" of cost is a different view that shows different types of activities or services

that would be common to each of the classes - for example, external/third-party

contractor costs; materials, telecommunications, etc. The following table shows the

Hurricane Rita reconstruction costs, exclusive of carrying costs, by functional class at

both the Texas Retail and at the Total Company levels:

3

Hurr Recon Costs 1-007

7
 Class (Type) of Cost Texas Retail Costs Total Company Costs
Transmission $36. 7 million $80.6 million
Generation $5.1 million $11.9 million
Other Plant/Suooort $1.1 million $2.4 million
Distribution Texas $350.3 million $355.6 million
Distribution Louisiana 1 -0- $110.4 million
Total $393.2 million $561 million

The following table shows the categories of Hurricane Rita reconstruction costs

at both the Texas Retail and the Total Company levels:

Cost Category Texas Retail Costs Total Comoanv Costs
Non-EnterQV Contractors $307 .2 million $428.3 million
EGSI Employee Expenses $13.7 million $19.3 million
EGSI Labor $9.4 million $15.6 million
Materials $36.2 million $55.1 million
Other Costsffelecommunications/ $18.1 million $28.1 million
Transportation
Affiliate CharQes $8.6 million $14.5 million
Total $393.2 million $561 million

The Company's presentation in this Application, however, is much more than

simply dollar amounts segregated in different ways. The Company's witnesses provide

detailed explanations as to:

• why Hurricane Rita was so destructive and thus costly;

• the unique issues faced by EGSI in the reconstruction; and

• the systems and practices in place or implemented in response to the storm to

monitor, control, and reduce costs, while also expediting reconstruction in a safe

and organized manner.

1
EGSI Texas is not requesting recovery of any Distribution Louisiana costs; this amount is included
in the $561 million Total Company figure as part of the Hurricane Rita reconstruction costs incurred
by EGSI, but it is not in the $363.2 million specifically requested by EGSI Texas in this filing.

4

Hurr Recon Costs 1-008

8
 B. Summary of Witnesses

In this Application, three witnesses directly support the reasonableness and

necessity of the Hurricane Rita reconstruction costs based on the four functional cost

classes:

• Joseph F. Domino, President and CEO of Entergy Texas, sponsors the

Generation class and the Other Plant/Support class;

• Randall W. Helmick, Vice President for Transmission Services of Entergy

Services, Inc. (ESI), sponsors the Transmission class; and

• John E. Mullins, Director of Distribution Operations for EGSI Texas sponsors the

Distribution- Texas.

The following three Company witnesses explain the proposed regulatory

treatment of the hurricane reconstruction costs, the detail to move from the $561 million

in Total Company costs down to the $393.2 million in Texas retail costs, and then

propose how those Texas costs should be functionalized and then allocated to the

Texas retail customers:

• J. David Wright, Directory of Regulatory Accounting with ESI, addresses:

accounting practices for identifying costs and deriving the Texas retail cost figure

from the Total Company cost; regulatory asset treatment of the Texas retail cost;

and request for carrying costs;

• Myra L. Talkington, Senior Staff Rate Analyst with ESI, addresses allocation of

costs to the Texas retail jurisdiction and among the Texas retail jurisdiction rate

classes and schedules; and

5

Hurr Recon Costs 1-009

9
 • Donald W. Peters, Manager, Revenue Requirements for ESI, addresses how the

Company proposes to apply allocation methods and factors.

The remaining five EGSI witnesses provide further support for the

reasonableness and necessity of the Hurricane Rita reconstruction costs as follows:

• Theodore H. Bunting. Jr., Vice President, CFO-Operations with ESI, addresses

internal cost compilation, review, approval and recording practices; the "not

higher than" and "at cost" prongs of the Texas affiliate cost recovery standard;

and the status of potential insurance and grant payments;

• Michael A. Herman, a partner with PricewaterhouseCoopers, provides an

external attestation review of the Company's storm reports;

• Steven M. Fetter, President of an external utility advisory firm, addresses credit

ratings and how this proceeding can affect EGSl's credit ratings;

• John P. Hurstell, Vice President of Entergy Management, System Planning and

Operations with ESI, describes the financial stress imposed by Hurricane Rita on

EGSI, and the effect on EGSl's ability to transact with fuel and purchased power

suppliers; and

• Grant L. Davies, CEO of Davies Consulting, Inc., provides an external

assessment of the magnitude of Hurricane Rita, EGSl's performance prior to and

during the Hurricane Rita reconstruction, and EGSI Texas' resource acquisition

strategy.

C. Summary of Proof

The proof of why the Company's Hurricane Rita reconstruction costs were

"reasonable and necessary" is led by the three cost class witness: Messrs. Domino,

6

Hurr Recon Costs 1-010

10
Helmick, and Mullins. The bullet points below are derived primarily from the testimony

and exhibits of those three witnesses. The remaining witnesses, however, are also

crucial to the ultimate proof that the Company's claimed costs were, in fact and in law,

reasonable and necessary.

• Hurricane Rita made landfall east of Sabine Pass in the early morning hours of

September 24, 2005 and tracked northward along the Texas/Louisiana border,

producing damaging and sustained hurricane and tropical storm force winds until

the early hours of September 25.

• The Beaumont area, for example, experienced sustained winds of 81 mph and

wind gusts of 105 mph with isolated reports up to 120 mph along with nine inches

of rain during Hurricane Rita's life.

• At the peak of outages, 286,609 of EGSl's Texas customers were without

electricity.

• Mr. Mullins testifies, based on his 21 years of experience as a first responder to

several storm events, that Hurricane Rita cut one of the widest paths he had

experienced, and that the damage was comparable to hundreds of tornadoes

sweeping through southeast Texas.

• Despite Hurricane Rita being the most destructive storm to hit EGSl's Texas

service territory in recent history, the Company, with the assistance of many

outside contractors, was able to restore service to its entire system in only three

weeks. This was achieved through pre-established plans and training, thoughtful

deployment and reaction, and overall coordinated and management under

EGSl's direction and control.

7

Hurr Recon Costs 1-011

11
• Before and during the storm, pre-established teams were mobilized to staging

areas with initial materials to begin restoration as soon as safely possible.

Internal communications and links with weather services and other first

responders and officials were established. Company witness Domino, in

particular, discusses the intensive communications established between EGSI,

its customers, and the Commission and State government to coordinate and

keep all parties informed and involved.

• During and immediately after the hurricane, a priority was to safely and timely

mobilize our internal crews, and to secure outside crews from other utilities and

third-party contractors, to restore service as soon as possible. In all, over 11,000

workers were mobilized and coordinated by EGSI to restore service and

reconstruct its electric system as a result of the damage caused by Hurricane

Rita.

• The initial reconstruction efforts were done in accordance with a pre-established

storm plan that anticipates natural disasters such as Hurricane Rita. Training

related to the storm plan and its execution is conducted at least annually as part

of the Company's annual system storm drill.

• EGSI, on a daily basis throughout the reconstruction effort, determined the

number of crews and resources needed throughout its Texas territory for the

reconstruction effort. This effort was coordinated between the distribution and

transmission functions to ensure that distribution reconstruction was taking place

in areas where transmission would be available and could support load. Crews

8

Hurr Recon Costs 1-012

12
 were deployed and released as necessary to achieve the work needed without

waste or duplicate efforts.

• A high priority was to re-establish the transmission grid so that power could flow

to reconstruct the damaged substations, and then on to the distribution feeders

as they were repaired.

• The crews faced significant reconstruction obstacles caused by: (1) the

hurricane, such as downed trees and debris across roadways, rights-of-way, and

work sites, and soft ground from the heavy rain and flooding, which prevented

truck access; (2) the original location of now-damaged equipment and downed

lines behind buildings or in alleys; and (3) operational obstacles, such as the

availability and access to staging areas that were being occupied by different

groups of first responders, and the logistics of EGSI managing the mobilization,

feeding, and lodging of internal and external reconstruction crews.

• Reconstruction as quickly as possible, but also as safely as possible, was critical

to get basic human services back up and running, such as hospitals, water and

sewage facilities, the Department of Energy's Strategic Petroleum Reserve,

petrochemical plants, and interstate natural gas pipeline pumping stations.

Reconstruction costs could potentially have been reduced if service restoration

had been prioritized on a slower track. But a slower track would have been

detrimental to the local, State, and national economies, and was not favored by

the local, State, and federal authorities.

• Company witnesses Domino, Helmick, and Mullins explain in detail what types of

costs were incurred within their respective functional cost classes, and within the

9

Hurr Recon Costs 1-013

13
 cost categories within their classes, and why these costs were incurred at the

stated levels.

• Contract work provided by third-party independent contractors and non-Entergy

utilities make up a majority of the reconstruction costs. Crews were brought in

from as far away as New York State to assist in the effort, and this just a month

after Hurricane Katrina had destroyed vast areas along the Gulf Coast and New

Orleans.

• Independent (third-party) contractor companies were needed to assist in the

emergency reconstruction. These contractors were needed to assist Company

crews to: repair damaged electrical infrastructure, remove or trim back downed

vegetation, provide emergency logistics support (including transportation, food

and housing) and other emergency, short-term services. Many of the contracts

with these vendors had been negotiated prior to the 2005 hurricane season and

executed at pre-storm, competitive rates. Additional independent contractors

who were not pre-signed with EGSI were needed for the reconstruction; their

rates were also negotiated at competitive rates that took into account the

contractors' skills, capabilities, work product, and safety practices.

• Utilities not affiliated with EGSI sent crews to assist in the reconstruction effort.

The "mutual-aid" utilities services were paid for at the cost incurred by those

utilities, without markup.

• EGSl's affiliated utilities also sent "loaned resource" crews to assist in the

reconstruction effort. These affiliated crews (and others) were just coming off, or

10

Hurr Recon Costs 1-014

14
 being redeployed from, the restoration efforts from Hurricane Katrina. They were

also reimbursed at their normal pay level with no markup.

• In addition to prudent contracting practices, EGSI was able to increase

productivity and decrease restoration time by staging crews close to their

designated repair sectors and engaging in night-time refueling and equipment

maintenance.

• The Company's witnesses accurately refer to the combined groups of EGSI

employees, affiliated utility employees, mutual aid utility employees, and third-

party contractors as an "army." In this case, a specialized and competent, well

organized and managed army that worked individual extended shifts of up to 16

hours per day.

• Company witness Davies provides an independent assessment of the EGSl's

response to Hurricane Rita. Based on his experience and after-action review of

the Company's response to the storm, Mr. Davies concludes that EGSI, among

other things: brought in the appropriate number of off-system line and vegetation

crews; responded to Hurricane Rita consistent with generally-accepted utility

restoration practices; had consistently expended more than most of the

comparable utilities in maintaining its transmission and distribution infrastructure,

meaning that the resulting damage was caused by the storm, and not by

inadequate prior maintenance practices.

• At the field level, the cost witnesses prove that the Hurricane Rita costs were

reasonable and necessary because the Company anticipated and planned for

11

Hurr Recon Costs 1-015

15
 the storm, organized and managed the reconstruction activities admirably under

the circumstances, and did so quickly and safely.

• Invoices for reconstruction services and materials were reviewed, verified, and, if

verified to be correct, approved for payment by EGSI personnel familiar with the

work subject to the invoices. Invoices and charges were also reviewed and

audited by internal accounting personnel for accuracy. Company witnesses

Bunting and Herman, in particular, describe the internal and external audits of the

Hurricane Rita costs to ensure accuracy of costs and the accounting system.

• Mr. Bunting also primarily describes the Company's internal accounting system

and the process through which Hurricane Rita reconstruction costs were received

and recorded into the Company's accounting system. His testimony, in part,

verifies the accuracy and control of the accounting system to properly record the

Hurricane Rita reconstruction costs.

• The affiliate cost portion of this case is a fraction of the total cost: less than 3% of

the Total Company cost. The cost witnesses explain why theses affiliate costs,

as distinct from the costs incurred directly by EGSI (the "non-affiliate" costs) meet

the first two of four prongs of the affiliate cost recovery test: that is, the costs are

(1) reasonable and (2) necessary. Company witness Bunting then explains why

these affiliate costs satisfy the third and fourth prongs of that test: that the affiliate

charges are (3) "not higher than" the charges by the affiliate to others; and (4) the

affiliate charges "reasonably approximate the actual cost" of the affiliate's

service.

12

Hurr Recon Costs 1-016

16
• Company witnesses Fetter and Hurstell address financial issues that resulted

from, or that can result from, a storm such as Hurricane Rita. Mr. Fetter

addresses the financial credit ratings that apply to and affect EGSI, and how

adverse ratings can affect a utility's cost of capital to the detriment of customers.

He testifies as to the importance of the prompt and full recovery of reasonable

and necessary costs incurred as a result of Hurricane Rita. He also explains why

it is appropriate for EGSI to recover the time value of its Hurricane Rita

expenditures. On a related point, Mr. Hurstell describes the financial stress that

Hurricane Rita placed on EGSI, particularly the difficulties in procuring fuel and

purchased power from suppliers concerned over EGSl's financial health resulting

from the storm.

