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

ACCEPTED
03-14-00709-CV
4187470
THIRD COURT OF APPEALS
AUSTIN, TEXAS
2/18/2015 9:33:00 AM
JEFFREY D. KYLE
CLERK
NO. 03-14-00709-CV

FILED IN
3rd COURT OF APPEALS
IN THE COURT OF APPEALS AUSTIN, TEXAS
FOR THE THIRD DISTRICT OF TEXAS2/18/2015 9:33:00 AM
AUSTIN, TEXAS JEFFREY D. KYLE
Clerk

ENTERGY TEXAS, INC.
Appellants,

v.

PUBLIC UTILITY COMMISSION OF TEXAS
Appellee.

Appeal from the 53rd Judicial District Court, Travis County, Texas
The Honorable Amy Clark Meachum, Judge Presiding

APPELLEE TEXAS INDUSTRIAL ENERGY CONSUMERS’ BRIEF

FEBRUARY 13, 2015

Rex D. VanMiddlesworth
rex.vanmiddlesworth@tklaw.com
State Bar No. 20449400
Benjamin Hallmark
benjamin.hallmark@tklaw.com
State Bar No. 24069865
THOMPSON & KNIGHT LLP
98 San Jacinto Blvd., Suite 1900
Austin, TX 78701
Telephone: (512) 469-6100
Facsimile: (512) 469-6180
ATTORNEYS FOR APPELLEE TEXAS
INDUSTRIAL ENERGY CONSUMERS

ORAL ARGUMENT REQUESTED
 TABLE OF CONTENTS
PAGE
TABLE OF AUTHORITIES .............................................................................................. iv

STATUTORY AUTHORITIES .......................................................................................... v

LEGISLATION ................................................................................................................... v

STATEMENT OF THE CASE ......................................................................................... vii

STATEMENT ON ORAL ARGUMENT ......................................................................... vii

RESTATED ISSUES PRESENTED ................................................................................. vii

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

I. The legislature delayed deregulation in ETI’s service area, but took a
small step towards competition by authorizing a CGS program................... 1

II. ETI proposed a CGS tariff in Commission Docket 37744. .......................... 3

III. The parties agreed on a different CGS program in Docket 38951, but
could not agree on what costs would be unrecovered as a result of its
implementation. ............................................................................................. 5

IV. The Commission found that the only costs that would be
unrecovered as a result of implementation of the new CGS program
were the costs to implement and administer it. ............................................. 6

V. The Commission rejected ETI’s proposal to surcharge pre-
implementation CGS regulatory expenses and denied ETI’s request
for interest on costs of implementing a CGS program. ............................... 10

SUMMARY OF ARGUMENT ......................................................................................... 11

ARGUMENT..................................................................................................................... 15

I. The Commission’s finding on ETI’s unrecovered costs is supported
by substantial evidence and consistent with the CGS statute. .................... 15

A. Standard of Review .......................................................................... 15

i
 B. The evidence showed that ETI would not incur any costs to
serve CGS customers that would be unrecovered, other than
implementation and administration costs. ........................................ 16

C. ETI did not prove that it has unavoidable fixed generation
costs that would be unrecovered as a result of the CGS
program. ........................................................................................... 19

D. The Commission properly determined that the costs to
implement and administer the CGS tariff would be
unrecovered and included this finding in its order. .......................... 22

E. The Commission properly rejected ETI’s attempt to recast the
statutory term “costs unrecovered” as lost revenues. ....................... 23

1. The Commission’s interpretation is consistent with the plain
language of PURA § 39.452(b)............................................. 23

2. The Commission’s decision is consistent with the
CenterPoint 2011 precedent.................................................. 25

3. ETI sought lost revenues at the Commission, not unrecovered
costs. ...................................................................................... 30

4. The Commission’s rejection of ETI’s lost-revenues theory is
consistent with the purposes of the CGS statute. .................. 33

5. High Plains is inapposite. ..................................................... 34

F. Contrary to ETI’s contentions, the Commission’s decision
was based on a vast evidentiary record, not “solely upon its
interpretation of the CGS statute” .................................................... 35

II. The Commission properly rejected ETI’s request to surcharge legal
and regulatory costs incurred from 2010 to 2013 as costs of
implementation. ........................................................................................... 38

III. The Commission properly rejected ETI’s request for interest on
CGSC rider costs. ........................................................................................ 42

A. When the legislature intends to award carrying costs, it says
so. ..................................................................................................... 42

B. The Commission has not allowed interest to be recovered on
similar expenses. .............................................................................. 44

ii
PRAYER ........................................................................................................................... 46

CERTIFICATE OF COMPLIANCE ................................................................................ 47

CERTIFICATE OF SERVICE .......................................................................................... 48

APPENDIX ....................................................................................................................... 49

iii
 TABLE OF AUTHORITIES

PAGE

Cases

CenterPoint Energy Houston Electric, LLC v. Public Util. Comm’n of Tex.
354 S.W.3d 899 (Tex. App. – Austin 2011, no pet.) ................................... passim
CenterPoint Energy Houston Electric, LLC v. Public Util. Comm’n of Tex.,
408 S.W.3d 910 (Tex. App. – Austin 2013, pet. Denied .....................................41

CenterPoint Energy, Inc. v. Public Util. Comm’n of Tex.
143 S.W.3d 81 (Tex. 2004) ..................................................................................46
City of El Paso v. Pub. Util. Comm’n,
883 S.W.2d 179 (Tex. 1994) ................................................................................16
In re Entergy Corp.,
142 S.W.3d 316 (Tex. 2004) .................................................................................1
Laidlaw Waste Sys., Inc. v. City of Wilmer,
904 S.W.2d 656 (Tex. 1995) ......................................................................... 44, 45
Moran Util. Co. v. R.R. Comm’n,
697 S.W.2d 447, (Tex. App.—Austin 1985, pet. granted) (aff’d in
relevant part, rev’d in part, 728 S.W.2d 764 (Tex. 1987) ....................................46
Office of Public Utility Counsel v. Texas-New Mexico Power Co.,
344 S.W.3d 446 (Tex. App.—Austin 2011, pet. denied)....................................38
R.R. Comm’n v. High Plains Natural Gas Co.,
628 S.W.2d 753 (Tex. 1981) ................................................................................34
R.R. Comm’n v. Texas Citizens for a Safe Future & Clean Water,
336 S.W.3d 619 (Tex. 2011) ......................................................................... 16, 24

Reliant Energy, Inc. v. Pub. Util. Comm’n,
153 S.W.3d 174 (Tex. App.—Austin 2004, pet. denied).....................................16
State Banking Board v. Allied Bank Marble Falls,
748 S.W.2d 447 (Tex. 1988) ...............................................................................38

iv
Texas Health Facilities Comm’n v. Charter Med.-Dallas, Inc.,
665 S.W.2d 446 (Tex. 1984) (citing Gerst v. Guardian Sav. & Loan
Ass’n, 434 S.W.2d 113 (Tex. 1968))............................................................. 15, 16

STATUTORY AUTHORITIES
Tex. Gov’t Code Ann. § 2001.174...........................................................................15

Tex. Gov’t Code Ann. § 2001.175...........................................................................15
Tex. Util. Code Ann. § 36.061 .................................................................... 43, 44, 45

Tex. Util. Code Ann. §§ 36.402 ........................................................................ 43, 44

Tex. Util. Code Ann. §§ 39.011-.359 ...................................................................... 1

Tex. Util. Code Ann. § 39.452 ......................................................................... passim
Tex. Util. Code Ann. § 39.4525 ........................................................................ 43, 44

Tex. Util. Code Ann. § 39.454 .......................................................................... 43, 44

Tex. Util. Code Ann. § 39.459 .......................................................................... 43, 44
Tex. Util. Code Ann. § 39.905 ...................................................................... 26,27,28

LEGISLATION

Act of May 24, 2005, 79th Leg., R.S., ch. 1072, § 1, 2005 Tex. Sess. Law
Serv. 3559, available at
http://www.legis.state.tx.us/tlodocs/79R/billtext/pdf/HB01567F.pdf ........ 1, 2, 24
Act of May 30, 2009, 81st Leg., R.S., ch. 1226, § 3, 2009 Tex. Sess. Law
Serv. 3913, available at
http://www.legis.state.tx.us/tlodocs/81R/billtext/pdf/SB01492F.pdf......................2, 24

v
 COMMISSION PROCEEDINGS

Application of CenterPoint Energy Houston Electric, LLC for a
Competition Transition Charge, Docket No. 30706 ............................................45

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................................................. 45, 46

Complaint of the City of McKinney Against Southwestern Bell Telephone
Company, Docket No. 11027 ...............................................................................45

Petition of Texas Electric Service Co. for Authority to Change Rates,
Docket 2606, 5 P.U.C. BULL. 109 .....................................................................45

vi
 STATEMENT OF THE CASE
This is an administrative appeal of an order of the Public Utility

Commission of Texas (the Commission) in a contested-case proceeding. The order

establishes a Competitive Generation Service (CGS) tariff, which would allow

eligible customers to obtain their electricity from a supplier other than Entergy

Texas, Inc. (ETI).

STATEMENT ON ORAL ARGUMENT
To the extent the Court grants any request for oral argument, TIEC requests

the opportunity to be heard.

RESTATED ISSUES PRESENTED
(1) Whether the Commission’s findings of fact regarding the costs that

would be unrecovered as a result of the implementation of the CGS program are

supported by substantial evidence and consistent with PURA § 39.452(b);

(2) Whether certain of ETI’s litigation and regulatory expenses, which

would have been incurred whether or not the Commission implemented a CGS

tariff, and which were already being recovered in ETI’s base rates, can be charged

to ratepayers as CGS implementation costs through a special rider; and

(3) Whether PURA mandates that ETI receive interest on the costs of CGS

implementation in the absence of any statutory reference to interest.

vii
 GLOSSARY OF ABBREVIATIONS

AR, Supp. Administrative Record and Supplemental Administrative Record,
AR organized by binders, exhibits, and transcripts
CGS Competitive Generation Service, created by PURA § 39.452(b)
The Competitive Generation Service Costs Rider was designed to
CGSC Rider recover the costs of implementing and administering the program;
approved by the PUC in Docket 39851 Order.
The Competitive Generation Service Unrecovered Costs Rider
CGSUSC
was first proposed by ETI in Docket No. 37744, but was not
Rider
approved in either Docket 37744 or 38951.
Commission Public Utility Commission of Texas
or PUC
Entergy Operating Committee, the entity that conducts generation
EOC
planning on behalf of ETI and its sister companies in other states.
ETI Entergy Texas, Inc.
“Large Industrial Power Service,” the tariff schedule under which
LIPS
most of ETI’s industrial customers take power.
MW Megawatt, a measure of energy (equal to 1000 kilowatts)
PFD Proposal for Decision
PURA Public Utility Regulatory Act, Tex. Util. Code §§ 11.001 et seq.
TIEC Texas Industrial Energy Consumers

viii
 STATEMENT OF FACTS
Appellee Texas Industrial Energy Consumers (TIEC) is an association of

industrial consumers whose principal purpose is to address electricity matters at the

Public Utility Commission (“the Commission”). 1 TIEC files this brief in support

of the Commission’s order implementing a Competitive Generation Service

(“CGS”) tariff for Entergy Texas, Inc. (“ETI”).

I. The legislature delayed deregulation in ETI’s service area, but took a
small step towards competition by authorizing a CGS program.
ETI is an investor-owned utility that provides bundled generation,

transmission, distribution, and customer service to retail customers in Southeast

Texas.2 In 1999, the legislature mandated that investor-owned utilities in Texas

transition to competition. 3 The transition in ETI’s service area, however, was not

smooth.4 Consequently, in 2005 the legislature enacted a special subchapter of

PURA to specifically address ETI during the move to competition. 5 This

subchapter applies to no other utilities. 6 The legislation removed the mandate that

1
Supp. AR, Docket No. 37744, Item 2, Motion to Intervene of TIEC; AR Binder 1, Docket No.
38951, Item 46, List of Participating Members of TIEC.
2
Supp. AR, Docket No. 37744, ETI Ex. 4, Domino Direct at 1.
3
Tex. Util. Code Ann. (“PURA”) §§ 39.011-.359.
4
See, e.g., In re Entergy Corp., 142 S.W.3d 316, 319-20 (Tex. 2004).
5
Act of May 24, 2005, 79th Leg., R.S., ch. 1072, § 1, 2005 Tex. Sess. Law Serv. 3559) (HB 1567)
(codified at PURA subch. J, §§ 39.451-39.463). This legislation can be accessed at
http://www.legis.state.tx.us/tlodocs/79R/billtext/pdf/HB01567F.pdf.
6
PURA § 39.451.
1
ETI proceed to a competitive market for generation, but still took a partial step

toward competition by requiring ETI to propose a CGS tariff that would, if

approved, allow eligible customers to obtain the generation of their electricity

from another source.7

In 2009, the legislature amended this provision to statutorily delay ETI’s

transition to competition. 8 At the same time, however, the legislature reiterated the

requirement that ETI propose a CGS tariff, adding additional instructions for

implementation. The legislature also removed any requirement that the CGS tariff

be proposed in a base rate case.9

The 2009 legislation is codified in PURA § 39.452. Section 39.452(b)

authorizes a CGS tariff that, if approved by the Commission, would allow certain

customers to purchase their electricity from a third party. ETI would continue to

provide transmission service and other services, but the electricity itself would be

generated and provided from another source. 10 The same section states that “the

utility’s rates shall be set, in the proceeding in which the tariff is adopted, to

7
Act of May 24, 2005, 79th Leg., R.S., ch. 1072, § 1, 2005 Tex. Sess. Law Serv. 3559) (HB
1567).
8
Act of May 30, 2009, 81st Leg., R.S., ch. 1226, § 3, 2009 Tex. Sess. Law Serv. 3913, 3914 (SB
1492) (codified at PURA § 39.452(i)). This legislation can be accessed at
http://www.legis.state.tx.us/tlodocs/81R/billtext/pdf/SB01492F.pdf.
9
Id. (codified at PURA § 39.452(b)), (removing “As part of a Subchapter C, Chapter 36, rate
proceeding, the” from PURA § 39.452 (b)).
10
PURA § 39.452(b).
2
recover any costs unrecovered as a result of the implementation of the tariff.” 11

The Commission’s application of this provision is at issue in this appeal.

