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

ACCEPTED
03-14-00735-CV
4704785
THIRD COURT OF APPEALS
AUSTIN, TEXAS
3/31/2015 9:56:35 AM
JEFFREY D. KYLE
CLERK
NO. 03-14-00735-CV

IN THE FILED IN
3rd COURT OF APPEALS
TEXAS COURT OF APPEALS AUSTIN, TEXAS
THIRD COURT OF APPEALS DISTRICT3/31/2015 9:56:35 AM
AT AUSTIN JEFFREY D. KYLE
Clerk

ENTERGY TEXAS, INC., ET AL.,
APPELLANTS,
V.

PUBLIC UTILITY COMMISSION OF TEXAS, ET AL.,
APPELLEES

ON APPEAL FROM THE FINAL JUDGMENT
IN CAUSE NO. D-1-GN-13-000121 (CONSOLIDATED),
353RD JUDICIAL DISTRICT COURT,
TRAVIS COUNTY, TEXAS,
HONORABLE JOHN K. DIETZ, JUDGE PRESIDING

APPELLANT’S BRIEF AND APPENDIX OF
THE OFFICE OF PUBLIC UTILITY COUNSEL

OFFICE OF PUBLIC UTILITY COUNSEL
Tonya Baer
Public Counsel
State Bar No. 24026771
Sara J. Ferris
Senior Assistant Public Counsel
State Bar No. 50511915
P.O. Box 12397
Austin, Texas 78711-2397
512/936-7500 (Telephone)
512/936-7525 (Facsimile)
Sara.Ferris@opuc.texas.gov
ORAL ARGUMENT REQUESTED
March 31, 2015
 IDENTITY OF PARTIES AND COUNSEL

PARTIES ATTORNEYS

OFFICE OF PUBLIC Sara J. Ferris
UTILITY COUNSEL Senior Assistant Public Counsel
Office of Public Utility Counsel
P.O. Box 12397
Austin, Texas 78711-2397
sara.ferris@opuc.texas.gov

ENTERGY TEXAS, INC. Marnie A. McCormick
John F. Williams
Duggins, Wren, Mann & Romero, LLP
P.O. Box 1149
Austin, Texas 78767-1149
mmcormick@dwmrlaw.com
jwilliams@dwmrlaw.com

CITIES OF ANAHUAC, Daniel J. Lawton
BEAUMONT, ET. AL. Lawton Law Firm PC
12600 Hill Country Boulevard, Suite R275
Austin, Texas 78738
dlawton@ecpi.com

STATE AGENCIES OF Katherine H. Farrell
TEXAS Assistant Attorney General
Administrative Law Division – Energy
Rates Section
Office of the Attorney General
P. O. Box 12548
Austin, Texas 78711-2548
katherine.farrell@texasattorneygeneral.gov

i
TEXAS INDUSTRIAL Rex VanMiddlesworth
ENERGY CONSUMERS Benjamin Hallmark
Thompson & Knight, LLP
98 San Jacinto Blvd, Suite 1900
Austin, Texas 78701
rex.vanm@tklaw.com
benjamin.hallmark@tklaw.com

PUBLIC UTILITY Elizabeth R. B. Sterling
COMMISSION OF TEXAS Assistant Attorney General
Environmental Protection Division
Office of the Attorney General
P. O. Box 12548, Capitol Station
Austin, Texas 78711-2548
elizabeth.sterling@texasattorneygeneral.gov

ii
 TABLE OF CONTENTS

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

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

INDEX OF AUTHORITIES .................................................................................................. v

GLOSSARY OF ABBREVIATIONS & TECHNICAL TERMS .................................... ix

STATEMENT OF THE CASE ............................................................................................... 1

STATEMENT REGARDING ORAL ARGUMENT........................................................ 2

ISSUE PRESENTED ............................................................................................................... 2
Did the Commission err by allowing the inclusion of $13,014,379 in
1997 ice storm restoration costs that were directly related to the
Company’s imprudence and reasonably anticipated? Did the
Commission act arbitrarily in allowing the inclusion of these costs
in the Company’s storm reserve balance, and violate PURA and
the Commission’s own rules? ................................................................................... 2

STATEMENT OF FACTS ..................................................................................................... 3
BACKGROUND ........................................................................................................................... 3
THE RATE CASE, DOCKET NO. 39896 ................................................................................... 7

SUMMARY OF THE ARGUMENT ................................................................................... 8

ARGUMENT ............................................................................................................................ 13
A. Standard of Review ........................................................................................................ 13
B. The Commission Erred as a Matter of Law in Allowing the Inclusion
of $13,014,379 in 1997 Ice Storm Restoration Costs That Were
Directly Related to the Company’s Imprudence and Which Were
Reasonably Anticipated. The Commission Acted Arbitrarily in
Allowing the Inclusion of These Costs in the Company’s Storm
Reserve Accrual and Storm Reserve Balance, and Violated PURA
and the Commission’s Own Rules. .............................................................................. 15

iii
 1. The Commission erred in approving the recovery of imprudent costs. .................... 16
2. The Commission erred by failing to hold ETI to its burden of showing that the
expenses it sought to include in the storm reserve were not reasonably
anticipated. .............................................................................................................. 20
3. Prior remedies assessed for poor quality of service, including imprudent
vegetation management do not address the subsequent imprudence of excessive
ice damage expenses. ............................................................................................... 22
4. The statutory burden of proof rests upon ETI to affirmatively prove each
element of its case. The Commission erred in excusing ETI from its burden of
proof merely because years had passed between the incurrence of the 1997 ice
storm restoration costs and Docket No. 39896. . .................................................. 25
a. ETI has the burden of persuasion on the entire case failed to prove each
required element to meet this burden. ............................................................ 27
b. The Commission erred in finding that ETI had established a prima facie
case sufficient to shift the burden of proof. .................................................... 28
c. The overall burden of proof remained on ETI to affirmatively prove each
element of its case by a preponderance of the evidence. The Commission
erred in failing to hold ETI to this burden. ................................................... 29
d. ETI’s statutory responsibilities do not expire or shift due to the passage of
time. .................................................................................................................. 31
e. The PFD adopted by the Commission improperly shifted the burden to
OPUC and intervening parties. ..................................................................... 32
f. Under Texas and Commission standards, ETI failed to meet its burden
of proof required for the inclusion of the $13,014,379 in 1997 ice storm
costs. ................................................................................................................. 36
5. The Commission’s decision to approve the inclusion of $13,014,379 in
1997 ice storm costs is arbitrary and capricious and constitutes an abuse
of discretion. ............................................................................................................. 37

PRAYER .................................................................................................................................... 40

CERTIFICATE OF COMPLIANCE .................................................................................. 41

iv
CERTIFICATE OF SERVICE ............................................................................................. 41

APPENDIX

A: District Court Judgement, Cause No. D-1-GN-13-000121
(Consolidated)
B: PUC Docket No. 39896, Order on Rehearing
C: PURA, Chapter 36, Subchapters A and B, and Chapter 37,
Subchapter D
D: Entergy Gulf States, Inc. v. Public Utility Commission,
112 S.W.3d 208 (Tex. App. – Austin 2003, pet. denied)
E: Texas Utilities Electric Company v. Public Utility Commission,
881 S.W.2d 387 (Tex. App. – Austin 1994) aff’d in part, rev’d in
part on other grounds, 935 S.W.2d 109 (Tex. 1997)
F: PUC Docket No. 18249, Order on Rehearing
G: Excerpt from: PUC Docket No. 16705, Proposal for
Decision
H: Excerpts from: PUC Docket No. 16705, Second Order on
Rehearing
I: 16 Tex. Admin. Code § 25.231

v
 INDEX OF AUTHORITIES

CASES

Apresa v. Montfort Insurance Co.,
932 S.W.2d 246 (Tex. App.—El Paso 1996, no writ) ......................................... 34

Boaz v. Harris,
30 S.W.2d 810 (Tex. Civ. App.—Fort Worth 1930, no writ) .....................27, 28

Cameron Compress Co. v. Kubecka,
283 S.W. 285 (Tex. Civ. App.—Austin 1926, writ ref’d) ................................... 27

City of El Paso v. Public Util. Commission,
883 S.W.2d 179 (Tex. 1994) ................................................................................. 14, 38

Clark v. Hiles,
67 Tex. 141, 2 S.W. 356 (1886) ................................................................................... 33

Coalition for Long Point Preservation v. Texas Commission on Environmental Quality,
106 S.W.3d 363 (Tex. App – Austin 2003, pet. denied) .................................... 14

Dodson v. Watson,
110 Tex. 355, 220 S.W. 771 (1920)............................................................................. 28

Entergy Gulf States, Inc. v. Public Utility Commission,
112 S.W.3d 208 (Tex. App.—Austin 2003, pet. denied) ................. 16, 23, 27, 29

Fritsche v. Niechoy,
197 S.W. 1017 (Tex. App. – Galveston 1917, writ dism’d w.o.j.)........................ 28

Hernandez v. State,
161 S.W.3d 491 (Tex. Crim. App. 2005) ................................................................. 28

In re E.I. DuPont de Nemours & Co.,
136 S.W.3d 218 (Tex. 2004) (orig. proceeding) .................................................... 28

vi
Koppe v. Koppe,
57 Tex. Civ. App. 204, 122 S.W. 68 (1909)............................................................. 33

Lykes Bros.-Ripley S. S. Co. v. Pluto,
146 S.W.2d 414 (Tex. Civ. App.—Galveston 1940, writ dism’d
judgm’t cor.) .................................................................................................................. 29

Public Utility Commission v. Gulf States Utilities,
809 S.W.2d 201 (Tex. 1991) ................................................................................ 12, 39

Public Utility Commission v. Houston Lighting & Power Co.,
778 S.W.2d 195 (Tex. App.—Austin 1989, no writ) ..................................... 27, 29

Reliant Energy, Inc. v. Public Util. Commission,
62 S.W.3d 833 (Tex. App. – Austin 2001, no pet.)............................................... 38

Texas Parks & Wildlife Department v. Dearing,
240 S.W.3d 330 (Tex. App.—Austin 2007, pet. denied) ................................... 28

Texas Utilities Electric Company v. Public Utility Commission,
881 S.W.2d 387 (Tex. App.—Austin 1994) aff’d in part, rev’d in part
on other grounds, 935 S.W.2d 109 (Tex. 1997) .................................................... 16, 18

Vance v. My Apartment Steak House,
677 S.W.2d 480 (Tex. 1984) ..................................................................................... 37

Wyeth v. Hall,
118 S.W.3d 487 (Tex. App. – Beaumont 2003, no pet.)....................................... 28

TEXAS STATUTES

TEX. GOV’T CODE § 2001.174 .................................................................................. 13-14, 15, 27
Public Utility Regulatory Act (PURA), TEX. UTIL. CODE §§ 11.001-66.017 .................. 2
PURA § 15.001 ........................................................................................................................... 13
PURA § 31.002(19) ..................................................................................................................... 3
PURA § 36.003(a) .................................................................................................................... 23
PURA § 36.006 ............................................................................................................ 23, 25, 27
vii
PURA § 36.051.................................................................................................................... 23, 25
PURA § 36.062 ....................................................................................................................23, 39
PURA § 36.064................................................................................................................... 20, 25
PURA § 36.064(a) .............................................................................................................. 15, 22
PURA § 36.101 – 36.111 ............................................................................................................... 3
PURA § 37.151.............................................................................................................................. 5
PURA § 38.001 ............................................................................................................................ 5
PURA § 39.452(e) ...................................................................................................................... 3

PUBLIC UTILITY COMMISSION OF TEXAS RULES

16 Tex. Admin. Code § 25.231 .......................................................................................... 12, 20
16 Tex. Admin. Code § 25.231(b) ........................................................................15, 16, 20, 25
16 Tex. Admin. Code § 25.231(b)(1)(G)................................... 12, 15-16, 20-21, 22, 25, 39
16 Tex. Admin. Code § 25.231(b)(2)(J)......................................................................... 12, 39

ADMINISTRATIVE PROCEEDINGS

Application of Entergy Texas for Approval of its Transition to Competition Plan and the
Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs,
Docket No. 16705, Proposal For Decision (Mar. 25, 1998). ......... 30, 34-35, 36

Application of Entergy Texas for Approval of its Transition to Competition Plan and the
Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs,
Docket No. 16705, Second Order on Rehearing (Oct. 14, 1998). ........... 4, 9, 26

Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705),
Docket No. 18249, Order on Rehearing
(Apr. 22, 1998). .......................................... 3, 4, 5, 6, 7, 8, 9, 12-13, 17, 18, 21, 22, 39

LEARNED TREATISE

35 Tex Jur 3d, Evidence § 103 (Gene A. Noland, ed., 1984) .............................................. 27

viii
 GLOSSARY OF ABBREVIATIONS & TECHNICAL TERMS

AR – Administrative Record

Cities – Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves,
Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North,
Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah,
Silsbee, Sour Lake, Splendora, Vidor, and West Orange Texas, Plaintiffs in this
appeal

Commission or PUC– Public Utility Commission of Texas

Company – Entergy Texas, Inc.

Docket No. 16705 – The Company’s last fully litigated rate case

Docket No. 18249 – The Company’s Quality of Service Issues docket

Docket No. 39896 – The PUC docket underlying this appeal

EGS or EGSI – Entergy Gulf States, Inc., predecessor to ETI

Entergy – Entergy Corporation, ETI’s parent company

ETI – Entergy Texas, Inc.

Order – The Commission’s “Order on Rehearing” signed on November 1, 2012, the
final and appealable order of the Commission in Docket No. 39896, from which
OPUC appeals in this suit for judicial review

OPUC – Office of Public Utility Counsel

PFD – Proposal for Decision

PURA – Public Utility Regulatory Act, Tex. Util. Code §§ 11.001-66.017

ROE – Return on Equity

ix
ROW – Right of Way

SAIDI – System Average Interruption Duration Index

SAIFI – System Average Interruption Frequency Index

Self-Insurance Storm Reserve – Account designed to provide for storm-related
property losses exceeding $50,000 that are not covered by commercial insurance
or eligible for securitization.

SOAH – State Office of Administrative Hearings

Test Year – July 1, 2010, through June 30, 2011

x
 BRIEF OF APPELLANT,
OFFICE OF PUBLIC UTILITY COUNSEL

TO THE HONORABLE COURT OF APPEALS:

The Office of Public Utility Counsel (OPUC), Appellant, submits this brief

in support of its appeal from a portion of the final judgment of the District Court

on judicial review of the final Order on Rehearing (Order) of the Public Utility

Commission of Texas (Commission or PUC) in Docket No. 39896. 1 Appellant

respectfully presents the following:

STATEMENT OF THE CASE

The case is an appeal from the final judgment of the 353rd Judicial District

Court of Travis County, Texas, the Honorable John K. Dietz, Judge Presiding, in

Entergy Texas, Inc., et al. v. Public Utility Commission of Texas, Cause No. D-1-GN-13-

000121 (Consolidated). The case involves the judicial review of the final Order of

the Commission in Docket No. 39896, styled Application of Entergy Texas, Inc. for

Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment, a

contested rate case. The final judgment of the District Court affirmed in part, and

reversed and remanded in part the final order of the Commission. OPUC appeals

the part of the District Court judgment affirming the Commission’s decision to

1
The final judgment of the District Court and the Commission’s Order on Rehearing are
submitted as Appendix A and Appendix B.
1
include in the Company’s storm reserve $13,014,379 in 1997 ice storm restoration

costs that were directly related to the Company’s imprudence.

STATEMENT REGARDING ORAL ARGUMENT

The Court should permit oral argument. Like most cases involving public

utility regulation, this case is complex; oral argument will assist the Court in

clarifying the law and facts of the case.