• Company witnesses Wright, Talkington, and Peters address the "rates" aspects

of this filing. They explain how the Total Company costs are assigned or

allocated from $561 million down to the $393.2 million Texas retail level; and how

the resulting costs should be functionalized and then allocated among the Texas

retail customer classes and schedules.

• Mr. Wright also specifically addresses the carrying charges that should be

applied to the hurricane reconstruction costs. He explains that the carrying

charge rate should be the Company's weighted average cost of capital from the

date on which the cost was incurred until the date hurricane reconstruction bonds

are issued pursuant to a financing order to be issued in a future docket.

13

Hurr Recon Costs 1-017

17
 D. Conclusion to Executive Summary

The Commission's decision in this case concerning EGSl's reasonable and

necessary costs associated with Hurricane Rita will define for the future the level of

urgency a utility should employ in restoring service after a major weather event. The

Commission should strive to create an incentive for Texas utilities to follow EGSl's

example in taking all actions reasonably available to restore service as quickly as

pos~ible for the benefit of customers and the regional economy.

1

II. BUSINESS ADDRESS AND AUTHORIZED REPRESENTATIVES

The business address of the Company is:

Entergy Gulf States, Inc.
350 Pine Street
Beaumont, Texas 77701.

, The business mailing address of the Company is:

Entergy Gulf States, Inc.
P.O. Box 2951
Beaumont, Texas 77704.

The business telephone number of the Company is (409) 838-6631.

14

H~rr Recon Costs 1-018

18
 The authorized representatives of the Company in this proceeding are:

Jack Blakley
Vice President, Regulatory Affairs
Entergy Gulf States, Inc.
Suite 840
919 Congress Ave.
Austin, Texas 78701
512-487-3975
(Fax) 512-487-3998

L. Richard Westerburg, Jr.
Assistant General Counsel
Entergy Services, Inc.
Suite 701
919 Congress Ave.
Austin, Texas 78701
512-487-3957
(Fax) 512-487-3958

Inquiries and pleadings concerning this Application should be directed to the

following representative:

L. Richard Westerburg, Jr.
Assistant General Counsel
Entergy Services, Inc.
Suite 701
919 Congress Ave.
Austin, Texas 78701
512-487-3957
(Fax) 512-487-3958

Ill. JURISDICTION AND AFFECTED PARTIES

The Commission has jurisdiction over EGSI and the subject matter of this

Application by virtue of Section 32.001 of the Public Utility Regulatory Act (PURA) and

House Bill 163, codified into PURA primarily at §§ 39.458 - .463. A copy of House Bill

163 is included as Attachment A to this Application.

15

Hurr Recon Costs 1-019

19
 The parties, classes of customers, and territories that would be affected by

approval of this Application are all customers who currently take or will take retail

electric service from EGSI in EGSl's Texas service territory.

IV. NOTICE

House Bill 163, PURA§ 39.462(e), explicitly states that "a rate proceeding under

Chapter 36 is not required to determine the amount of recoverable hurricane

reconstruction costs as provided by this section." Therefore, the notice requirements

specified in P.U.C. PROC. R. 22.51, which apply to Chapter 36 proceedings, do not apply

to this docket. Rather, P.U.C. PROC. R. 22.55 applies in this docket, which provides that

the Presiding Officer may require a party to provide reasonable notice to affected
2
persons. EGSI proposes the following with regard to public notice of this matter:

1. the Company proposes to publish notice of this application by one-time

publication in newspapers having general circulation in each county of the

Company's Texas retail service area beginning as soon as practicable

after filing this Application;

2. the Company will serve a copy of this filing on all active parties who

intervened in the Company's last general base rate filing before the

Commission: Docket No. 30123, Application of Entergy Gulf States, Inc.

for Authority to Change Rates and Reconcile Fuel Costs; and

3. the form of the notice to be provided is included as Attachment B to this

Application. The Company requests that the Commission find that the

Company's proposed notice is sufficient.

2
This proposed form of notice is the same type of notice and form approved in Docket No. 31544,
Application of Entergy Gulf States, Inc. for Recovery of Transition to Competition Costs.

16

Hurr Recon Costs 1-020

20
 V. CONFIDENTIAL INFORMATION AND PROTECTIVE ORDER

Certain information that may be provided through the course of this proceeding

may contain confidential or highly-sensitive information. To facilitate evaluation of this

information by the Commission Staff and other parties in this proceeding, the Company

has prepared a Protective Order that is included as Attachment C. The proposed

Protective Order duplicates the protective order approved in the Company's currently

pending fuel reconciliation proceeding, Docket No. 32710. 3 EGSI requests that the

Protective Order be adopted for use in this proceeding.

VI. CONCLUSION TO APPLICATION AND RELIEF REQUESTED

Through this Application, Entergy Gulf States, Inc. respectfully requests that the

Commission:

1. hear this case directly;

2. declare that notice of this filing is sufficient and authorized as provided in

Section IV above;

3. adopt the Protective Order provided in Attachment C for use in this docket;

4. within 150 days of this filing:

a) find the Company's Texas retail-jurisdictional hurricane reconstruction

costs of $393,236,384, through March 31, 2006, to be reasonable and

necessary and issue an order determining that amount of hurricane

reconstruction costs eligible for recovery and securitization;

b) authorize the Company to recover, in the financing proceeding to be

filed subsequent to this docket, carrying costs on the approved hurricane

3
Application of Entergy Gulf States, Inc. for the Authority to Reconcile Fuel and Purchased Power
Costs (filed May 15, 2006).

17

Hurr Recon Costs 1-021

21
 reconstruction costs at the Company's weighted average cost of capital

from the date on which the cost was incurred until the date transition

bonds are issued pursuant to a financing order issued in the financing

proceeding; and

c) approve the manner in which hurricane reconstruction costs will be

functionalized and the associated revenue requirement allocated in the

future financing proceeding, as discussed in the testimonies of Company

witnesses Wright, Talkington, and Peters attached to this Application; and

5. grant such other relief to which EGSI shows itself entitled.

18

Hurr Recon Costs 1-022

22
 - - - - - - - - - - - - - - - - - - - - - - -

Respectfully submitted,

L. Richard Westerburg, Jr.
Steven H. Neinast
ENTERGY SERVICES, INC.
919 Congress Ave.
Suite 701
Austin, Texas 78701
(512) 487-3957 telephone
(512) 487~ 958 facsimil

By: ;
L. Richard We rburg, Jr.
State Bar No. 21216950

Mark Strain
Scott Olson
Clark, Thomas & Winters
A Professional Corporation
300 West 5th Street, 151h Floor
Austin, Texas 78701
(512) 472-8800
(512) 474-1129 (Fax)

Stephen Fogel
5806 Sierra Madre
Austin, Texas 78759-3924
(512) 487-3946
(512) 996-0983 (Fax)

ATTORNEYS FOR
ENTERGY GULF STATES, INC.

CERTIFICATE OF SERVICE

I certify that a copy of this document was served on all active parties of record in

Docket No. 30123 on July 5, 2006, by hand-delivery, first class ii, or overnight

delivery.

19

Hurr Recon Costs 1-023

23
 DOCKET NO. 32907

APPLICATION OF ENTERGY GULF § PUBLIC UTILITY COM~S~~ON
~. ' ~· ;:")
STATES, INC. FOR DETERMINATION § ~";
\

..-·"-
OF HURRICANE RECONSTRUCTION § OF TEXAS /
'
COSTS § \.

, . 0
ORDER 0 ~
'-:~,
This Order approves the application of Entergy Gulf States, Inc. (EGSI) as modif'red
through an unopposed Settlement Agreement (Agreement) filed in this docket on
November 17, 2006. EGSI, the Public Utility Commission of Texas's Staff (Commission Staff),
the Cities of Beaumont, Conroe, Groves, Pine Forest, Nederland, Port Neches, Rose City and
Silsbee (collectively, Cities), the City of Port Arthur (Port Arthur), the Office of Public Utility
Counsel (OPC), Texas Industrial Energy Consumers (TIEC), and the State of Texas (State)
(collectively, Signatories) support the Agreement and request that the Public Utility Commission
of Texas (Commission) approve the Agreement without modification. The East Texas
Cooperatives (ETC) 1 state that they neither oppose nor support the Agreement and that they do
not request an evidentiary hearing in this docket. This docket was processed in accordance with
applicable statutes and Commission rules. EGSI' s application, consistent with the Agreement, is
approved.

The Commission adopts the following findings of fact and conclusions of law:

I. Findings of Fact

Procedural History
1. On July 5, 2006, EGSI filed an application, under §§ 39.458-.463 of the Public Utility
Regulatory Act, 2 for: (1) a determination that the Hurricane Rita reconstruction costs in
the amount of $393,236,384, incurred through March 31, 2006, are eligible for recovery
and securitization; (2) authority to recover carrying costs at EGSI' s weighted average

1
.East Texas Electric Cooperative, Inc., Tex-La Electric Cooperative of Texas, Inc., and Sam Rayburn
G&T Electric Cooperative, Inc., collectively the East Texas Cooperatives.
2
Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-66.017 (Vernon 1998 & Supp. 2006)
(PURA).

\
DOCKET NO. 32907 ORDER PAGE2of10

cost of capital on those hurricane reconstruction costs from the date the costs were
incurred through the date that transition bonds are issued under a financing order issued
in a future docket in which EGSI requests a financing order (financing order proceeding);
and (3) approval of the manner in which the hurricane reconstruction costs will be
functionalized and the associated revenue requirement allocated in the financing order
proceeding.

2. EGSI's application, filed on July 5, 2006, included the prefiled direct testimony, exhibits,
and workpapers of eleven witnesses in support of EGSI' s request.

3. EGSI's witnesses, as a whole, provide testimony that EGSI contends supports EGSI's
requests.

4. On July 7, 2006, the Commission issued Order No. 1, which provided for a protective
order applicable to this docket and required comment on the proposed notice.

5. On July 28, 2006, the Commission issued Order Requesting List of Issues, which
requested that parties file lists of issues that may be addressed in this docket.

6. On July 31, 2006, the Commission issued Order No. 6, which, among other things,
established a procedural schedule applicable to this docket, including dates for parties to
file testimony, discovery deadlines, and a November 1, 2006 commencement date for the
Open Meeting hearing on the merits.

7. The intervention deadline established for this docket was August 31, 2006.

8. On or before August 31, 2006, the following parties filed unopposed motions to
intervene, and their motions were granted by the Commission: OPC; Cities; TIEC; State;
ETC; and Port Arthur.

9. On September 1, 2006, EGSI filed its proof of notice.
DOCKET NO. 32907 ORDER PAGE3of10

10. On September 8, 2006, the Commission issued its Preliminary Order in this docket.

11. Discovery on EGSI's direct case concluded on September 19, 2006.

12. On October 9, 2006, all intervenors, except ETC, filed testimony and supporting
documents addressing EGSI's application and direct testimony, and State and Port Arthur
also filed statements of position.

13. All intervenors that filed testimony recommended various adjustments to the Hurricane
Rita reconstruction costs and proposed carrying costs, or to the proposed
functionalization and allocation, requested by EOSI.

14. On October 12, 2006, State and TIEC filed cross-rebuttal testimony.

15. On October 16, 2006, Commission Staff filed its testimony and a statement of position,
which, among other things, recommended a lower carrying cost rate than EGSI had
requested.

16. On October 17, 2006, the Commission issued Order No. 9, which, among other things,
directed parties not prefiling direct testimony but wishing to participate in the hearing on
the merits to file a statement of position no later than October 24, 2006.

17. On October 23, 2006, EGSI filed rebuttal testimony and a statement of position.

18. On October 27, 2006, the Commission issued Order No. 12, which ruled on EGSI's
objections and motion to strike various portions of the pre-filed testimony and supporting
documents filed by the intervenors.

19. At a prehearing conference convened on October 30, 2006, the Commission admitted into
evidence: (a) all of the parties' pre-filed testimony and supporting documents, except as

3
DOCKET NO. 32907 ORDER PAGE4of10

modified or stuck by Order No. 12 and the parties' errata to their pre-filed evidence; (b)
the parties' cross-examination exhibits; and (c) the parties' optional completeness
exhibits. The Commission took under advisement the admissibility of several proffered
exhibits pending its review of motions filed in response to Order No. 12. In addition,
under Order No. 9, the parties were to convene on November 1, 2006, before the start of
the hearing on the merits, for a continuation of the prehearing conference to address any
remaining exhibit items.

20. On October 30, 2006, after the prehearing conference was concluded, the Commission
issued Order No. 13, which ruled on State's and EGSl's motions filed in response to
Order No. 12, clarified which portions of pre-filed testimony and supporting documents
were modified or struck by Order No. 12, and admitted additional cross-examination
exhibits.

21. On November 1, 2006, at the prehearing conference convened before the start of the
hearing on the merits, the parties present requested a delay in the start of the hearing on
the merits to enable them to continue settlement talks. The Commission granted the
request.