II. ETI proposed a CGS tariff in Commission Docket 37744.
ETI initially proposed a CGS program in Docket 37744, a base rate case, in

2009. 12 The Commission referred the case to the State Office of Administrative

Hearings (“SOAH”) to be tried by an administrative law judge (“ALJ”). 13 ETI

raised a number of issues with the costs it claimed would be unrecovered under the

CGS tariff it submitted. 14 One such issue was ETI’s witness’s assertion that ETI

would still be required to provide capacity to a CGS customer even if that

customer was purchasing its capacity elsewhere. 15 That was because the Entergy

Operating Committee (“EOC”)—the entity that conducted generation planning on

behalf of ETI and its sister companies in other states—would not recognize that a

contract between the CGS customer and the CGS supplier would be a firm contract

for ETI’s planning purposes. 16 According to ETI, this meant that, despite the fact

11
Id.
12
Supp. AR, Docket No. 37744, ETI Ex. 1, Entergy Texas, Inc.’s Statement of Intent and
Application for Authority to Change Rates and Reconcile Fuel Costs.
13
Supp. AR, Docket No. 37744, Item 1, Order of Referral to State Office of Administrative
Hearings (SOAH).
14
Supp. AR, Docket No. 37744, Item 37, Proposal for Decision (PFD) at 26, (“…ETI has given
the Commission a worst-case scenario of 75 million dollars in unrecovered costs if every eligible
customer participates.”).
15
Supp. AR, Docket No. 37744, Item 21, Initial Brief of Entergy Texas, Inc. on Proposed CGS
at 20-21; Supp. AR, Docket No. 37744, Transcripts, HOM Vol. D at 51-52.
16
Supp. AR, Docket No. 37744, Item 37, PFD at 35-36.
3
that a CGS customer would be obtaining its electricity from an outside supplier,

ETI would still be required to pay for generation capacity as if the CGS customer

were actually buying its electricity from ETI. 17

For whatever reason, ETI proposed no limits whatsoever on the number of

customers or megawatts that could use CGS service, and then asserted that it could

potentially lose all of the Large Industrial Power Service class (“LIPS”) to the CGS

program. 18 At the time, these customers represented 651 megawatts of ETI’s total

demand. 19

The ALJ in Docket 37444 agreed with ETI that, under the CGS program ETI

had proposed, ETI would still incur production costs to serve CGS customers

despite the fact that these customers would obtain their electricity elsewhere,

because the EOC would require ETI to buy capacity for these customers as if they

were buying from ETI. 20 In light of this finding, and the fact that ETI’s proposal

would save no capacity costs but merely shift these costs to ETI’s other

customers, 21 the ALJ recommended that the CGS program ETI proposed in Docket

17
Supp. AR, Docket No. 37744, Item 21, Initial Brief of Entergy Texas, Inc. on Proposed CGS
at 20.
18
Supp. AR, Docket No. 37744, ETI Ex. 9, May Direct at 13.
19
Id.
20
Supp. AR, Docket No. 37744, Item 37, PFD at 36, FoF 44.
21
Id. at FoF 17.
4
37444 be rejected altogether.22 It was unsurprising that ETI did not object to this

recommendation.23

III. The parties agreed on a different CGS program in Docket 38951, but
could not agree on what costs would be unrecovered as a result of its
implementation.
ETI’s statement of facts describes in detail the CGS program it originally

proposed in Docket 37444,24 but it fails to describe the key elements of the

program the Commission actually approved in Docket 38951, from which this

appeal lies. Because of this, one could be left with the impression that the program

ETI proposed (and ultimately abandoned) in Docket 37444 is the CGS program at

issue in this case. However, the Commission did not approve that program.

Instead, the Commission severed the CGS issues into Docket 38951 for further

consideration.25 At the Commission’s urging, the parties began settlement talks on

a revised CGS program and subsequently agreed on a new approach. The key

element of this revised program was that the EOC would recognize that the CGS

customer’s electricity was being provided by a third party, not ETI. 26 Thus, ETI

22
Supp. AR, Docket No. 37744, Item 37, PFD at 41.
23
Supp. AR, Docket No. 37744, Item 41, Exceptions of Entergy Texas, Inc. at 1.
24
ETI’s Appellant’s Brief at 9.
25
Supp. AR, Docket No. 37744, Item 53, PUC Order No. 14 – Memorializing Decision Granting
Motion to Sever.
26
ETI’s agreement to do so was conditioned on certain conditions being met. AR Binder 2,
Docket No. 38951, Item 119, Final Order at Finding of Fact (“FoF”) 41G.
5
would no longer have to incur any capacity costs to serve the CGS customer. 27

The parties also agreed that only a small amount of ETI’s total load—a maximum

of 115 megawatts—could participate in the CGS program. 28

While the parties were able to agree on most of the previously contested

issues surrounding the CGS program, they were not able to agree on what costs

would be unrecovered as a result of its implementation. 29 Accordingly, the parties

submitted additional testimony on the costs that would be unrecovered under the

new program, and the Commission held an evidentiary hearing to decide the

issue. 30

IV. The Commission found that the only costs that would be unrecovered as
a result of implementation of the new CGS program were the costs to
implement and administer it.
ETI maintained in Docket 38951 that it was entitled to recover lost revenues

for every kilowatt that a CGS customer purchased from a source other than ETI,

even though ETI would no longer have any obligation to provide generation for the

27
Under the agreement, ETI would still provide back-up power when the CGS customer was
unavailable. The CGS customer would pay for this power. AR Binder 4, Docket No. 38951,
TIEC Ex. 15, Supplemental Direct Testimony and Exhibits of Jeffry Pollock at 15; AR Binder 2,
Docket No. 38951, Item 119, Final Order at 19-20 (describing unserved energy rate and CGS
cost distribution).
28
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 36.
29
Id. at 3-4.
30
Id.
6
CGS customer. 31 Thus, despite the changes to the CGS program, ETI did not

depart from the cost-recovery approach embodied in the rider it proposed in

Docket 37744:

This Competitive Generation Service Unrecovered Service Cost Rider
(“Rider CGSUSC” or “Rider”) defines the procedure by which
Entergy Texas, Inc. (“Company”) shall implement and adjust rates for
recovery of lost base rate revenue resulting from customers
participating in the Company’s Competitive Generation Service
(“CGS Program”). The purpose of this Rider is to provide a
mechanism for recovery of such lost base rate revenues that were
included in the Company’s last general rate case proceeding before
the Public Utility Commission of Texas (“PUCT”). 32

In a nutshell, ETI contended that it was entitled to recover the hypothetical

revenues (or “embedded generation costs” as ETI uses the term 33) that a CGS

customer would have paid if it had purchased its electricity from ETI instead of

from a third party. 34

Other parties disagreed that ETI was entitled to lost revenues and submitted

testimony that the revised CGS tariff would cost ETI nothing from a capacity

31
AR Binder 2, Docket No. 38951, Item 119, Final Order at 7; AR Binder 3, Docket No. 38951,
ETI Ex. 91, May Supp. Direct at 5-8.
32
Supp. AR, Docket No. 37744, ETI Ex. 9, May Direct at Exhibit PRM-1 at 5 (emphasis added);
see also AR Binder 5, Transcripts Vol. B, HOM Tr. At 72-73 (Apr. 19, 2012); AR Binder 3,
Docket No. 38951, ETI Ex. 91, May Supp. Direct at 5-8.
33
ETI’s Appellant’s Brief at 8 (stating that the CGSUSC Rider would have recovered embedded
generation costs that “migrating customers” would have paid but for CGS program).
34
Supp. AR, Docket No. 37744, Item 37, PFD at 22-13 and FoFs 14-18; Supp. AR, Docket No.
37744, Transcripts, Vol. D at 165-166 (Jul. 16, 2010).
7
standpoint.35 The testimony submitted by intervenor witnesses was that, under the

new framework, a CGS supplier would be required to enter into a purchase

agreement directly with ETI (or on ETI’s behalf) under which the supplier would

provide firm power to a CGS customer. 36 The CGS supplier’s charges to provide

the power would be passed directly through to the CGS customer. 37 And ETI’s

other costs of serving CGS customers, such as costs to provide transmission

service and back-up power, would be charged to the very CGS customers who

received those services.38 Thus, in addition to being presented with several

stipulations regarding the structure of the agreed-to CGS program, 39 the

Commission heard intervenor testimony that, under this framework, the CGS

customer would pay ETI for the full cost of all of the service that ETI provides that

customer, and the CGS customer would pay the CGS supplier for the cost of the

power that the CGS supplier provides. 40

Additionally, the stipulations presented to the Commission provided that the

CGS customers would pay ETI’s incremental cost of implementing and

35
See, e.g., AR Binder 3, Docket No. 38951, Cities Ex. 6C, Nalepa Supp. Direct at 7-8; AR
Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 14-21.
36
Id.
37
Id.
38
Id.
39
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 12-18.
40
AR Binder 3, Docket No. 38951, Cities Ex. 6C, Nalepa Supp. Direct at 10; AR Binder 4,
Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 16.
8
administering the CGS program. 41 Although those costs were unknown at the time

of the hearing, the Commission (with ETI’s agreement) ordered that ETI could

subsequently file an application to recover them. 42

After considering the testimony, stipulated facts, agreements, and multiple

rounds of briefing, the Commission made the following ultimate finding of fact as

to unrecovered costs associated with the revised CGS program tariff then before it:

The Commission finds that the costs that will be unrecovered as a
result of the implementation of the CGS program tariff are the costs to
implement and administer the CGS program tariff. 43

The Commission also rejected ETI’s assertion that it was entitled to charge

other ratepayers for the difference between what a CGS customer paid and what a

full firm LIPS customer would have paid, 44 which ETI had characterized as “lost

base rate revenues” in its proposed rider in Docket 37744.45 After this Court

rejected a similar lost revenues argument in CenterPoint Energy Houston Electric,

LLC v. Public Utility Commission (“CenterPoint 2011”),46 ETI downplayed the

“lost revenues” language in its proposal, and instead used the terms “embedded

41
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 35.
42
Id.
43
Supp. AR, Docket No. 37744, Item 27, SOAH Order No. 12 – Interim Order Approving
Revised Interim Rates at FoF 40; AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF
51.
44
AR Binder 2, Docket No. 38951, Item 119, Final Order at CoL 2.
45
Supp. AR, Docket No. 37744, ETI Ex. 9, May Direct at Exhibit PRM-1 at 5.
46
354 S.W.3d 899 (Tex.App.—Austin 2011, no pet.).
9
generation costs” or “embedded production costs.” 47 But ETI’s witness made clear

that they were the same thing. 48 Whatever the lexicon, the Commission rejected

ETI’s argument that the statutory reference to unrecovered costs meant lost

revenues. Specifically, the Commission made a conclusion of law that:

PURA § 39.452(b) does not allow for the recovery of lost revenue or
embedded generation costs.49

The Commission’s order cited this Court’s decision in CenterPoint 2011 as

precedent in support of its determination that PURA § 39.452(b)‘s reference to

“costs unrecovered” did not mean “lost revenues.” 50

V. The Commission rejected ETI’s proposal to surcharge pre-
implementation CGS regulatory expenses and denied ETI’s request for
interest on costs of implementing a CGS program.
ETI also proposed a “CGSC” rider that was to recover the company’s

incremental development and ongoing CGS program operation costs, under the

theory that these costs would otherwise be unrecovered as a result of the

implementation of the CGS tariff. 51 ETI sought to surcharge ratepayers for its

alleged historical CGS regulatory and litigation expenses dating back to November

47
AR Binder 3, Docket No. 38951, ETI Ex. 91, May Supp. Direct at 5-8; See, e.g., ETI’s
Appellant’s Brief at 8, 15.
48
AR Binder 5, Transcripts, Vol. B, HOM Tr. At 72-73.
49
AR Binder 2, Docket No. 38951, Item 119, Final Order at CoL 2.
50
Id. at 7.
51
Supp. AR, Docket No. 37744, ETI Ex. 9, May Direct at Exhibit PRM-1 at 3; PURA §
39.452(b).
10
10, 2010—years before any decision of whether there would even be a CGS tariff

to implement. 52 These costs would have been incurred even if the Commission had

denied the proposal to implement a CGS program in its July 2013 final order at

issue in this appeal. The Commission denied ETI’s request and determined that

the costs of implementing the CGS program tariff would begin if and when a CGS

program was implemented.53 The Commission also determined that ETI was not

entitled to interest on any costs of implementing a CGS program. 54

ETI appealed the Commission’s order in Docket 38951 to district court.55

Following full briefing and oral argument, the trial court, Judge Meachum

presiding, affirmed the Commission’s order in all respects. 56 ETI then filed this

appeal.

SUMMARY OF ARGUMENT
PURA § 39.452(b) states that a utility’s rates “shall be set . . . to recover any

costs unrecovered as a result of the implementation of the tariff.” 57 The evidence

showed that under the revised CGS tariff approved by the Commission, ETI would

not incur any costs to serve CGS customers that would be unrecovered, other than

52
AR Binder 3, Docket No. 38951, ETI Ex. 103, Roach Supp. Reb. at 2:19-21.
53
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 51.
54
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 57.
55
CR4-19.
56
CR523-26.
57
Emphasis added.
11
as-yet unquantified implementation and administration costs. The revised program

required that the CGS supplier, not ETI, would provide firm power to serve the

CGS customer. Thus, unlike the program initially proposed in Docket 37744, ETI

would not have any capacity costs associated with CGS customers. ETI would

indisputably incur costs to provide back-up power, transmission, and other

ancillary services to CGS customers. However, under the framework approved by

the Commission, all of these costs would be charged to those CGS customers and

would thus not be “unrecovered.”

ETI contends that it has unavoidable fixed production costs, and asserts that

these should be considered unrecovered costs.58 As an initial matter, ETI did not

propose to measure and recover any fixed production costs that would somehow be

unrecovered as a result of the CGS program. It simply sought revenues that it

would have hypothetically charged if any future CGS customer had chosen to buy

full firm power from ETI rather than from CGS suppliers. Further, the evidence

contradicts ETI’s claim. ETI purchases, rather than self-generates, the vast

majority of the power it supplies to its retail customers, 59 and it is projecting

substantial capacity shortfalls in the coming years. 60 ETI also projects steady

58
ETI Appellant’s Brief at 15-16.
59
Supp. AR, Docket No. 37744, Item 37, PFD at 31.
60
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 42, 43.
12
growth in demand in its service area. 61 And, under the revised CGS framework

approved by the Commission, the program was capped at 115 MW. Taken

together, these facts mean that the implementation of the CGS program would not

result in any load loss; it would merely slow ETI’s load growth and thus ameliorate

ETI’s capacity shortfall.62 In other words, even if one assumes that all future CGS

customers would have taken full firm power from ETI (rather than, for example,

self-generating power or locating in another utility’s service territory), the CGS

program would merely cause ETI to purchase less electricity than it otherwise

would have.