ISSUE PRESENTED

Did the Commission err by allowing the inclusion of $13,014,379 in 1997 ice storm

restoration costs that were directly related to the Company’s imprudence and

reasonably anticipated? Did the Commission act arbitrarily in allowing the

inclusion of these costs in the Company’s storm reserve balance, and violate PURA

and the Commission’s own rules? 2

2
Public Utility Regulatory Act, PURA, Tex. Util. Code §§ 11.001-66.017.
2
 STATEMENT OF FACTS

BACKGROUND

Entergy Texas, Inc. (ETI or the Company), an investor-owned electric

utility with a retail service area in southeastern Texas, filed an application with

the Commission on November 28, 2011 for authority to increase its rates. ETI’s

application was designated as Commission Docket No. 39896. See generally, PURA

§§ 31.002(19), 36.101–36.111; Administrative Record (AR), Binder 7, Item 244, Order

on Rehearing. 3 Previously, the Company had been known as Entergy Gulf States,

Inc. (EGS) but on December 31, 2007, EGS jurisdictionally separated pursuant to

PURA § 39.452(e).4 ETI succeeded to EGS’s certificate of convenience and

necessity (CCN) for its Texas retail jurisdiction. 5 Prior to 1993 and Entergy

Corporation’s merger with Gulf States Utilities, Inc., the company serving this

territory and holding the CCN was Gulf States Utilities. 6

On November 27, 1996, EGS filed its transition to competition plan and rate

case in PUC Docket No. 16705. In this docket, the Commission issued two

preliminary orders related to EGS’s service quality. The second or supplemental

3
In this brief, citations to the Administrative Record will be in the following format: AR, Binder
X, Item X, Item name.
4
Docket No. 34800, Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile
Fuel Costs, Order at 1-2 n.1 (Mar. 16, 2009).
5
Id.
6
See Docket No. 18249, Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705),
Order on Rehearing at 1 (Apr. 22, 1998). This Order is submitted as Appendix F.
3
preliminary order addressed whether EGS’s management policy devoted adequate

resources to ensure adequate and reliable service to its ratepayers, whether there

were patterns of variable service quality in the service territory, what were the

cause and resolution of the variations, and what procedures should the

Commission implement to monitor EGS’s service quality and to respond when its

service quality falls below benchmark levels. 7 On November 4, 1997, the

Commission severed the quality of service issues from Docket No. 16705 into

Docket No. 18249.8 One of the issues which remained in Docket No. 16705 was the

amount of the Company’s storm reserve funding includable in rates. The

Commission considered the Company’s proposal to include a post-test-year

adjustment for the January 1997 ice storm expenses. In Finding of Fact Number

147, the Commission found:

Any reduction to the reserve fund occurring after the test year should
not be considered in this case because EGS did not prove a
reasonable post-test year level for its existing reserve fund or that the
amount expended in 1997 to reduce the fund was prudent or
appropriate. Reserve fund levels following the test year in this case
can be addressed in EGS’ November 1998 rate filing when all parties
will have the opportunity to evaluate the reasonableness of changes
to the insurance reserve fund. (emphasis added) 9

7
Id. at 2.
8
Id. at 3.
9
Application of Entergy Texas for Approval of its Transition to Competition Plan and the Tariffs Implementing
the Plan, and for the Authority to Reconcile Fuel Costs, Docket No. 16705, Second Order on Rehearing
(Oct. 14, 1998). Excerpts from this Order are submitted with this brief as Appendix H.
4
 In the severed Service Quality Issues proceeding (Docket No. 18249), after a

hearing on the merits presided over by two Commissioners and briefing by the

parties, the Commission issued its Order on Rehearing on April 22, 1998. 10 The

Order on Rehearing discussed the importance of reliability and the vital role

electricity plays in our lives. Under Texas law, an electric utility is required by

PURA § 37.151 to provide “continuous and adequate service” in its service area, and

is further obligated by PURA § 38.001 to furnish service, instrumentalities and

facilities that are safe, adequate, efficient and reasonable. In Docket No. 18249, the

Commission concluded that the quality of the Company’s electric service to its

customers in Texas had been less than adequate, specifically since Entergy

Corporation acquired Gulf States Utilities, Inc., in 1993. 11 The Commission also

discussed numerous deficiencies in the Company’s service quality, including

inadequate distribution maintenance policies, inadequate vegetation management

practices, distribution poles in poor condition or in need of comprehensive

vegetation clearing, and inadequate pole inspection and repair work cycles. 12 The

culmination of these inadequacies led the Commission to make findings regarding

10
Docket No. 18249, Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705), Order
on Rehearing at 4 (Apr. 22, 1998).
11
Id. at 1.
12
Id. at 8-19.
5
the state of the Company’s distribution maintenance, including its vegetation

management practices. 13

The Commission also considered the damage caused in the EGS (now ETI)

service territory due to a severe ice storm which occurred in January 1997. After

finding that EGS should have been better prepared to deal with the January 1997

ice storm, the Commission found that up to 120,000 of the Company’s

approximately 318,000 customers were without power and that the restoration of

service took seven days to complete. 14 The Commission then found in Finding of

Fact 102 that EGS’s restoration efforts would have been more effective if the

Company had been more diligent in its preventative vegetation management

practices and if it had a better communication and management program in place

to deal with emergency situations. The Commission also stated the following:

A major cause of the outages during the storm were broken or bowed
ice-laden tree limbs overhanging the wires. Tree limbs in ROW
overhanging distribution lines pose a threat to system reliability, and
are largely within EGS’ control. The Company’s failure to clear the
limbs before the storm was a major factor in the number and duration
of outages experienced by customers. While Company’s initial efforts
to mobilize and deploy additional non-EGS personnel were slow and
cause concern, vegetation management failures greatly aggravated the
situation. 15

13
Id. at 42-49, Findings of Fact Nos. 45, 46, 67, 79-83, 91-92, 94-96, 97-99, 102, 123-124, and 127;
See Id. at 50, Conclusions of Law Nos. 5-7.
14
Id. at 46, Findings of Fact Nos. 91 and 92.
15
Id. at 18-19.
6
The Order on Rehearing in Docket No. 18249 also contained the following
findings of fact:

82. Neglect and backlog of vegetation management projects has
posed unacceptable risks of increasing and recurrent service
outages, especially during major ice storms.

83. The Commission finds that the Company’s vegetation
management efforts have not been adequate, have led to a
backlog in vegetation clearing, and have resulted in an unacceptably
high risk to the system. (emphasis added)

97. The impact of the January 1997 ice storm was greatly
exacerbated by the Company’s failure to maintain its ROW
clear of excessive vegetation.

THE RATE CASE, DOCKET NO. 39896

In the underlying rate case now on appeal, ETI included in the storm reserve

$13,014,379 in 1997 ice storm expenses but did not provide an affirmative case

supporting the prudence of the 1997 ice storm costs. Instead, the Company’s

testimony focused on future quality of service practices and anticipated future

storm costs. The Commission’s Order failed to make required findings as to the

prudence of these costs or whether the costs ETI sought to include “were not

reasonably anticipated” as required by PURA and the Commission’s rules. OPUC

appeals the Commission’s consequent inclusion of the 1997 ice storm costs as legal

error.

7
 SUMMARY OF THE ARGUMENT

The Commission’s Order contains legal error that prejudices the rights of

residential and small commercial customers. The Commission’s inclusion of the

1997 ice storm restoration expenses in the Company’s self-insurance storm reserve

violates PURA and the Commission’s own rules, was arbitrary, and capricious,

and made through unlawful procedure. For these reasons, the District Court’s

judgment upholding the Commission’s Order on this issue should be reversed and

the case remanded to the Commission for further proceedings based upon the

existing evidentiary record and consistent with this Court’s decision.

It is a violation of PURA to include imprudent costs in rates. When there is

imprudence within a utility’s request for recovery, any imprudent costs must be

removed either by separating them out from the prudent costs, or disallowing the

entire amount of the intermingled requested costs. Despite the Commission’s

finding in Docket No. 18249 that the 1997 ice storm damage was greatly

exacerbated by the Company’s imprudence, particularly with regard to its

vegetation management, ETI made no showing or even an attempt at showing that

the costs of cleaning up the damage caused by its imprudent actions had been

excluded from its storm balance request. Nor did the Commission hold ETI to this

required showing.

ETI also bore the burden of showing that any cost it sought to include in the

8
storm reserve was “not reasonably anticipated.” Both PURA and the Commission’s

rules require that costs included in the storm reserve be “not reasonably

anticipated.” Vegetation management is required in order to prevent foreseeable

damage due to tree limbs or other vegetation coming into contact with conductors

or power lines. The damage resulting from imprudent vegetation management is

by its very nature, “reasonably anticipated.” Thus, the inclusion of the $13,014,379

in 1997 ice storm restoration costs was improper and in violation of the applicable

law.

The Commission committed legal error in failing to hold ETI to its burden of

proving that the $13,014,379 in costs the Company was seeking to include in the

storm reserve, the cost of service and ultimately reflected in rates, were not

reasonably anticipated. The Commission, through the adopted PFD, erroneously

relied on a 60 basis point reduction to the return on equity (ROE) from Docket

No. 18249 that was imposed to compensate ratepayers for poor quality of service.

The ROE reduction did not address or remedy the imprudent restoration costs

that were caused by the original imprudent acts. In fact, the Commission’s Order

in Docket No. 16705, which was issued after the Docket No. 18249 Order,

expressly contemplated that the reasonableness of including the 1997 ice storm

costs in the Company’s storm reserve would be addressed in the next rate case

because the Company had not proven the prudence of those costs in its request to

9
include them in that docket as a post-test year adjustment. The underlying docket

to this appeal, Docket No. 39896 is the first fully-litigated rate case for the

Company since Docket No. 16705. The Commission erred in failing to give effect

to this prior order and further erred by failing to require ETI to address the

imprudence findings from Docket No. 18249 before having 1997 ice storm costs

included in the storm reserve.

The Commission violated PURA by approving the recovery of the entire

$13,014,379 in ice storm restoration expenses without requiring ETI to show that

no costs caused by imprudent vegetation management were included in the

Company’s request. Under PURA, the burden of proof rests upon ETI to

affirmatively prove each element of its case. The Commission erred in lifting that

burden from ETI because fifteen years had passed between the incurrence of the

1997 ice storm restoration costs and Docket No. 39896. The Company’s burden to

prove that the requested costs were reasonable, prudent, and not reasonably

anticipated under PURA does not expire.

The burden of proof in an electric rate proceeding is on the utility and it is

ETI’s burden to prove that each dollar included in rates was reasonable and

prudent. ETI failed to provide evidence that the $13,014,379 in 1997 ice storm costs

were “not reasonably anticipated.” With regard to prudence, ETI only provided

10
evidence as to the reasonableness of how the clean-up was carried out; ETI wholly

failed to address the prudence of these costs with regard to what portion was or

was not related to the exacerbated damage caused by the imprudent vegetation

management, or what amount would have been incurred even if no imprudent

conditions had existed at the time of the storm. Further, ETI made no attempt to

separate out imprudent costs from prudent costs, and the Commission erred in

adopting the portion of the PFD that excused this lack of evidence due to the

passage of time.

Further, the Commission erroneously shifted the burden of proof to OPUC and

intervening parties and compounded this error by applying an improper standard

of proof. Requiring OPUC and intervening parties to challenge specific expense

items is contrary to what is required when rebutting a prima facie case under Texas

law and Commission precedent. Under those standards, ETI failed to meet its

burden of proof for the inclusion of $13,014,379 in the storm reserve, the cost of

service, and ultimately reflected in rates. ETI failed to prove the existence of each

element of its claim and consequently, the Commission erred in approving the

inclusion of the $13,014,379 in 1997 ice storm restoration costs in the storm reserve.

Moreover, the Commission’s decision approving the $13,014,379 in 1997 ice

storm restoration costs was arbitrary and capricious. The Commission failed to

consider factors the legislature directs it to consider, including whether the costs
11
were “not reasonably anticipated” and prudently incurred. Tellingly, there were

no findings of fact or conclusions of law with regard to whether the costs were not

reasonably anticipated. The Commission also considered irrelevant factors,

including the passage of time between the rate case and the incurrence of the

storm expenses, and the 60 basis-point reduction to the Company’s ROE imposed

for poor quality of service.

Additionally, the Commission acted arbitrarily and capriciously by failing to

“follow the clear, unambiguous language of its own regulation.” 16 The Commission

failed to follow the clear, unambiguous language of Rule 25.231, which clearly

states that “any expenditure found by the Commission to be unreasonable,

unnecessary or not in the public interest” “shall never be a component of the cost

of service.” 16 Tex. Admin. Code § 25.231(b)(2)(J). The Commission also acted

arbitrarily and capriciously by failing to follow its own rule which only allows

storm costs to be included in the storm reserve to the extent they are reasonable

and necessary, and are not reasonably anticipated. 16 Tex. Admin. Code

§ 25.231(b)(1)(G). In allowing the 1997 ice storm restoration costs to be included

without addressing what portion was due to damage related to poor vegetation

management, the Commission disregarded its prior finding from the final order of

the Commission in Docket No. 18249 that storm damage was “greatly exacerbated

16
Public Util. Comm’n v. Gulf States Utilities, 809 S.W.2d 201, 207 (Tex. 1991).
12
by the state of the Company’s vegetation management.”

As discussed in the sections below, the Commission committed reversible error

in approving the inclusion of $13,014,379 in the storm reserve balance ultimately

reflected in rates. The Commission’s decision violates PURA and the

Commission’s own rules, is arbitrary, and capricious, affected by other error of law

and made through unlawful procedure. For these reasons, the District Court’s

judgment upholding the Commission’s Order on this issue should be reversed and

the case and remanded to the Commission for further proceedings based upon the

existing evidentiary record and consistent with this Court’s decision.

ARGUMENT

A. Standard of Review

Any party to a proceeding before the Commission is entitled to judicial

review under the substantial evidence rule. PURA § 15.001. The statutory

standard of review is as follows:

If the law authorizes review of a decision in a contested case under
the substantial evidence rule or if the law does not define the scope of
judicial review, a court may not substitute its judgment for the
judgment of the state agency on the weight of the evidence on
questions committed to agency discretion but:

(1) may affirm the agency decision in whole or in part; and
(2) shall reverse or remand the case for further proceedings if
substantial rights of the appellant have been prejudiced
13
 because the administrative findings, inferences, conclusions, or
decisions are:
(A) in violation of a constitutional or statutory provision;
(B) in excess of the agency’s statutory authority;
(C) made through unlawful procedure;
(D) affected by other error of law;
(E) not reasonably supported by substantial evidence
considering the reliable and probative evidence in the
record as a whole; or
(F) arbitrary or capricious or characterized by abuse of
discretion or clearly unwarranted exercise of discretion.

Tex. Gov’t Code § 2001.174.

In conducting a substantial evidence review, the court must determine

whether the evidence as a whole is such that reasonable minds could have reached

the same conclusion as the agency in the disputed action. 17 The court may not

substitute its judgment for that of the agency and may consider only the record on

which the agency based its decision. 18 The issue for the reviewing court is not

whether the agency reached the correct conclusion, but rather, whether there is

some reasonable basis in the record for its action. 19

The Commission’s Order prejudices the substantial rights of residential and

small commercial customers by the excessive rates established in the Order, and

because the Order’s findings, inferences, conclusions and decisions with regard to

17
Coalition for Long Point Preservation v. Texas Commission on Environmental Quality, 106 S.W.3d 363,
366 (Tex. App – Austin 2003, pet. denied).
18
Id.
19
City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 185 (Tex. 1994).
14
the 1997 ice storm restoration expenses included in the Company’s self-insurance

storm reserve and reflected in the Company’s cost of service were in violation of

PURA, affected by other error of law, and were arbitrary, and capricious. Under

the standard articulated in Tex. Gov’t Code § 2001.174, the Commission’s Order

should be reversed and the case remanded for determination based upon the

existing evidentiary record to determine rates consistent with the Court’s

decision.