22. Later in the morning of November 1, 2006, the parties present announced that they had
reached a settlement on all issues, stated that there was no need to conduct a hearing on
the merits, and requested the opportunity to prepare a settlement agreement to file with
the Commission. The Commission granted the request.

23. On November 17, 2006, EGSI filed the Agreement, which resolves all issues in this
docket, on behalf of itself, Commission Staff, and all active parties. The filing stated on
behalf of ETC that ETC neither supports nor objects to the Agreement.

The Agreement
24. Under the Agreement, the amount of EGSI' s reasonable and necessary hurricane
reconstruction costs incurred through March 31, 2006, that is eligible for recovery and
DOCKET NO. 32907 ORDER PAGE5of10

securitization is $381,236,384 plus carrying costs, as set forth in findings of fact 26
through 35.

25. The Agreement does not reflect or determine resolution of any hurricane reconstruction
costs that were charged to EGSI's books after March 31, 2006.

26. In addition to $381,236,384, the Agreement authorizes EGSI to include in hurricane
reconstruction costs and to securitize carrying costs at the rate of 7.9% per annum as
reflected in Attachment A to this Order,3 from the later of October 15, 2005 or the date
incurred until the issuance of securitization bonds. The balance upon which carrying
costs are determined will be reduced by the amount of insurance payments when received
as provided in findings of fact 27 through 30. 4

27. The Agreement directs EGSI to credit $65. 7 million in the manner described in finding of
fact 35, reflecting EGSI' s expectation that it will receive insurance payments in that
amount attributable to Texas Retail.

28. Under the Agreement, carrying costs at the rate referenced in finding of fact 26 shall
apply to: (1) any portion of the $65.7 million referenced in finding of fact 27 not actually
received by EGSI, until EGSI actually receives such payments attributable to Texas
Retail; and (2) the trued-up amount, as provided in finding of fact 29, until such trued-up
amount (plus associated carrying costs at the rate of 7.9% per annum) is recovered in
base rates.

29. The Agreement provides that after EGSI receives all insurance payments related to
Humcane Rita, the $65.7 million credited, as provided in finding of fact 27, shall be
trued up to reflect the difference between the $65.7 million credited and all insurance

3
Attachment Ais a copy of Exhibit A to the Agreement.
4
The insurance carriers include Oil Insurance Limited, Lloyd's and Hartford Steam Boiler Inspection and
Insurance Company. EGSI expects to receive $65.7·million for the Texas retail allocation (Texas Retail) out of the
total insurance payments. The total insurance payments would include amounts allocated to EGSI Louisiana as well
as EGSI Texas.

5
DOCKET NO. 32907 ORDER PAGE6of10

payments actually received by EGSI related to Hurricane Rita attributable to Texas
Retail.

30. Under the Agreement, in the event EGSI receives insurance payments related to
Hurricane Rita attributable to Texas Retail in excess of $65. 7 million after the
Commission's issuance of a financing order in the financing order proceeding, such
payments shall be passed through to ratepayers in the form of a rider with carrying costs
calculated on the unamortized balance of such payments at the rate of 7 .9% per annum.

31. The Agreement directs EGSI to continue to pursue EGSI's application for proceeds from
governmental grants.

32. With regard to the treatment of grant proceeds distributed prior to securitization, the
Agreement provides as follows:

A. Any proceeds from governmental grants distributed directly to EGSI before the
Commission issues a financing order shall be administered in a manner consistent
with the conditions and directions of the grant, and, if consistent with the
conditions and directions of the grant, shall be used to reduce the amount
securitized. For illustrative purposes with respect to the preceding sentence, a
reduction in the securitized amount is not considered consistent with the
conditions and directions of the grant when, based on the cost allocation provided
in the Agreement, such a reduction in the amount securitized would result in rates
(transition charges) that would allocate the credit or reduction associated with the
grant proceeds among customers or customer classes in a manner inconsistent
with the conditions and instructions of the grant.

B. If a reduction of the securitized amount is not consistent with the conditions and
directions of the grant as described in finding of fact 32, item A, and the grant
does not prescribe carrying costs on the grant proceeds (either explicitly or
implicitly, e.g., by instructing that the proceeds be escrowed or treated similarly),
DOCKET NO. 32907 ORDER PAGE7 oflO ·

EGSI will reduce the securitized amount by the amount of carrying costs on the
grant proceeds, calculated at 7.9 % per annum from EGSI's actual receipt of grant
proceeds until the issuance of securitization bonds.

33. The Agreement provides that any proceeds from governmental grants distributed directly
to EGSI after the Commission's issuance of a financing order shall be administered in a
manner consistent with the conditions and directions of the grant, and, if consistent with
the conditions and directions of the grant, shall be passed. through to ratepayers in the
form of a rider with carrying costs calculated on the unamortized balance of such
proceeds at the rate of 7.9% per annum.

34. In regard to the receipt of governmental grant proceeds as described in findings of fact 32
and 33, the Agreement further provides that, in any event, any reduction in rates
associated with the receipt of governmental grant proceeds shall be no greater than the
amount of such proceeds, subject to the calculation of carrying costs provided in findings
of fact 32 and 33.

35. Under the Agreement, the total dollar amount eligible to be securitized in the financing
order proceeding (as reflected in Attachment A to this Order) shall be: $381,236,384 plus
carrying costs at the· rate and for the time period specified in findings offact 26 through
30, minus $65.7 million related to insurance, plus all other qualified costs, to be
determined by the Commission in the financing order proceeding, provided for in PURA
§ 39.460(d).

36. The Agreement provides that the present value of the benefit, if any, of accumulated
deferred federal income taxes and method of handling such benefit will be part of EGSI's
presentation in the financing order proceeding and subject to the Commission's
determination about how such benefit, if any, should be treated in the financing order or a
subsequent proceeding.

7
DOCKET NO. 32907 ORDER PAGESoflO

37. Under the Agreement: (a) the functionalization and allocation methodology proposed by
EGSI in its filed case shall be utilized in the financing order proceeding; and (b)
adjustments described in findings of fact 24 through 36 shall be functionalized and
allocated pro rata in the same manner as proposed by EGSI in its filed case.

38. The Agreement includes standard provisions regarding waiver, general terms and
conditions, lack of precedential effect, and termination of the Agreement in the event the
Commission does not accept the Agreement as presented.

39. The Agreement resolves all issues of fact and law applicable to this docket.

40. Approval of the Agreement is in the public interest.

II. Conclusions of Law

1. EGSI is a public utility as that term is defined in §§ 11.004 and 31.002 of PURA.

2. The Commission has jurisdiction over this proceeding under PURA§§ 39.458-.463.

3. EGSI provided appropriate notice of this proceeding in accordance with P.U.C. PROC.
R. 22.55.

4. EGSI's application was processed in accordance with PURA §§ 39.458-.463 and the
Administrative Procedure Act, TEX. Gov'T CODE ANN. §§ 2001.001-.902 (Vernon 2000
& Supp. 2006).

5. PURA §§ 39.458-.463 allow, among other things, EGSI to obtain timely recovery of
reasonable and necessary Hurricane Rita reconstruction costs and to use securitization
financing to recover those costs.
 DOCKET NO. 32907 ORDER PAGE 9of10

· 6. The functionalization and allocation methodology proposed by EGSI in its filed case
complies with PURA§ 39.460(g).

7. The evidentiary record, which includes testimony and exhibits filed by EGSI,
Commission Staff, Cities, TIEC, OPC, and State, supports the Agreement.

8. Because the Agreement is the result of an unopposed agreement among the parties, an
adjudicatory hearing is not required to process EGSI's application in this docket.

III. Ordering Paragraphs

1. EGSI's request for a determination of the dollar amount of its Hurricane Rita
reconstruction costs, incurred through March 31, 2006, plus carrying costs, that are
eligible for recovery and securitization in the financing order proceeding, as described in
finding of fact 35 and the Agreement, is approved.

2. In the financing order proceeding, the hurricane reconstruction costs shall be
functionalized and the associated revenue requirement allocated in the manner proposed
by EGSI in its case filed on July 5, 2006.

3. EGSI shall comply with the true-up provisions regarding insurance payments as set out in
findings of fact 28 through 30.

4. EGSI shall treat governmental grant proceeds in the manner set out in findings of fact 32
through 34.

5. EGSI shall continue to pursue its application for proceeds from governmental grants.

6. EGSI shall file, semi-annually from the date of this order, in Project No. 33560,
Compliance Report of Entergy Gulf States, Inc. in Response to Final Order in Docket No.
32907, a report detailing all alternative sources of recovery of its hurricane reconstruction
costs, including but not limited to insurance and grants.
DOCKET NO. 32907 ORDER PAGE lOoflO

7. Entry of this Order does not indicate the Commission's endorsement or approval of any
principle or methodology that may underlie the Agreement. Neither shall the entry of the
Order be regarded as binding precedent as to the appropriateness of any principle
underlying the Agreement.

8. All other motions, requests for entry of specific findings of fact and conclusions of law,
and any other request for general or specific relief, if not expressly granted herein, are
denied.

SIGNED AT AUSTIN, TEXAS the \ G\- day of December 2006.

PUBLIC UTILITY COMMISSION OF TEXAS

q:\cadm\orders\final\32000\32907 fo.doc
 Attachment A

Entergy Gulf StatM, Inc. Docket No. 32907
Rita Stonn R"toratlon CoaU for TX Settlement Agreement
btlmate Of Carrying C09t for TX Reta• Exhibit A
For C09ta Incurred September 2001 - March 2oot Paga 1of1
(Amount. In Doller.)

TX Retail Carrying Colt

Beginning Adjusted Colt
Month of TXRetaA Accrual Including Balance for Settlement
Carrying Coet Colt Adjustment Settlement Canylng Coet Carrying Coata Adjuatmanta
Sep05 1,552,688 1,504,592 1,504,592 (48,093)
Oct05 66,174,848 (475,471) 63,649,651 219,419 65,373,662 (2,049,724)
Nov05 82,799,332 147,669 80,382,344 694,961 146,450,974 (2,584,657)
Dec05 58,588,197 (361,211) 56,421,944 1,149,858 204,022,778 (1,815,042)
Jan 08 34,649,048 626,801 34,202,617 1,455,734 239,681,128 (1,073,232)
Feb OS 55,318,008 (134,812) 53,469,755 1,753,905 294,904,788 (1,713,440)
Maroa 88,324,964 (35,544,631) 50,044,523 2,106,186 347 ,055,496 (2,735,810)
Apr-08 25,086,733 25,086,733 2,367,359 374,509,588
May-o& 10,654,922 10,654,922 2,500,594 387,665,104
Jun-08 2,552,1211 390,217,232
Jul-08 2,568,930 392, 786, 182
Aug-06 2,585,842 383,228,245 (12, 143,780)
Sep-08 2,522,919 385,751, 184
Oct-08 2,539,528 388,290,892
Nov-06 2,556,247 . 390,846,940
Dec-Oii 2,573,076 393,420,015
Jan-07 2,590,015 396,010,030
Feb-07 2,607,066 398,617,098
Mar-07 2,624,229 401,241,329
Apr-07 2,641,505 403,882,831
May-o7 2,658,8915 406,541,728
Sub-Tofall 387,417,080 375,417,080 43,268,406 (12,000,000) (12, 143,780)

leaaAFUDC
Sep 05 - Mar 06 (5.819,304)

Total Carrying Coata 37,449,102

Sum1111ry
TX Re1al Costa N1ove 371,417 ,080
AFUOC 5,819,3fM
Total TX Retal Coats Per Exh JOW-2 leaa Seti. Adj. 381,236,314

Total Canying Coa1a 37,449,102

Total to Recover Alsuming a June 1 Securitlzallon 418,685,481
(Carrying coala to be calculated untll lnuance of bonds)

Ina. to Remove for Securitlzalion (TX Re1al'Amt.) 85,700,000

Total to Securitiza Anuming a June 1 Securitization 3152,986,481

Notes:
TX Retall Coat excludes AFUOC.
Accruals Adjustment subtracts coala that are accrued but not yet paid. Accruals are assumed to be paid In lul by May 2006.
Carrying Coat • (Current Month Adjusted Coat • 112 Month + Prier Month Balance to Recover) • Carrying Cost
Hurricane Rita tax benefits have not been re11llzad as the Company ls In a net operating toss carryforward position.
Amounts may not aum to totals due to rounding.
Plus al other qualliad coats provided for in Section 39.480(d) of PURA.

Carrying Coat 7.911%

/7 Page 10 of 10
•
·~·Entergy
Entergy Services, Inc.
Legal Services
919 Congress Avenue
Suite 701
Austin, TX 78701

f :•.:'/ 17 f';J}. !!~rd Westerburg, Jr.
Assis~1 General Counsel
PUt!Lf;; :. r :siop1 512-487-3944
I i~;i;., CUL , 512-487-3958

November 17, 2006

Judge Andrew Kang
Administrative Law Judge
Public Utility Commission of Texas
1701 North Congress Avenue
Austin, Texas 78711

Re: P.U.C. Docket No. 32907,Application of Entergy Gulf States, Inc.for
Determination ofHurricane Reconstruction Costs

Dear Judge Kang:

Pursuant to Order No. 15, please find attached the Settlement Agreement and Proposed
Order in Docket No. 32907 for consideration and decision at the Commission's
December 1, 2006 Open Meeting. Also, pursuant to Order No. 1, the statutory deadline
for the issuance of an order is December 2, 2006. Accordingly, Entergy Gulf States, Inc.
requests the Order be signed by the Commission on December 1, 2006.