The Commission also properly rejected ETI’s position that by “costs

unrecovered,” the legislature actually meant “lost revenues.” The plain language

of the statute makes no reference to revenues, and this Court’s decision in

CenterPoint 2011 confirms that a reference to “costs” in PURA does not mean

“revenues.”

ETI attempts to distinguish the CenterPoint 2011 holding by asserting that it

sought to recover its “embedded production costs.” However, this contention is

belied by the language of ETI’s proposed rider, in which ETI expressly sought

recovery of “lost base rate revenues,” not unrecovered costs. It is also belied by

61
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 22, JP-3 (citing
Entergy’s Strategic Resource Plan).
62
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 9.
13
the evidence, including testimony from an ETI witness that ETI sought to recover

all revenues it would have received if a CGS customer that purchased power from

a third party had instead purchased power under ETI’s full firm rates, even if that

customer had never purchased power from ETI prior to signing up for the CGS

program. The hypothetical revenue a new customer might have generated from

ETI if it had chosen to purchase power from ETI under a firm rate cannot logically

be considered an unrecovered cost to ETI. It is clear that ETI proposed a lost-

revenues theory that is foreclosed by PURA and CenterPoint 2011.

The Commission properly found that ETI will incur costs to implement and

administer the CGS program, which will not be recovered by the CGS tariff itself.

Accordingly, the Commission determined that these costs were unrecovered costs

and provided a mechanism for their recovery. The Commission’s determination

that these were the only costs that would be unrecovered is supported by the

evidence, consistent with the plain language of the implementing statute, and

faithful to this Court’s recent precedent in CenterPoint 2011.

The Commission’s denial of ETI’s request to surcharge customers for

regulatory costs incurred from November 2010 to July 2013 as costs of

implementation should also be upheld. These costs would have been incurred

regardless of whether the CGS program was ever implemented, and, under the

14
statute, ETI may only recover costs that are unrecovered as a result of

implementation. Further, the record showed that ETI actually sought and was

recovering pre-implementation costs related to the CGS program through its base

rates.

Finally, the Commission properly rejected ETI’s request to recover interest

on the costs of CGS implementation. Contrary to ETI’s claim that it is statutorily

entitled to interest, the statute makes no reference to carrying costs, and the

Commission has long denied interest on similar regulatory expenses.

ARGUMENT

I. The Commission’s finding on ETI’s unrecovered costs is supported by
substantial evidence and consistent with the CGS statute.
A. Standard of Review
Judicial review of the Commission’s findings of fact concerning

unrecovered costs is under the substantial evidence rule. 63 The substantial

evidence standard of review does not allow a court to substitute its judgment for

that of the agency. 64 The scope of review under the substantial evidence rule is

limited; the issue for the reviewing court is not whether the agency reached the

correct conclusion, but whether there is “some reasonable basis in the record for

63
PURA § 15.001; Tex. Gov’t Code §§ 2001.174, 2001.175.
64
Texas Health Facilities Comm’n v. Charter Med.-Dallas, Inc., 665 S.W.2d 446, 452 (Tex.
1984) (citing Gerst v. Guardian Sav. & Loan Ass’n, 434 S.W.2d 113, 115 (Tex. 1968)).
15
the action taken by the agency.” 65 Substantial evidence requires only more than a

mere scintilla, and “the evidence in the record actually may preponderate against

the decision of the agency and nonetheless amount to substantial evidence.” 66 A

court must uphold an agency decision if a reasonable basis exists in the record for

the decision.67

ETI also argues that the Commission misconstrued the terms of § 39.452 of

PURA. A reviewing court gives great weight to the agency’s interpretation of the

statute it implements and enforces. 68 If a statute is subject to more than one

interpretation, a court must uphold the agency’s interpretation if it is reasonable

and in harmony with the statute. 69

B. The evidence showed that ETI would not incur any costs to serve
CGS customers that would be unrecovered, other than
implementation and administration costs.
To understand the CGS program, it is helpful to draw an analogy. Consider

a natural gas utility that provides service to an industrial consumer under a firm

contract. Prior to deregulation, the gas utility would generally purchase or produce

65
See City of El Paso v. Pub. Util. Comm’n, 883 S.W.2d 179, 185 (Tex. 1994).
66
Charter Med.-Dallas, 665 S.W.2d at 452 (citing Lewis v. Metropolitan Sav. & Loan Ass’n, 550
S.W.2d 11, 13 (Tex. 1977)).
67
See City of El Paso, 883 S.W.2d at 185.
68
Reliant Energy, Inc. v. Pub. Util. Comm’n, 153 S.W.3d 174, 187 (Tex. App.—Austin 2004,
pet. denied).
69
R.R. Comm’n v. Texas Citizens for a Safe Future & Clean Water, 336 S.W.3d 619, 629 (Tex.
2011).
16
the natural gas and then transport it to the customer on the utility-owned pipeline.

However, if a CGS-style program were introduced, the customer could choose to

purchase its natural gas from a third party, but it would still pay to have it shipped

on the utility’s pipeline. Logically, this should result in the utility avoiding the

costs necessary to either purchase or produce the gas that the customer was no

longer buying from the utility. However, if there were some overarching

requirement that the utility was still responsible for buying natural gas for the

customer even though the customer was obtaining it elsewhere, the utility might

argue that it could not avoid its costs to provide gas to the customer. This is

essentially what ETI argued in connection with the CGS program it initially

proposed in Docket 37744.

The key impediment to the CGS program proposed in that docket was the

insistence by ETI and the Entergy Operating Committee that ETI would still have

to incur production costs for a CGS customer even though that customer was not

obtaining its electricity from ETI. 70 Critically, this impediment was resolved under

the approach the Commission adopted in Docket 39851, because the revised

program allowed the CGS customer to get its firm power from the CGS supplier

without cost to ETI. The evidence established that this and other changes to the

70
Supp. AR, Docket No. 37744, Item 21, Initial Brief of Entergy Texas, Inc. on Proposed CGS
at 20.
17
CGS program meant that ETI would not incur production costs to serve CGS

customers.

TIEC witness Jeffry Pollock 71 testified that, under the revised CGS program,

the CGS customer would pay ETI for all costs associated with its service. 72 For

example, even though the CGS customer would use an alternative source for its

generation supply, it would still use the ETI transmission and distribution system

to deliver the electricity. For this use, the CGS customer would pay ETI the full

wires charges that any other electricity user in the ETI area would pay. 73 And,

since there may be times when the CGS supplier experiences an outage, the CGS

customer would pay ETI the full cost of back-up power, just as a customer that

self-generates its own power would pay ETI for back-up power. 74 In short, ETI

would not incur any production costs to serve the CGS customer that it would not

recoup. As stated by Cities witness Karl Nalepa, “[t]he current CGS program has

been designed such that no production costs need go unrecovered.” 75

71
Mr. Pollock’s pre-filed testimony on unrecovered costs under the revised CGS program in
Docket No. 38951 is attached to this brief for the Court’s reference.
72
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 15.
73
Id.
74
Id. See also AR Binder 2, Docket No. 38951, Item 119, Final Order at 19-20 (describing
Unserved Energy rate and CGS Fixed Cost Contribution).
75
AR Binder 3, Docket No. 38951, Cities Ex. 6C, Nalepa Supp. Direct at 10.
18
 C. ETI did not prove that it has unavoidable fixed generation costs
that would be unrecovered as a result of the CGS program.
ETI argues in its brief that its costs of generation are fixed and do not change

with changes in demand. 76 The crux of ETI’s argument is that implementing the

CGS program will cost ETI money in the form of generation costs that neither the

CGS customer nor any other customer will pay. 77 As an initial matter, ETI did not

submit to the Commission a rider that would have measured any such

“unrecovered” generation costs. The rider ETI submitted sought, by its own terms,

“lost base rate revenue resulting from customers participating in the [CGS

program].” 78 Further, the evidence showed that ETI would not have any

unavoidable fixed production costs that would be unrecovered.

ETI is a “short” utility—it has relatively little capacity in the form of ETI-

owned power plants. 79 Accordingly, to satisfy its obligation to serve, ETI

purchases the vast majority of its capacity in the wholesale market and resells that

capacity to its retail customers. 80 In addition, ETI purchases capacity each month

76
See ETI’s Appellant’s Brief at 8, 15.
77
Id.
78
Supp. AR, Docket No. 37744, ETI Ex. 9, May Direct at Exhibit PRM-1 at 5 (emphasis added).
79
Supp. AR, Docket No. 37744, Item 37, PFD at 31.
80
See Docket No. 37744, Schedule P-6.1 and Schedule H-12.4a-g. ETI submitted that it had
$124,341,000 in generated capacity cost and another 186,534,000 (IPCR - Capacity Rider of
$25,769,780 + Other - Base Rate Costs of $160,764,523) in purchased capacity cost for a total of
$310,875,000 in capacity costs.
19
from its affiliates based on ETI’s actual capacity shortfall in the month. 81 Thus,

when ETI has additional demand from its customers, it must purchase additional

power. Conversely, if an existing customer leaves the system or becomes a CGS

customer, ETI would no longer need to purchase capacity for that customer. And

if a customer new to ETI’s service area signed up for CGS service, ETI would not

have to purchase any additional power whatsoever to serve that customer.

The evidence also showed that ETI was experiencing considerable “load

growth” (or increased demand for electricity). 82 Based on an assessment of both its

load requirements and generating capability, ETI projected a capacity shortfall

going forward.83 In fact, ETI stipulated that it would have a shortfall of 260 MW

in 2012, which would grow to 506 MW by 2013.84 This evidence was significant

given that the revised CGS program was limited to a maximum of 115 MW.85

With the cap, the CGS program—even if fully subscribed—would do no more than

slow ETI’s projected load growth and reduce ETI’s need to purchase additional

81
Supp. AR, Docket No. 37744, Item 37, PFD at 31.
82
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 22, JP-3 (citing
Entergy’s Strategic Resource Plan).
83
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 42, 43.
84
Id. at FoF 43.
85
Id. at FoF 36.
20
capacity. 86 Because a CGS customer would obtain its own electricity supply, ETI

could use its existing generation resources to serve existing and new non-CGS

load.87 As Mr. Pollock testified, “ETI has been experiencing substantial load

growth, and the addition of a CGS Program with a cap would only have the effect

of slowing the load growth, not reducing ETI’s revenues.” 88

In sum, the evidence showed that the CGS program, whether comprised of

new load, existing LIPS customers, or some combination thereof, would do no

more than to reduce the additional amount of power that ETI would have to

purchase to serve its system in the future. ETI’s brief suggests that CGS customers

would somehow get a “free lunch” at ETI’s expense. 89 As demonstrated by the

foregoing, however, under the program adopted by the Commission, CGS

customers would buy their lunch from the CGS suppliers and relieve ETI of the

need to buy lunch on their behalf.

86
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 21-23. The evidence
in the underlying proceeding showed that ETI projected load growth of about 2 percent, or 80
megawatts per year, through 2029.
87
Id. at 24.
88
Id. at 9.
89
ETI Appellant’s Brief at 19.
21
 D. The Commission properly determined that the costs to implement
and administer the CGS tariff would be unrecovered and
included this finding in its order.
The evidence showed that the only costs that would be unrecovered as a

result of the implementation of the program were implementation and

administrative costs.90 Intervenor witnesses testified that ETI could recover these

incremental CGS start-up and implementation costs, 91 and ETI agreed to seek these

costs in an application in a subsequent proceeding. 92 Mr. Pollock’s testimony

made clear that there would be no other unrecovered costs:

Q Would any unrecovered costs exist after start-up,
on-going and backup power costs are paid by the CGS
customer?
A No. Recall that, under the CGS Program described
in the Stipulation, the CGS Customer would effectively
buy its own capacity and energy from the CGS Supplier.
With the exception of the capacity credit and fixed fuel
factor, a CGS Customer will pay ETI a retail rate that
includes all other charges the customer would pay as a
firm customer, including a transmission and distribution
rate and all other applicable tariffs (e.g., Rider TTC,
HRC, SRC, SCO, AFC and FF charges, if applicable).
There would be no other unrecovered costs. 93

90
AR Binder 2, Docket No. 38951, Item 119, Final Order at 8.
91
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 15.
92
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 54A.
93
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 16.
22
 ETI had the burden of proving that additional costs beyond those found by

the Commission would be unrecovered.94 It failed to do so. The Commission’s

finding that the only costs that would be unrecovered were those to implement and

administer the tariff is supported by substantial evidence and should be upheld.

E. The Commission properly rejected ETI’s attempt to recast the
statutory term “costs unrecovered” as lost revenues.
While the Commission made a factual finding on the basis of extensive

evidence, it also rejected ETI’s proposed interpretation of the statute that would

equate “costs unrecovered” with the hypothetical lost revenues that a CGS

customer would have paid had it chosen to purchase electricity under ETI’s LIPS

rate instead. The Commission’s decision is consistent with the plain language of

the statute, which provides that the utility’s rates will be set “to recover any costs

unrecovered as a result of the implementation of the tariff. 95

1. The Commission’s interpretation is consistent with the
plain language of PURA § 39.452(b).
Common definitions of “cost” are “the amount of money that is needed to

pay for or buy something” and “expenditure.” 96 As set out above, the Commission

carefully examined the expenditures that ETI would incur as a result of the

94
PURA § 36.006.
95
PURA § 39.452(b) (emphasis added).
96
Definition of “cost”, Merriamwebster.com, http://www.merriam-webster.com/dictionary/cost
(last visited Feb. 12, 2015).
23
program, but the record showed that ETI would not incur production expense or

any other types of costs that would not be recovered (other than costs to implement

and administer). Accordingly, the Commission’s decision is entirely consistent

with the plain language of PURA § 39.452(b). Further, to the extent there is any

ambiguity in the statute with respect to whether the statutory term “any costs

unrecovered as a result of” includes lost revenues, the Commission’s determination

is reasonable and is therefore entitled to deference. 97

ETI argues that the framework of § 39.452(b) somehow plainly indicates

that, because unrecovered costs must be ascertained in the same proceeding in

which the CGS tariff is approved, these “costs” must be based on the test year used

to set base rates.98 But ETI fails to point out that there is no requirement that the

Commission implement the CGS program in a base rate case in which test year

expenses and revenues are determined. The 2009 amendments to the CGS statute

removed the requirement that the CGS tariff be set in a rate case. 99 As amended,

the statute mandates that the Commission consider a CGS tariff by a date certain,

97
Texas Citizens for a Safe Future & Clean Water, 336 S.W.3d at 629. Notably, the ALJ in
Docket No. 37744 concluded that this term was vague. Supp. AR, Docket No. 37744, Item 37,
PFD at 30.
98
ETI’s Appellant’s Brief at 17.
99
Compare Act of May 24, 2005, 79th Leg., R.S., ch. 1072, § 1, 2005 Tex. Sess. Law Serv. 3559)
(HB 1567) with PURA § 39.452(b); see also Act of May 30, 2009, 81st Leg., R.S., ch. 1226, § 3,
2009 Tex. Sess. Law Serv. 3913, 3914 (SB 1492) (codified at PURA § 39.452(i)).
24
whether or not ETI filed a rate case. 100 So any notion of a base rate test year is

absent from § 39.452(b).