B. The Commission Erred as a Matter of Law in Allowing the Inclusion of
$13,014,379 in 1997 Ice Storm Restoration Costs That Were Directly
Related to the Company’s Imprudence and Which Were Reasonably
Anticipated. The Commission Acted Arbitrarily in Allowing the Inclusion
of These Costs in the Company’s Storm Reserve Accrual and Storm
Reserve Balance, and Violated PURA and the Commission’s Own Rules.
The PFD adopted by the Commission erroneously found the entirety of

ETI’s $13,014,379 in storm expenses related to the 1997 ice storm to be reasonable

and necessary and properly included in the self-insurance storm reserve.20 By

adopting the PFD on these points, the Commission erred as a matter of law by

violating PURA’s and PUC Substantive Rule 25.231(b)’s requirement that

expenses included in rates be reasonable and necessary, and further erred by

violating the requirement of both PURA § 36.064(a) and PUC Substantive Rule

25.231(b)(1)(G) that only those property and liability losses which “could not have

20
AR, Binder 5, Item No. 185, PFD at 56 and 57.
15
been reasonably anticipated” may be included in a self-insurance plan.21 The

Commission’s failure to either disallow the entire $13,014,379 in ice storm costs or

determine what portion of those costs was incurred imprudently as a result of the

Company’s poor vegetation management results in the inclusion of imprudent

costs in the Company’s rates.

1. The Commission erred in approving the recovery of imprudent costs.

Imprudently incurred costs may not be recovered in the utility’s base rates. 22

The utility bears the burden of proving the prudence of each cost for which

recovery is sought, and if some but not all of the requested costs are imprudent,

the imprudent costs must be removed either by separating them out or

disallowing the intermingled requested costs. In Texas Utilities Electric Company v.

Public Utility Commission, the Texas Third Court of Appeals found that, where a

portion of the utility’s $537.90 million in costs for the Comanche Peak nuclear

project were imprudently incurred, the Commission acted properly in disallowing

some but not all of the costs due to imprudence. 23 In the originating docket, the

21
16 Tex. Admin. Code § 25.231(b). The PUC’s Cost of Service Rule, 16 Tex. Admin.
Code § 25.231, is submitted as Appendix I.
22
See Entergy Gulf States, Inc. v. Public Utility Commission, 112 S.W.3d 208, 214 (Tex. App.—Austin
2003, pet. denied) (“[I]n order to raise the price of its product, the utility must participate in a
rate case and bear the burden of proving that each dollar of cost incurred was reasonably and
prudently invested.”) (Appendix D).
23
Texas Utilities Electric Company v. Public Utility Commission, 881 S.W.2d 387, 405-406 (Tex. App.—
16
utility had argued that all of its Comanche Peak costs were prudently incurred,

while intervening parties had argued that the costs should be disallowed

entirely. 24 The Commission had then brought in a third party to evaluate the

prudence of the costs. Based upon the third party recommendation, the

Commission disallowed part of the costs because they were imprudent but

allowed other costs. 25 The Austin court, reviewing the Commission’s decision to

reject an all-or-nothing approach and disallow a portion of the expenses, stated

that “it is the Commission that is charged with sifting through the evidence and

deciding whether imprudent conduct caused certain expenditures.” 26

The instant case is distinguishable from Texas Utilities Electric Company in that

the decision as to whether imprudent conduct caused certain expenditures has

already been made. “The impact of the January 1997 ice storm was greatly

exacerbated by the Company’s failure to maintain its ROW clear of excessive

vegetation.” 27 Finding of Fact 97 from PUC Docket No. 18249 provided the

Commission with the starting point in its decision-making process, and it was the

Commission’s job at that point to either deny ETI’s requested 1997 storm expenses

Austin 1994) aff’d in part, rev’d in part on other grounds, 935 S.W.2d 109 (Tex. 1997). Texas Utilities
Electric Company is submitted as Appendix E.
24
Id. at 404.
25
Id. at 403-405.
26
Id. at 404.
27
Appendix F, Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705), Docket No.
18249 at 47, FoF No. 97 (Apr. 22, 1998).
17
in their entirety or determine what portion was imprudently incurred and deny

the portion of expenses that were caused by ETI’s imprudence in managing its

system. The Commission erroneously failed to take either approach, and the

imprudent costs became part of the approved rates through their inclusion in the

storm reserve. Additionally, the Commission’s discussion of the 1997 ice storm in

its Order on Rehearing in Docket No. 18249, the Company’s Service Quality Issues

docket, included the following statement:

The January 1997 ice storm was certainly a severe storm that would
have adversely affected even the best-maintained distribution system.
EGS’ distribution system, however, is not the best-maintained. A
major cause of the outages during the storm were broken or
bowed ice-laden tree limbs overhanging the wires. Tree limbs in
ROW overhanging distribution lines pose a threat to system
reliability, and are largely within EGS’ control. The Company’s
failure to clear the limbs before the storm was a major factor in
the number and duration of outages experienced by customers. 28

Unlike in the Texas Utilities Electric Company case, in the absence of evidence

from ETI in the underlying docket (Docket No. 39896) on what portion of the

costs were attributable to the Company’s imprudence, the Commission did not

have a third party recommend what portion was due to imprudence. Nor did the

Commission consider alternative recommendations for partial disallowance in the

evidentiary record. OPUC provided evidence the Commission could have relied

28
Id. at 18 (Emphasis added).
18
upon to disallow a portion of the expenses if the Commission wished to avoid

making a total disallowance. In addition to recommending total disallowance of

the 1997 ice storm expenses, OPUC offered a reasonable, alternative

recommendation which would have disallowed a portion of the 1997 ice storm

expenses to account for the Company’s imprudence that heavily contributed to

the expenses, but the Commission did not adopt either of OPUC’s

recommendations. 29

Despite the Commission’s finding in Docket No. 18249 that the ice storm

damage was greatly exacerbated by the Company’s failings, ETI made no showing

or even an attempt at showing that the fruit of their imprudent actions has been

excluded from their storm balance request. As OPUC Witness Nathan Benedict

testified, “the Company has provided no analysis regarding the incremental

damage caused by its imprudent vegetation management practices.” 30 Despite this,

the Commission failed to hold ETI to its burden of proof and ignored the fact that

imprudence had already been established as the cause of at least some of the storm

damage that is the subject of the restoration costs in question. The Commission

committed reversible error in failing completely to take into account the expenses

29
AR Binder 39, OPUC Exhibit No. 6 (Benedict Direct) at 16.
30
AR, Binder 39, OPUC Exhibit No. 6, Benedict Direct at 13.
19
that resulted from the Company’s imprudence established in a prior Commission

final order to have, in fact, been a major cause of the ice storm damage.

2. The Commission erred by failing to hold ETI to its burden of showing
that the expenses it sought to include in the storm reserve were not
reasonably anticipated.
In addition to the burden of proving that the costs the Company incurred

were reasonable and necessary or “reasonably and prudently invested” and in the

public interest, ETI also bore the burden of showing that any cost it sought to

include in the storm reserve was “not reasonably anticipated.” The purpose of the

storm reserve is set forth in PURA § 36.064. PURA Section 36.064 authorizes an

electric utility to “self-insure all or part of the utility’s potential liability or

catastrophic property loss . . . that could not have been reasonably anticipated and

included under operating and maintenance expenses.”

The Commission’s cost of service rule, 16 Tex. Admin. Code § 25.231, further

explains what the Company must show in order to include storm damage

expenses in the storm reserve. One component of the cost of service is allowable

expenses. Subsection 25.231(b), entitled “allowable expenses” states that “only

those expenses which are reasonable and necessary to provide service to the public

shall be included in allowable expenses.” Rule 25.231(b)(1) sets out the

components of allowable expenses and states that “allowable expenses, to the

20
extent they are reasonable and necessary, and subject to this section, may

include . . .(G) Accruals credited to reserve accounts for self-insurance under a

plan requested by the Commission.” Rule 25.231(b)(1)(G) also states that the

reserve accounts are to be charged with “property and liability losses which occur,

and which could not be reasonably anticipated and included in operating and

maintenance expenses and are not paid or reimbursed by commercial insurance.”

Expenses incurred due to the Company’s “neglect of regular vegetation

clearing” 31 are not unanticipated. The very purpose of vegetation management is

to anticipate and prevent future damage. As stated in the PFD adopted by the

Commission in the Company’s Service Quality Issues docket, vegetation

management is employed to ensure, to the greatest extent possible, that vegetation

in or near the utility’s right-of-way does not come into contact with the

conductors and cause wire breakage or ground faults. 32 The existence of a storm

reserve account, combined with the fact that expenses were incurred in the

cleanup efforts related to the 1997 storm, in no way speaks to whether these past

storm expenses were reasonably anticipated, prudently incurred and properly

31
Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket No. 16705), Docket No. 18249, Order
on Rehearing at 16 and 19, Finding of Fact No. 97 (April 21, 1998) (submitted with this brief as
Appendix F). This cited portion of the order is also found at AR, Binder 39, OPC Exhibit No. 6,
Benedict Direct at Exhibit NAB-2.
32
See Appendix F, Docket No. 18249, Entergy Gulf States, Inc. Service Quality Issues (Severed from Docket
No. 16705), Order on Rehearing at 14 (Apr. 22, 1998).
21
includable in the storm damage accrual. ETI failed to demonstrate that the 1997

ice storm costs were “not reasonably anticipated.”

By failing to hold ETI to this required showing, the Commission’s Order

results in violations of the requirements in both PURA § 36.064(a) and PUC

Substantive Rule 25.231(b)(1)(G) that only those property and liability losses

which “could not have been reasonably anticipated” may be included in a self-

insurance plan. See Appendix C and Appendix I. Expenses that directly result

from the Company’s “neglect of regular vegetation clearing” 33 are not

unanticipated. The purpose of vegetation management is to prevent damage

caused by vegetation in or near the utility’s right-of-way coming into contact with

the conductors and causing wire breakage or ground faults. 34 The Commission’s

failure to disallow the inclusion of $13,014,379 in storm restoration costs or

determine what portion of those costs were incurred imprudently as a result of the

Company’s imprudent vegetation management violates PURA and results in a

storm reserve that impermissibly includes costs that were reasonably anticipated.

3. Prior remedies assessed for poor quality of service, including imprudent
vegetation management do not address the subsequent imprudence of
excessive ice damage expenses.

33
Appendix F, Docket No. 18249, Order on Rehearing at 16 and 19, Finding of Fact No. 97.
34
See Appendix F, Docket No. 18249, Order on Rehearing at 14.
22
 The PFD adopted by the Commission states on page 57 that “the

Commission’s retroactive reduction of ETI’s ROE in Docket No. 18249 in part

compensated ratepayers for the poor service issues that exacerbated the storm

damage.”35 This statement misses the point. The 60 basis point reduction to the

ROE was the ratepayers’ remedy for poor quality of service, including for such

things as billing rate error and call center response time, and should not be

presumed to inoculate the Company from facing the costs caused as a result of its

poor performance with regard to vegetation management. Reducing the ROE was

consistent with PURA § 36.062’s requirement that the utility’s quality of service

and efficiency of operations be considered when establishing a return on invested

capital. The PFD adopted by the Commission in Docket No. 39896 confuses one

set of imprudence (poor quality of service) and its remedy (60 basis-point

reduction), with a second, separate imprudence (costs associated with excessive

ice damage caused by imprudence). This second imprudent condition requires a

separate remedy; that is, the costs associated with the damage caused by

imprudence should be disallowed. Moreover, PURA requires that imprudent

costs not be included in rates.36 The Commission’s decision to allow all of the 1997

ice storm costs is an error of law.

35
AR, Binder 5, Item No. 185, PFD at 57.
36
Tex. Util. Code §§ 36.003(a), 36.006(1) and 36.051; See Entergy Gulf States, Inc. v. Public Utility
23
 The PFD adopted by the Commission stated that ETI had to take

appropriate action to repair the damage and restore service and that ETI had

established that the expenses incurred in those efforts were reasonable and

necessary. However, costs can be imprudent in two different ways. First, costs

can be imprudent because of their source, the fruit of a bad act. Second, costs can

be imprudent due to how they are carried out, such as the amount spent or

activities performed. The evidence provided by ETI went to this second type of

prudence question (i.e., the prudence of costs incurred to restore exacerbated

levels of storm damage), but ETI wholly failed to show which or how much of the

$13,014,379 of expenses was caused or not caused by the poor vegetation

management. The Commission erred in allowing the entirety of ETI’s $13,014,379

in 1997 ice storm costs and ignoring the established fact that imprudence was a

major factor in the extent of damage. The Commission’s failure to take into

account or determine what portion of the requested 1997 ice storm costs were

imprudent due to the exacerbated damage and what portion could reasonably

have been anticipated violated PURA and the Commission’s own rules and

consequently, the District Court’s Judgment and the Commission’s Order should

Commission, 112 S.W.3d 208, 214 (Tex. App.—Austin 2003, pet. denied) (“[I]n order to raise the
price of its product, the utility must participate in a rate case and bear the burden of proving
that each dollar of cost incurred was reasonably and prudently invested.”) (Appendix D).
24
be reversed and remanded to correct this error of law based upon the existing

record.

4. The statutory burden of proof rests upon ETI to affirmatively prove
each element of its case. The Commission erred in excusing ETI from its
burden of proof merely because years had passed between the
incurrence of the 1997 ice storm restoration costs and Docket No. 39896.

The PFD adopted by the Commission erroneously absolves ETI of its burden

of proof on the 1997 ice storm restoration costs due to the passage of time and

merely states that it is “not feasible to accurately determine now what portion of

ice storm damage that occurred 15 years ago was caused by preventative

maintenance issues.”37 This attempt at justification is in error; the Company is

charged with the affirmative burden of proof under PURA § 36.006, and must

show not only that its expenses included in rates are reasonable and necessary, but

that expenses included in the storm reserve were not reasonably anticipated. 38

PURA § 36.006 unequivocally establishes that the utility has the burden of proof

on the case. If too much time had passed to prove what portion of the storm costs

was not related to the imprudence, then the Commission should have found that

ETI failed to meet its burden of proof and disallowed the entire amount.

37
AR, Binder 5, Item No. 185, PFD at 56.
38
PURA §§ 36.051 and 36.064; 16 Tex. Admin. Code § 25.231(b) and (b)(1)(G).
25
 More directly, the Commission failed to give effect to the Order in Docket

No. 16705 with regard to the storm costs. In that docket, the Company had

proposed recovery of the 1997 costs as a post-test year adjustment. The

Commission rejected ETI’s request and expressly found:

147. Any reduction to the reserve fund occurring after the test year
should not be considered in this case because EGS did not prove a
reasonable post-test-year level for its existing reserve fund or that the
amount expended in 1997 to reduce the fund was prudent or
appropriate. Reserve fund levels following the test year in this case
can be addressed in EGS’ November 1998 rate filing when all parties
will have the opportunity to evaluate the reasonableness of changes to
the insurance reserve fund. 39

The underlying docket to this appeal, Docket No. 39896, is the first fully

litigated rate case for the Company since Docket No. 16705 due to a rate freeze

imposed on the Company and settlement of all subsequent rate cases for the

Company after the freeze was lifted. As such, Docket No. 39896 represented the

first opportunity to address the inclusion of 1997 storm costs. The parties

effectively stood in the same position as if it was November 1998, and it was error

for the Commission to treat the issue and the parties as if it were otherwise.