As reflected in the Settlement Agreement, the East Texas Cooperatives (ETC) (East
Texas Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative, Inc., and Tex-
La Electric Cooperative of Texas, Inc.), who are intervenors in this docket, have
authorized the Signatories to represent that ETC neither supports nor opposes this
Agreement and that ETC does not request an evidentiary hearing in this docket.

Sincerely,// r )
1 lt~h-#'}:dt'~-
L. Richard Westerburg, Jr.

cc: PUC Filing Clerk
All Parties
 DOCKET NO. 32907

APPLICATION OF ENTERGY GULF § BEFORE THE
STATES, INC. FOR § PUBLIC UTILITY COMMISSION
DETERMINATION OF HURRICANE § OF TEXAS
RECONSTRUCTION COSTS §

SETTLEMENT AGREEMENT

1. Preamble.

1.1. This Settlement Agreement (Agreement) is entered in this docket

before the Public Utility Commission of Texas (Commission) by and among:

Entergy Gulf States, Inc. (EGSI or Company); the Staff of the Public Utility

Commission. of Texas (Staff); the Cities of Beaumont, Conroe, Groves, Pine

Forest, Nederland, Port Neches, Rose City and Silsbee (collectively, Cities); the

City of Port Arthur (Port Arthur); the Office of Public Utility Counsel (OPC); Texas

Industrial Energy Consumers {TIEC); and the State of Texas {State) (collectively,

Signatories ). 1

1.2. On July 5, 2006, EGSI filed an application in Commission Docket

No. 32907, under House Bill 163, for: (1) a determination that the Hurricane Rita

reconstruction costs in the amount of $393,236,384 (Texas retail jurisdictional

amount), incurred by EGSI through March 31, 2006, are eligible for recovery and

securitization; (2) authority to recover carrying costs at the Company's weighted

average cost of capital on those hurricane reconstruction costs from the date the

costs were incurred through the date that transition bonds are issued under a

1
The only other parties in the case-the East Texas Cooperatives (ETC} (East Texas
Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative, Inc. and Tex-La Electric
Cooperative of Texas, lnc.)-authorize the Signatories to represent that ETC neither supports nor
opposes this Agreement and that ETC does not request an evidentiary hearing in this docket.

Docket No. 32907
Settlement Agreement
Page 1of10
financing order issued in a future docket in which the Company requests a

financing order (financing order proceeding); and (3) approval of the manner in

which the hurricane reconstruction costs will be functionalized and the associated

revenue requirement allocated in the financing order proceeding. The

Signatories filed direct and rebuttal testimony, and statements of position, stating

their respective positions in this docket. The Signatories agree to the following

terms in settlement of issues arising in this docket.

2. Reasonable and Necessary Hurricane Reconstruction Costs.

The amount of the Company's reasonable and necessary hurricane

reconstruction costs determined, in this docket, to be eligible for recovery and

securitization is $381,236,384 plus carrying costs, as set forth in paragraph nos.

3 through 6 of this Agreement. This Agreement does not reflect or determine

resolution of any hurricane reconstruction costs that were charged to the

Company's books after March 31, 2006.

3. Carrying Costs.

In addition to $381,236,384, the Company is authorized to include in

hurricane reconstruction costs and securitize carrying costs at the rate of 7 .9%

per annum, as reflected in Exhibit A attached to this Agreement, from the later of

October 15, 2005 or the date incurred until the issuance of securitization bonds.

The balance upon which carrying costs are determined will be reduced by the

amount of insurance payments when received, as provided in paragraph no. 4 to

this Agreement.

Docket No. 32907
Settlement Agreement
Page 2of10
4. Insurance Proceeds.

The Company shall credit $65. 7 million in the manner described in

paragraph no. 6 to this Agreement, reflecting the Company's expectation that it

will receive insurance payments in that amount (Texas Retail). Carrying costs at

the rate referenced in paragraph no. 3 shall apply to: (1) any portion of the $65.7

million not actually received by the Company, until the Company actually

receives (Texas Retail) such payments; and (2) the trued-up amount, as provided

below, until such trued-up amount (plus associated carrying costs at the rate of

7.9% per annum) is recovered in base rates. Subsequent to the receipt of all

insurance payments related to Hurricane Rita, the $65.7 million credited, as

provided in this paragraph, shall be trued up to reflect the difference between the

$65.7 million credited and all insurance payments actually received by the

Company related to Hurricane Rita for Texas Retail. In the event the Company

receives insurance payments related to Hurricane Rita for Texas Retail in excess

of $65.7 million after the Commission's issuance of a financing order in the

financing order proceeding, such payments shall be passed through to

ratepayers in the form of a rider with carrying costs calculated on the

unamortized balance of such payments at the rate of 7.9% per annum.

Docket No. 32907
Settlement Agreement
Page 3of10
5. Proceeds from Governmental Grants.

A. Pursuit of Governmental Grants.

5.1 The Company shall continue to pursue its application for proceeds

from governmental grants.

B. Treatment of grant proceeds distributed prior to securitization.

5.2 Any proceeds distributed directly to the Company prior to the

Commission's issuance of a financing order shall be administered in a manner

consistent with the conditions and directions of the grant, and, if consistent with

the conditions and directions of the grant, shall be used to reduce the amount

secu ritized.

5.3 For illustrative purposes with respect to paragraph no. 5.2 of this

Agreement, a reduction in the securitized amount is not considered consistent

with the conditions and directions of the grant when, based on the cost allocation

provided in this Agreement, such a reduction in the amount securitized would

result in rates (transition charges) that would allocate the credit or reduction

associated with the grant proceeds among customers or customer classes in a

manner inconsistent with the conditions and instructions of the grant.

5.4 If a reduction of the securitized amount is not consistent with the

conditions and directions of the grant as described in the paragraph no. 5.3 of

this Agreement and the grant does not prescribe carrying costs on the grant

proceeds (either explicitly or implicitly, e.g., by instructing that the proceeds be

escrowed or treated similarly), the Company will reduce the securitized amount

by the amount of carrying costs on the grant proceeds, calculated at 7 .9% per

Docket No. 32907
Settlement Agreement
Page 4of10
s
annum from the Company's actual receipt of grant proceeds until the issuance of

securitization bonds.

C. Treatment of grant proceeds distributed after securitization.

5.5 Any proceeds distributed directly to the Company after the

Commission's issuance of a financing order shall be administered in a manner

consistent with the conditions and directions of the grant, and, if consistent with

the conditions and directions of the grant, shall be passed through to ratepayers

in the form of a rider with carrying costs calculated on the unamortized balance of

such proceeds at the rate of 7 .9% per annum.

D. Reduction in rates due to grant proceeds.

5.6 In any event, any reduction in rates associated with the receipt of

grant proceeds, whether before or after securitization, shall be no greater than

the amount of such proceeds, subject to the calculation of carrying costs

provided in paragraph nos. 5.4 and 5.5 of this Agreement.

6. Amount to be Securitized.

The total amount eligible to be securitized in the financing order

proceeding (as reflected in Exhibit A attached to this Agreement) shall be:

$381,236,384 plus carrying costs at the rate and for the time period specified in

paragraph no. 3, minus $65. 7 million related to insurance, plus all other qualified

costs, to be determined by the Commission in the financing order proceeding, as

provided for in Section 39.460(d) of the Public Utility Regulatory Act, TEX. UTIL.

CODE Title 2. The present value of the benefit, if any, of accumulated deferred

federal income taxes and method of handling such benefit will be part of the

Docket No. 32907
Settlement Agreement

b Page 5of10
Company's presentation in the financing order proceeding and subject to the

Commission's determination about how such benefit, if any, should be treated in

the financing order or a subsequent proceeding.

7. Functionalization and Allocation.

The parties agree that the functionalization and allocation methodology

proposed by EGSI in its filed case shall be utilized in the financing order

proceeding. Adjustments described in the preceding paragraphs shall be

functionalized and allocated pro rata in the same manner as proposed by EGSI

in its filed case.

8. No Waiver.

Except as to matters determined in this Agreement, no Signatory, by

entering into the Agreement, waives its right to take any position in any

proceeding as to any issue(s) related to the Hurricane Rita reconstruction costs

that may arise in any other docket, appeal, or any other matter. Each Signatory

specifically reserves, and does not waive, its individual right to file any pleading,

or to participate in, or to initiate any proceeding to assert or support such

position, or to engage in any combination of these activities, except a pleading

that is inconsistent with the settlement points described in this Agreement.

Docket No. 32907
Settlement Agreement
Page 6of10
7
9. Other Terms and Conditions.

After extensive negotiations, the Signatories have reached a compromise

and settlement regarding each of the matters discussed in this Agreement. The

Signatories agree that this Agreement is in the public interest and urge the

Commission to adopt a final order consistent with all of its terms. Oral and

written statements made during the course of the settlement negotiations shall

not be used as an admission or concession of any sort or as evidence in this or

any other proceeding. None of the Signatories agrees to the propriety of any

regulatory theory or principle that may be said to underlie any of the issues

resolved by this Agreement. Because this is a stipulated agreement, the

Signatories recognized that no Signatory is under any obligation to take the same

position as set out in this Agreement in any other docket, except as specifically

required by this Agreement, whether or not that docket presents the same or

similar circumstances.

10. No Precedent.

Further, given that the matters resolved in this Agreement are resolved on

the basis of compromise and settlement, the Signatories agree that nothing in

this Agreement should be considered to be precedent in any other Commission

proceeding, except a proceeding to enforce the terms of this Agreement. This

Agreement reflects a compromise, settlement and accommodation among the

Signatories, and the terms and conditions of this Agreement are interdependent.

All actions by the Signatories contemplated or required by this Agreement are

conditioned upon entry by the Commission of a final and appealable order

Docket No. 32907
Settlement Agreement
Page 7of10
consistent with this Agreement. If the Commission does not accept this

Agreement as presented and enters an order inconsistent with any term of this

Agreement, any Signatory shall have the right to withdraw from this Agreement,

which withdrawal shall render the Agreement null and void. Any Signatory

electing to withdraw from this Agreement shall notify all other Signatories in

writing of such withdrawal. After the withdrawal, a new hearing will be held, if

requested, and the parties have the right to file new testimony. This Agreement

is binding on each of the Signatories only for the purpose of settling the issues

described in this Agreement and for no other purpose.

11. Authorization to Sign.

Each person executing this Agreement represents that (s)he is authorized

to sign this Agreement on behalf of the party represented.

12. Countersigned Originals.

This document may be countersigned by each party on separate originals.

Each signature shall be treated as if it is an original signature.

Docket No. 32907
Settlement Agreement
Page 8of10
11/17/2006 15:40 FAX 5129367268 PUC LEGAL AND ENFORCEMEN ~002/003

STAFF OF THE CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS NEDERLAND, PINE FOREST, PORT NECHES,
ROSE CITY, AND SILSBEE

Date of Execution: November 11~ 2006. Date of Execution: November __, 2006

By~~Zttt
0FRCE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS,
OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November , 2006 Date of Execution: November , 2006

By:_ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ __

CITY OF PORT ARTHUR TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November __, 2006 Date of Execution: November __, 2006

By:_ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ __

ENTERGY GULF STATES, INC.

Date of Execution: November __, 2006

By:._ _ _ _ _ _ _ _ _ _ _ __

Docket No. 32907
Settlement Agreement
Page 9of10
STAFF OF THE CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS NEDERLAND, PINE FOREST, PORT NECHES,
ROSE CITY, AND SILSBEE

Date of Execution: November _ _ , 2006. Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ _ __

OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS,
OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November JZ. 2006 Date of Execution: November __ , 2006

By:'l&f~ By: _ _ _ _ _ _ _ _ _ _ _ _ __

CITY OF PORT ARTHUR TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November _ _ , 2006 Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ _ _ __

ENTERGY GULF STATES, INC.

Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ _ __

Docket No. 32907
Settlement Agreement
Page 9of10
I(
NOV-17-2006 FRI 09:43 AM FAX NO. P. 03

sTAFF OF nm: CITIES OF BEAUMONT, CONROE, GROVES,
NEDERLAND, PINE fOREST, PORT NECHES,
PUBLIC UTILITY COMMlSSION OF TEXAS
ROSf:: CliY, AND SILSSEE

Date of Execution: November~-· 2006. Date of Execution: November_, 2006

By:________._ _ _ _ __ By; ______________

OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS,
OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November_, 2006 Date of Execution: November_. 2006

By: _ _ _ _ _ _ _ _ _ _ ~

By:_ _ _~

Cl'TY OF PORT ARTHUR TEXAS INDUSTRIAL ENERGV CONSUMERS

Date of Execution: November J!]_, 2006 Date of Execution: November
- , 2006

By:~ ....;;.••: ... ,;.... B y : _ N_ _

ENTERGY GULF STATES, INC.