Further, ETI fails to explain how a bare reference to “costs that would be

unrecovered as a result of implementation of the tariff” correlates to a utility’s test

year revenue requirement in some imagined rate case. ETI’s attempt to assert

some statutory link between unrecovered costs and some unidentified rate case test

year is without merit.

2. The Commission’s decision is consistent with the
CenterPoint 2011 precedent.
Had the legislature intended that ETI be permitted to charge customers for

hypothetical lost revenues, it would have so stated. This is the crux of this Court’s

decision in CenterPoint 2011. In that case, CenterPoint, ETI, and other utilities

challenged one of the Commission’s energy efficiency rules, 101 which was intended

to encourage residential and commercial customers to reduce their usage through

energy efficiency measures.102 ETI and the other utilities argued that they should

be allowed to charge customers for their lost revenues resulting from energy

100
PURA § 39.452(b).
101
Centerpoint Energy Houston Electric, LLC v. Pub. Util. Comm’n, 354 S.W.3d 899 (Tex.
App.—Austin 2011, no pet.).
102
Rulemaking Proceeding to Amend Energy Efficiency Rules, Project No. 37623, Order at 1
(Aug. 9, 2010).
25
efficiency measures.103 The Court held, however, that in those rare instances in

which the legislature intended to allow a utility to charge ratepayers for a loss in

revenue, it has explicitly provided for recovery of a “loss of revenue” or a

“decrease in revenue.” 104 The Court therefore upheld the Commission’s order

denying a lost revenue adjustment mechanism very similar to the one proposed by

ETI here, explaining:

The legislature’s failure in PURA section 39.905 to specifically
provide for recovery of “lost revenues,” in addition to “costs,”
indicates that it intended for the EECRF [Energy Efficiency Cost
Recovery Factor] to serve as a mechanism for a utility to recover out-
of-pocket expenditures associated with its implementation of energy-
efficiency programs, not to compensate a utility for any associated
lost revenues attributable to those programs. 105

As the Court observed, “[i]n at least two other provisions of PURA, the

legislature expressly distinguishes ‘costs’ from ‘revenues,’ indicating that its use of

the term ‘costs’ by itself does not encompass lost revenues.” 106 The Court noted

that “PURA section 55.024(b) provides that a telecommunication utility may

recover ‘all costs incurred and all loss of revenue’ resulting from imposition of

charges for providing mandatory two-way extended area service to customers.” 107

103
AR Binder 4, Docket No. 38951, TIEC Ex. 24, Amicus Curiae Brief of Entergy Texas, Inc.,
El Paso Electric Company and Southwestern Electric Power Company at 3.
104
CenterPoint 2011, 354 S.W.3d at 903-04.
105
Id. at 904.
106
Id. at 903-04.
107
Id. at 904 (emphasis in original).
26
Similarly, “in PURA section 56.025(e), the legislature directed the Commission to

‘implement a mechanism to replace the reasonably projected increase in costs or

decrease in revenue’ caused by a governmental agency’s order, rule, or policy.”108

The Court concluded that, since the legislature expressly provided for recovery of

lost revenue when that was the intent, the absence of such language in the energy

efficiency provisions compelled the conclusion that such intent was absent.109

The Commission reasonably relied on this precedent. The Commission

found that, like the statutory language regarding energy efficiency cost recovery in

PURA § 39.905, “PURA § 39.452(b) only provides for ‘costs unrecovered as a

result of implementation of the tariff’ and does not specifically provide for the

utility to recover lost revenues or any other types of costs.” 110 The Commission’s

interpretation of the statute was consistent with the statutory language, reasonably

based on the evidence, and consistent with the CenterPoint 2011 precedent.

ETI’s attempts to distinguish the CenterPoint 2011 decision are unavailing.

ETI first tries to diminish the Third Court’s precedent by distinguishing the energy

efficiency statute, PURA § 39.905, from PURA § 39.452(b) on the basis that the

EECRF statute, PURA § 39.905, authorizes “cost recovery for utility expenditures

108
Id. at 904 (emphasis in original).
109
Id. at 903-04.
110
AR Binder 2, Docket No. 38951, Item 119, Final Order at 8.
27
made to satisfy the goal of this section . . .,” whereas the CGS statute, PURA

§ 39.452(b), requires that “rates shall be set . . . to recover any costs unrecovered as

a result of the implementation of the tariff.” 111 ETI ignores that the words costs

and expenditures are synonyms. 112 It also ignores the simple point of the

CenterPoint 2011 decision: when the legislature has intended to allow recovery for

lost revenues, it has expressly stated as much.

Indeed, the arguments that ETI unsuccessfully made in CenterPoint 2011

bear a striking resemblance to its contentions here. ETI’s chief point in both cases

was that the legislature created a program that will (i) cause ETI implementation

costs and (ii) allegedly result in lost revenues because of reduced demand caused

by the program. In CenterPoint 2011, ETI argued:

PURA section 39.905 requires electric utilities to incur two kinds of
costs: the cost of the utilities’ expenditures on energy efficiency
programs implemented under the statute, and the value of lost revenue
recovery due to depressed revenues that result from energy efficiency
measures. 113

Here, ETI asserts:

This new “competitive generation service” or “CGS” program costs
ETI money to develop and administer. It also costs ETI money in that
the CGS program permits eligible customers to contract for electric

111
ETI’s Appellant’s Brief at 22, 23 (emphases added).
112
Definition of “cost”, Merriam-Webster.com, http://www.merriam-
webster.com/dictionary/cost (last visited Feb. 12, 2015).
113
AR Binder 4, Docket No. 38951, TIEC Ex. 24, Amicus Curiae Brief of Entergy Texas, Inc.,
El Paso Electric Company and Southwestern Electric Power Company at 2.
28
 generation resources from alternative suppliers, which allows them to
avoid paying some of ETI’s costs that would otherwise be allocated to
them under ETI’s base rates. 114

In both cases, ETI argued that it should not only be entitled to the costs to

implement and administer the program at issue, but also to the revenues it would

have received in its absence. And in both cases, ETI argued that if the

Commission does not allow it to recover its lost revenues, it will be deprived of the

opportunity to recover its reasonable and necessary expenses. 115 The only real

difference between ETI’s approach in the two cases is its choice of nomenclature.

In CenterPoint 2011, ETI openly referred to its desire to recover “lost

revenues,” whereas in this case ETI frames the issue as one of “fixed production

costs,” 116 “embedded generation costs,”117 or “embedded production costs.”118 It is

abundantly clear, however, that ETI is still referring to lost revenues. The Court

properly rejected ETI’s claim for lost revenues in CenterPoint 2011, and it should

do the same here.

114
ETI Appellant’s Brief at 6.
115
AR Binder 4, Docket No. 38951, TIEC Ex. 24, Amicus Curiae Brief of Entergy Texas, Inc.,
El Paso Electric Company and Southwestern Electric Power Company at 4; ETI Appellant’s
Brief at 28.
116
ETI Appellant’s Brief at 23.
117
Id. at 9.
118
Id. at 15.
29
 3. ETI sought lost revenues at the Commission, not
unrecovered costs.
Relatedly, ETI tries to distinguish the CenterPoint 2011 case with its claim

that it “indisputably” sought only “costs” here, 119 when in fact that very claim was

hotly contested and ultimately rejected by the Commission.120 What ETI

characterized as costs, were, according to multiple witnesses, simply its lost

revenues.121 Relying on the PFD from Docket 37744, ETI states that “[n]one of

the experts in this case disputed that the CGS program could lead to unrecovered

‘costs’ of the type claimed by ETI.”122 Notably, ETI’s citation is to testimony

concerning the program initially proposed by ETI in Docket 37744 under which

the EOC required ETI to provide capacity for CGS customers even though they

were buying their electricity elsewhere. 123 Multiple witnesses testified that the

revised CGS program in Docket 38951—the program that was actually

approved—would not result in any costs that would be unrecovered as a result of

the program. 124 Mr. Pollock, for example, testified that under the CGS program

119
ETI’s Appellant’s Brief at 24.
120
AR Binder 2, Docket No. 38951, Item 119, Final Order at 7-8.
121
AR Binder 3, Docket No. 38951, Cities Ex. 6C, Nalepa Supp. Direct at 3, 7-8; AR Binder 4,
Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 14-15.
122
ETI’s Appellant’s Brief at 25 .
123
Id. at n. 35.
124
AR Binder 3, Docket No. 38951, Cities Ex. 6C, Nalepa Supp. Direct 3, 7-8; AR Binder 4,
Docket No. 38951, TIEC Ex. 27, Pollock Second Supp. Direct at 14-15.
30
adopted by the Commission, “no unrecovered costs would exist that need to be

allocated to other customers and customer classes.” 125

Indeed, ETI’s claim that it sought “costs” is based on its post-CenterPoint

2011 attempt to frame the relief it sought at the Commission as its “embedded

production costs” rather than its lost revenues. The term “embedded generation

costs” does not appear anywhere in PURA or the Commission’s Rules. 126 By

“embedded,” ETI means the “costs” that are contained in its rates. And when ETI

refers to “embedded generation costs,” it is not referring to costs that it incurs

because of the CGS program, but instead to the hypothetical revenues it will lose if

new customers buy CGS power instead of ETI’s power, or if existing customers

stop buying electricity from ETI. ETI essentially concedes as much in its brief. 127

That ETI sought lost revenues is also evident from the CGSUSC rider ETI

proposed in Docket 37744. As noted, ETI’s stated purpose for its proposed

CGSUSC rider was to “adjust rates for recovery of lost base rate revenue resulting

from customers participating in the [CGS progam].” 128 If that were not clear

enough, ETI’s witness Phillip May testified that ETI considered itself entitled to

125
AR Binder 4, Docket No. 38951, TIEC Ex. 15, Pollock Supp. Direct at 8.
126
Nor does “embedded production costs.”
127
ETI’s Appellant’s Brief at 24-26 (stating, for example: “What would have been billed may
logically be termed ‘revenues’”).
128
Supp. AR, Docket No. 37744, ETI Ex. 9, May Direct at Exhibit PRM-1 at 5.
31
lost revenues from CGS sales whether or not the utility had ever incurred

production costs to serve a CGS customer:

Q Okay. So your proposal for the CGSUSC Rider is to
calculate the difference between what would have billed -
- been billed under traditional LIPS service and the
amounts collected under the CGS service?
A That’s a fair characterization.

Q Okay. So let me get this straight. Under the
company’s proposal, if a brand-new industrial customer
came to you that had never received service from ETI
and they said, "We want to sign up for CGS," ETI would
still seek to recover lost revenues based on LIPS from
that customer?

A Yeah, I believe that is consistent with the
program . . . . 129

Mr. May’s testimony lays bare that ETI is attempting to recover revenues

regardless of whether it has ever incurred any cost to serve or even planned to

serve a customer. The Commission saw ETI’s use of “embedded generation costs”

for what it was—an attempt to repackage a lost revenue-theory that is foreclosed

by the plain language of PURA § 39.452(b) and CenterPoint 2011.

129
Supp. AR, Docket No. 37744, Transcripts, Vol. D, HOM Tr. at 165:23-166:11 (Jul. 16, 2010).
Mr. May confirmed at the Commission’s April 19, 2012 evidentiary hearing that ETI sought the
same lost-revenues relief in Docket No. 38951 that it sought in Docket No. 37744. Tr. At 72-73;
see also AR Binder 3, Docket No. 38951, ETI Ex. 91, May Supp. Direct at 5-8.
32
 4. The Commission’s rejection of ETI’s lost-revenues
theory is consistent with the purposes of the CGS statute.
ETI’s proposal is also inconsistent with the purposes of the CGS program.

Two of the legislative purposes for the program were to provide the industrial base

in ETI’s region with some opportunity to shop for more competitive power, and to

ensure that residential customers were well served. 130 ETI’s proposal that it be

permitted to recover hypothetical lost revenues detached from any cost it actually

incurs as result of the CGS program serves neither purpose. As ETI is at pains to

point out in its brief, if it is entitled to recover these revenues, someone will have

to pay for them. If it is all customers other than the CGS participants that must

pay, this will harm the legislative goal that residential consumers be served well.

If the CGS participants themselves were charged for the very revenues that ETI

would have collected but for their decision to take CGS service, there would,

needless to say, be no incentive to sign up.

As the Commission recognized, ETI’s interpretation of the statute is

unreasonable and would only serve to torpedo the entire program. For example, at

the evidentiary hearing on the revised CGS program in Docket 38951, Chairman

Donna Nelson stated:

130
Supp. AR, Docket No. 37744, Item 19, Initial Brief of TIEC, Attachment 1, Transcript of
Proceedings before the Texas State Senate 81st Legislature, Senate Committee on Business and
Commerce, at 9-10 (Apr. 14, 2009). Video of the proceedings can be found at
http://www.senate.state.tx.us/75r/senate/commit/c510/c510.htm.
33
 Well, and I guess I would say I’m not going to say this is my final
conclusion, but I would say it would seem to me that if you follow
Entergy’s logic in this case, you would end up with an absurd result
and a program that doesn’t work. So I’m not going to say one way or
the other because I’m certainly going to review everything, but I can’t
see how you arrive at any other conclusion. 131

Chairman Nelson’s concerns with ETI’s lost-revenues proposal were well placed.

The Commission properly rejected it.