Altering the burden of proof, ignoring the imprudence finding related to the cause

of the storm damage and failing to require the company to show the

39
Docket No. 16705, Application of Entergy Texas for Approval of its Transition to Competition Plan and the
Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, Second Order on Rehearing at
84 (Finding of Fact No. 147) (Oct. 14, 1998).
26
reasonableness of including these costs in the reserve fund constitutes reversible

error under APA § 2001.174(2)(A),(D),(E) and (F).

a. ETI has the burden of persuasion on the entire case failed to prove
each required element to meet this burden.
The burden of proof for a contested electric utility rate proceeding is on the

electric utility. PURA Section 36.006(1) states that the electric utility has the

burden of proving that the rate change is just and reasonable, if the utility

proposes the change. 40 Courts have interpreted this statutory burden of proof to

mean that, “in order to raise the price of its product, the utility must participate in

a rate case and bear the burden of proving that each dollar of cost incurred was

reasonably and prudently invested.” 41 PURA Section 36.006 serves to place the

burden of persuasion on the electric utility in that if no evidence at all were

offered, the electric utility would not prevail. 42 The burden of persuasion does not

shift but remains with the same party for the entire case.43

40
PURA Chapter 36, subchapters A and B and Chapter 37, subchapter D is submitted as
Appendix C.
41
Entergy Gulf States, Inc. v. Public Utility Commission, 112 S.W.3d 208, 214 (Tex. App.—Austin 2003,
pet. denied) citing Public Utility Commission v. Houston Lighting & Power Co., 778 S.W.2d 195, 198 (Tex.
App.—Austin 1989, no writ)); See Boaz v. Harris, 30 S.W.2d 810, 811 (Tex. Civ. App.—Fort Worth
1930, no writ). Entergy Gulf States, Inc. v. Public Utility Commission is submitted as Appendix D.
42
See Cameron Compress Co. v. Kubecka, 283 S.W. 285, 286 (Tex. Civ. App.—Austin 1926, writ ref’d)
(“[T]he burden of proof rests upon the party who holds the affirmative of an issue or proposition
of fact.” . . . The general test in determining who has the affirmative of an issue is “which party
would be successful if no evidence at all were given.”).
43
Boaz v. Harris, 30 S.W. 2d 810, 811; 35 Tex Jur 3d, Evidence § 103 at 190 (Gene A. Noland, ed.,
27
 b. The Commission erred in finding that ETI had established a prima
facie case sufficient to shift the burden of proof.
Another subset of the burden of proof is the burden of production. This

burden may shift from party to party during the case and is the burden of

producing or going forward with the evidence in order to make or meet a prima

facie case. Boaz v. Harris, 30 S.W.2d 810, 811 (quoting Fritsche v. Niechoy, 197 S.W. 1017,

1018 (Tex. App. – Galveston 1917, writ dism’d w.o.j.) (“The burden of proof does

not shift at any time in the trial of a cause, though the weight of the evidence

does.”)). 44 The establishment of a prima facie case plays a role in determining which

party has the burden of production. Prima facie evidence is evidence that suffices

for proof of a particular fact until it is contradicted and overcome by other

evidence. 45 The prima facie standard requires the production of sufficient evidence

with which to support a rational inference that the allegation of fact is true. 46 A

prima facie case must be established for each and every element of proof. 47 If a prima

facie case is fully established, the burden of production shifts to the opponent.

1984).
44
See Texas Parks & Wildlife Department v. Dearing, 240 S.W.3d 330, 355-56 (Tex. App.—Austin
2007, pet. denied).
45
Dodson v. Watson, 110 Tex. 355, 358, 220, S.W. 771, 772 (1920).
46
See In re E.I. DuPont de Nemours & Co., 136 S.W.3d 218, 223 (Tex. 2004) (orig. proceeding).
47
See Hernandez v. State 161 S.W.3d 491, 497-98 (Tex. Crim. App. 2005); Wyeth v. Hall, 118 S.W.3d
487, 491 (Tex. App. – Beaumont 2003, no pet.).
28
 However, if the plaintiff fails to establish a prima facie case, the defendant is

under no obligation or duty to produce any evidence. 48 In Docket No. 39896, ETI

failed to prove that the requested $13,014,379 in 1997 ice storm costs were “not

reasonably anticipated” and further failed to affirmatively prove that the costs

were prudently incurred with regard to the reason why the costs had to be

expended, not merely how the clean-up was carried out. The Commission erred in

failing to hold ETI to its burden of proof on these elements.

c. The overall burden of proof remained on ETI to affirmatively prove
each element of its case by a preponderance of the evidence. The
Commission erred in failing to hold ETI to this burden.
In the electric rate case context, Texas courts have stated that once the

utility has presented a prima facie case in support of its application, the burden of

going forward or burden of production shifts to the intervening parties, and that in

turn, once the utility’s prima facie case is rebutted, the burden falls back onto the

utility to prove its case by a preponderance of the evidence. 49 Texas courts have

held that “a utility enjoys no presumption that the expenditures reflected therein

have been prudently incurred by simply opening its books to inspection.” 50 Past

48
Lykes Bros.-Ripley S. S. Co. v. Pluto, 146 S.W.2d 414, 416 (Tex. Civ. App.—Galveston 1941, writ
dism’d judgm’t cor.).
49
Entergy Gulf States, Inc. v. Public Utility Commission, 112 S.W.3d 208, 215 (Tex. App.—Austin 2003,
pet. denied).
50
Id. citing Public Utility Commission v. Houston Lighting & Power Co., 778 S.W.2d 195, 198 (Tex. App.—
Austin 1989, no writ).
29
Commission orders provide further guidance as to the burden of proof in the

context of a prima facie case. The PFD adopted by the Commission in the

Company’s last litigated rate case, PUC Docket No. 16705, discussed the burden of

proof in the context of a prima facie case, stating:

The utility's task is not finished when it makes a prima facie case, by a
preponderance of the evidence that its expenditures were in fact
reasonably incurred. That case may be challenged, and the
challenger can make a reasonable challenge without introducing
evidence which directly establishes imprudence. A challenger need
not establish that a particular decision proximately caused
unnecessary or [avoidable] costs. The challenging evidence need
only tend to disprove prudence by making a prima facie case.
Once such evidence has been produced by the challenger, the burden
returns to the utility to produce evidence to show, by a
preponderance of the evidence, that the challenged decisions were
prudent.

When what is at issue is not simple facts, such as the price actually
paid, but why certain things were done, … [and when] one party is
far better able to know what the relevant facts were and how they
fit together, it is manifestly reasonable to require only that a
challenge be plausible, and that rebuttal be substantial. . . .

A utility which does not present all the evidence relevant to its
claim to have acted prudently cannot succeed by pointing to mere
evidentiary gaps in challengers' cases. “Only upon presentation of
the affirmative evidence supporting all of the utility's actions during
the reconciliation period can interested or affected persons know
exactly what actions were taken.” 51

51
Application of Entergy Texas for Approval of its Transition to Competition Plan and the Tariffs Implementing
30
This discussion from the Company’s last fully-litigated rate case details the

burden-shifting process that applies in electric utility rate cases and makes clear

that despite the potential shifting of the burden of production, the overall burden

of proof remains on the utility to show by a preponderance of the evidence that the

expenditures it seeks to recover in rates were reasonably and prudently incurred.

The Commission erred in failing to hold ETI to its burden of proof in violation of

PURA.

d. ETI’s statutory responsibilities do not expire or shift due to the
passage of time.
Merely because many years have elapsed from the time the costs were

incurred to the time the costs were presented as part of ETI’s Docket No. 39896

rate increase request, does not mean that the Company is somehow absolved of its

burden to affirmatively prove each element required for those costs to be included

in the storm reserve and reflected in rates. A reasonable company, after

experiencing a 60 basis-point reduction in its authorized rate of return due to

quality of service inadequacies and having it expressly stated in the same

Commission Order that the amount of storm damage was greatly exacerbated due

to the Company’s inadequate vegetation management, would make some attempt

the Plan, and for Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for
Under-Recovered Fuel Costs, PUC Docket No. 16705, Proposal For Decision at 7-9 (Mar. 25, 1998)
(Citations omitted) (Emphasis in bold added). An excerpt from the Docket No. 16705 PFD is
submitted as Appendix G.
31
to quantify or carve out what portion of the storm restoration costs were due to

the exacerbated damage. This could have been done by the Company in 1998, very

close in time to the actual restoration effort, or anytime in the years thereafter

prior to filing its rate case in Docket No. 39896. There are other ways beyond

tracking expenses the Company could have attempted in order to show what ice

storm costs a prudent company would have incurred, but the passage of time does

not excuse the Company from carrying its burden. The distance in time is not a

valid basis on which to decide not to require proof of prudence from the Company,

and the Commission erred in adopting this faulty justification.

e. The PFD adopted by the Commission improperly shifted the burden
to OPUC and intervening parties.
The PFD adopted by the Commission erroneously found that ETI had

established a prima facie case that shifted the burden of proof to OPUC and the

intervening parties. As discussed in the above sections, ETI failed to establish a

prima facie case on each required element of proof. However, even if ETI had

established a prima facie case sufficient to prevail if unrebutted, the standard of

proof imposed on OPUC and other parties by the PFD adopted by the Commission

was far beyond what is required under Texas law and established Commission

precedent.

Texas law makes clear that, in order to defeat a prima facie case, the opponent
32
must meet the weight of the evidence provided and, once met, the party with the

burden of proof must prove its case by a preponderance of the evidence. The

Texas Court of Civil Appeals articulated the rule to be followed:

The rule that, when the defendant seeks to defeat the prima facie case
made by the plaintiff by evidence tending to show that some fact
necessary to establish such prima facie case is not true, the burden
does not rest upon him to establish the nonexistence of such fact by a
preponderance of the evidence, but in such case, unless the jury find
from a preponderance of all the evidence that the facts necessary to
establish plaintiff’s right to recover are true, they should find for the
defendant, is firmly fixed by the decisions of our Supreme Court.

Koppe v. Koppe, 57 Tex. Civ. App. 204, 210, 122 S.W. 68, 71-72 (1909). One of the

Supreme Court decisions Koppe referred to is Clark v. Hiles, 67 Tex. 141, 2 S.W. 356

(1886). Clark was an appeal of a boundary dispute in which the question presented

to the Court dealt with the burden of proof and what shifts when a plaintiff has

made out a prima facie case. Id. at 360, 148. The Court stated that the general rule is

that “the burden of proof ‘remains on a party affirming a fact in support of his case,

and does not change in any aspect of the cause, though the weight of the evidence

may shift from side to side, according to the nature and strength of proof

offered in support or denial of the main fact to be established.’” Id. at 360, 148

(citations omitted) (emphasis added).

33
 Going beyond the required standard for sufficiently rebutting a prima facie

case, The PFD adopted by the Commission placed upon OPUC the burden to

produce evidence to challenge “specific expense items included in the storm

damage reserve.” AR, Binder 5, Item No. 185, PFD at 56. This standard for

production required OPUC to go beyond rebutting prima facie evidence; it required

OPUC to rebut data on a level of specificity the Company did not present in

evidence. Rebuttal evidence is “evidence given to disprove facts given in evidence by

an adverse party.” 52

In the electric rate case context, the Commission in the past has articulated

what is required when rebutting a prima facie case. In the Company’s last litigated

rate case, PUC Docket No. 16705, the Commission adopted the majority of the

March 25, 1998 Proposal for Decision, including an analysis of the burden of proof

in the context of a prima facie case and, citing past PUC precedent, stated:

The utility's task is not finished when it makes a prima facie case,
by a preponderance of the evidence that its expenditures were in fact
reasonably incurred. That case may be challenged, and the
challenger can make a reasonable challenge without introducing
evidence which directly establishes imprudence. A challenger need
not establish that a particular decision proximately caused
unnecessary or [avoidable] costs. The challenging evidence need
only tend to disprove prudence by making a prima facie case.

52
Apresa v. Montfort Ins. Co., 932 S.W.2d 246, 251 (Tex. App.—El Paso 1996, no writ).
34
 Once such evidence has been produced by the challenger, the burden
returns to the utility to produce evidence to show, by a
preponderance of the evidence, that the challenged decisions were
prudent. 53

The PFD further stated:

A utility which does not present all the evidence relevant to its
claim to have acted prudently cannot succeed by pointing to mere
evidentiary gaps in challengers' cases. “Only upon presentation of
the affirmative evidence supporting all of the utility's actions during
the reconciliation period can interested or affected persons know
exactly what actions were taken.” 54

As noted above, the standard for rebutting a prima facie case is not as high as that

which the Commission imposed on OPUC in Docket No. 39896. The

Commission’s error in finding that ETI had established a prima facie case was

compounded by shifting the burden and improperly requiring OPUC to produce

evidence on specific expense items in order to rebut ETI’s prima facie case.

53
Application of Entergy Texas for Approval of its Transition to Competition Plan and the Tariffs Implementing
the Plan, and for Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for
Under-Recovered Fuel Costs, PUC Docket No. 16705, Proposal For Decision at 7-9 (Mar. 25, 1998)
(citations omitted) (emphasis in bold added).
54
Id. (citations omitted) (emphasis in bold added).
35
 f. Under Texas and Commission standards, ETI failed to meet its
burden of proof required for the inclusion of the $13,014,379 in 1997
ice storm costs.
To summarize, under the burden of proof standards articulated by the

Commission, ETI failed to make a prima facie case.55 And, even assuming for the

sake of argument that ETI had made a prima facie showing, the Commission erred

in imposing an improper standard of proof for rebutting any such prima facie

showing. OPUC and Cities provided evidence that “tends to disprove” prudence

and supports the conclusion that the expenses were in fact reasonably

anticipated. 56 The burden then returned to the Company to produce evidence that

affirmatively showed by a preponderance of the evidence that either the entirety of

the approx. $13 million in restoration costs were unrelated to the imprudent

action, or to show what portion thereof was and was not related to the imprudent

action and was not reasonably anticipated.

ETI failed to establish a prima facie case for each element of proof required in

order to include its requested $13,014,379 of 1997 ice storm restoration costs in the

storm reserve balance. By allowing ETI to include its requested 1997 ice storm

restoration costs in the storm reserve balance without actually establishing a prima

55
Id.
56
AR, Binder 39, OPUC Exhibit No. 6, Benedict Direct at 6-12, 78-87 and 88; AR Binder 8, Cities
Exhibit No. 5, Pous Direct at 46-59.
36
facie case for each element of proof, the Commission violated PURA’s requirement

that the burden of proof be placed on the utility. For this reason, the

Commission’s Order should be reversed on the issue of the storm reserve balance

and remanded to the Commission based upon the existing evidentiary record.

ETI’s task was to show “the existence of each element of [its claim],” i.e., “to

prove every fact essential to their case.” 57 ETI failed to show that the expenses the

Company requested to include in its storm reserve balances are reasonable and

prudent and not reasonably anticipated. Consequently, the Commission erred as a

matter of law in failing to hold ETI to its burden of proof with regard to storm

damage expenses.

5. The Commission’s decision to approve the inclusion of $13 ,014,379 in
1997 ice storm costs is arbitrary and capricious and constitutes an abuse
of discretion.