Date of Execution: November , 2006

By: ___ w·---------

Docket No. 32907
Settlement Agreement
Page 9of10
STAFF OF THE CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS NEDERLAND, PINE FOREST, PORT NECHES,
ROSE CITY, AND SILSBEE

Date of Execution: November _ _ , 2006. Date of Execution: November n. 2006

By: _ _ _ _ _ _ _ _ _ _ _ __ By:U{~
OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS,
OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November _ _ , 2006 Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ _ __

CITY OF PORT ARTHUR TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November _ _, 2006 Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ _ __

ENTERGY GULF STATES, INC.

Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ _ __

Docket No. 32907
Settlement Agreement
Page 9of10
13
11/14/2006 22:08 512-322-9114 PAR/ATTV.GEN.OFC. PAGE 02/02

STAFF PF THE CITIES OF BEAUMONT, CONROE,.GROVES,
PUBLIC UTILITY COMMISSION Of TEXAS NEDERLAND, PINE FOREST, PORT NECHES,
ROSE CITY, AND SILSBE:E

Date of Execution: November_, 2006. Date of Execution: November_, 2006

By: By:._ _ _ _ _ _ _ _ _ _ __

OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS,
OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November._, 2006 Date of Execution: November J.1_, 2006

By: By:t.W~ffi~
;O }~ .
CITY OF PORT ARTHUR TEXAS INDUSl'RIAL ENERGY CONSUMERS

Date of Execution: November____.:_, 2006 Date of Execution: November_. 2006

ENTERGY GULF'. STATES, INC.

Date of Execution: November_. 2006

By:_ _ _ _ _ _ _ _ _ _ _ __

Docket No. 32907
Settlement Agreement
Page 9of10·

If
11-17-06 09:18am From-ANOREWSKURTH +5123209292 T-186 P.002/002 F-418

STAFF OF THE CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS NEDERLAND, PINE FOREST, PORT NECHES,
ROSE CITY, AND SILSBEE

Date of Execution: November __ , 2006. Date of Execution: November __ , 2006

By:_ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ __

OFFICE OF PUBLIC UTILITY COUNSEL STATe OF TEXAS,
OFFICE OF THE ATTORNEY GeN5RAL

Date of Execution: November __ , 2006 Date of Execution: November __ , 2006

By: By: _ _ _ _ _ _ _ _ _ _ _ __
-------------
CITY OF PORT ARTHUR TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November __ , 2006 Date of Execution: November I(t' , 2006

By:-----------~-

ENTERGY GULF STATES, INC.

Date of Execution: November~-· 2006

By:
-------------

Docket No. 32907
Settlement Agreement
Page 9of10
STAFF OF THE CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS NEDERLAND, PINE FOREST, PORT NECHES,
ROSE CITY, AND SILSBEE

Date of Execution: November __ , 2006. Date of Execution: November _ _ , 2006

By:. _ _ _ _ _ _ _ _ _ _ _ __ By:. _ _ _ _ _ _ _ _ _ _ _ __

OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS,
OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November __ , 2006 Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ _ __

CITY OF PORT ARTHUR TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November __ , 2006 Date of Execution: November _ _ , 2006

By: _ _ _ _ _ _ _ _ _ _ _ __ By: _ _ _ _ _ _ _ _ _ _ _ __

Docket No. 32907
Settlement Agreement
Ib Page 9of10
Entergy Gulf States, Inc. Docket No. 32907
Rita Stonn Restoration Costs for TX Settlement Agreement
Estimate of Carrying Cost for TX Retail Exhibit A
For Costs Incurred September 2006 - March 2006 Page 1of1
(Amounts in Dollars)

TX Retail Carrying Cost

Beginning Adjusted Cost Estimated
Month of TX Retail Accrual Including Balance for Settlement Insurance
Carrying Cost Cost Adjustment Settlement Carrying Cost Carrying Costs Adjustments Payments
Sep OS 1,SS2,666 1,S04,S92 1,504,592 (48,093)
Oct OS 66,174,646 (47S,471) 63,649,6S1 219,419 65,373,662 (2,049,724)
Nov OS 82,799,332 147,669 80,382,344 694,968 146,450,974 (2,564,6S7)
Decos S8,S98,197 (361,211) S6,421,944 1,149,8S8 204,022,776 (1,815,042)
Jan 06 34,649,048 626,801 34,202,617 1,455,734 239,681,126 (1,073,232)
Feb 06 5S,318,008 (134,812) 53,469,7S5 1,7S3,90S 294,904,786 (1,713,440)
Mar06 88,324,964 (3S,S44,631) S0,044,S23 2,106,186 347,055,496 (2,735,810)
Apr-06 25,086,733 25,066,733 2,367,359 374,509,588
May-06 10,6S4,922 10,654,922 2,500,594 367 ,665, 104
Jun-06 2,5S2,129 390,217 ,232
Jul-06 2,568,930 392,786,162
Aug-06 2,585,842 383,228,245 (12, 143,760)
Sep-06 2,S22,919 365,751,164
Oct-06 2,539,528 388,290,692
Nov-06 2,556,247 390,846,940
Dec-06 2,S73,076 393,420,015
Jan-07 2,590,015 396,010,030
Feb-07 2,607,066 398,617,096
Mar-07 2,624,229 401,241,326
Apr-07 2,641,505 403,882,831
May-07 2,658,89S 406,541, 726
Sub-Totals 387,417,080 37S,417,080 43,268,406 (12,000,000) (12, 143,760)

LessAFUDC
Sep OS - Mar 06 (5,819,304)

Total Carrying Costs 37,449,102

Summary

TX Retail Costs Above 375,417,080
A FU DC 5,819,304
Total TX Retail Costs Per Exh JDW-2 Less Setl. Adj. 381,236,384

Total Carrying Costs 37,449,102

Total to Recover Assuming a June 1 Securitization 418,686,486
(Carrying costs to be calculated until issuance of bonds)

Ins. to Remove tor Securitization (TX Retail Amt.) 65,700,000

Total to Securitize Assuming a June 1 Securitization 352,985,486

Notes:
TX Retail Cost excludes AFUDC.
Accruals Adjustment subtracts costs that are accrued but not yet paid. Accruals are assumed to be paid in full by May 2006.
Carrying Cost= (Current Month Adjusted Cost* 1/2 Month + Prior Month Balance to Recover) • Carrying Cost
Hurricane Rita tax benefits have not been realized as the Company is in a net operating loss carryforward position.
Amounts may not sum to totals due to rounding.
Plus all other qualified costs provided for in Section 39.460(d) of PURA.

Carrying Cost 7.90%

/7 Page 10 of 10
 PUC DOCKET NO. 32907

APPLICATION OF ENTERGY GULF § PUBLIC UTILITY COMMISSION
STATES, INC. FOR §
DETERMINATION OF HURRICANE § OF TEXAS
RECONSTRUCTION COSTS §

PROPOSED ORDER

This Order approves the application of Entergy Gulf States, Inc. (EGSI), as modified
through an unopposed Settlement Agreement (Agreement) filed in this docket on November
17, 2006. EGSI, the Public Utility Commission of Texas's Staff (Commission Staff), the Cities
of Beaumont, Conroe, Groves, Pine Forest, Nederland, Port Neches, Rose City and Silsbee
(collectively, Cities), the City of Port Arthur (Port Arthur), the Office of Public Utility Counsel
(OPC), Texas Industrial Energy Consumers (TIEC), and the State of Texas (State) (collectively,
Signatories) support the Agreement and request that the Public Utility Commission of Texas
(Commission) approve the Agreement without modification. The East Texas Cooperatives
1
(ETC) state that they neither oppose nor support the Agreement and that they do not request an
evidentiary hearing in this docket. This docket was processed in accordance with applicable
statutes and Commission rules. EGSI' s application, consistent with the Agreement, is approved.

The Commission adopts the following findings of fact and conclusions of law:

I. Findings of Fact

Procedural History
1. On July 5, 2006, EGSI filed an application, under §§ 39.458-.463 of the Public Utility
Regulatory Act, 2 for: (1) a determination that the Hurricane Rita reconstruction costs in
the amount of $393,236,384 (Texas retail jurisdictional amount), incurred through March
31, 2006, are eligible for recovery and securitization; (2) authority to recover carrying
costs at EGSI's weighted average cost of capital on those hurricane reconstruction costs
from the date the costs were incurred through the date that transition bonds are issued
under a financing order issued in a future docket in which EGSI requests a financing

1
East Texas Electric Cooperative, Inc., Tex-La Electric Cooperative of Texas, Inc., and Sam Rayburn
G&T Electric Cooperative, Inc., collectively the East Texas Cooperatives (ETC).
2
Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-66.017 (Vernon 1998 & Supp. 2006)
(PURA).
/8
PUC DOCKET NO. 32907
PROPOSED ORDER PAGE2

order (financing order proceeding); and (3) approval of the manner in which the
hurricane reconstruction costs will be functionalized and the associated revenue
requirement allocated in the financing order proceeding.

2. EGSI's July 5, 2006 application included the prefiled direct testimony, exhibits, and
workpapers of eleven witnesses in support of EGSI' s request.

3. EGSI's witnesses, as a whole, provide testimony that EGSI contends supports EGSI's
requests.

4. On July 7, 2006, the Commission issued Order No. 1, which provided for a protective
order applicable to this docket and required comment on the proposed notice.

5. On July 28, 2006, the Commission issued Order Requesting List of Issues, which
requested that parties file lists of issues that may be addressed in this docket.

6. On July 31, 2006, the Commission issued Order No. 6, which, among other things,
established a procedural schedule applicable to this docket, including dates for parties to
file testimony, discovery deadlines, and a November 1, 2006 commencement date for the
hearing on the merits.

7. The intervention deadline established for this docket was August 31, 2006.

8. On or before August 31, 2006, the following parties filed unopposed motions to
intervene, and their motions were granted by the Commission: OPC; Cities; TIEC; State;
ETC; and Port Arthur.

9. On September 1, 2006, EGSI filed its proof of notice.

10. On September 8, 2006, the Commission issued its Preliminary Order in this docket.

11. Discovery on EGSI's direct case concluded on September 19, 2006.
PUC DOCKET NO. 32907
PROPOSED ORDER PAGE3

12. On October 9, 2006, all intervenors, except ETC, filed testimony and supporting
documents addressing EGSI's application and direct testimony, and State and Port Arthur
also filed statements of position.

13. All intervenors that filed testimony recommended various adjustments to the Hurricane
Rita reconstruction costs and proposed carrying costs, or to the proposed
functionalization and allocation, requested by EGSI.

14. On October 12, 2006, State and TIEC filed cross-rebuttal testimony.

15. On October 16, 2006, Commission Staff filed its testimony, which, among other things,
recommended a lower carrying cost rate than EGSI had requested, and also filed a
statement of position.

16. On October 17, 2006, the Commission issued Order No. 9, which, among other things,
directed parties not prefiling direct testimony but wishing to participate in the hearing on
the merits to file a statement of position no later than October 24, 2006.

17. On October 23, 2006, EGSI filed rebuttal testimony and a statement of position.

18. On October 27, 2006, the Commission issued Order No. 12, which ruled on EGSI's
objections and motion to strike various portions of the pre-filed testimony and supporting
documents filed by the intervenors.

19. At a prehearing conference convened on October 30, 2006, the Commission admitted into
evidence: (a) all of the parties' pre-filed testimony and supporting documents, except as
modified or stuck by Order No. 12 and the parties' errata to their pre-filed evidence; (b)
the parties' cross-examination exhibits; and (c) the parties' optional completeness
exhibits. The Commission took under advisement the admissibility of several proffered
exhibits pending its review of motions filed in response to Order No. 12. In addition,
under Order No. 9, the parties were to convene on November 1, 2006, before the start of
PUC DOCKET NO. 32907
PROPOSED ORDER PAGE4

the hearing on the merits, for a continuation of the prehearing conference to address any
remaining exhibit items.

20. On October 30, 2006, after the prehearing conference was concluded, the Commission
issued Order No. 13, which ruled on State's and EGSI's motions filed in response to
Order No. 12, clarified which portions of pre-filed testimony and supporting documents
were modified or struck by Order No. 12, and admitted additional cross-examination
exhibits.

21. On November 1, 2006, at the prehearing conference convened before the start of the
hearing on the merits, the parties present requested a delay in the start of the hearing on
the merits to enable them to continue settlement talks. The Commission granted the
request.

22. Later in the morning of November 1, 2006, the parties present announced that they had
reached a settlement on all issues, stated that there was no need to conduct a hearing on
the merits, and requested the opportunity to prepare a settlement agreement to file with
the Commission. The Commission granted the request.