5. High Plains is inapposite.
ETI’s reliance on the High Plains Natural Gas case to justify its position is

misplaced.132 High Plains Natural Gas, which was decided more than thirty years

ago, did not fundamentally alter PURA Chapter 36’s ratemaking framework. The

case does not stand for the proposition that utilities may recover lost revenues or

costs they do not incur. Rather, in High Plains Natural Gas, the Texas Supreme

Court examined the issue of whether PURA allowed the Railroad Commission to

utilize a purchase gas adjustment to compensate for increased fuel costs after a

base rate case had concluded. Examining a PURA article that stated “[i]n fixing

the rates of a public utility the regulatory authority shall fix its overall revenues at a

level which will permit such utility to recover its operating expenses together with

a reasonable return on its invested capital,” the court held that this “mandates that

131
AR Binder 5, Docket No. 38951, Transcripts, Vol. B, HOM Transcript at 207-208 (Apr. 19,
2012).
132
ETI Initial Brief at 18-19 (discussing R.R. Comm’n v. High Plains Natural Gas Co., 628
S.W.2d 753 (Tex. 1981) (per curiam)).
34
the Commission structure a system that will permit the utility to recover all of its

operating expenses.”133 The Public Utility Commission has done this through its

Chapter 36 ratemaking process, which has been in place for many years.

F. Contrary to ETI’s contentions, the Commission’s decision was
based on a vast evidentiary record, not “solely upon its
interpretation of the CGS statute”
ETI argues that “the Commission did not reach the issue of how much of

ETI’s costs will be unrecovered as a result of implementing the CGS program,

because the Commission defined the term “unrecovered costs” in a way that

precludes the issue from arising. This is simply incorrect. It is true that the

Commission concluded as a matter of law that PURA § 39.452(b)‘s reference to

“costs unrecovered” does not encompass ETI’s recovery theory because, regardless

of whether ETI called them “lost base rate revenues” or “embedded production

costs,” ETI was seeking to charge for lost revenues, not costs. However, the

Commission also embarked on a factual inquiry into what costs actually would be

unrecovered. Indeed, before the Commission issued its order regarding ETI’s

unrecovered costs in Docket 38951, it considered extensive supplemental

testimony on the revised CGS framework, including testimony regarding the

definition, existence, and calculation of any costs that would be unrecovered as a

133
High Plains Natural Gas, 628 S.W.2d 753, 753 (construing Tex. Rev. Civ. Stat. Ann. art.
1446c).
35
result of the new proposal. The Commission then held an additional evidentiary

hearing on the revised program and the issue of unrecovered costs. The

commissioners even took the unusual step of conducting this hearing personally

rather than referring the case to SOAH.

Having considered the evidence on the new CGS proposal, the Commission

made detailed findings on its mechanics. 134 As discussed above, the Commission

also made detailed findings on ETI’s resource position and its projected future

capacity shortfall.135 These latter findings in particular would be completely

superfluous if the Commission’s order was based purely on statutory construction.

Based on all of its subsidiary findings, the Commission made its ultimate finding

(Finding of Fact 51) that “the costs that will be unrecovered as a result of the

implementation of the CGS program tariff are the costs to implement and

administer the CGS program tariff.” 136

Unable to contest this finding on the evidence, ETI resorts to distraction.

Specifically, ETI plucks words like “defined,” and “interpretation” out of context

in an attempt to show that the Commission’s decision was based on the statute

134
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 32.
135
Id. at 42-43.
136
AR Binder 2, Docket No. 38951, Item 119, Final Order at FoF 51.
36
alone.137 Notably, in making this argument, ETI quotes several passages from the

Commission’s order, but is careful not to quote the operative finding, Finding of

Fact 51. Further, the passages relied upon by ETI do not prove its point. For

example, ETI cites a passage in which the Commission used the word

“interpretation.” However, the cited sentence is explicit that the Commission’s

decision was “Based on the evidence and testimony.” 138 How this sentence could

possibly indicate that the Commission based its decision purely on statutory

construction is a mystery.

ETI’s contention that the Commission defined unrecovered costs in a

manner that would categorically exclude the recovery of its production costs is also

belied by the order. The Commission never stated that ETI’s only costs eligible for

consideration under the statute are CGS implementation and administration costs.

It determined that these were the only costs that actually would be unrecovered.

Indeed, there is no dispute that ETI will incur production costs to provide back-up

power to a CGS customer. However, the parties stipulated that the CGS customer

would pay for that power under the program, which stipulation the Commission

expressly noted in its finding of facts.139 If there were no provision for ETI

recovering its back-up power production costs, the Commission would have

137
ETI Appellant’s Brief at 29.
138
AR Binder 2, Docket No. 38951, Item 119, Final Order at 8.
139
Id. at FoF 41E&F.
37
properly found that they were unrecovered costs under the statute. But this was

simply not the case with the program the Commission evaluated.

Agency orders are construed as a whole to ascertain the intent of the

administrative body. 140 As the Texas Supreme Court has put it, “[t]here is no

precise form for an agency’s articulation of underlying facts, and courts will not

subject an agency’s order to some “hypertechnical standard of review.” 141 In this

case, the order makes clear that the Commission made a factual finding as to what

actual costs would be unrecovered. That finding is supported by substantial

evidence and should be upheld.

II. The Commission properly rejected ETI’s request to surcharge legal and
regulatory costs incurred from 2010 to 2013 as costs of implementation.
ETI’s argument in its second issue is that the Commission is required to

adopt a special rider for costs related to the CGS program that were incurred prior

to any determination that there would even be a CGS program. ETI’s argument

fails for two principal reasons.

First, the costs of which ETI complains would have been incurred whether

or not a CGS tariff was implemented. Had the Commission decided to reject a

140
Office of Pub. Util. Counsel v. Texas-New Mexico Power Co., 344 S.W.3d 446, 450-51 (Tex.
App.—Austin 2011, pet. denied) (citations omitted).
141
State Banking Bd. v. Allied Bank Marble Falls, 748 S.W.2d 447, 449 (Tex. 1988).
38
CGS tariff, as many parties repeatedly invited it to do, 142 there would have been no

implementation of a CGS tariff whatsoever, and accordingly, there could have

been no costs unrecovered as a result of the implementation of the tariff.143 Any

costs incurred in the regulatory process leading up to a decision of whether to

implement a tariff are subject to the Commission’s standard ratemaking

procedures.

Costs prior to the Commission’s decision to implement a tariff were not

caused by the “implementation of the tariff,” they were caused by the statutory

mandate to delay competition and for ETI to propose a competitive generation

tariff, which the Commission was authorized to implement or not. They are among

the many regulatory costs that utilities incur to comply with statutory mandates,

and they would have been incurred whether or not a CGS tariff was actually

implemented by the Commission. The Commission’s decision that costs incurred

before any decision to implement a CGS tariff cannot be deemed to be “as a result

of the implementation of the tariff” within the meaning of PURA § 39.45(b) was

correct.

Second, the record before the Commission showed that ETI had actually

sought and was recovering pre-implementation costs related to the CGS program

142
Supp. AR, Docket No. 37744, State Ex. 2, Pevoto Direct at 38; Supp. AR, Docket No. 37744,
Cities Ex. 6, Nalepa Direct at 60; AR Binder 4, Docket No. 38951, Kroger Ex. 2, Townsend
Direct at 7.
143
PURA § 39.452(b) (emphasis added).
39
through its base rates. At the time of the final hearing in Docket 38951, ETI had

already been allowed to include $310,746 per year in CGS-related costs in its base

rates. 144 The record in this case does not reflect how long those base rates have

been in effect, how much ETI has recovered in CGS-related regulatory costs

through those base rates, or how much of CGS-related costs continue to be

included in base rates. Accordingly, there is no evidence in the record to indicate

whether ETI has over-collected or under-collected its actual pre-implementation

CGS-related costs.

In any case, there is no basis for requiring the Commission to ensure that the

previously approved base rates recovered exactly the amount of ETI’s pre-

implementation CGS costs. It is fundamental to ratemaking that the level of the

utility’s actual costs are constantly changing. Indeed, before the ink is dry on a

final order, a utility will be experiencing higher costs in some categories and lower

costs in other categories. Nothing in PURA requires the PUC to allow ETI to take

one shot at recovering pre-implementation CGS costs through base rates and

another shot through a special CGS rider.

144
AR Binder 3, Docket No. 38951, ETI Ex. 103, Roach Supp. Rebuttal at 3 n.2 (recognizing
that ETI’s current retail base rates include $299,372 in costs related to the CGS program for
Total Retail, $11,374 for Wholesale, for a Total Company amount of $ 310,746).
40
 ETI’s reliance on CenterPoint Energy Houston Electric, LLC v. Public

Utility Commission (“CenterPoint 2013”) 145 is also misplaced. In CenterPoint

2013, the Third Court of Appeals held that the Commission misapplied an energy

efficiency rule by excluding from the calculation of a utility’s performance bonus a

portion of the money that the utility had spent administering energy efficiency

programs. 146 The Commission did not award CenterPoint the full amount of the

performance bonus it had sought, arguing that because a portion of the money

spent on the programs had been spent under a settlement agreement, and not

specifically pursuant to the Commission’s rule, that portion was not considered

eligible for the bonus program outlined in the rule.147 Importantly, it was

undisputed that the utility had administered various energy efficiency programs for

which it had actually incurred costs.148 The appellate court held that because

CenterPoint had spent money on energy efficiency programs that surpassed their

goal of consumption reduction, the costs that CenterPoint had actually incurred

should be considered when calculating the utility’s bonus.149

CenterPoint 2013 is inapposite because, unlike ETI, CenterPoint did not

seek to recover the money it spent prior to implementing the energy efficiency

145
408 S.W.3d 910 (Tex. App.—Austin 2013, pet. denied).
146
CenterPoint 2013, 408 S.W.3d at 922.
147
Id. at 917.
148
Id. at 918.
149
Id. at 921.
41
programs. Rather, the utility sought to include the costs that it had actually incurred

to administer its energy efficiency programs in the calculation of its performance

bonus. These costs related to the actual administration of energy efficiency

programs, whereas the costs that ETI seeks to recover here do not relate to

administration of a CGS program, but rather to regulatory proceedings that were

required whether or not a CGS program would be implemented. The

Commission’s decision to deny a surcharge for ETI’s pre-implementation costs

should be affirmed.

III. The Commission properly rejected ETI’s request for interest on CGSC
rider costs.
ETI can point to no statutory requirement that the Commission allow interest

on the costs of CGS implementation, and utilities are not typically entitled to

interest on expenses. The Commission’s decision should be upheld.

A. When the legislature intends to award carrying costs, it says so.
ETI argues that it is entitled to recover its interest on implementation costs

because it believes PURA § 39.452(b) gives it a right to recover “all costs”

associated with the program, including interest. 150 ETI overstates what it claims to

be its CGS entitlement. 151 Notably, where PURA has mandated carrying costs, it

has specifically stated. There are provisions that expressly provide for recovery of

150
ETI’s Appellant’s Brief at 34.
151
See id. at 36 (“ETI is statutorily entitled to recover . . . interest.”).
42
carrying costs in PURA, but PURA § 39.452(b) is not one of them. For example,

PURA § 36.402(b) provides that system restoration costs for a hurricane “shall

include carrying costs at the utility’s weighted average cost of capital.” PURA

§ 39.4525(d), which authorizes special hiring assistance for federal proceedings,

provides: “the commission shall allow the electric utility to recover both the total

costs the electric utility paid under Subsection (c) and the carrying charges for

those costs through a rider established annually to recover the costs paid and

carrying charges incurred during the preceding calendar year.” PURA § 39.454,

which authorizes recovery for ETI’s transition to competition charges, provides

that “[a] rate rider implemented to recover approved transition to competition costs

shall provide for recovery of those costs over a period not to exceed 15 years, with

appropriate carrying costs.” PURA § 39.459, which relates to hurricane

reconstruction costs, provides: “[i]f the commission determines it to be

appropriate, hurricane reconstruction costs may include carrying costs from the

date on which the hurricane reconstruction costs were incurred until the date that

transition bonds are issued.” PURA § 36.061, which authorizes bill payment

assistance costs for military veterans, provides that the electric utility is entitled to

“apply carrying charges at the utility’s weighted average cost of capital to the

extent related to the bill payment assistance program.” The legislature knows how

43
to specify the recovery of interest on program costs, and it chose not to do so with

the CGS program.

These provisions in PURA indicate that the legislature did not intend for the

recovery of carrying costs on CGS costs; otherwise, the CGS statute would include

an explicit provision allowing it. A cardinal principle of statutory construction is

that if items are listed specifically, items not mentioned are excluded, unless

otherwise stated.152 Similarly, if a term such as “carrying costs” is specified in one

section of a statute (PURA §§ 36.402(b), 36.061(c)(3), 39.4525(d), 39.454, and

39.459(b)), but omitted in another section, it is presumed that the legislature did

not intend to include it in the latter section. 153 Applying these principles of

statutory construction, it is clear that the legislature did not require interest on CGS

costs.

B. The Commission has not allowed interest to be recovered on
similar expenses.
In reaching its determination that there was no need for interest on CGSC

rider costs, the Commission analogized these costs to rate case expenses. The

Commission does not allow interest to accrue on the unamortized balance of rate

152
Laidlaw Waste Sys., Inc. v. City of Wilmer, 904 S.W.2d 656, 659 (Tex. 1995).
153
Id. (“When the Legislature employs a term in one section of a statute and excludes it in
another section, the term should not be implied where excluded.”).
44
case expenses. 154 The Commission has a precedent of disallowing the recovery of

interest in such instances. 155 For example, in Docket 30706, CenterPoint Energy

sought to recover its rate case expenses over three years with a return on the unpaid

balance. The Commission rejected CenterPoint’s request for interest, explicitly

noting its “practice of not permitting utilities to receive interest on unpaid rate-case

expenses.”156

Not allowing interest on CGS implementation costs is consistent with the

treatment of rate case expenses, which are typically amortized over a three-year

period without a return on the unamortized balance.157 ETI cites no Commission

precedent allowing a return on the unamortized amount of rate-case expenses.