The Commission committed legal error by abusing its discretion and acting

in an arbitrary and capricious manner when approving the inclusion of the 1997 ice

storm costs in ETI’s storm reserve, cost of service, and rates. An administrative

agency’s decision is arbitrary or results from an abuse of discretion if the agency:

(1) failed to consider a factor the legislature directs it to consider; (2) considers an

irrelevant factor; or (3) weighs only relevant factors that the legislature directs it
57
Vance v. My Apartment Steak House, 677 S.W.2d 480, 482 (Tex. 1984).
37
to consider but still reaches a completely unreasonable result. 58 In allowing the

inclusion of all $13,014,379 of ice storm expenses in ETI’s cost of service, the

Commission failed to consider factors the legislature directs it to consider,

including whether the costs were “not reasonably anticipated” and prudently

incurred. Tellingly, there were no findings of fact or conclusions of law with

regard to whether the costs were not reasonably anticipated.

The Commission also acted in an arbitrary and capricious manner by

considering irrelevant factors. The Commission, through the adopted PFD,

erroneously considered the passage of time between the rate case and the

incurrence of the storm expenses, and absolved the Company of its burden to

prove what portion of the approximately $13 million was due to the exacerbated

damages caused by the imprudent vegetation management and what portion

would have been incurred even with prudent management. 59 The Commission,

through the adopted PFD, also erroneously considered the 60 basis-point

reduction to the Company’s ROE imposed for poor quality of service including

poor call center response time. 60

58
City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 184 (Tex. 1994). See also, Reliant Energy, Inc. v.
Public Util. Comm’n, 62 S.W.3d 833, 841 (Tex. App. – Austin 2001, no pet.).
59
AR, Binder 5, Item No. 185, PFD at 56; see supra pp. 16-19, 25-26 and 31-32.
60
Id.; see supra pp. 22-24.
38
 Additionally, when an agency fails to “follow the clear, unambiguous

language of its own regulation,” it acts arbitrarily and capriciously. 61 The

Commission failed to follow the clear, unambiguous language of its own

substantive rule which states unequivocally that “any expenditure found by the

Commission to be unreasonable, unnecessary or not in the public interest” “shall

never be a component of the cost of service.” 16 Tex. Admin. Code

§ 25.231(b)(2)(J).62 The Commission also failed to follow its own substantive rule

which allows storm costs to be included in the storm reserve, to the extent they

are reasonable and necessary, and are not reasonably anticipated. 16 Tex. Admin.

Code § 25.231(b)(1)(G). Moreover, as stated above, the Commission made no

findings of fact or conclusions of law as to whether the ice storm expenses were

not reasonably anticipated. Further, the Commission disregarded the prior-

established finding from the final order of the Commission in Docket No. 18249

which found that storm damage was greatly exacerbated by the state of the

Company’s vegetation management.

For these reasons, it was arbitrary and capricious to include all of the

Company’s requested ice storm expenses in SPS’s storm reserve and allow these

costs to be reflected in SPS’s cost of service and rates.

61
Public Util. Comm’n v. Gulf States Utilities, 809 S.W.2d 201, 207 (Tex. 1991).
62
See also PURA § 36.062(4).
39
 PRAYER

For the reasons stated in this brief, the Office of Public Utility Counsel

respectfully prays that the Court reverse the district court’s judgment insofar as it

upholds the Commission’s decision in the respects discussed above. OPUC

further prays that the Court remand the case to the Commission for further

proceedings, based upon the existing evidentiary Record, to determine rates

consistent with the Court’s decision. Finally, OPUC respectfully prays that this

Court grant the OPUC such other and further relief to which it may be justly

entitled.

Respectfully submitted,

Tonya Baer
Public Counsel
State Bar No. 24026771

/s/ Sara J. Ferris___________________________
Sara J. Ferris
Senior Assistant Public Counsel
State Bar No. 50511915

OFFICE OF PUBLIC UTILITY COUNSEL
1701 N. Congress Avenue, Suite 9-180
P.O. Box 12397, Capitol Station
Austin, Texas 78711-2397
512/936-7500 (Telephone)
512/936-7525 (Facsimile)

40
 CERTIFICATE OF COMPLIANCE

I certify that the Appellant’s Brief and Appendix of the Office of Public
Utility Counsel contains 8,113 words, as measured by the undersigned counsel’s
word-processing software, and therefore complies with the word limit found in
Tex. R. App. P. 9.4(i)(2)(B).

__ /s/ Sara J. Ferris_________________
Sara J. Ferris

CERTIFICATE OF SERVICE

I certify that the Appellant’s Brief and Appendix of the Office of Public
Utility Counsel 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 of the
Appellant’s Brief and Appendix of the Office of Public Utility Counsel was served
upon counsel for each party of record, listed below, by electronic service or 1st
Class U.S. Mail, on this 31st day of March, 2015.

ENTERGY TEXAS, INC. CITIES OF ANAHUAC,
Marnie A. McCormick BEAUMONT, ET. AL
John F. Williams Daniel J. Lawton
Duggins, Wren, Mann & Romero, LLP Lawton Law Firm PC
P.O. Box 1149 12600 Hill Country Blvd, Suite R275
Austin, Texas 78767-1149 Austin, Texas 78738
(512) 744-9300 (512) 322-0019
mmcormick@dwmrlaw.com dlawton@ecpi.com
jwilliams@dwmrlaw.com

41
PUBLIC UTILITY COMMISSION TEXAS INDUSTRIAL ENERGY
OF TEXAS CONSUMERS
Elizabeth R. B. Sterling Rex VanMiddlesworth
Assistant Attorney General Benjamin Hallmark
Environmental Protection Division Thompson Knight LLP
Office of the Attorney General 98 San Jacinto Blvd, Suite 1900
P. O. Box 12548, Capitol Station Austin, Texas 78701
Austin, Texas 78711-2548 (512) 320-9200
(512) 475-4152 rex.vanm@tklaw.com
elizabeth.sterling@texasattorneygeneral.gov benjamin.hallmark@tklaw.com

STATE AGENCIES OF TEXAS
Katherine H. Farrell
Assistant Attorney General
Admin Law Div. – Energy Rates Section
Office of the Attorney General
P. O. Box 12548
Austin, Texas 78711-2548
(512) 475-4173
katherine.farrell@texasattorneygeneral.gov

_ /s/ Sara J. Ferris_________________
Sara J. Ferris

42
 Appendix to the Appellant’s Brief
of the Office of Public Utility Counsel

A: District Court Judgement, Cause No. D-1-GN-13-000121
(Consolidated)

B: PUC Docket No. 39896, Order on Rehearing

C: PURA, Chapter 36, Subchapters A and B, and Chapter 37,
Subchapter D

D: Entergy Gulf States, Inc. v. Public Utility Commission, 112 S.W.3d
208 (Tex. App. – Austin 2003, pet. denied)

E: Texas Utilities Electric Company v. Public Utility Commission, 881
S.W.2d 387 (Tex. App. – Austin 1994) aff’d in part, rev’d in
part on other grounds, 935 S.W.2d 109 (Tex. 1997)

F: PUC Docket No. 18249, Order on Rehearing

G: Excerpt from: PUC Docket No. 16705, Proposal for
Decision

H: Excerpts from: PUC Docket No. 16705, Second Order on
Rehearing

I: 16 Tex. Admin. Code § 25.231
 Appendix A

District Court Judgement,
Cause No. D-1-GN-13-000121 (Consolidated)
 DC BK14295 PG132

Filed In 1°h o·
of Travis ~ •strict Cour:·
ounty, Texas
EM OCT 1~ tUl'I
CAUSE NO. D-l-GN-13-000121 At (/ ·d-t..f. A
Amalia Rodriguez.Mendoza, c;e~·

ENTERGY TEXAS, INC., § IN THE DISTRICT COURT OF
Plaintiff §
§
v. § TRAVIS COUNTY, TEXAS
§
PUBLIC UTILITY COMMISSION, §
Defendant § 353RD JUDICIAL DISTRICT

ORDER ON ADMINISTRATIVE APPEAL

On July 22, 2014, the Court heard Plaintifrs appeal from Defendant' s Order in PUC

Docket No. 39896, SOAH Docket No. XXX-XX-XXXX. The administrative record was admitted

into evidence, and the Court heard oral argument. Entergy, the Cities, and OPUC each asserted

points of error challenging the Commission's order. Having considered the pleadings, the

evidence and the arguments of counsel, the Court makes the following rulings:

1. Entergy' s Point of Error No. 1 addressing the use of a current line loss study rather
that a prior-approved line loss study in allocating line loss costs among classes of
customers establishes that the Commission erred in applying the current study in
violation of Commission rules found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a)
and (c)(2)(B). Accordingly, the Court FINDS that the PUC's ruling was arbitrary and
capricious and constitutes an error of Jaw. The Court REVERSES such ruling and
REMANDS this matter to the Commission for further proceedings consistent with
this Court's Order.
2. All other points of error are DENIED, and the Commission's Order is in all other
respects AFFIRMED.

All relief not granted, herein, is DENIEDL l /
# rl.. llc114t.
Signed this J day of ~telli~r, 20 14.

J
 Appendix B

PUC Docket No. 39896, Order on Rehearing
 f ` , ^,n 7^^^ a a *^,

PUC DOCKET NO. 39896 201"`` Noy -2
V 9: 24
SOAH DOCKET NO. XXX-XX-XXXX

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, § OF TEXAS
AND OBTAIN DEFERRED §
ACCOUNTING TREATMENT §

ORDER ON REHEARING

This Order addresses the application of Entergy Texas, Inc. for authority to change rates,
reconcile fuel costs, and defer costs for the transition to the Midwest Independent System
Operator (MISO). In its application, Entergy requested approval of an increase in annual base-
rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff
schedules, including new riders to recover costs related to purchased-power capacity and
renewable-energy credit requirements, requested final reconciliation of its fuel costs, and
requested waivers to the rate-filing package requirements.

On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law

judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase
for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781
million. The ALJs also recommended approving total fuel costs of approximately $1.3 billion.

The ALJs did not recommend approving the renewable-energy credit rider and the Commission
earlier removed the purchased-power capacity rider as an issue to be addressed in this docket.'
On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the
exceptions and replies of the parties.2 Except as discussed in this Order, the Commission adopts
the proposal for decision, as corrected, including findings of fact and conclusions of law.

Parties filed motions for rehearing on September 25 and October 4, 2012 and filed replies
to the motions for rehearing on October 15, 2012. The Commission considered the motions for

' Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012).
2
Letter from SOAH judges to PUC (Aug. 8, 2012).
PUC Docket No. 39896 Order on Rehearing Page 2 of 44
SOAH Docket No. XXX-XX-XXXX

rehearing at the October 25, 2012 open meeting. The Commission granted Commission Staff's
motion for rehearing that requested technical corrections to reflect the rates that resulted from the
Commission Staff number-running memo that was filed on August 28, 2012. The Commission
modifies findings of fact 205, 206, 208, and 210 as requested by Commission Staff and attaches
Commission schedules I through V to reflects its decisions. The Commission granted the
Department of Energy's motion for rehearing requesting that finding of fact 198 be modified to
reflect the applicable off-season for the schedulable intermittent pumping service. Finding of
fact 198 is modified to reflect that the off-season is October through May. In its motion for
rehearing, Entergy noted that findings of fact 17B and 17D should be modified to more
accurately reflect the procedural history. The Commission modifies findings of fact 17B and
17D to state that Entergy agreed to extend time to provide the Commission sufficient time to
consider the issues in this proceeding on two occasions-at the July 27 and August 30, 2012
open meetings.

1. Discussion

A. Prepaid Pension Asset Balance
Entergy included in rate base an approximately $56 million item named Unfunded
Pension.3 This amount represents the accumulated difference between the annual pension costs
calculated in accordance with the Statement of Financial Accounting Standards (SFAS) No. 87
and the actual contributions made by Entergy to the pension fund-Entergy contributed nearly
$56 million more to its pension fund than the minimum required by SFAS No. 87.4

In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding
the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued
deferred federal income taxes (ADFIT) to be included in rate base.5 For the excluded portion,
the Commission allowed the accrual of an allowance for funds used during construction

3 Proposal for Decision at 23 (July 6, 2012) (PFD).
'` PFD at 23-24.
5 Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on
Rehearing (March 4, 2008).
 PUC Docket No. 39896 Order on Rehearing
SOAH Docket No. XXX-XX-XXXX Page 3 of 44

(AFUDC).6 The ALJs concluded that this approach was sound and should be followed in this
case.7 Thus, the ALJs recommended that the CWIP-related portion of Entergy's prepaid pension

asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However,
the ALJs did not address ADFIT.

The Commission agrees that the CWIP-related portion of Entergy's pension asset should

be excluded from the asset and that this excluded portion should accrue AFUDC. However, the
Commission also finds that the impact of this exclusion on Entergy's ADFIT should be reflected.
When items are excluded from rate base, the related ADFIT should also be excluded. The
adjusted ADFIT for the prepaid pension asset remaining in Entergy's rate base should be reduced

by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds
new finding of fact 28A to reflect this modification to Entergy's ADFIT.

B. FIN 48
The Financial Accounting Standards Board's Interpretation No. 48 (FIN 48) prescribes
the way in which a company must analyze, quantify, and disclose the potential consequences of
tax positions that the company has taken that are legally uncertain. Entergy reported that its
uncertain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on
Entergy's balance sheet as a tax liability. Entergy also reported that it made a cash deposit with
the IRS in the amount of $1,294,683 associated with its FIN 48 liability.9

The ALJs concluded that Entergy's FIN 48 liability should be included in its ADFIT
balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy's
FIN 48 liability should not be included in Entergy's ADFIT balance. Accordingly, the ALJs
recommended that $4,621,778 (Entergy's FIN 48 liability of $5,916,461 less the $1,294,683 cash
deposit Entergy has already made with the IRS) be added to Entergy's ADFIT balance and thus

6 Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change
Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011).
' PFD at 26.
8 Id at 24-26.

9 PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony
of Roberts, Entergy Ex. 64 at 8).
 PUC Docket No. 39896 Order on Rehearing Page 4 of 44
SOAH Docket No. XXX-XX-XXXX

be used to offset Entergy's rate base.10 The ALJs did not recommend the addition of a deferred-

tax-account rider because no party expressly advocated the addition of such a rider. II

The Commission adopts the proposal for decision regarding the adjustment to Entergy's
ADFIT for the amount attributable to Entergy's FIN 48 liability. However, the Commission also
follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the
proposal for decision on this point. In CenterPoint's Electric Delivery Company's last rate case,
Docket No. 38339,12 the Commission found that tax schedule UTP-on which companies must
describe, list, and rank each uncertain tax position-would provide the IRS auditors sufficient
information to quickly determine which uncertain tax positions are of a magnitude worth
investigating and that an IRS audit would be more likely to occur on some uncertain tax
positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome,
the utility would not be able to earn a return on the amount paid to the IRS until the next rate
case.

Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable
FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on
a prospective basis
an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN-
48 unfavorable-tax-position audit. The return will be applied prospectively to FIN-48
amounts
disallowed by an IRS audit after such amounts are actually paid to the federal government. If
Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position
decision by the IRS, then any amounts collected under rider related to that overturned decision
shall be credited back to ratepayers.

The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent
with its decision to authorize the deferred-tax-account tracker.