23. On November 17, 2006, EGSI filed the Agreement, which resolves all issues in this
docket, on behalf of itself, Commission Staff, and all active parties. The filing stated on
behalf of ETC that ETC neither supports nor objects to the Agreement.

The Agreement
24. Under the Agreement, the amount of EGSI' s reasonable and necessary hurricane
reconstruction costs incurred through March 31, 2006 that is eligible for recovery and
securitization is $381,236,384 plus carrying costs, as set forth in findings of fact 26
through 35.

25. The Agreement does not reflect or determine resolution of any hurricane reconstruction
costs that were charged to EGSI's books after March 31, 2006.
PUC DOCKET NO. 32907
PROPOSED ORDER PAGES

26. In addition to $381,236,384, the Agreement authorizes EGSI to include in hurricane
reconstruction costs and securitize carrying costs at the rate of 7.9% per annum as
reflected in Attachment A to this Order, 3 from the later of October 15, 2005 or the date
incurred until the issuance of securitization bonds. The balance upon which carrying
costs are determined will be reduced by the amount of insurance payments when received
as provided in findings of fact 27 through 30.

27. The Agreement directs EGSI to credit $65.7 million in the manner described in finding of
fact 35, reflecting EGSI's expectation that it will receive insurance payments in that
amount (Texas Retail).

28. Under the Agreement, carrying costs at the rate referenced in finding of fact 26 shall
apply to: (1) any portion of the $65.7 million referenced in finding of fact 27 not actually
received by EGSI, until EGSI actually receives (Texas Retail) such payments; and (2) the
trued-up amount, as provided in finding of fact 29, until such trued-up amount (plus
associated carrying costs at the rate of 7.9% per annum) is recovered in base rates.

29. The Agreement provides that after EGSI receives all insurance payments related to
Hurricane Rita, the $65.7 million credited, as provided in finding of fact 27, shall be
trued up to reflect the difference between the $65.7 million credited and all insurance
payments actually received by EGSI related to Hurricane Rita for Texas Retail.

30. Under the Agreement, in the event EGSI receives insurance payments related to
Hurricane Rita for Texas Retail in excess of $65.7 million after the Commission's
issuance of a financing order in the financing order proceeding, such payments shall be
passed through to ratepayers in the form of a rider with carrying costs calculated on the
unamortized balance of such payments at the rate of 7 .9% per annum.

31. The Agreement directs EGSI to continue to pursue EGSI' s application for proceeds from
governmental grants.

3
Attachment A is a copy of Exhibit A to the Agreement. .
2~
PUC DOCKET NO. 32907
PROPOSED ORDER PAGE6

32. With regard to the treatment of grant proceeds distributed prior to securitization, the
Agreement provides as follows:

A. Any proceeds from governmental grants distributed directly to EGSI before the
Commission issues a financing order shall be administered in a manner consistent
with the conditions and directions of the grant, and, if consistent with the
conditions and directions of the grant, shall be used to reduce the amount
securitized. For illustrative purposes with respect to the preceding sentence, a
reduction in the securitized amount is not considered consistent with the
conditions and directions of the grant when, based on the cost allocation provided
in the Agreement, such a reduction in the amount securitized would result in rates
(transition charges) that would allocate the credit or reduction associated with the
grant proceeds among customers or customer classes in a manner inconsistent
with the conditions and instructions of the grant.

B. If a reduction of the securitized amount is not consistent with the conditions and
directions of the grant as described in finding of fact 32, item A, and the grant
does not prescribe carrying costs on the grant proceeds (either explicitly or
implicitly, e.g., by instructing that the proceeds be escrowed or treated similarly),
EGSI will reduce the securitized amount by the amount of carrying costs on the
grant proceeds, calculated at 7 .9 % per annum from EGSI' s actual receipt of grant
proceeds until the issuance of securitization bonds.

33. The Agreement provides that any proceeds from governmental grants distributed directly
to EGSI after the Commission's issuance of a financing order shall be administered in a
manner consistent with the conditions and directions of the grant, and, if consistent with
the conditions and directions of the grant, shall be passed through to ratepayers in the
form of a rider with carrying costs calculated on the unamortized balance of such
proceeds at the rate of7.9% per annum.

34. In regard to the receipt of governmental grant proceeds as described in findings of fact 32
and 33, the Agreement further provides that, in any event, any reduction in rates
PUC DOCKET NO. 32907
PROPOSED ORDER PAGE7

associated with the receipt of governmental grant proceeds shall be no greater than the
amount of such proceeds, subject to the calculation of carrying costs provided in findings
of fact 32 and 33.

35. Under the Agreement, the total dollar amount eligible to be securitized in the financing
order proceeding (as reflected in Attachment A to this Order) shall be: $381,236,384 plus
carrying costs at the rate and for the time period specified in findings of fact 26 through
30, minus $65.7 million related to insurance, plus all other qualified costs, to be
determined by the Commission in the financing order proceeding, provided for in PURA
§ 39.460(d).

36. The Agreement provides that the present value of the benefit, if any, of accumulated
deferred federal income taxes and method of handling such benefit will be part ofEGSI's
presentation in the financing order proceeding and subject to the Commission's
determination about how such benefit, if any, should be treated in the financing order or a
subsequent proceeding.

37. Under the Agreement: (a) the functionalization and allocation methodology proposed by
EGSI in its filed case shall be utilized in the financing order proceeding; and (b)
adjustments described in findings of fact 24 through 36 shall be functionalized and
allocated pro rata in the same manner as proposed by EGSI in its filed case.

38. The Agreement includes standard prov1s10ns regarding waiver, general terms and
conditions, lack of precedential effect, and termination of the Agreement in the event the
Commission does not accept the Agreement as presented.

39. The Agreement resolves all issues of fact and law applicable to this docket.

40. Approval of the Agreement is in the public interest.
PUC DOCKET NO. 32907
PROPOSED ORDER PAGES

II. Conclusions of Law

1. EGSI is a public utility as that term is defined in §§ 11.004 and 31.002 of PURA.

2. The Commission has jurisdiction over this proceeding under PURA §§ 39.458-.463.

3. EGSI provided appropriate notice of this proceeding in accordance with P.U.C. PROC.
R. 22.55.

4. EGSI's application was processed in accordance with PURA §§ 39.458-.463 and the
Administrative Procedure Act, TEX. Gov'T CODE ANN. §§ 2001.001-.902 (Vernon 2000
& Supp. 2006).

5. PURA §§ 39.458-.463 allow, among other things, EGSI to obtain timely recovery of
reasonable and necessary Hurricane Rita reconstruction costs and to use securitization
financing to recover those costs.

6. The functionalization and allocation methodology proposed by EGSI in its filed case
complies with PURA§ 39.460(g).

7. The evidentiary record, which includes testimony and exhibits filed by EGSI,
Commission Staff, Cities, TIEC, OPC, and State, supports the Agreement.

8. Because the Agreement is the result of an unopposed agreement among the parties, an
adjudicatory hearing is not required to process EGSI's application in this docket.

III. Ordering Paragraphs

1. EGSI's request for a determination of the dollar amount of its Hurricane Rita
reconstruction cost, incurred through March 31, 2006, plus carrying costs, that are
eligible for recovery and securitization in the financing order proceeding, as described in
finding of fact 35 and the Agreement, is approved.
PUC DOCKET NO. 32907
PROPOSED ORDER PAGE9

2. In the financing order proceeding, the hurricane reconstruction costs shall be
functionalized and the associated revenue requirement allocated in the manner proposed
by EGSI in its case filed on July 5, 2006.

3. EGSI shall comply with the true-up provisions regarding insurance payments as set out in
findings of fact 28 through 30.

4. EGSI shall treat governmental grant proceeds in the manner set out in findings of fact 32
through 34.

5. EGSI shall continue to pursue its application for proceeds from governmental grants.

6. Entry of this Order does not indicate the Commission's endorsement or approval of any
principle or methodology that may underlie the Agreement. Neither shall the entry of the
Order be regarded as binding precedent as to the appropriateness of any principle
underlying the Agreement.

7. All other motions, requests for entry of specific findings of fact and conclusions of law,
and any other request for general or specific relief, if not expressly granted herein, are
denied.

SIGNED AT AUSTIN, TEXAS the _ _ _ _ day of _ _ _ _ _ _ _ _ 2006.

PUBLIC UTILITY COMMISSION OF TEXAS

PAUL HUDSON, CHAIRMAN

JULIE PARSLEY, COMMISSIONER

BARRY T. SMITHERMAN, COMMISSIONER
Entergy Gulf States, Inc. Docket No. 32907
Rita Storm Restoration Costs for TX Attachment A
Estimate of Carrying Cost for TX Retail Page 1of1
For Costs Incurred September 2005 - March 2006
(Amounts in Dollars)

TX Retall Carrying Cost

Beginning Adjusted Cost Estimated
Month of TX Retail Accrual Including Balance for Settlement Insurance
Carrying Cost Cost Adjustment Settlement Carrying Cost Carrying Costs Adjustments Payments
Sep OS 1,552,686 1,504,592 1,504,592 (48,093)
Oct OS 66,174,846 (475,471) 63,649,651 219,419 65,373,662 (2,049,724)
Nov OS 82,799,332 147,669 80,382,344 694,968 146,450,974 (2,564,657)
Decos 58,598,197 (361,211) 56,421,944 1,149,858 204,022,776 (1,815,042)
Jan 06 34,649,048 626,801 34,202,617 1,455,734 239,681,126 (1,073,232)
Feb 06 55,318,008 (134,812) 53,469,755 1,753,905 294,904,786 (1,713,440)
Mar06 88,324,964 (35,544,631) 50,044,523 2, 106, 186 347,055,496 (2,735,810)
Apr-06 25,086,733 25,086,733 2,367,359 374,509,588
May-06 10,654,922 10,654,922 2,500,594 387,665, 104
Jun-06 2,552,129 390,217,232
Jul-06 2,568,930 392,786, 162
Aug-06 2,585,842 383,228,245 (12, 143,760)
Sep-06 2,522,919 385,751,164
Oct-06 2,539,528 388,290,692
Nov-06 2,556,247 390,846,940
Oec-06 2,573,076 393,420,015
Jan-07 2,590,015 396,010,030
Feb-07 2,607,066 398,617,096
Mar-07 2,624,229 401,241,326
Apr-07 2,641,505 403,882,831
May-07 2,658,895 406,541,726
Sub-Totals 387,417,080 375,417,080 43,268,406 (12,000,000) (12, 143,760)

LessAFUOC
Sep 05 - Mar 06 (5,819,304)

Total Carrying Costs 37,449,102

Summary

TX Retail Costs Above 375,417,080
AFUOC 5,819,304
Total TX Retail Costs Per Exh JDW-2 Less Seti. Adj. 381,236,384

Total Carrying Costs 37,449,102

Total to Recover Assuming a June 1 Securitization 418,685,486
(Carrying costs to be calculated until issuance of bonds)

Ins. to Remove for Securitization (TX Retail Amt.) 65,700,000

Total to Securitize Assuming a June 1 Securitization 352,985,486

Notes:
TX Retail Cost excludes AFUDC.
Accruals Adjustment subtracts costs that are accrued but not yet paid. Accruals are assumed to be paid in full by May 2006.
Carrying Cost= (Current Month Adjusted Cost• 1/2 Month + Prior Month Balance to Recover)• Carrying Cost
Hurricane Rita tax benefits have not been realized as the Company is in a net operating loss carryforward position.
Amounts may not sum to totals due to rounding.
Plus all other qualified costs provided for in Section 39.460(d) of PURA.

Carrying Cost 7.90%
 PUC DOCKET NO. 34800
SOAH DOCKET NO. XXX-XX-XXXX

APPLICATION OF ENTERGY §
GULF ST ATES, INC. FOR §
AUTHORITY TO CHANGE RATES §
AND TO RECONCILE FUEL §
COSTS §

ORDER

1
This order addresses the application of Entergy Gulf States, Inc. (EGSI) for
authority to change rates and reconcile fuel costs. The docket was processed in accordance
with applicable statutes and Public Utility Commission of Texas rules. EGSI,
Commission Staff, the Office of Public Utility Counsel (OPC), the Community
Associations of the Woodlands (CATW), the Entergy Texas, Inc. Service Area Cities'
Steering Committee (Cities), the State of Texas, Texas Industrial Energy Consumers
(TIEC), Texas Legal Services Center (TLSC), Texas Ratepayers' Organization to Save
Energy (Texas ROSE), Wal-Mart Stores Texas, LLC , through their duly authorized
representatives (Wal-Mart) (collectively, signatories) filed a stipulation and settlement
agreement that resolves all of the issues in this proceeding. The Kroger Company and TX
Energy, LLC did not sign the stipulation and do not oppose it. Consistent with the
stipulation, EGSI's application is approved.