There is ample and longstanding Commission precedent, however, that denies the

154
AR Binder 2, Docket No. 38951, Item 119, Final Order at 10. Utilities and municipalities are
reimbursed for legal expenses incurred during rate cases. PURA §§ 36.061(b)(2), 33.023.
155
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
22355, Order at FoF 98G (Oct. 4, 2001) (“The Commission finds that Reliant should not earn a
return on the outstanding balance of its rate case expenses.”). See also Petition of Texas Electric
Service Co. for Authority to Change Rates, Docket 2606, 5 P.U.C. BULL. 109 (Oct. 16, 1979)
(finding that in amortizing legal expenses arising from previous Commission investigation and
prior rate case, Commission refused to include requested carrying charge in utility’s cost of
service as an allowance for the time value of money); Complaint of the City of McKinney
Against Southwestern Bell Telephone Company, Docket 11027, Final Order at CoL 9 (May 17,
1995) (noting that nothing “in PURA authorizes McKinney to recover interest on its rate case
expenses.”).
156
Application of CenterPoint Energy Houston Electric, LLC for a Competition Transition
Charge, Docket 30706, Order at 32 (Jul. 14, 2005).
157
AR Binder 4, Docket No. 38951, TIEC Ex. 27, Pollock Second Supp. Direct at 27.
45
recovery of interest on these types of costs. 158 Further, this Court has affirmed the

Railroad Commission’s refusal under PURA to allow a utility to recover interest

on its rate-case expenses.159

Lastly, ETI mistakenly relies on CenterPoint Energy, Inc. v. Public Utility

Commission (“CenterPoint 2004”).160 That case dealt with the unique situation of

the calculation of stranded costs for utilities that were subject to deregulation. ETI

continues to be subject to traditional cost-of-service regulation. Nothing in

CenterPoint 2004 suggests that the Commission’s longstanding practice of not

allowing interest on expenses is unlawful.

Contrary to ETI’s assertion, utilities have no general right to charge interest

on expenses. The Commission’s denial of interest is consistent with PURA and

should be upheld.

PRAYER
For all the foregoing reasons, TIEC prays that the Court affirm the district

court’s judgment in all respects and grant TIEC all other such relief to which it

may show itself justly entitled.

158
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
22355, Order at 61 n.130 (Oct. 4, 2001).
159
Moran Util. Co. v. R.R. Comm’n, 697 S.W.2d 447, 452 (Tex. App.—Austin 1985, pet.
granted) (aff’d in relevant part, rev’d in part, 728 S.W.2d 764 (Tex. 1987)).
160
ETI Appellant’s Brief at 35-36 (citing CenterPoint Energy, Inc. v. Pub. Util. Comm’n, 143
S.W.3d 81, 83 (Tex. 2004)).
46
 Respectfully submitted,

/s/ Rex D. VanMiddlesworth
Rex D. VanMiddlesworth
State Bar No. 20449400
Benjamin Hallmark
State Bar No. 24069865
THOMPSON & KNIGHT LLP
98 San Jacinto Blvd., Suite 1900
Austin, TX 78701
Telephone: (512) 469-6100
Facsimile: (512) 469-6180

ATTORNEYS FOR APPELLEE TEXAS
INDUSTRIAL ENERGY CONSUMERS

CERTIFICATE OF COMPLIANCE
I certify that this document contains 11,437 words in the portions of the

document that are subject to the word limits of Texas Rule of Appellate Procedure

9.4(i), including the Glossary of Abbreviations, as measured by the undersigned’s

word-processing software.

/s/ Benjamin Hallmark

47
 CERTIFICATE OF SERVICE
As required by Texas Rule of Appellate Procedure 9.5, I certify that on the

13th day of February, 2015, 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

listed below via electronic service:

Counsel for Entergy Texas, Inc. David C. Duggins
John F. Williams
Marnie A. McCormick
Duggins Wren Mann & Romero, LLP
600 Congress Ave., Ste. 1900
Austin, Texas 78701

Counsel for the Public Utility Commission Elizabeth R. B. Sterling
of Texas Megan M. Neal
Environmental Protection Division
Office of the Attorney General
P.O. Box 12548
Austin, Texas 78711-2548

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

/s/ Benjamin Hallmark

48
 APPENDIX

D. 38951 – Excerpt from Supplemental Direct Testimony
and Exhibits of Jeffry Pollock

49
 PUC DOCKET NO. 38951

§
APPLICATION OF ENTERGY §
TEXAS, INC. FOR APPROVAL OF § PUBLIC UTILITY
COMPETITIVE GENERATION §
SERVICE TARIFF (ISSUES § COMMISSION OF TEXAS
SEVERED FROM DOCKET NO. §

~
37744)

Supplemental Direct Testimony and Exhibits

of

JEFFRY POLLOCK

On Behalf of

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February, 2012

}.POLLOCK

1
 Jeffry Pollock
Supplemental Direct
Page 14

3. UNRECOVERED COSTS FROM THE CGS PROGRAM

1 Q WHY IS THE ISSUE OF THE DEFINITION OF "UNRECOVERED COSTS" BEING

2 ADDRESSED IN THIS PROCEEDING?

3 A PURA § 39.452(b) provides that Ell's rates "shall be set, in the proceeding in which

4 the tariff is adopted, to recover any costs unrecovered as a result of the

5 implementation of the tariff." ETI and TIEC do not agree about what "costs" this

6 refers to. Just as ETI and other utilities unsuccessfully argued with respect to energy

7 efficiency program costs, ETI claims the reference to "costs" would allow it to recover

8 not just its actual expenditures in implementing a CGS Program but also hypothetical

9 lost revenues ETI may have received if all CGS Customers paid Ell's full firm rate

10 instead. ETI's proposed Rider CGSUSC clearly states that it "defines the procedure

11 by which Entergy Texas, Inc. ('Company') shall implement and adjust rates for

12 recovery of lost base rate revenue resulting from customers participating in the

13 Company's Competitive Generation Service ('CGS Program')." 1 (emphasis added)

14 Definition of Unrecovered Costs

15 Q HOW SHOULD UNRECOVERED COSTS BE DEFINED?

16 A Unrecovered costs should not include ETI's hypothetical lost revenues. If a CGS

17 tariff is adopted, the costs that could be unrecovered as a result of implementation of

18 the tariff should include the expenditures actually incurred by ETI to implement and

1
Docket No. 37744, ETI Ex. 9 at Exhibit PRM-1.

3. Unrecovered Costs From the CGS Program

J.POLLOCK
INCORPORATED

15
 Jeffry Pollock
Supplemental Direct
Page 15

1 maintain a CGS Program, as well as the cost of providing backup power to CGS

2 Customers. All of those costs should be fully paid by the CGS Customers.

3 Q WHAT EXPENDITURES WOULD ETI INCUR TO IMPLEMENT AND MAINTAIN

4 THE CGS PROGRAM ONCE THE PROGRAM IS ADOPTED?

5 A ETI witness, Mr. Phillip R. May, has stated that ETI will incur both start-up and on-

6 going costs associated with the CGS Program. This will include costs related to

7 incremental implementation and ongoing operating costs incurred to support the

8 CGS Program. 2 According to Mr. May:

9 ETI must modify its Customer Information System ("CIS") and Large
10 Power Billing Systems ("LPBS") within its Major Account Billing
11 function to support the CGS Program as it is currently designed.

12 In addition to the initial implementation costs explained above, the
13 CGSC Rider will also recover incremental on-going costs incurred to
14 support the CGS Program. These incremental costs are primarily
15 focused around the Major Accounts Billing and its systems support. 3

16 Q HOW SHOULD THESE COSTS BE RECOVERED?

17 A As I discussed in my testimony in Docket No. 37744, these costs should be

18 recovered from CGS Customers based on a fixed monthly charge. ETI's program

19 development and ongoing costs will depend on the scope of the program that is

20 ultimately approved.

21 Q WHAT COSTS WILL ETI INCUR TO PROVIDE BACKUP POWER?

22 A ETI will provide generation services when a CGS Supplier cannot provide the CGS

23 Contract Capacity in any given hour (provided that the CGS Customer has not
2
Docket No. 37744, Direct Testimony of Phillip R. May at 14.
3
/dat 19.

3. Unrecovered Costs From the CGS Program

J.POLLOCK
INCORPORATED

16
---------------------------------------------------- --

Jeffry Pollock
Supplemental Direct
Page 16

1 simultaneously curtailed its CGS load). Thus, ETI will incur additional fuel and other

2 variable costs as well capacity costs to stand ready to provide backup service.

3 Q HOW WILL THE COSTS OF BACKUP POWER BE RECOVERED?

4 A The costs of backup power will be paid for by CGS Customers through the Unserved

5 Energy Rate and a Fixed Cost Contribution Fee referenced in the Stipulation.

6 Unserved Energy will be priced at 105% of avoided energy cost plus an O&M Adder.

7 This is similar to how ETI currently prices backup power in Schedule SMS. 4 In

8 addition, the CGS Customer will be required to pay a Fixed Cost Contribution Fee of

9 $1.10 per kW-Month of CGS Contract Capacity. The Unserved Energy pricing

10 mechanism ensures that CGS Customers pay all of the incremental variable costs

11 associated with back-up power plus a contribution to generation fixed costs.

12 Q WOULD ANY UNRECOVERED COSTS EXIST AFTER START-UP, ON-GOING

13 AND BACKUP POWER COSTS ARE PAID BY THE CGS CUSTOMER?

14 A No. Recall that, under the CGS Program described in the Stipulation, the CGS

15 Customer would effectively buy its own capacity and energy from the CGS Supplier.

16 With the exception of the capacity credit and fixed fuel factor, a CGS Customer will

17 pay ETI a retail rate that includes all other charges the customer would pay as a firm

18 customer, including a transmission and distribution rate and all other applicable

19 tariffs (e.g., Rider TTC, HRC, SRC, SCO, AFC and FF charges, if applicable). There

20 would be no other unrecovered costs.

4
The same O&M Adder is also used in Schedule SMS. In addition, Schedule SMS customers pay for
energy at 100% of avoided cost rather than 105%.

3. Unrecovered Costs From the CGS Program

J.POLLOCK
INCORPORATED

17
 Jeffry Pollock
Supplemental Direct
Page 17

1 Hypothetical Lost Revenues Are Not Unrecovered Costs

2 Q WHAT IS ETI'S DEFINITION OF UNRECOVERED COSTS?

3 A In addition to start-up, on-going, and backup power costs, ETI defines its

4 unrecovered costs as lost base rate revenue from CGS Customers. As described in

5 its proposed Rider CGSUSC tariff in Docket No. 37744, the purpose of its Rider

6 CGSUSC is as follows:

7 This Competitive Generation Service Unrecovered Service Cost
8 Rider ("Rider CGSUSC" or "Rider") defines the procedure by
9 which Entergy Texas, Inc. ("Company") shall implement and adjust
10 rates for recovery of lost base rate revenue resulting from
11 customers participating in the Company's Competitive Generation
12 Service ("CGS Program"). The purpose of this Rider is to provide
13 a mechanism for recovery of such lost base rate revenues that
14 were included in the Company's last general rate case proceeding
15 before the Public Utility Commission of Texas ("PUCT").
16 (emphasis added)5

17 Thus, ETI asserts that lost revenues and unrecovered costs are the same.

18 Q HOW DOES ETI CALCULATE UNRECOVERED COSTS FROM LOST BASE

19 RATE REVENUES?

20 A ETI is proposing to calculate unrecovered costs based on the revenues associated

21 with the generation cost components reflected in the ETI firm rate that would

22 otherwise apply to the CGS Customer. Lost revenues are the product of generation-

23 related charges (e.g., $6.84 per kW-Month for the current LIPS rate based on the

24 rates established in Docket No. 37744) and the amount of CGS load, less certain

25 offsets.

5
Docket No. 37744, ETI Ex. 9 at Exhibit PRM-1.

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1 Q WHAT ARE THOSE OFFSETS?

2 A ETI proposes to reduce lost revenues to reflect the following off-setting revenue

3 contributions/cost reductions:

4 1. The Fixed Cost Contribution Fee of $1.10 per kW-Month;
5 2. Revenues from the Variable O&M Adder when Unserved Energy is
6 provided; and
7 3. A reduction in Schedule MSS-1 payments to the other Entergy
8 operating companies as a result of treating CGS as firm capacity,
9 which ETI calculates as $3.10 per kW-Month.
10 These offsets are shown in ETI's Exhibit PRM-4. ETI calculates net unrecovered

11 costs at current rates of $2.64 kW-Month, less whatever offset would result from the

12 O&M Adder.

13 Q ARE LOST REVENUES AND COSTS THE SAME THING?

14 A No. Costs are ETI's actual expenditures to serve a CGS Customer, not its

15 anticipated revenues from hypothetical lost sales to customers.

16 Q ARE YOU FAMILIAR WITH ANY COMMISSION PRECEDENT REGARDING THE

17 ISSUE OF WHETHER A UTILITY'S COSTS MAY INCLUDE LOST REVENUES?

18 A Yes. I am aware that the Commission in Project No. 37623 and Docket No. 38213

19 rejected a lost revenues approach to determining costs associated with energy

20 efficiency programs and that the Commission's decision has been upheld by the

21 courts, most recently in a 2011 Court of Appeals decision.

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1 Q DID THE COURT OF APPEALS DISCUSS THE DISTINCTION BETWEEN

2 "COSTS" AND "LOST REVENUES"?

3 A Yes. The court specifically found that the term "costs" in PURA is not intended to

4 include lost revenues, stating as follows:

5 In at least two other provisions of PURA, the legislature
6 expressly distinguishes "costs" from "revenues," indicating that its use
7 of the term "costs" by itself does not encompass lost revenues. For
8 example, PURA section 55.042(b) provides that a telecommunications
9 utility may recover "all costs incurred and all loss of revenue" resulting
10 from imposition of charges for providing mandatory two-way extended
11 area service to customers. See Tex. Util. Code Ann. § 55.042(b)
12 (West 2007) (emphasis added). In PURA section 56.025(e), the
13 legislature directed the Commission to "implement a mechanism to
14 replace the reasonably projected increase in costs or decrease in
15 revenue" caused by a governmental agency's order, rule, or policy.
16 See id. § 56.025(e) (West 2007) (emphasis added). These
17 provisions further support our conclusion that the term "costs,"
18 as used by the legislature in PURA, is not intended to include
19 lost revenues. The legislature's failure in PURA section 39.905 to
20 specifically provide for recovery of "lost revenues," in addition to
21 "costs," indicates that it intended for EECRF to serve as a mechanism
22 for a utility to recovery out-of-pocket expenditures associated with its
23 implementation of energy-efficiency programs, not to compensate a
24 utility for any associated lost revenues attributable to those programs.
6
25 (emphasis added)

26 Q ARE THERE ANY POLICY REASONS TO ALLOW ETI TO RECOVER LOST

27 REVENUES THAT IT ATTRIBUTES TO THE CGS PROGRAM?

28 A No. As previously discussed, the CGS Program would allow a retail customer to

29 replace ETI generation service with electricity provided from a QF in Ell's service

30 area. This is no different than a customer that chooses to install generation or

31 energy efficiency to displace the service that would otherwise be provided by ETI.