^o PFD at 29.
Id. at 29.
12
Application of CenterPoint Electric Delivery Company, LLC for Authority
to Change Rates, Docket
No. 38339, Order on Rehearing at 3-4 ( June 23, 2011).
PUC Docket No. 39896 Order on Rehearing Page 5 of 44
SOAH Docket No. XXX-XX-XXXX

C. Capitalized Incentive Compensation
Entergy capitalized into plant-in-service accounts some of the incentive payments made
to employees and sought to include those amounts in rate base. The ALJs determined that
Entergy should not be able to recover its financially based incentive-compensation costs.13
Therefore, the portion of Entergy's incentive-compensation costs capitalized during the period
July 1, 2009 through June 30, 2010 that were financially based was excluded from Entergy's rate
base. The ALJs also determined that the actual percentages should be used to determine the
amount that is financially based. 14

In discussing Entergy's incentive compensation as a component of operating expenses,
the ALJs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for
calculating the amount of the financially based incentive costs. This method uses the actual
percentage reductions applicable to each of the annual incentive programs that included a
component of financially-based costs. 15

In its exceptions regarding capitalized incentive compensation, Entergy advocated for the
use of TIEC's methodology to also calculate the amount of capitalized incentive compensation
that is financially based. Entergy also noted that the amount of the disallowance reflected in the
schedules, $1,333,352, was calculated using a disallowance factor that included incentive
compensation tied to cost-control measures, which the ALJs found to be recoverable in the
operating-cost incentive-compensation calculation.16 When the TIEC methodology is applied to
the capitalized incentive-compensation costs in rate base, the net result under TIEC's
methodology is that only $335,752.96 should be disallowed from capital Costs. 17

The Commission agrees that capitalized incentive compensation that is financially based
should be excluded from rate base and that the exclusion only applies to incentive costs that
Entergy capitalized during the period from July 1, 2009 through June 30, 2010. However, the
Commission finds that a consistent methodology should be used to calculate the amount to be

"PFDat 171.
1aki. at 72.
15 Id. at 174; see also Entergy's Exceptions to the Proposal for Decision at 25-26 (July 23, 2012).
16 Entergy's Exceptions to the Proposal for Decision at 25-26.
" !d. at 25-26.
 PUC Docket No. 39896 Order on Rehearing Page 6 of 44
SOAH Docket No. XXX-XX-XXXX

excluded and therefore that TIEC's methodology should also be used for calculating the amount

of capitalized financially based incentive-compensation costs that should be excluded from rate
base. Accordingly, the total amount of capitalized incentive-compensation costs that should be
disallowed from rate base is $335,752.96. Finding of fact 61 is modified to reflect this
determination.

As noted by Commission Staff, this disallowance to plant-in-service alters the expense
for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad
valorem taxes is $24,921,022," an adjustment of $1,222,106 to Entergy's test year amount.

Finding of fact 151 is modified to reflect this adjustment to property taxes.

D. Rate of Return and Cost of Capital
The ALJs found the proper range of an acceptable return on equity for Entergy would be
from 9.3 percent to 10.0 percent.19 The mid-point of the range is 9.65 percent. The ALJs found
that the effect of unsettled economic conditions facing utilities on the appropriate return on
equity should be taken into account and that the effect would be to move the ultimate return on
equity towards the upper limits of the range that was determined to be reasonable.20 The ALJs
found that the reasonable adjustment would be 15 basis points, moving the reasonable return on
equity to 9.80 percent.21

The Commission must establish a reasonable return for a utility and must consider
applicable factors.22 The Commission disagrees with the ALJs that a utility's return on equity

should be determined using an adder to reflect unsettled economic conditions facing utilities.
The Commission agrees with the ALJs, however, that a return on equity of 9.80 percent will

allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but
finds this rate appropriate independent of the 15-point adder recommended by the ALJs. A
return on equity of 9.80 percent is within the range of an acceptable return on equity found by

18 Commission Number-Run Memorandum at 2 (Aug. 28, 2012).
19 PFD at 94.
20 id

21 Id. at 94.

22 PURA §§ 36.051,.052.
PUC Docket No. 39896 Order on Rehearing Page 7 of 44
SOAH Docket No. XXX-XX-XXXX

the ALJs. Accordingly, the Commission adds new finding of fact 65A to reflect the
Commission's decision on this point.

E. Purchased-Power Capacity Expense
The ALJs rejected Entergy's request to recover $31 million more in purchased-power
capacity costs than its actual test-year expenses because Entergy had failed to prove that the
adjustment was known and measurable,23 and because the request violated the matching
principle.24 Consequently, the ALJs recommended that Entergy's test-year expenses of
$245,432,884 be used to set rates in this docket.25

Entergy pointed to an additional $533,002 of purchased-power capacity expenses that
were properly included in Entergy's rate-filing package, but not provided for in the proposal for
decision.26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for

Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for
an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of
purchased-power capacity costs were incurred during the test-year and should be added to the
purchased-power capacity costs in Entergy's revenue requirement. The Commission modifies
findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year
purchased-power capacity costs, increasing the total amount to $245,965,886.

F. Labor Costs - Incentive Compensation
The ALJs found that $6,196,037, representing Entergy's financially-based incentives paid
in the test-year, should be removed from Entergy's O&M expenses.27 The ALJs agreed with
Commission Staff and Cities that an additional reduction should be made to account for the
FICA taxes that Entergy would have paid for those costs,28 but did not include this reduction in a
finding of fact.

23 PFD at 108-09.
24 Id. at 109. •
s id

26 Entergy's Exceptions to the Proposal for Decision at 51.
''' PFD at 175.
21 1a! at 175-76.
PUC Docket No. 39896 Order on Rehearing Page 8 of 44
SOAH Docket No. XXX-XX-XXXX

The Commission agrees with the ALJs, but modifies finding of fact 133 to specifically
include the decision that an additional reduction should be made to account for the FICA taxes
Entergy would have paid on the disallowed financially-based incentive compensation. The
Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this
Order.29

G. Affiliate Transactions
OPUC argued that Entergy's sales and marketing expenses exclusively benefit the larger
commercial and industrial customers, but the majority of the sales, marketing, and customer
service expenses are allocated to the operating companies based on customer counts. Therefore,
the majority of these expenses are allocated to residential and small business customers. OPUC
argued that it is inappropriate for residential and small business customers to pay for these
expenses.30 The ALJs did not adopt OPUC's position on this issue.

The Commission agrees with OPUC and reverses the proposal for decision regarding
allocation of Entergy's sales and marketing expense and finds that $2.086 million of sales and
marketing expense should be reallocated using direct assignment. The Commission has
previously expressed its preference for direct assignment of affiliate expenses.31 The
Commission finds that the following amounts should be allocated based on a total-number-of-
customers basis: (1) $46,490 for Project E 10PCR56224 - Sales and Marketing - EGSI Texas;
(2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for
Project F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power
Service.32 The reallocation has the effect of increasing the revenue requirement allocated to the
large business class customers and reduces the revenue requirement for small business and
residential customers. New finding of fact 164A is added to reflect the proper allocation of these
affiliate transactions.

29 See Commission Number Run-Memorandum at 3 (Aug. 28, 2012).
30 Direct Testimony of Carol Szerszen, OPUC Ex. I at 44-45.
31 Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997).
'Z Direct Testimony of Carol Szerszen, OPUC Ex. 1 at Schedule CAS-7.
PUC Docket No. 39896 Order on Rehearing Page 9 of 44
SOAH Docket No. XXX-XX-XXXX

H. Fuel Reconciliation
Entergy proposed to allocate costs for the fuel reconciliation to customers using a line-
loss study performed in 1997. Entergy conducted a line-loss study for the year ending December
31, 2010, which falls in the middle of the two year fuel reconciliation period-July 2009 through

June 2011-and therefore reflects the actual line losses experienced by the customer classes
during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the
reconciliation period should reflect the current line-loss study performed by Entergy for this case
and recommended approval on a going-forward basis. Fuel factors under P.U.C. SUBST.
R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described
in P.U.C. SUBST. R. 25.236. P.U.C. SUSST. R. 25.236(d)(2) defines the scope of a fuel
reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel
expenses and whether the utility has over- or under-recovered its reasonable fuel expenses.33
Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the
reconciliation period using the current line-losses. The ALJs rejected Cities' proposed
adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission-
approved line losses that were in effect at the time fuel costs were billed to customers in a fuel
reconciliation. 34

The Commission agrees with Cities and reverses the proposal for decision regarding
which line-loss factors should be used in Entergy's fuel reconciliation. Entergy used the 2010
study line-loss calculations to calculate the demand- and energy-related allocations in its cost of
service analysis supporting its requested base rates. These same currently available line-loss
factors should have been utilized in Entergy's fuel reconciliation. The Commission finds that
Entergy's 2010 line-loss factors should be used to calculate Entergy's fuel reconciliation
over-recovery. As a result, Entergy's fuel reconciliation over-recovery should be reduced by

$3,981,271. Finding of fact 246A and conclusions of law 19A and 19B are added to reflect the
Commission's finding that the 2010 line-loss factors be used to reconcile Entergy's fuel costs.

'3 Cities' Exceptions to the Proposal for Decision at 20-21 (July 23, 2012).
31 PFD at 327-328.
PUC Docket No. 39896 Order on Rehearing Page 10 of 44
SOAH Docket No. XXX-XX-XXXX

1. MISO Transition Expenses
During the Commission's consideration of the proposal for decision, the parties that
contested the amount of Entergy's MISO transition expenses and how the transition expenses
should be accounted for reached announced on the record that they had reached an agreement on
these issues.35 Those parties agreed that the MISO transition expenses would not be deferred and
that Entergy's base rates should include $1.6 million for MISO transition expense.36 The
Commission adopts the agreement of the parties and accordingly modifies finding of fact 251
and deletes finding of fact 252.

J. Purchased-Power Capacity Cost Baseline
The Commission modified the amount of purchased-power capacity expense in the
test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the
change to the proper test-year purchased-power capacity expense.

K. Other Issues
New findings of fact 17A, 17B, 17C, 17D, and 17 E are added to reflect procedural
aspects of the case after issuance of the proposal for decision.

In addition, to reflect corrections recommended by the ALJs, findings of fact 116, 123,
192, 194, and 202 are modified; and new finding of fact 182A is added.

The Commission adopts the following findings of fact and conclusions of law:

II. Findings of Fact

Procedural History
l. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a
retail service area located in southeastern Texas.

35
Open Meeting Tr. at 138 (Aug. 17, 2012).
36 /d
PUC Docket No. 39896 Order on Rehearing Page I I of 44
SOAH Docket No. XXX-XX-XXXX

2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
Commission (FERC) regulates ETI's wholesale electric operations.

3. On November 28, 2011, ETI filed an application requesting approval of. (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted test-
year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate
Filing Package for Generating Utilities (RFP) accompanying ETI's application and
including new riders for recovery of costs related to purchased-power capacity and
renewable energy credit requirements; (3) a request for final reconciliation of ETI's fuel
and purchased-power costs for the reconciliation period from July 1, 2009 to
June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V
accompanying ETI's application.

4. The 12-month test-year employed in ETI's filing ended on June 30, 2011 (test-year).

5. ETI provided notice by publication for four consecutive weeks before the effective date
of the proposed rate change in newspapers having general circulation in each county of
ETI's Texas service territory. ETI also mailed notice of its proposed rate change to all of
its customers. Additionally, ETI timely served notice of its statement of intent to change
rates on all municipalities retaining original jurisdiction over its rates and services.

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

7. On November 29, 2011, the Commission referred this case to the State Office of
Administrative Hearings (SOAH).
 PUC Docket No. 39896 Order on Rehearing Page 12 of 44
SOAH Docket No. XXX-XX-XXXX

8. On December 7, 2011, the Commission issued its order requesting briefing on threshold
legal/policy issues.

9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31
issues to be addressed in this proceeding.

10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order
No. 2, which approved an agreement among the parties to establish a June 30, 2012
effective date for the company's new rates resulting from this case pursuant to certain
agreed language and consolidate Application of Entergy Texas, Inc. for Authority to Defer
Expenses Related to its Proposed Transition to Membership in the Midwest Independent
System Operator, Docket No. 39741 ( pending) into this proceeding. Although it did not
agree, Staff did not oppose the consolidation.

11. On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for
admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and
participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick
D. Chamberlain to appear and participate as counsel for Wal-Mart.

12. On January 19, 2012, the Commission issued a supplemental preliminary order
identifying two additional issues to be addressed in this case and concluding that the
company's proposed purchased-power capacity rider should not be addressed in this case
and that such costs should be recovered through base rates.

13. ETI timely filed with the Commission petitions for review of the rate ordinances of the
municipalities exercising original jurisdiction within its service territory. All such
appeals were consolidated for determination in this proceeding.

14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues
into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC
Docket No. 39896, Docket No. 40295 (pending).

15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
revenues to approximately $104.8 million over adjusted test-year revenues.

16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.
PUC Docket No. 39896 Order on Rehearing Page 13 of 44
SOAH Docket No. XXX-XX-XXXX

17. Initial post-hearing briefs were filed on May 18 and reply briefs were tiled on May 30,
2012.

17A. On August 7, 2012, the SOAH ALJs filed a letter with the Commission recommending
changes to the PFD.

17B At the July 27, 2012 open meeting, ETI agreed to extend time to August 31, 2012 to
provide the Commission sufficient time to consider the issues in this proceeding.

17C. The Commission considered the proposal for decision at the August 17, 2012 and August
30, 2012 open meetings.

17D. At the August 30, 2012 open meeting, ETI agreed to extend time to September 14, 2012
to provide the Commission sufficient time to consider the issues in this proceeding.

17E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the
amount of costs for the transition to MISO.

Rate Base
18. Capital additions that were closed to ETI's plant-in-service between July 1, 2009 and
June 30, 2011, are used and useful in providing service to the public and were prudently
incurred.

19. ETI's proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 ( Dec. 13, 2010).

20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased
when Docket No. 37744 concluded because the asset would have then begun earning a
rate of return as part of rate base.

21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
test-year in the present case, and less the amount of additional insurance proceeds
received by ETI after the conclusion of Docket No. 37744.

22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
remain in rate base, applying a five-year amortization rate beginning August 15, 2010.
 PUC Docket No. 39896 Order on Rehearing Page 14 of 44
SOAH Docket No. XXX-XX-XXXX

23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.

24. The company requested in rate base its prepaid pension assets balance of $55,973,545,
which represents the accumulated difference between the Statement of Financial
Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual
contributions made by the company to the pension fund.

25. The prepaid pension assets balance includes $25,311,236 capitalized to construction work
in progress (CWIP).

26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
was insufficient evidence showing that major projects under construction were efficiently
and prudently managed.

27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not
be included in ETI's rate base.

28. The remainder of the prepaid pension assets balance should be included in ETI's rate
base.

28A. When items are excluded from rate base, the related ADFIT should also be excluded.
The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded
from rate base is $8,858,933. The adjusted ADFIT for the prepaid pension asset
remaining in Entergy's rate base should be reduced by $8,858,933.

29. ETI should be permitted to accrue an allowance for funds used during construction on the
portion of ETI's Prepaid Pension Assets Balance capitalized to CWIP.

30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48
(FIN 48), "Accounting for Uncertainty in Income Taxes," requires ETI to identify each of
its uncertain tax positions by evaluating the tax position on its technical merits to

determine whether the position, and the corresponding deduction, is more-likely-than-not
to be sustained by the Internal Revenue Service (IRS) if audited.

31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
PUC Docket No. 39896 Order on Rehearing Page 15 of 44
SOAH Docket No. XXX-XX-XXXX

purposes and record it as a potential liability with interest to better reflect the company's
financial condition.

32. At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon
tax positions that the company believes will not prevail in the event the positions are
challenged, via an audit, by the IRS.

33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 liability.

34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48
liability.

35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.

36. ETI may never have to pay the IRS the FIN 48 liability.

37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48
liability funds.

38. Until actually paid to the IRS, the FIN 48 liability represents cost-free capital and should
be deducted from rate base.

39. The amount of $4,621,778 (representing ETI's full FIN 48 liability of $5,916,461 less the
$1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be
added to ETI's ADFIT and thus be used to reduce ETI's rate base.

40. ETI's application and proposed tariffs do not include a request for a tracking mechanism
or rider to collect a return on the FIN 48 liability.