The Commission adopts the following findings of fact and conclusions of law:

I. Findings of Fact

Procedural History

1. On September 26, 2007, EGSI filed an application for approval of: ( 1) base rate
tariffs and riders designed to collect a total non-fuel revenue requirement for the

1
On December 31, 2007, EGSI jurisdictionally separated pursuant to * 39.452( e) of the Public Utility
Regulatory Act (PURA), TEX. UTIL. CODE ANN. Title 2 and Entergy Texas, Inc. (ETI) succeeded to EGSI's certificate of
PUC Docket No. 34800 Order Page 2of15
SOAH Docket No. XXX-XX-XXXX

Texas retail jurisdiction of $605 million; (2) a set of proposed tariff schedules
presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP)
accompanying EGSI's application; (3) a request for final reconciliation of EGSI's
fuel and purchased power costs for the reconciliation period from January 1, 2006
to March 31, 2007, as well as deferred costs from prior proceedings; and (4) certain
waivers to the instructions in RFP Schedule V accompanying EGSI's application.

2. The 12-month test year used in EGSI's application ended on March 31, 2007.

3. EGSI provided notice by publication for four consecutive weeks before the
effective date of the proposed rate change in newspapers having general circulation
in each county of EGSI's Texas service territory. EGSI also mailed notice of its
proposed rate change to all of its customers. Additionally, EGSI timely served
notice of its statement of intent to change rates on all municipalities retaining
original jurisdiction over its rates and services.

4. The following parties were granted intervenor status in this docket: OPC, Alliance
for Retail Markets (ARM), CATW, Cities, Kroger Company, State, TIEC, TLSC,
Texas ROSE, TX Energy, LLC, and Wal-Mart.2 Commission Staff was also a
participant in this docket.

5. On October 1, 2007, the Commission referred this case to the State Office of
Administrative Hearings (SOAH) for processing.

6. EGSI appealed the rate decisions adopted by the Cities of Chester, Woodville,
Ames, Dayton, Devers, Liberty, New Waverly, Riverside, Trinity, Bedias,
Bremond, Caldwell, Calvert, Franklin, Madisonville, Somerville, Patton Village,
Cut and Shoot, Willis, Plum Grove, Shepherd, Oak Ridge North, Normangee,
Daisetta, Hardin, Corrigan, Groveton, Anderson, Kosse, North Cleveland,
Woodloch, Midway, Panorama Village, Taylor Landing, Rose Hill Acres, China,
Hearne, Bevil Oaks, Colmesneil, Kountz, Nome, Lumberton, and Todd Mission.

convenience and necessity for its Texas retail jurisdiction. For continuity and ease of reference, EGSI, Commission
Staff, and intervenors have continued to make reference to EGSI for purposes of pleadings in this docket.
2
OPC, ARM, Cities, Kroger Company, State, and TIEC were granted party status on October 22, 2007. See
Prehearing Conference Tr. at 6.
PUC Docket No. 34800 Order Page 3of15
SOAH Docket No. XXX-XX-XXXX

7. As provided for in Order Nos. 3, 9, 12, 14, and 23, the SOAH administrative law
judges (ALJs) consolidated EGSI's appeals of the rate decisions adopted by the
cities in Finding of Fact No. 6.

8. Cities participated in this case representing the Cities of Beaumont, Bridge City,
Conroe, Groves, Houston, Huntsville, Navasota, Nederland, Orange, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake,
Vidor, and West Orange. These municipalities have adopted rates consistent with
the stipulation discussed below.

9. The Commission established in its Order on Appeal of Order No. 8 an effective
date for EGSI's proposed rate change of September 26, 2008.

10. On April 8, 2008, the State filed a motion for partial summary decision regarding
the continued applicability of the 20% base rate discount for state institutions of
higher education under § 36.351 of the Public Utility Regulatory Act, TEX. UTIL.
CODE ANN.§§ 11.001-66.016 (Vernon 2007 & Supp. 2008) (PURA).

11. On July 16, 2008, the SOAH ALJs issued a proposal for decision (PFD)
recommending that the Commission grant the State's April 18, 2008 motion for
partial summary decision.

12. On August 15, 2008, the Commission entered an order adopting the PFD on the
State's motion for partial summary decision.

13. The Commission entered an order on November 4, 2008, extending the effective
date ofEGSI's proposed rate change until November 27, 2008.

14. Commission Staff, State, and TIEC filed a non-unanimous stipulation (NUS) on
May 19, 2008. EGSI and certain other parties filed a separate NUS on May 20,
2008. 3 The EGSI NUS was opposed by Commission Staff, State, and TIEC. A
hearing was held on both NUSs on June 23 through July 2, 2008.

15. At Open Meetings on October 23 and November 5, 2008, the Commission
considered a PFD from the SOAH ALJ s which recommended resolution of the rate
PUC Docket No. 34800 Order Page 4of15
SOAH Docket No. XXX-XX-XXXX

case through adoption of the EGSI NUS. On November 7, 2008, the Commission
issued its order on remand rejecting the PFD and remanding the docket to SOAH
for a hearing on the merits of EGSI's original application.

16. During the November 5, 2008 Open Meeting, EGSI agreed to extend the statutory
jurisdictional deadline in this docket to March 2, 2009. EGSI subsequently agreed
to extend the statutory jurisdictional deadline to March 16, 2009. 4

17. The SOAH ALJs granted ARM's motion to withdraw as an intervenor on
December 2, 2008, pursuant to Order No. 49.

18. The hearing on the merits on remand took place on December 3 and 4, 2008, and
December 8 through December 12, 2008. The hearing was recessed on
December 12, 2008, in order to allow the parties to work on concluding a
settlement.

19. On December 16, 2008, the signatories submitted a settlement term sheet to reflect
their agreement in principle resolving all outstanding issues regarding EGSI's
application, including those issues raised by the Commission in its November 7,
2008 order on remand.

20. On December 16, 2008, the signatories submitted an agreed motion to implement
interim rates.

21. On December 19, 2008, the SOAH ALJs filed Order No. 52, granting interim
approval of rates consistent with the settlement term sheet, effective with bills
rendered on and after January 28, 2009, for usage on and after December 19, 2008.

22. On February 5, 2009, the signatories submitted a stipulation resolving all
outstanding issues in this docket.

23. On February 10, 2009, the SOAH ALJs filed Order No. 56, returning this docket to
the Commission.

3
The EGSI NUS was subsequently amended on June 27, 2008.
4
EGSI letter filed February 18, 2009.
PUC Docket No. 34800 Order Page 5of15
SOAH Docket No. XXX-XX-XXXX

Description of the Stipulation and Settlement Agreement

24. The signatories agree that EGSI will institute an overall mcrease in base rate
revenues of $46. 7 million.

25. The signatories agree to a reasonable return on equity for EGSI of 10.00%.

26. The signatories agree that the cost of service underlying the base-rate revenue
increase does not include any unreasonable or unjust expenses.

27. The signatories agree that EGSI will implement a rate-case-expense rider to recover
$2.3 million per year for three years. The rate-case expenses will be allocated to
customer classes based on total base-rate revenues. The rates established under the
rate-case expense rider will be determined based on energy consumption in
kilowatt-hours (kWh), except for the Large Industrial Power Service (LIPS)
customer class, whose rates will be set on a kilowatt (kW) basis.

28. The Signatories agree to leave the mechanisms for recovery of EGSI's municipal
franchise-fee riders unchanged as a result of this docket.

29. The Signatories agree that EGSl's proposed Market Value Energy Rider (MYER)
will not be offered as a result of this docket.

30. The signatories agree that the Incremental Purchased Capacity Recovery Rider
(IPCR) will expire contemporaneously with the implementation of rates approved
in Order No. 52.

31. The signatories agree that the base-rate revenue increase, the rate-case expense
rider and the municipal franchise-fee riders addressed in the stipulation became
effective for bills rendered on and after January 28, 2009 for usage on and after
December 19, 2008, as approved in Order No. 52.

32. The signatories reached the following specific agreements regarding rate design as
a part of the overall resolution of this docket:

a. Supplemental Short Term Service (SSTS). Rate Schedule SSTS will
terminate six months after a final, appealable order approving the
stipulation is issued by the Commission in this docket. Beginning with the
PUC Docket No. 34800 Order Page 6of15
SOAH Docket No. XXX-XX-XXXX

base rates implemented as a result of this stipulation, EGSI will bill SSTS
usage as follows: (SSTS charges+ LIPS charges)/2.

b. Interruptible Service (IS). Rate Schedule IS will be modified as follows:

1. 30-minute notice service is eliminated;

ii. The credit for 5-minute notice service 1s reduced to $3.75/kW-
month;

111. The credit for no-notice service is reduced to $4.88/kW-month;

1v. The credits shall be applied to the· LIPS and LIPS-Time of Use
(TOU) tariffs (current High Load Factor Service (HLFS) and Large Power
Service (LPS) customers will be transferred to LIPS); and

v. Rate Schedule IS remains closed to new business.

c. Competitive Generation Service. EGSI's competitive generation-service
proposal shall not be withdrawn, but shall be severed from this docket and
addr('<::<::ed in a separate docket wherein the Commission will (a) exercise its
authority to approve, reject, or modify EGSI's proposal; and (b) address
reCOV' • any costs unrecovered as a result of the implementation of the

,J
\.J ~ 'neons Electric Service Charges. No change shall be made to
Miscellaneous Electric Service Charges.

e. Lighting Class Rates. Lighting-class rates for all lighting fixtures shall be
designed in a manner so that each fixture is charged a uniform base-rate
percentage increase as established for the entire lighting class.

f. Additional Facilities Charge (AFC). Rate Schedule AFC, governing
additional-facilities charge, will be designed to result in a reduction to
1.49%, with the resulting revenue reduction allocated among those
customer classes with AFC revenue based on the percentage of AFC
revenues in each customer class.
PUC Docket No. 34800 Order Page 7of15
SOAH Docket No. XXX-XX-XXXX

g. Economic as Available Power Service/Standby Maintenance Service.
No substantive changes shall be made as a result of this docket to: (a) Rate
Schedule EAPS, governing Economic-as-Available Power Service; or (b)
Rate Schedule SMS, governing Standby Maintenance Service.

h. Interconnection Terms and Conditions. No changes shall be made as a
result of this docket to EGSI's terms and conditions regarding costs for
interconnection of customers.

L Electric Extension Policy. No changes shall be made as a result of this
docket to EGSI's electric extension policy.

J. Large Interruptible Power Service. The signatories stipulate that the
contract demand ratchet provisions in Rate Schedule LIPS will be retained;
provided, however, that the billing demand provision contained in
Paragraph V of Rate Schedule SSTS will no longer apply to customers
taking service under Rate Schedule LIPS after Rate Schedule SSTS
terminates.

33. The signatories agree to the class-cost allocation set forth in Attachment A to the
stipulation and further agree that this allocation is reasonable.

34. The signatories agree to a River Bend nuclear generating station 20-year life
extension adjustment to EGSI's calculation of nuclear depreciation and
decommissioning costs effective January 1, 2009.

35. The signatories agree that EGSI will reduce depreciation expense related to EGSI's
steam production plants by the amount of $2,731,478 on a total Texas retail basis
effective January 1, 2009.

36. The signatories agree that EGSI will present a new depreciation study as part of its
next base-rate case, or by January 5, 2010, whichever is earlier.

37. The signatories agree that the base-rate increase, rate riders, and associated rate
design and class-cost allocation agreed to in the stipulation are reasonable and are
PUC Docket No. 34800 Order Page 8of15
SOAH Docket No. XXX-XX-XXXX

reflected in the rate schedules approved by Order No. 52 and revised by errata
filings on December 22, 2008, January 27, 2009, and March 5, 2009.

38. The signatories agree that EGSI will fund its Public Benefit Fund at an annualized
amount of $2 million.

39. In order to include a greater portion of the eligible population in the Public Benefit
Fund program, EGSI agrees to use its best efforts to contract for and implement an
automatic enrollment program. EGSI's automatic enrollment program will be
modeled upon the matching procedures used by other Texas utilities to identify
eligible customers and will be implemented within 30 days of the Commission's
filing of the final order in this case.

40. The signatories agree that EGSI will amend its low-income energy-efficiency
program on a trial basis as specified in the stipulation.

41. The signatories agree that the amendment of EGSI' s low-income energy-efficiency
program does not increase base rates to recover uncollected expenses associated
with revenues billed under EGSI's energy-efficiency rider approved in Docket
No. 35626.5

42. The signatories agree to a fuel disallowance of $4.5 million, booked in the month
of a final Commission order approving the application, consistent with the
stipulation.

43. The signatories agree to adopt Commission Staffs position on the following
resolution of fuel-related matters set out in Commission Staffs pre-filed direct
testimony: (a) recovery of sulfur dioxide (S02) and nitrous oxide (NOx) emissions
revenues recorded in Account 411.8 and expenses recorded in Account 509 will be
allowed as eligible fuel expense going forward until further order of the
.
Commission realigning such costs; (b) special circumstances should be granted to
treat the costs of natural-gas call options incurred during the reconciliation period

5
Application of Entergy Texas, Inc. for Approval of an Energy Efficiency Cost Recovery Factor
(EECRF) Pursuant to PURA§ 39.905(b) and P.UC. Subst. R. 25.181(/), Docket No. 35626, Order (Aug. 14,
2008).
PUC Docket No. 34800 Order Page 9of15
SOAH Docket No. XXX-XX-XXXX

as eligible fuel expense; (c) good cause exists to sever and defer the River Bend
performance-based ratemaking (PBR) calculation for the final seven months of the
reconciliation period to EGSI's next fuel reconciliation proceeding; and (d) the
River Bend PBR plan should terminate in light of EGSI's jurisdictional separation.