6
CenterPoint Energy Houston Elec., LLC v. Public Utility Com'n, 354 S.W.3d 899 (Tex.App.-
Austin, 2011).

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1 Q IS ETI ALLOWED TO RECOVER LOST REVENUES FROM A CUSTOMER THAT

2 INSTALLS EITHER SELF-GENERATION OR ENERGY EFFICIENCY?

3 A No. Given that there is no difference between CGS, installing self-generation, and

4 energy-efficiency in terms of its impact on the regulated utility, it would not be good

5 public policy to treat the CGS Program differently from either self-generation or

6 energy efficiency. The utility should not be allowed to recover more than the actual

7 costs of providing the service associated with a particular program.

8 Q ARE THERE OTHER POLICY REASONS TO REJECT ETI'S LOST REVENUE

9 APPROACH?

10 A Yes. ETI's lost revenue approach assumes that it would have provided generation

11 services to all loads that opt to participate in the CGS Program. 7 This is not a valid

12 assumption. For example:

13 • An existing self-generation customer could choose to replace its
14 existing generation with CGS power because CGS power is more
15 economical than generation services purchased from ETI;
16 • A customer could restart an idled facility because the CGS Program
17 makes the restart economically viable;
18 • An existing ETI customer could decide to add facilities, or;
19 • A new customer could locate in ETI's service area because electricity
20 is less expensive under the CGS Program than under ETI's other
21 ~ri~.

22 In each of these scenarios, the customer would not have purchased generation

23 services from ETI under a firm rate. ETI clearly cannot claim that it lost any

24 revenues as a result of the CGS Program in these instances. In fact, ETI would

7
ETI's Response to TIEC 1-9.

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1 enjoy higher revenues. Yet, all of these scenarios would be counted in ETI's

2 definition of lost revenues.

3 There are No Lost Revenues

4 Q IF THE COMMISSION ADOPTS ETI'S LOST REVENUES APPROACH TO

5 CALCULATING COSTS, WOULD ETI EXPERIENCE ANY UNRECOVERED

6 COSTS AS A RESULT OF THE IMPLEMENTATION OF THE PROGRAM?

7 A No.

8 Q PLEASE EXPLAIN.

9 A ETI's lost revenues approach is flawed because it has failed to recognize the impact

10 of its increased revenues from load growth. With the proposed cap, the CGS

11 Program would at most have the effect of slowing ETI's load growth, not reducing its

12 load. As load grows, each additional kW and kWh sold will provide a contribution to

13 all fixed costs, including embedded generation capacity costs. Any reduction in

14 embedded generation cost recovery that may be attributable to the CGS Program

15 may be more than offset by the increased revenues resulting from load growth.

16 Stated differently, as long as ETI continues to collect the same amount of revenue or

17 more as its embedded generation costs established for a test-year, it cannot claim

18 that any costs are unrecovered, irrespective of how it defines unrecovered costs.

19 Instead, those costs are simply being recovered from new customers or through

20 growth in the demand of existing customers.

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1 Q CAN YOU PLEASE PROVIDE AN EXAMPLE OF HOW LOAD GROWTH WOULD

2 OFFSET Ell'S LOST REVENUES FROM A CUSTOMER THAT GOES ON THE

3 CGS PROGRAM?

4 A Yes. Assume a hypothetical utility's base rates are set based on test year sales of

5 1,000 MW. Then assume in a subsequent year the utility has 1,000 MW of firm load

6 plus 100 MW of load associated with a CGS Customer that provides its own

7 generation. In this simplified example, the utility has clearly experienced no

8 unrecovered capacity costs associated with the 100 MW CGS Customer. It is still

9 responsible for providing capacity for 1000 MW of firm load, and it receives revenues

10 from 1,000 MW of firm load.

11 Q IS ETI CONTINUING TO EXPERIENCE LOAD GROWTH?

12 A Yes. Exhibit JP-2 quantifies the growth in sales experienced by ETI since its last

13 rate case. As can be seen, ETI is serving 10,515 (2.6%) more customers, selling

14 887 million (5.9%) more kWh, and the billing demand for the demand metered

15 classes has increased by 1. 7 million kW (7 .2%) since the last rate case.

16 Q IS ETI PROJECTING LOAD GROWTH OVER ITS PLANNING HORIZON?

17 A Yes. Exhibit JP-3 is an excerpt from Entergy's Strategic Resource Plan (SRP)

18 Refresh. It shows the projected long-term load growth for each operating company,

19 including ETI. As can be seen, ETI is projecting load growth through the year 2029.

20 On average, ETI's projected annual growth is about 2%, which translates into about

21 80 MW per year. Over the next five years, projected load growth will average nearly

22 74 MW per year.

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1 Q WOULD THE ADDITIONAL REVENUES DERIVED FROM ETI'S PROJECTED

2 LOAD GROWTH MORE THAN OFFSET ETI'S CLAIMED LOST REVENUES?

3 A Yes. This is shown in Exhibit JP-4. The starting point for the analysis is the lost

4 revenues per kW calculated in ETI's Exhibit PRM-4, line 6. Assuming that the

5 maximum 150 MW of load were to subscribe to CGS service, ETI would calculate

6 annual lost revenues at $4.8 million at current rates {line 2). However, each

7 additional kilowatt of load would generate $6.84 per kW of additional capacity-related

8 revenue (line 3). At this rate, ETI would have to experience only 58 MW of load

9 growth to fully offset the lost revenues (line 4 ).

10 Q WOULD THE RESULTS CHANGE MATERIALLY IF THE RATES THAT ETI IS

11 PROPOSING TO IMPLEMENT IN ITS PENDING RATE CASE WERE ADOPTED?

12 A No. For illustration only, I have also analyzed the impact if the rates proposed in

13 ETI's pending rate case (Docket No. 39896) were adopted. As can be seen,

14 revenues from projected annual load growth would exceed the projected loss of

15 revenues from 150 MW of CGS service.

16 Q WHAT REASON DID ETI GIVE FOR NOT OFFSETTING ITS LOST REVENUES

17 WITH REVENUES FROM LOAD GROWTH?

18 A Mr. May asserts that "Load growth is not a concept that can be appropriately applied

19 within the context that rates are set in Texas based upon an historical test year with

20 known and measureable costs.'.s However, Mr. May's assertion is inconsistent with

21 ETI's lost revenue approach, which would make an out-of-test-year adjustment by

8
Supplemental Testimony of Phillip R. May at 12.

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1 quantifying its change in revenues resulting from loads that convert to CGS.

2 Equating lost revenues with unrecovered costs is wrong in the first place, but even if

3 one accepted that hypothetical, ETI's approach fails to recognize offsetting changes,

4 such as load growth.

5 Q DO YOU AGREE WITH MR. MAY THAT LOAD GROWTH IS ONLY OFFSETTING

6 INCREMENTALCOSTS?

7 A Yes. However, that is exactly what .a load growth offset to lost revenues would

8 accomplish. As shown by Exhibit PRM-4, ETI is asserting that CGS is creating a net

9 incremental cost of between $2.64 and $3.54 per kW month. It is, therefore,

10 appropriate to recognize how load growth can offset this incremental cost.

11 Other Offsetting Cost Savings

12 Q ARE THERE ANY OTHER OFFSETTING COST SAVINGS FROM THE CGS

13 PROGRAM?

14 A Yes. Because a CGS Customer is effectively self-supplying generation that ETI

15 does not have to procure, operate and maintain, ETI can utilize existing generation

16 resources to serve both existing and new non-CGS loads. This, in turn, would allow

17 ETI to defer or displace additional generation capacity that would be needed to

18 maintain reliable service. As discussed later, ETI is short of capacity; specifically

19 base-load capacity. The CGS Program can provide the needed base-load capacity

20 at a lower cost than the alternatives.

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1 Q DOES ETI'S LOST REVENUE APPROACH RECOGNIZE HOW THE CGS

2 PROGRAM COULD POTENTIALLY OFFSET THE NEED FOR NEW BASE-LOAD

3 CAPACITY AND PRODUCE OPERATING SAVINGS?

4 A No, it does not. ETI has a significant supply deficit. This is shown in Exhibit JP-5,

5 which is an excerpt from Entergy's 2009 Strategic Resource Plan (SRP). The

6 supply deficit is shown for each different capacity supply role; that is, Base Load,

7 Core Load Following, Seasonal Load Following, and Peaking Plus Reserves. As

8 can be seen, ETI's total deficit is about 978 MW. However, its total deficit of base-

9 load supply is 969 MW. Thus, ETI's supply deficit is almost entirely base-load

10 capacity. If CGS can be counted as firm capacity, it can reduce ETI's base-load

11 capacity deficit.

12 Q WHAT CONDITIONS MUST CGS SUPPLY MEET IN ORDER TO BE COUNTED

13 AS FIRM CAPACITY?

14 A At a minimum, a CGS Supplier must enter into a contract with ETI to provide CGS

15 capacity on a 24x7 basis, except when the supplier's resource is not physically

16 available. Further, the CGS Supplier must obtain the status of a network resource

17 under Entergy's OATT. And finally, the CGS Supplier must make the necessary

18 arrangements to ensure that there is adequate transmission to support any CGS

19 contract for the duration of the proposed contract. 9 Assuming all of these minimum

20 conditions are met, there is no legitimate reason for not treating the CGS Supply as

21 firm capacity.

9
I have observed that several of ETI's Purchased Power Agreements obligate ETI (and not the seller)
to obtain network transmission service.
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1 Q WHY DO YOU ASSERT THAT CGS SUPPLY IS A MORE ECONOMICAL

2 RESOURCE THAN BASE-LOAD CAPACITY THAT ETI WOULD OTHERWISE

3 NEED IN THE ABSENCE OF CGS?

4 A The SRP identifies a combined cycle gas turbine (CCGT) as the best option for

5 meeting the Entergy system's base-load capacity deficit. 10 The estimated installed

6 cost and levelized fixed cost of new CCGT capacity is provided in Exhibit JP-6.

7 The information was obtained from a variety of different sources, including

8 the Entergy SRP, Ninemile Unit 6 (a capacity addition planned by Entergy Louisiana,

9 LLC), and the Energy Information Administration (EIA). As can be seen, the installed

10 costs range from $1 ,235 to $1 ,280 per kW. Using the same levelized fixed charge

11 rate that Entergy uses in evaluating self-build generation options, the range of

12 levelized annual fixed cost would be $168 to $177 per kW-Year ($13.99 to $14.74

13 per kW-Month). The embedded generation capacity cost reflected in current rates is

14 $82 per kW-Year ($6.84 per kW-Month). Thus, adding self-build base-load capacity

15 will drive rates up for all ETI customers.

16 Q HAS THE COMMISSION EMPLOYED A SIMILAR GENERATION PROXY IN

17 DETERMINING THE COST EFFECTIVENESS OF ENERGY EFFICIENCY

18 PROGRAMS?

19 A Yes. In Subst. R. 25.183(b)(2) the Commission has established a capacity benefit of

20 energy efficiency programs of $80 per kW-Year or $6.66 per kW-Month. Although

21 this proxy is based on the cost of typically lower-cost peaking capacity (and is

10
Entergy System Planning & Operations, 2009 Strategic Resource Plan at 1-10.

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1 therefore not directly comparable to CGS Supply, which is base-load capacity), it is

2 clearly comparable to the generation capacity charges included currently in base

3 rates that ETI uses as the starting point for its lost revenue calculations.

4 Q YOU PREVIOUSLY MENTIONED THAT ETI TREATS THE LOWER PAYMENTS

5 UNDER SCHEDULE MSS-1 AS AN OFFSET TO LOST REVENUES. WHAT IS

6 SCHEDULE MSS-1?

7 A Schedule MSS-1 is a FERC approved tariff that "equalizes" reserve capacity

8 throughout the Entergy system. Each operating company is required to have

9 sufficient capacity to meet its firm load obligation. An operating company that does

10 not have sufficient capacity to meet its firm load obligation is said to have a "deficit,"

11 while an operating company with more capacity than is needed to meet its firm load

12 obligation is said to have a "surplus." Under Schedule MSS-1, the deficit companies

13 make a reserve equalization payment to the surplus companies. The reserve

14 equalization payment is based on the embedded cost of the older steam units on the

15 Entergy System that are designated as reserve capacity. The sum of the payments

16 by the deficit companies equals the sum of the receipts by the surplus companies.

17 Thus, Schedule MSS-1 is a transfer payment between the Entergy operating

18 companies.

19 Q DOES ENTERGY TEXAS HAVE A SURPLUS OR A DEFICIT OF RESERVE

20 CAPACITY?

21 A ETI is a deficit company. Thus, it makes reserve equalization payments to the

22 surplus operating companies.

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1 Q HOW WOULD THE CGS PROGRAM AFFECT THE AMOUNT OF RESERVE

2 EQUALIZATION PAYMENTS THAT ETI MAKES UNDER SCHEDULE MSS-1?

3 A If the CGS Suppliers are counted as firm resources, it will decrease ETI's reserve

4 capacity deficit, which in turn will reduce the amount of reserve equalization

5 payments. For this reason, ETI recognizes this reduction as an offset to lost

6 revenues.

7 Q DOES THAT MAKE SCHEDULE MSS-1 A PROXY FOR THE VALUE OF CGS

8 CAPACITY?

9 A No. As previously stated, the Schedule MSS-1 charges are a transfer payment

10 between the Entergy operating companies for existing generation capacity

11 resources. CGS, by contrast, would be a new system resource. Further, CGS would

12 be a 24x7 base-load resource, while Schedule MSS-1 is based on the cost of

13 existing reserve capacity, which is comprised of peaking resources that are used

14 infrequently. Thus, it would be incorrect to use the Schedule MSS-1 rate (which

15 reflects the cost of existing peaking capacity resources) to value CGS Power (which

16 is an incremental base-load resource).