40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to
recover on a prospective basis an after-tax return of 8.27% on the amounts paid to the
IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN
48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by
an IRS audit after such amounts are actually paid to the federal government. If ETI
prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider
related to that decision should be credited back to ratepayers.
PUC Docket No. 39896 Order on Rehearing Page 16 of 44
SOAH Docket No. XXX-XX-XXXX

41. Deleted.

42. Investor-owned electric utilities may include a reasonable allowance for cash working
capital in rate base as determined by a lead-lag study conducted in accordance with the
Commission's rules.

43. Cash working capital represents the amount of working capital, not specifically addressed
in other rate base items, that is necessary to fund the gap between the time expenditures
are made and the time corresponding revenues are received.

44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted
for known and measurable changes, and is consistent with P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii).

45. It is reasonable to establish ETI's cash working capital requirement based on ETI's lead-
lag study as updated in Jay Joyce's rebuttal testimony and on the cost of service approved
for ETI in this case.

46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7,
2008) and Docket No. 37744, the Commission did not approve ETI's storm damage
expenses since 1996 and its storm damage reserve balance.

47. ETI established a prima facie case concerning the prudence of its storm damage expenses
incurred since 1996.

48. Adjustments to the storm damage reserve balance proposed by intervenors should be
denied.

49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.

50. ETI's appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51. The amount of $9,846,037, representing the value of the average coal inventory
maintained at ETI's coal-burning facilities, is reasonable, necessary, and should be
included in rate base.
PUC Docket No. 39896 Order on Rehearing Page 17 of 44
SOAH Docket No. XXX-XX-XXXX

52. The Spindletop gas storage facility (Spindletop facility) is used and useful in providing
reliable and flexible natural gas supplies to ETI's Sabine Station and Lewis Creek
generating plants.

53. The Spindletop facility is critical to the economic, reliable operation of the Sabine Station
and Lewis Creek generating plants due to their geographic location in the far western
region of the Entergy system.

54. It is reasonable and appropriate to include ETI's share of the costs to operate the
Spindletop facility in rate base.

55. Staff recommended updating ETI's balance amounts for short-term assets to the 13-
month period ending December 2011, which was the most recent information available.
Staff's proposed adjustments should be incorporated into the calculation of ETI's rate
base.

56. The following short-term asset amounts should be included in rate base: prepayments at
$8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the
Spindletop facility, represent actual costs incurred to process and close the acquisition,
not mere mark-up costs.

58. ETI's $1,127,778 in capitalized acquisition costs should be included in rate base because
ETI incurred these costs in conjunction with the purchase of a viable asset that benefits
its retail customers.

59. In its application, ETI capitalized into plant in service accounts some of the incentive
payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60. A portion of those capitalized incentive accounts represent payments made by ETI for
incentive compensation tied to financial goals.

61. The portion of ETI's incentive payments that are capitalized and that are financially-
based should be excluded from ETI's rate base because the benefits of such payments
inure most immediately and predominantly to ETI's shareholders, rather than its electric
 PUC Docket No. 39896 Order on Rehearing Page 18 of 44
SOAH Docket No. XXX-XX-XXXX

customers. ETI's capitalized incentive compensation that is financially based is
$335,752.96 and should be removed for rate base.

62. The test-year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the
reasonableness of ETI's capital costs (including capitalized incentive compensation) for
that prior period was dealt with by the Commission in that proceeding and is not at issue
in this proceeding.

63. In this proceeding, ETI's capitalized incentive compensation that is financially-based
should be excluded from rate base, but only for incentive costs that ETI capitalized
during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010
(the commencement of the current test-year).

Rate of Return and Cost of Capital
64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable
opportunity to earn a reasonable return on its invested capital.

65. The results of the discounted cash flow model and risk premium approach support a ROE
of 9.80 percent.

65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions
facing utilities.

66. A 9.80 percent ROE is consistent with ETI's business and regulatory risk.

67. ETI's proposed 6.74 percent embedded cost of debt is reasonable.

68. The appropriate capital structure for ETI is 50.08 percent long-term debt and
49.92 percent common equity.

69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is
reasonable in light of ETI's business and regulatory risks.

70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help
ETI attract capital from investors.
PUC Docket No. 39896 Order on Rehearing Page 19 of 44
SOAH Docket No. XXX-XX-XXXX

71. ETI's overall rate of return should be set as follows:

CAPITAL WEIGHTED AVG
COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL
LONG-TERM DEBT 50.08% 6.74% 3.38%
COMMON EQUITY 49.92% 9.80% 4.89%
TOTAL 100.00% 8.27%

Operating Expenses
72. ETI's test-year purchased capacity expenses were $245,965,886.

73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its
purchased capacity costs. This request was based on ETI's projections of its purchased
capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
rate-year).

74. ETI's purchased capacity expense projections were based on estimates of rate-year
expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments
under third-party capacity contracts; and (c) payments under affiliate contracts.

75. ETI's projection of its rate-year reserve equalization payments under Schedule MSS-1 is
based on numerous assumptions, including load growths for ETI and its affiliates, future
capacity contracts for ETI and its affiliates, and future values of the generation assets of
ETI and its affiliates.

76. There is substantial uncertainty with regard to ETI's projection of its rate-year reserve
equalization payments under Schedule MSS-1.

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

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

79. ETI's estimates of its rate-year purchases under affiliate contracts are based on a
mathematical formula set out in Schedule MSS-4.
PUC Docket No. 39896 Order on Rehearing Page 20 of 44
SOAH Docket No. XXX-XX-XXXX

80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments
will be based on ratios and costs that cannot be determined until the month that the
payments are to be made.

81. Over $11 million of ETI's affiliate transactions were based on a 2013 contract (the EAI
WBL Contract) that was not signed until April 11, 2012.

82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the
rate-year than it purchased in the test-year.

84. ETI experienced substantial load growth in the two years before the test-year, and it
continues to project similar load growth in the future.

85. ETI did not meet its burden of proof to demonstrate that a known and measurable
adjustment of $30,809,355 should be made to its test-year purchased capacity expenses.

86. ETI's purchased capacity expense in this case should be based on the test-year level of
$245,965,886.

87. ETI incurred $1,753,797 of transmission equalization expense during the test-year.

88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization
expense. This request was based on ETI's projections of its transmission equalization
expenses during the rate-year.

89. The transmission equalization expense that ETI will pay in the rate-year will depend on
future costs and loads for each of the Entergy operating companies.

90. ETI's projection of its rate-year transmission equalization expenses is uncertain and
speculative because it depends on a number of variables, including future transmission
investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
expenses, and loads of each of the Entergy operating companies.

91. ETI seeks increased transmission equalization expenses for transmission projects that are
not currently used and useful in providing electric service. ETI's post-test-year
adjustment is based on the assumption that certain planned transmission projects will go
PUC Docket No. 39896 Order on Rehearing Page 21 of 44
SOAH Docket No. XXX-XX-XXXX

into service after the test-year. At the close of the hearing, none of the planned
transmission projects had been fully completed and some were still in the planning phase.

92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
expenses related to projects that are not yet in-service.

93. ETI's request for a post-test-year adjustment of $8,942,785 for rate-year transmission
equalization expenses should be denied because those expenses are not known and
measurable. ETI's post-test-year adjustment does not with reasonable certainty reflect
what ETI's transmission equalization expense will be when rates are in effect.

94. ETI's transmission equalization expense in this case should be based on the test-year
level of $1,753,797.

95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the
accumulation of recognized allocations of original cost, representing the recovery of
initial investment over the estimated useful life of the asset.

96. Except in the case of the amortization of the general plant deficiency, the use of the
remaining life depreciation method to recover differences between theoretical and actual
depreciation reserves is the most appropriate method and should be continued.

97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line
basis over the remaining, expected useful life of the item or facility.

98. Except as described below, the service lives and net salvage rates proposed by the
company are reasonable, and these service lives and net salvage rates should be used in
calculating depreciation rates for the company's production, transmission, distribution,
and general plant assets.

99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing
production plant depreciation rates.

100. The retirement (actuarial) rate method, rather than the interim retirement method, should
be used in the development of production plant depreciation rates.

101. Production plant net salvage is reasonably based on the negative five percent net salvage
in existing rates.
PUC Docket No. 39896 Order on Rehearing Page 22 of 44
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102. The net salvage rate of negative 10 percent for ETI's transmission structures and
improvements (FERC Account 352) is the most reasonable of those proposed and should
be adopted.

103. The net salvage rate of negative 20 percent for ETI's transmission station equipment
(FERC Account 353) is the most reasonable of those proposed and should be adopted.

104. The net salvage rate of negative five percent for ETI's transmission towers and fixtures
(FERC Account 354) is the most reasonable of those proposed and should be adopted.

105. The net salvage rate of negative 30 percent for ETI's transmission poles and fixtures
(FERC Account 355) is the most reasonable of those proposed and should be adopted.

106. The net salvage rate of negative 30 percent for ETI's transmission overhead conductors
and devices (FERC Account 356) is the most reasonable of those proposed and should be
adopted.

107. A service life of 65 years and a dispersion curve of R3 for ETI's distribution structures
and improvements (FERC Account 361) are the most reasonable of those proposed and
should be approved.

108. A service life of 40 years and a dispersion curve of R1 for ETI's distribution poles,
towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and
should be approved.

109. A service life of 39 years and a dispersion curve of R0.5 for ETI's distribution overhead
conductors and devices (FERC Account 365) are the most reasonable of those proposed
and should be approved.

110. A service life of 35 years and a dispersion curve of R1.5 for ETI's distribution
underground conductors and devices (FERC Account 367) are the most reasonable of
those proposed and should be approved.

111. A service life of 33 years and a dispersion curve of L0.5 for ETI's distribution line
transformers (FERC Account 368) are the most reasonable of those proposed and should
be approved.
PUC Docket No. 39896 Order on Rehearing Page 23 of 44
SOAH Docket No. XXX-XX-XXXX

112. A service life of 26 years and a dispersion curve of L4 for ETI's distribution overhead
service (FERC Account 369.1) are the most reasonable of those proposed and should be
approved.

113. The net salvage rate of negative five percent for ETI's distribution structures and
improvements (FERC Account 361) is the most reasonable of those proposed and should
be adopted.

114. The net salvage rate of negative 10 percent for ETI's distribution station equipment
(FERC Account 362) is the most reasonable of those proposed and should be adopted.

115. The net salvage rate of negative seven percent for ETI's distribution overhead conductors
and devices (FERC Account 365) is the most reasonable of those proposed and should be
adopted.

116. The net salvage rate of positive five percent for ETI's distribution line transformers
(FERC Account 368) is the most reasonable of those proposed and should be adopted.

117. The net salvage rate of negative 10 percent for ETI's distribution overhead services
(FERC Account 369.1) is the most reasonable of those proposed and should be adopted.

118. The net salvage rate of negative 10 percent for ETI's distribution underground services
(FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119. A service life of 45 years and a dispersion curve of R2 for ETI's general structures and
improvements (FERC Account 390) are the most reasonable of those proposed and
should be approved.

120. The net salvage rate of negative 10 percent for ETI's general structures and
improvements (FERC Account 390) is the most reasonable of those proposed and should
be adopted.

121. It is reasonable to convert the $21.3 million deficit that has developed over time in the
reserve for general plant accounts to General Plant Amortization.

122. A ten-year amortization of the deficit in the reserve for general plant accounts is
reasonable and should be adopted.
PUC Docket No. 39896 Order on Rehearing Page 24 of 44
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123. FERC pronouncement AR- 15 requires amortization over the same life as recommended
based on standard life analysis. A standard life analysis determined that a five-year life
was appropriate for general plant computer equipment (FERC Account 391.2).
Therefore, a five year amortization for this account is reasonable and should be adopted.

124. ETI proposed adjustments to its test-year payroll costs to reflect: ( a) changes to employee
headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage
increases set to go into effect after the end of the test-year.

125. The proposed payroll adjustments are reasonable but should be updated to reflect the
most recent available information on headcount levels as proposed by Commission Staff.
In addition to adjusting payroll expense levels, the more recent headcount numbers
should be used to adjust the level of payroll tax expense, benefits expense, and savings
plan expense.

126. Staff has appropriately updated headcount levels to the most recent available data but
errors made by Staff should be corrected. The corrections related to: (a) a double
counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost
percentage in the calculation of ESI benefits costs; ( c) an inappropriate reduction of
savings plan costs when such costs were already included in the benefits percentage
adjustments; and (d) corrections for full-time equivalents calculations. Staffs ETI
headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll
reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll
increase by $37,531.

127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128. The compensation packages that ETI offers its employees include a base payroll amount,
annual incentive programs, and long-term incentive programs. The majority of the
compensation is for operational measures, but some is for financial measures.

129. Incentive compensation that is based on financial measures is of more immediate and
predominant benefit to shareholders, whereas incentive compensation based on
operational measures is of more immediate and predominant benefit to ratepayers.
PUC Docket No. 39896 Order on Rehearing Page 25 of 44
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130. Incentives to achieve operational measures are necessary and reasonable to provide utility
services but those to achieve financial measures are not.

131. The $5,376,975 that was paid for long term incentive programs was tied to financial
measures and, therefore, should not be included in ETI's cost of service.

132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
was tied to financial measures and, therefore, should be disallowed.

133. In total, the amount of incentive compensation that should be disallowed is $6,196,037
because it was related to financial measures that are not reasonable and necessary for the
provision of electric service. An additional reduction should be made to account for the
FICA taxes ETI would have paid on the disallowed financially based incentive
compensation.

134. The amount of incentive compensation that should be included in the cost of service is
$7,991,707.

135. To attract and retain highly qualified employees, the Entergy companies provide a total
package of compensation and benefits that is equivalent in scope and cost with what other
comparable companies within the utility business and other industries provide for their
employees.

136. When using a benchmark analysis to compare companies' levels of compensation, it is
reasonable to view the market level of compensation as a range rather than a precise,
single point.

137. ETI's base pay levels are at market.

138. ETI's benefits plan levels are within a reasonable range of market levels.

139. ETI's level of compensation and benefits expense is reasonable and necessary.

140. ETI provides non-qualified supplemental executive retirement plans for highly
compensated individuals such as key managerial employees and executives that, because
of limitations imposed under the Internal Revenue Code, would otherwise not receive
retirement benefits on their annual compensation over $245,000 per year.
PUC Docket No. 39896 Order on Rehearing Page 26 of 44
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141. ETI's non-qualified supplemental executive retirement plans are discretionary costs
designed to attract, retain, and reward highly compensated employees whose interests are
more closely aligned with those of the shareholders than the customers.

142. ETI's non-qualified executive retirement benefits in the amount of $2,114,931 are not
reasonable or necessary to provide utility service to the public, not in the public interest,
and should not be included in ETI's cost of service.

143. For the employee market in which ETI operates, most peer companies offer moving
assistance. Such assistance is expected by employees, and ETI would be placed at a
competitive disadvantage if it did not offer relocation expenses.

144. ETI's relocation expenses were reasonable and necessary.

145. The company's requested operating expenses should be reduced by $40,620 to reflect the
removal of certain executive prerequisites proposed by Staff.

146. Staff properly adjusted the company's requested interest expense of $68,985 by removing
$25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
2012), leaving a recommended interest expense of $43,047.

147. During the test-year, ETI's property tax expense equaled $23,708,829.

148. ETI requested an upward pro forma adjustment of $2,592,420, to account for the property
tax expenses ETI estimates it will pay in the rate-year.

149. ETI's requested pro forma adjustment is not reasonable because it is based, in part, upon
the prediction that ETI's property tax rate will be increased in 2012, a change that is
speculative is not known and measurable.