Evidence Supporting the Stipulation and Agreement

44. Considered in light of (a) the pre-filed testimony by the parties entered into
evidence, and (b) the additional evidence and testimony presented by the parties
during the course of the hearing on the merits on EGSI's application, the stipulation
is the result of compromise from each party, and these efforts, as well as the overall
result of the stipulation viewed in light of the record evidence as a whole, support
the reasonableness and benefits of the terms of the stipulation.

45. The evidence addressed in finding of fact 44 demonstrates that the rates, terms, and
conditions resulting from the stipulation are just and reasonable and consistent with
the public interest when the merits of the issues contested by Commission Staff and
intervenors are considered.

46. The stipulated revenue requirement does not include any amounts for financial-
based incentive compensation.

47. To the extent that affiliate costs are included in the stipulated revenue requirement
and fuel expense, they are reasonable and necessary for each class of affiliate costs
presented in EGSI' s application.

48. To the extent that affiliate costs are included in the stipulated revenue requirement
and fuel expense, the price charged to EGSI is not higher than the prices charged by
the supplying affiliate for the same item or class of items to its other affiliates or
divisions, or a non-affiliated person within the same market area or having the
same market conditions.

49. The Texas retail revenue requirement in the stipulation does not include any of the
following expenses, whether allocated or direct-billed to EGSI: legislative
advocacy expenses; entertainment; charitable contributions; advertising expense to
promote the increased consumption of electricity or to promote the image of the
PUC Docket No. 34800 Order Page 10of15
SOAH Docket No. XXX-XX-XXXX

electric utility industry; advertising products marketed by other affiliates; civil
penalties or fines; any other expenses listed in PURA §§ 36.061, 36.062, and
36.063; payments made to cover costs of an accident, equipment failure, or
negligence at a utility facility owned by a person or governmental body not selling
power inside the State of Texas (except those made under an insurance or risk-
sharing arrangement executed before the date of loss); the costs for processing a
refund or credit under PURA § 36.11 O; any profit or loss that results from the sale
of merchandise not integral to providing utility service; construction work in
progress in rate base; or plant held for future use in rate base.

50. EGSI's current supplemental short-term service, Schedule SSTS, should be
terminated within six months after the filing of a final, appealable Commission
order in this docket, as provided for in the stipulation.

51. It is reasonable to modify EGSI's current interruptible service, Schedule IS, in
accordance with the terms and conditions of the stipulation.

52. It is reasonable in light of the compromise reached in the stipulation for no
substantive modifications to be made to EGSI's economic as-available power
service, Schedule EAPS, or standby maintenance service, Schedule SMS.

53. The depreciation and decommissioning adjustments for nuclear production assets
agreed to in the stipulation and consistent with Louisiana rate treatment are
reasonable.

54. The depreciation adjustments to EGSl's steam production assets agreed to in the
stipulation are reasonable.

55. The increase in storm cost accruals provided for in the stipulation is reasonable.

56. The low-income programs provided for in the stipulation are reasonable.

57. EGSI's energy-efficiency costs are recovered through a rider approved by the
Commission in Docket No. 35626.

58. The PBR plan for the River Bend nuclear generating station contemplates an
annual calculation of penalties and rewards. Good cause exists to sever and defer
PUC Docket No. 34800 Order Page 11of15
SOAH Docket No. XXX-XX-XXXX

the PBR calculation for the final seven months of the reconciliation period to
EGSI's next fuel reconciliation proceeding.

59. It is reasonable to terminate the application of the PBR plan to the River Bend
operations on and after January 1, 2008 when Entergy Texas, Inc. no longer has an
ownership interest in River Bend.

60. EGSI is entitled to a special circumstances exception for the cost of the natural-gas
call options because they resulted in increased reliability of supply and reduced fuel
expense.

61. The class allocation methodologies described in the stipulation are reasonable.

62. The total level of invested capital in the Texas retail revenue requirement 1s
reasonable.

63. The EGSI stipulation proposes to collect the existing incremental franchise fees of
the Cities of Beaumont, Port Arthur, and Conroe as a municipal franchise-fee rider.
The Commission has reviewed its finding in paragraph ILE of its remand order of
November 7, 2008 and determines that the existing incremental franchise fees were
the result of franchise agreements adopted subsequent to the passage of PURA
§ 39.456.

II. Conclusions of Law

1. EGSI is a public utility as that term is defined in PURA § 11.004( 1) and an electric
utility as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over EGSI and jurisdiction over the
subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101,
33.002, 33.051, 36.001-36.111, 36.203, 39.452, and 39.455.

3. SOAH had jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053
and TEX. Gov'T CODE ANN. § 2003.049.
PUC Docket No. 34800 Order Page 12of15
SOAH Docket No. XXX-XX-XXXX

4. This docket was processed in accordance with the requirements of PURA and the
Texas Administrative Procedure Act. 6

5. EGSI provided notice of its application in compliance with PURA§ 36.103, P.U.C.
PROC. R. 22.5l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).

6. This docket contains no remaining contested issues of fact or law.

7. The stipulation, taken as a whole, is a just and reasonable resolution of all the
issues it addresses, results in just and reasonable rates, terms and conditions, is
supported by a preponderance of the credible evidence in the record, is consistent
with the relevant provisions of PURA, and is consistent with the public interest.

8. EGSI has properly accounted for the amount of fuel and IPCR-related revenues
collected pursuant to the fuel factor and Rider IPCR during the reconciliation
period.

9 The revenue requirement, cost allocation, revenue distribution, and rate design
implementine: the stipulation result in rates that are just and reasonable, comply
•• 1~ ratemaking provisions in PURA, and are not unreasonably discriminatory,
prcfrr :tial, t.. ..;ial.
1 ;~
\)ever'-' .•1 c'0SI's proposed competitive generation service into a separate
·ket :::iL ~it r, ',,,addressed separately is reasonable.

EGS1 ,:. ~mi 'cd to a special circumstances exception under P.U.C. SUBST. R.
25.236(a)(6) for :he cost of natural gas call options.

12. Consistent with the stipulation, good cause exists to treat EGSl's emissions
revenues and expenses referenced in finding of fact 43 as eligible fuel expense on a
going-forward basis until further order of the Commission realigning such costs.

13. Based on the evidence in this docket, the overall total invested capital through the
end of the test year meets the requirement in PURA§ 36.053(a) that electric utility
rates be based on the original cost, less depreciation, of property used by and useful
to the utility in providing service.

6
TEX. GOV'T. CODE ANN. Chapter 2001(Vernon2000 and Supp. 2007).
PUC Docket No. 34800 Order Page 13of15
SOAH Docket No. XXX-XX-XXXX

14. The Commission has reviewed its finding in paragraph ILE of its remand order of
November 7, 2008 and determines that because the existing incremental franchise
fees were the result of franchise agreements subsequent to the passage of PURA
§ 39.456, they qualify as new franchise agreements and are therefore in compliance
with PURA§ 39.456 when recovered as a municipal franchise-fee rider.

15. The final resolution of the instant docket does not impose any conditions,
obligations, or limitations on EGSI's right to file a base-rate proceeding and obtain
rate relief in accordance with PURA.

16. Consistent with the stipulation, EGSI has met its burden of proof in demonstrating
that it is entitled to the agreed upon level of Texas retail base-rate and rider
revenue.

17. Consistent with the stipulation and PURA, EGSI has met its burden of proof in
demonstrating that the rates are just and reasonable.

III. Ordering Paragraphs

In accordance with these findings of fact and conclusions of law, the Commission
issues the following orders:

1. Consistent with the stipulation, EGSI's application for authority to (a) change its
rates; (b) reconcile its fuel and purchased power costs for the Reconciliation Period
from January 1, 2006 to March 31, 2007, as well as deferred costs from prior
proceedings; and (c) for other related relief is approved.

2. Consistent with the stipulation, the rates, terms, and conditions described in this
order are approved.

3. Consistent with the stipulation, the tariffs and riders approved on an interim basis
by Order No. 52 and revised by errata on December 22, 2008, January 27, 2009,
and March 5, 2009, are approved.
PUC Docket No. 34800 Order Page 14of15
SOAH Docket No. XXX-XX-XXXX

4. Consistent with the stipulation, EGSI shall implement the low-income programs
described in this order.

5. Consistent with the stipulation, EGSI's Competitive Generation Services tariff is
severed from this docket and shall be addressed in Application of Entergy Texas,
Inc.for Approval of Competitive Generation Services Tariff, Docket No. 36713.

6. Consistent with the stipulation, EGSI's storm-cost accruals shall be increased by $2
million for a total accrual of $3.65 million annually beginning January l, 2009,
which amount will be incorporated in revenues recovered through base rates.

7. Consistent with the stipulation, EGSI shall terminate rate schedule SSTS and Rider
IPCR.

8. Consistent with the stipulation, EGSI shall adjust depreciation and
decommissioning expense related to the River Bend nuclear generating station and
depreciation expense related to EGSI's steam production assets.

9. Consistent with the stipulation, EGSI shall submit a new depreciation study.

10. Consistent with the stipulation, the Rider IPCR and fuel costs, including coal-
related costs deferred from prior proceedings are reconciled and approved through
March 31, 2007.

11. EGSI shall adjust its fuel over/under recovery balance consistent with the findings
in this order.

12. The entry of this order consistent with the stipulation does not indicate the
Commission's endorsement of any principle or methodology that may underlie the
stipulation. Neither should entry of this order be regarded as precedent as to the
appropriateness of any principle or methodology underlying the stipulation.

13. All other motions, requests for entry of specific findings of fact, conclusions of
law, and ordering paragraphs, and any other requests for general or specific relief,
if not expressly granted in this order, are hereby denied.
PUC Docket No. 34800 Order Page 15of15
SOAH Docket No. XXX-XX-XXXX

SIGNED AT AUSTIN, TEXAS the _ _ day of March 2009

PUBLIC UTILITY COMMISSION OF TEXAS

~
/.
B ITHERMAN, CHAIRMAN

DONNA L. NELSON, COMMISSIONER

q.\cadm\orders\final\34000\34800fo2.doc
 SOAH DOCKET NO. XXX-XX-XXXX
PUC DOCKET NO. 37744

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE § OF
RATES AND RECONCILE FUEL COSTS § ADMINISTRATIVE HEARINGS

DIRECT TESTIMONY AND EXHIBITS

OF

JACOBPOUS

ON BEHALF OF

CERTAIN CITIES SERVED BY ENTERGY TEXAS, INC.

JUNE 9, 2010

Diversified Utility Consultants Inc.
1912 West Anderson Lane, Suite 202
Austin, TX 78757
 1 between Texas and Louisiana reflected in the storm reserve be retained. This
2 recommendation reverses the Company's proposed reassignment of costs.
3
4 Q. PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE
5 RESERVE DEFICIT BALANCE.
6 A. In association with the securitization process relating to Hurricanes Rita and Katrina, the
7 Company has received insurance proceeds or has revised its insurance estimates
8 subsequent to the analysis reflected in Adjustment 15 to the Company's filing. 204 The
9 Company states there have been two additional changes that impact the insurance related
10 amount reflected in the Company's filing. First, the actual proceeds for Hurricane Katrina
11 received in December 2009 exceeded the estimated proceeds by $7,290. Second, the
12 Company revised the estimated proceeds for Hurricane Rita that exceeded the previous
13 estimate by $1,511,688. 205 Therefore, the combined total of these two insurance proceed
14 related adjustments total $1,518,978 and should be recognized in this case.
15
16 Q. PLEASE DISCUSS YOUR LAST ADJUSTMENT TO THE INSURANCE
17 RESERVE DEFICIT BALANCE.
18 A. 1 recommend reversal of Company proposed Adjustment 15. This proposed adjustment
19 attempts to remove from the insurance reserve the unrecovered hurricane insurance
20 proceeds, insurance proceeds in excess of insurance proceeds included in the
21 securitization process and carrying costs. 206 ETI proposes to carve $25 million out of the
22 insurance reserve and establish a separate regulatory component for which it also
23 proposes a 5-year amortization. There is no valid basis for this proposed separate and
24 unique treatment. Therefore, ETI's proposed Adjustment 15, Hurricane Securitization,
25 should be eliminated by returning the $25 million amount to the insurance reserve. This
26 recommendation does not impact rate base, but does reduce the net annual amortization
27 by $3,791,732 due to the differing amortization periods (5 years Adjustment 15
28 versus 20 years for storm insurance reserve).
29

204
Response to Rose City 23-21.
ws Id.
206
Testimony of Mr. Wright at page 20.

113