17 Further, Entergy does not take its MSS-1 costs into account for resource

18 planning purposes. That is, when planning to meet ETI's resource needs through

19 either a purchase power agreement (PPA) or other resource, MSS-1 costs are not

20 considered. 11

11
Docket No. 37744, Deposition of Robert Cooper at 24-25.

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1 Q IF SCHEDULE MSS-1 IS A PROXY FOR THE INCREMENTAL COST OF

2 CAPACITY, WOULD IT EVER MAKE ECONOMIC SENSE FOR ETI TO ENTER

3 INTO PURCHASED POWER AGREEMENTS THAT WERE MORE EXPENSIVE

4 THAN THE MSS-1 RATE?

5 A No, because this presumes Ell's incremental cost of capacity is the MSS-1 rate. In

6 fact, ETI is paying higher demand charges (substantially higher in some PPAs) than

7 $3.73 per kW-Month, which is the current Schedule MSS-1 rate as shown in Exhibit

8 PRM-3. If the value of capacity was only $3.73 per kW, it is unlikely that these PPAs

9 would be considered prudent.

10 Q PLEASE SUMMARIZE YOUR ANALYSIS OF THE COST OF CGS SUPPLY

11 RELATIVE TO THE ALTERNATIVES.

12 A ETI's lost revenues approach assumes that the cost of CGS Supply would be equal

13 to ETI's embedded generation capacity costs or $82 per kW-Year ($6.84 per kW-

14 Month x 12). Put another way, it is ETI's position that even though the parties have

15 agreed that the CGS Customer will pay for its own capacity pursuant to the CGS

16 Customer-Supplier Agreement, ETI's capacity costs for the CGS Program will be at

17 least equal to $6.84 per kW-Month (before offsets). However, as demonstrated

18 above, the cost of alternative capacity resources that would offset its projected base-

19 load capacity deficit would be $14 or more per kW-Month, which is substantially

20 above ETI's embedded generation capacity costs. Thus, from a capacity

21 perspective, CGS power can be a lower cost option for ETI than the base-load

22 resources ETI would otherwise need to meet its projected capacity.

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1 Q HAVE YOU REVIEWED THE TESTIMONY OF ANDREW J. O'BRIEN ON BEHALF

2 OF ETI?

3 A Yes. Mr. O'Brien contends (on pages 7-8) that CGS Supply will have little or no

4 capacity value.

5 Q DO YOU AGREE WITH MR. O'BRIEN'S ANALYSIS?
'I
6 A No. Mr. O'Brien has clearly 'undervalued the capacity benefits of CGS power. First,

7 it should be noted that Mr. O'Brien makes this claim with respect to CGS power, but

8 ETI admits that it has done no comparison of the value of CGS power to its existing

9 purchase power contracts. 12 Mr. O'Brien's testimony should be given very little

10 weight for this reason. Second, Mr. O'Brien's analysis ignores the specific supply

11 role that a particular resource (such as CGS) may be selected to provide. As

12 previously stated, Entergy defines four major supply roles:

13 • Base Load;
14 • Core Load Following;
15 • Seasonal Load Following; and
16 • Peaking Plus Reserves.

17 It is reasonable to expect that each different type of resource will possess the

18 characteristics required to meet its specific supply role. In other words, a particular

19 resource need not possess every attribute identified in Mr. O'Brien's testimony to be

20 of value.

21 For example, with regard to flexibility, Mr. O'Brien asserts that CGS capacity

22 has no flexibility, it cannot be cycled or used to follow load variations or controlled by

12
ETI's Response to TIEC 1-2.

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1 the Entergy System Operator. 13 These limitations would be of concern if CGS power

2 was intended to be a load following product. It is not a concern for a base-load

3 product. As such, CGS power is similar to a nuclear plant. A nuclear plant will either

4 be totally on or totally off. As long as a nuclear plant is capable of operating at full

5 output, there would never be a reason for the System Operator to change the

6 dispatch of the plant. Further, it is unclear how Mr. O'Brien accounts for the fact that

7 the Entergy System Operator will be able to order the CGS Supplier to curtail or not

8 operate during system emergencies, the same as other network resources.

9 Q WOULD THE UNIT CONTINGENT NATURE OF CGS CAPACITY MAKE IT LESS

10 VALUABLE THAN OTHER ETI RESOURCES?

11 A No, not necessarily. Mr. O'Brien asserts that CGS would be less firm than other

12 resources. However, he has provided no analysis to support his assertion. Further,

13 his concern about the "priority" of the host loads behind all QFs (including the QFs

14 that sell unit contingent power to ETI) is misplaced. This is because the failure to

15 achieve the required performance can be costly. The CGS Supplier will not be

16 immune from performance risk.

17 The 24x7 nature of the CGS product will require the CGS Supplier to commit

18 only the amount of capacity that can meet a high level of performance. Further, as

19 previously stated, the CGS Supplier is obligated to achieve an 80% capacity factor

20 during on-peak hours. Failure to do so would subject the CGS Customer to

21 additional costs and potentially trigger liquidated damage charges.

13
ETI's Response to TIEC 1-1.

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1 Q HAS ENTERGY ENTERED INTO SHORT-TERM UNIT CONTRACTS?

2 A Yes. ETI has entered into numerous unit contingent contracts, including both

3 affiliates and third party contracts. Exhibit JP-7 is a list of the currently effective unit

4 contingent contracts and the term of each separate transaction. As can be seen,

5 most of these unit contingent transactions have terms as short as one to three years.

6 Q DO MR. O'BRIEN'S CONCERNS ABOUT THE MINIMUM SIZE OF A CGS

7 CONTRACT HAVE MERIT?

8 A No. The CGS Program is essentially being offered as a pilot. Accordingly,

9 limitations have been placed on the scope of the program, including the eligible

10 suppliers and the maximum amount of CGS load. It is unclear that potential

11 customers would want to risk a significant amount of load without first gaining more

12 experience.

13 However, the initial offering could result in up to 150 MW of firm base-load

14 capacity. This is comparable in size to the majority of ETI's unit contingent contracts,

·15 as shown in Exhibit JP-7.

16 If the pilot is a success, there is no reason not to expect customers to commit

17 more of their load to CGS and potentially enter into longer term contracts.

18 Q DO YOU AGREE WITH MR. O'BRIEN'S RANKING OF CGS RELATIVE TO

19 ENERGY COST?

20 A No. The moderate ranking is based on the fact that CGS energy is priced at avoided

21 cost. However, Mr. O'Brien ignores that the CGS Customer will be paying ETI

22 avoided cost for every kWh purchased by ETI from the CGS Supplier and resold to

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1 the customer. Thus, the CGS Program will have a "zero" net energy cost to ETI's

2 customers. Even base-load units have some positive energy cost. For this reason,

3 CGS should be ranked as "highly valuable" with respect to energy cost.

4 Q DOES THE LOCATION OF CGS SUPPLY DIMINISH ITS VALUE?

5 A No. Ideally, resources should be located close to the loads they serve. The CGS

6 Supply will be located in ETI's service area. This service area is within the WOTAB

7 planning region, which is considered a capacity-constrained region. 14

8 Q DOES ETI PURCHASE CAPACITY THAT IS LOCATED OUTSIDE OF WOTAB?

9 A Yes. For example, the resources supporting the EAI-WBL are located outside of

10 WOTAB. This fact has not diminished ETI's willingness to pay a high price for this

11 capacity.

12 Q DOES MR. O'BRIEN'S TESTIMONY PLACE A HIGH VALUE ON ANY ASPECT

13 OF CGS SUPPLY?

14 A Yes. His testimony ascribes a high value on firming up QF Puts. As discussed

15 below, firming up the QF Puts would reduce the need for flexible capacity and lower

16 operating costs.

14
Entergy System Planning & Operations, 2009 Strategic Resource Plan at 2-10. The WOTAB
planning region is the area generally west of the Baton Rouge, Louisiana metropolitan area, to the
westernmost portion of Entergy's service territory in Texas. The westernmost portion ofWOTAB is
the Western area (a sub-area), which encompasses the westernmost part of ETI's service territory,
generally west of the Trinity River.

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1 Q WHAT IS A QF PUT?

2 A A QF Put is when a Qualifying Facility generates excess energy that cannot be

3 otherwise used by the OF's host load. This excess energy is "put" to the Entergy

4 system. QF Puts are unscheduled, and they are also highly variable. According to

5 Entergy, in 2008 QF Puts change an average of 182 MW or more during a one hour

6 period and 891 MW in a 24-hour period. Five percent of the time, the QF Put

7 changed by 1,674 MW or more during a 24-hour period. 15

8 Q IS THERE A COST INCURRED BY ENTERGY TO MANAGE QF PUTS?

9 A Yes. Entergy says it incurs significant costs to manage QF Puts. For example:

10 The amount of energy put to the System by Qualifying Facilities (QFs)
11 varies significantly from minute-to-minute and hour-to-hour.
12 Changes in the injection or retraction of QF Put energy require
13 the System to have a substantial amount of flexible load
14 following capacity ready and available to the System Dispatcher
15 to increase or decrease System generation so that changes in
16 QF puts can be managed without compromising reliability. 16
17 (emphasis added)

18 Q HOW MUCH FLEXIBLE CAPACITY DOES ENTERGY SAY IT REQUIRES?

19 A According to Entergy:

20 The amount of flexible capacity that must be operating in any
21 particular time is typically on the order of 4,000 to 6,000 MWs. At
22 times during the year, the amount of flexible capacity that must be
23 committed can be as much as 9,000 MWs. 17

15
/d. at 7-13.
16 /d.
17
/d. at 8-8.

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1 Q WOULD CGS FIRM-UP THE QF PUTS?

2 A Yes. CGS could eliminate up to 150 MW of QF Puts. By reducing the QF Puts, the

3 system should require less flexible capacity and incur lower operating costs.

4 Q HAS THE ENTERGY SYSTEM HAD EXPERIENCE WITH FIRMING-UP QF

5 CAPACITY?

6 A Yes. In November 2008 Entergy Gulf States Louisiana, LLC (EGSL) sought

7 approval of a three-year contract with Calpine for the purchase of 485 MW of

8 capacity. The generation facility was part of a QF. In supporting the proposed

9 contract, EGSL cited a number of benefits:

10 Q. DOES THE ECONOMIC ANALYSIS INCLUDE ANY BENEFITS
11 ASSOCIATED WITH FIRMING UP THE QF PUT CURRENTLY
12 ASSOCIATED WITH THE CARVILLE FACILITY AND REDUCING
13 THE OPERATIONAL FLEXIBILITY REQUIREMENTS?
14 A. No. As a QF, the Carville Facility otherwise has the right to "put"
15 non-firm, as-available energy to the Company and be paid the
16 Company's avoided cost for that energy, subject to certain limitations
17 provided for in PURPA and the Federal Energy Regulatory
18 Commission's ("FERC") implementing regulations and incorporated
19 into the LPSC's Avoided Cost General Order. However, under the
20 Calpine Contract, Calpine will not put unscheduled energy to
21 the Company, but rather will allow the Company to "firm up" the
22 delivery of energy associated with the capacity under contract
23 from Calpine's generating units at the Carville Facility. The
24 Carville Contract provides the System dispatcher certainty
25 about the output from the capacity under contract from the
26 Carville Facility and effectively reduces the operational
27 flexibility requirements for the System. However, the exact

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1 economic value of this benefit is difficult to estimate. ESI took the
2 conservative approach and chose not to calculate any specific
3 savings associated with this benefit. It should be noted that the
4 benefits of firming up QF put exist during each year of the
5 contract term. 18 (emphasis added)

6 Q HAS ENTERGY QUANTIFIED THE VALUE OF FLEXIBLE CAPACITY?

7 A

8 Q CAN THE CGS PROGRAM OFFSET SOME OF THE COSTS INCURRED TO

9 PROVIDE FLEXIBLE CAPACITY?

10 A Yes. Firming up 150 MW of OF Puts will reduce the costs associated with flexible

11 capacity. Based on a review of various studies presented in recent filings, I believe

12 $2 million per year would be a conservative estimate of the lower operating costs.

13 Q PLEASE SUMMARIZE THE BENEFITS OF CGS SUPPLY.

14 A CGS can provide the needed base-load supply at a lower capacity cost than ETI's

15 alternatives. Replacing the QF Puts with CGS will reduce the Entergy System's (and

16 ETI's) requirements for flexible capacity, thereby resulting in lower operating costs.

17 In summary, CGS Supply will provide significant economic benefits to all ETI

18 customers. These economic benefits are ignored in ETI's lost revenue analysis.

18
LPSC Docket No. U-28805 Subdocket B: In Re: Application of Entergy Gulf States Louisiana,
L.L.C. for Authorization to Participate in a Contract for the Purchase of Capacity and Electric Power
from Calpine Energy Services, L.P. and Carville Energy Center, LLC; November 25, 2008,
Application at 17-18.
19
ETI's Response to TIEC 1-3.

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1 Q SHOULD LOST REVENUES BE INCLUDED AS UNRECOVERED COSTS?

2 A No. For all of the reasons cited, including Commission and court precedent rejecting

3 lost revenues as a "cost," the similar impacts between CGS Program, self-

4 generation, and energy efficiency, and Ell's failure to recognize load growth and the

5 potential economic benefits of the CGS Program, the Commission should reject

6 ETI's definition of unrecovered costs. The only legitimate unrecovered costs are

7 those associated with start-up, on-going implementation, and backup power. As

8 these costs will be paid by the CGS Customers, there would be no unrecovered

9 costs associated with the CGS Program.

10 Q IF THE COMMISSION DECIDES THAT Ell'S UNRECOVERED COSTS SHOULD

11 INCLUDE LOST REVENUES, HOW SHOULD LOST REVENUES BE

12 QUANTIFIED?

13 A I would recommend modifying ETI's lost revenue analysis as follows:

14 • Lost revenues shown in Exhibit PRM-4 should only be calculated for
15 loads that actually purchased generation services from ETI. This
16 excludes new customers, new loads of existing customers, self-
17 generation displacement, and inactive loads that are brought back on
18 line that would otherwise not have purchased electricity from ETI
19 absent the CGS Program. This would recognize that ETI did not
20 provide generation services under each of these scenarios.
21 • Lost revenues should be further offset by load growth and any other
22 quantifiable benefits of CGS (e.g., capacity deferral, lower operating
23 costs).
24 As previously stated, ETI is projecting sufficient load growth to more than offset any

25 lost revenues even before consideration of any other quantifiable benefits.

26 Recognizing these other benefits clearly demonstrates the overall benefits of the

27 CGS Program and that ETI would have zero unrecovered costs.

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