150. Staff's recommendation to increase ETI's test-year property tax expenses by $1,214,688
is based on the historical effective tax rate applied to the known test-year-end plant in
service value, consistent with Commission precedent, and based upon known and
measurable changes.

151. ETI's test-year property tax burden should be adjusted upward by $1,222,106 for a total
expense of $24,921,022.
PUC Docket No. 39896 Order on Rehearing Page 27 of 44
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152. Staff recommended reducing ETI's advertising, dues, and contributions expenses by
$12,800. The recommendation, which no party contested, should be adopted.

153. The final cost of service should reflect changes to cost of service that affect other
components of the revenue requirement such as the calculation of the Texas state gross
receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
Expenses.

154. The company's requested Federal income tax expense is reasonable and necessary.

155. ETI's request for $2,019,000 to be included in its cost of service to account for the
company's annual decommissioning expenses associated with River Bend is not
reasonable because it is not based upon "the most current information reasonably
available regarding the cost of decommissioning" as required by P.U.C. SUBST.
R. 25.231(b)(1)(F)(i).

156. Based on the most current information reasonably available, the appropriate level of
decommissioning costs to be included in ETI's cost of service is $1,126,000.

157. ETI's appropriate total annual self-insurance storm damage reserve expense is
$8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual
expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the
reserve from its current deficit.

158. ETI's appropriate target self-insurance storm damage reserve is $17,595,000.

159. ETI should continue recording its annual storm damage reserve accrual until modified by
a Commission order.

160. The operating costs of the Spindletop facility are reasonable and necessary.

161. The operating costs of the Spindletop facility paid to PB Energy Storage Services are
eligible fuel expenses.

Affiliate Transactions
162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of
these O&M expenses-$69,098,041-were charged to ETI by ESI. The remaining
affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana,
PUC Docket No. 39896 Order on Rehearing Page 28 of 44
SOAH Docket No. XXX-XX-XXXX

L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.;
Entergy Operations, Inc.; and non-regulated affiliates.

163. ESI follows a number of processes to ensure that affiliate charges are reasonable and
necessary and that ETI and its affiliates are charged the same rate for similar services.
These processes include: (a) the use of service agreements to define the level of service
required and the cost of those services; (b) direct billing of affiliate expenses where
possible; (c) reasonable allocation methodologies for costs that cannot be directly billed;
(d) budgeting processes and controls to provide budgeted costs that are reasonable and
necessary to ensure appropriate levels of service to its customers; and (e) oversight
controls by ETI's Affiliate Accounting and Allocations Department.

164. Affiliates charged expenses to ETI through 1292 project codes during the test-year.

164A. The $2,086,145 in affiliate transactions related to sales and marketing expenses should be
reallocated using direct assignment. The following amounts should be allocated to all
retail classes in proportion to number of customers: (1) $46,490 for Project
E10PCR56224 - Sales and Marketing - EGSI Texas; (2) $17,013 for Project
F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for Project
F3PPMMALI2 - Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial
Power Service.

165. ETI agreed to remove the following affiliate transactions from its application:
(1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
(2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288;
and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated
with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non
Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the
provision of electric utility service and are not in the public interest.

167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts
Settlement) are not normally-recurring costs and should not be recoverable.
PUC Docket No. 39896 Order on Rehearing Page 29 of 44
SOAH Docket No. XXX-XX-XXXX

168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are
related to ESI's operations, it is more immediately related to Entergy Louisiana, Inc. and
Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169. The $171,032 of costs associated with Project F3PPE998IS (Integrated Energy
Management for ESI) are research and development costs related to energy efficiency
programs. As such, they should be recovered through the energy efficiency cost recovery
factor rather than base rates.

170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate
transactions were reasonable and necessary, were allowable, were charged to ETI at a
price no higher than was charged by the supplying affiliate to other affiliates, and the rate
charged is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation
171. ETI has one full or partial requirements wholesale customer - East Texas Electric
Cooperative, Inc.

172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set
the wholesale load results in a retail production demand allocation factor of
95.3838 percent.

173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used
by the FERC to allocate between jurisdictions.

174. Using 12CP methodology to allocate production costs between the wholesale and retail
jurisdictions is the best method to reflect cost responsibility and is appropriate based on
ETI's reliance on capacity purchases.

Class Cost Allocation and Rate DesiQn
175. There is no express statutory authorization for ETI's proposed Renewable Energy Credits
rider (REC rider).

176. REC rider constitutes improper piecemeal ratemaking and should be rejected.
 PUC Docket No. 39896 Order on Rehearing Page 30 of 44
SOAH Docket No. XXX-XX-XXXX

177. ETI's test-year expense for renewable energy credits, $623,303, is reasonable and
necessary and should be included in base rates.

178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
public rights-of-way to locate its facilities within municipal limits.

179. ETI is an integrated utility system. ETI's facilities located within municipal limits
benefit all customers, whether the customers are located inside or outside of the
municipal limits.

180. Because all customers benefit from ETI's rental of municipal right-of-way, municipal
franchise fees should be charged to all customers in ETI's service area, regardless of
geographic location.

181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA)

§ 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt
hour ( kWh) sales, without an adjustment for the MFF rate in the municipality in which a
given kWh sale occurred.

182. The same reasons for allocating and collecting MFF as set out in Finding of Fact
Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts
Taxes. The company's proposed allocation of these costs to all retail customer classes

based on customer class revenues relative to total revenues is appropriate.

182A. ETI's proposed gross plant-based allocator is an appropriate method for allocating the
Texas franchise tax.

183. The Average and Excess (A&E) 4CP method for allocating capacity-related production
costs, including reserve equalization payments, to the retail classes is a standard
methodology and the most reasonable methodology.

184. The A&E 4CP method for allocating transmission costs to the retail classes is standard
and the most reasonable methodology.

185. ETI appropriately followed the rate class revenue requirements from its cost of service
study to allocate costs among customer classes. ETI's revenue allocation properly sets
rates at each class's cost of service.
PUC Docket No. 39896 Order on Rehearing Page 31 of 44
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186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
replacement of a functioning light with a lower-wattage bulb.

187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a
study regarding the feasibility of instituting LED-based rates and, if the study shows that
such rates are feasible, ETI should file proposals for LED-based lighting and traffic
signal rates in its next rate case.

188. An agreement was reached by the parties and approved by the Commission in Docket
No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
ratchet for existing customers in the Large Industrial Power Service (LIPS), Large
Industrial Power Service-Time of Day, General Service, General Service-Time of Day,
Large General Service, and Large General Service-Time of Day rate schedules.

189. ETI's proposed tariffs in this case did not remove the life-of-contract demand ratchet
from these rate schedules consistent with the parties' agreement in Docket No. 37744.

190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI
proposed, is not reasonable.

191. ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
agreement that was adopted by the Commission as just and reasonable in Docket
No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact
No. 192-194.

192. ETI's Schedule LIPS and LIPS Time of Day § VI should be changed to read:
DETERMINATION OF BILLING LOAD

The kW of Billing Load will be the greatest of the following:

(A) The Customer's maximum measured 30-minute
demand during any 30-minute interval of the current billing
month, subject to §§ III, IV and V above; or

(B) 75% of Contract Power as defined in § VII; or

(C) 2,500 kW.
PUC Docket No. 39896 Order on Rehearing Page 32 of 44
SOAH Docket No. XXX-XX-XXXX

193. ETI's Schedule LIPS and LIPS Time of Day § VII should be changed to read:
DETERMINATION OF CONTRACT POWER

Unless Company gives customer written notice to the contrary,
Contract Power will be defined as below:

Contract Power - the highest load established under § VI(A) above
during the 12 months ending with the current month. For the
initial 12 months of Customer's service under the currently
effective contract, the Contract Power shall be the kW specified in
the currently effective contract unless exceeded in any month
during the initial 12-month period.

194. The Large General Service, Large General Service-Time of Day, General Service, and
General Service-Time of Day schedules should be similarly revised to eliminate ETI's
life-of-contract demand ratchet.

195. In its proposed rate design for the LIPS class, the company took a conservative approach
and increased the current rates by an equal percentage. This minimized customer bill
impacts while maintaining cost causation principles on a rate class basis.

196. It is a reasonable move towards cost of service to add a customer charge of $630 to the
LIPS rate schedule with subsequent increases to be considered in subsequent base rate
cases.

197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy
charges and increase the demand charges as proposed by Staff witness
William B. Abbott.

198. DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent
Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs
in the off-season (October through May), that can be cancelled at any time, and for load
not lasting more than 80 hours in a year. For customers whose loads match these SIPS
characteristics (for example, DOE's Strategic Petroleum Reserve), the 12-month demand
ratchet provision of Schedule LIPS does not apply to demands set under the provisions of
the SIPS rider. The monthly demand set under the SIPS provisions would be applicable
for billing purposes only in the month in which it occurred. In short, if a customer set a
PUC Docket No. 39896 Order on Rehearing Page 33 of 44
SOAH Docket No. XXX-XX-XXXX

12-month ratchet demand in that month, it would be forgiven and not applicable in the
succeeding 12 months.

199. DOE's proposed Schedule SIPS is not restricted solely to the DOE and should be
adopted. It more closely addresses specific customer characteristics and provides for
cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.

200. Standby Maintenance Service (SMS) is available to customers who have their own
generation equipment and who contract for this service from ETI.

201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance
power to qualifying facilities should recognize system wide costing principles and should
not be discriminatory.

202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
charge equivalent to that of the LIPS rate schedule only for SMS customers not
purchasing supplementary power under another applicable rate; and (b) revising the tariff
as follows:
Distribution Transmission
Charge
(less than 69KV) (69KV and greater)
Billing Load Charge ($/kW):
Standby $2.46 $0.79
Maintenance $2.27 $0.60
Non-Fuel Energy Charge (0/kWh)
On-Peak 4.2450 4.0740
Off-Peak 0.5750 0.5520

203. ETI's Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental
charge paid by a customer when ETI installs facilities for that customer that would not
normally be supplied, such as line extensions, transformers, or dual feeds.

204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
Option B, which applies when a customer elects to amortize the directly-assigned
facilities over a shorter term ranging from one to ten years, has a variable monthly
charge. There is also a term charge that applies after the facility has been fully
depreciated.
PUC Docket No. 39896 Order on Rehearing Page 34 of 44
SOAH Docket No. XXX-XX-XXXX

205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.11 percent
per month of the installed cost of all facilities included in the agreement for additional
facilities.

206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and
the Post Term Recovery Charge as follows:

Selected Recovery Term Recovery Term Charge Post Recovery Term Charge
1 9.52% 0.28%
2 5.14% 0.28%
3 3.68% 0.28%
4 2.95% 0.28%
5 2.52% 0.28%
6 2.23% 0.28%
7 2.03% 0.28%
8 1.88% 0.28%
9 1.76% 0.28%
10 1.67% 0.28%

207. The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the
costs of running, operating, and maintaining the directly-assigned facilities.

208. It is reasonable to modify the Large General Service rate schedule by increasing the
demand charge from $8.56 to $11.43; decreasing the energy charge from $.00854 to
$.00458; and reducing the customer charge to $260.00.

209. Staff's proposed change to the General Service (GS) rate schedule to gradually move GS
customers towards their cost of service by recommending a decrease in the customer
charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is
reasonable and should be adopted.

210. ETI's Residential Service (RS) rate schedule is composed of two elements: a customer
charge and a consumption-based energy charge. In the months November through April
(winter), the rates are structured as a declining block, in which the price of each unit is
reduced after a defined level of usage. ETI's proposed increase in the RS customer
charge to $6 per month is reasonable and should be adopted. For the RS summer rate and
PUC Docket No. 39896 Order on Rehearing Page 35 of 44
SOAH Docket No. XXX-XX-XXXX

the first winter block rate, the 6.2960 per kWh energy charge resulting from the increased
revenue requirement for residential customers is reasonable and should be adopted.

211. ETI's Schedule RS declining block rate structure is contrary to energy-efficiency efforts
and the Legislature's goal of reducing both energy demand and energy consumption in
Texas, as stated in PURA § 39.905.

212. Schedule RS winter block rates should be modified consistent with the goal set out in
PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block
differential proposed by ETI and subsequent reductions should be reviewed for
consideration at the occurrence of each rate case filing.

213. Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation
214. ETI incurred $616,248,686 in natural-gas expenses during the reconciliation period,
which is from July 2009 through June 2011.

215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
negotiated operational balancing agreements with various pipeline companies.

216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet
its natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217. ETI's natural gas expenses were reasonable and necessary expenses incurred to provide
reliable electric service to retail customers.

218. ETI incurred $90,821,317 in coal expenses during the reconciliation period.

219. ETI prudently managed its coal and coal-related contracts during the reconciliation
period.

220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal
burned at the Big Cajun II, Unit 3 facility.

221. ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable
electric service to retail customers.
PUC Docket No. 39896 Order on Rehearing Page 36 of 44
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222. ETI incurred $990,041,434 in purchased-energy expenses during the reconciliation
period.

223. The Entergy System's planning and procurement processes for purchased-power
produced a reasonable mix of purchased resources at a reasonable price.

224. During the reconciliation period, ETI took advantage of opportunities in the fuel and
purchased-power markets to reduce costs and to mitigate against price volatility.

225. ETI's purchased-energy expenses were reasonable and necessary expenses incurred to
provide reliable electric service to retail customers.

226. ETI provided sufficient contemporaneous documentation to support the reasonableness of
its purchased-power planning and procurement processes and its actual power purchases
during the reconciliation period.

227. The Entergy system sold power off system when the revenues were expected to be more
than the incremental cost of supplying generation for the sale, subject to maintaining
adequate reserves.

228. The System Agreement is the tariff approved by the FERC that provides the basis for the
operation and planning of the Entergy system, including the six operating companies.
The System Agreement governs the wholesale-power transactions among the operating
companies by providing for joint operation and establishing the bases for equalization
among the operating companies, including the costs associated with the construction,
ownership, and operation of the Entergy system facilities.

229. Under the terms of the Entergy System Agreement, ETI was allocated its share of
revenues and expenses from off-system sales.

230. During the reconciliation period, ETI recorded off-system sales revenue in the amount of
$376,671,969 in FERC Account 447 and credited 100 percent of off-system sales
revenues and margins from off-system sales to eligible fuel expenses.

231. ETI properly recorded revenues from off-system sales and credited those revenues to
eligible fuel costs.
PUC Docket No. 39896 Order on Rehearing Page 37 of 44
SOAH Docket No. XXX-XX-XXXX

232. The Entergy system consists of six operating companies, including ETI, which are
planned and operated as a single, integrated electric system under the terms of the System
Agreement.

233. Service schedule MSS-1 of the System Agreement determines how the capability and
ownership costs of reserves for the Entergy system are equalized among the operating
companies. These inter-system "reserve equalization" payments are the result of a
formula rate related to the Entergy system's reserve capability that is applied on a
monthly basis.

234. Reserve capability under service schedule MSS-1 is capability in excess of the Entergy
system's actual or planned load built or acquired to ensure the reliable, efficient operation
of the electric system.

235. By approving service schedule MSS-1, the FERC has approved the method by which the
operating companies share the cost of maintaining sufficient reserves to provide
reliability for the Entergy system as a whole.

236. Service schedule MSS-3 of the System Agreement determines the pricing and exchange
of energy among the operating companies. By approving service schedule MSS-3, the
FERC has approved the method by which the operating companies are reimbursed for
energy sold to the exchange energy pool and how that energy is purchased.

237. Service schedule MSS-4 of the System Agreement sets forth the method for determining
the payment for unit power purchases between operating companies. By approving
service schedule MSS-4, the FERC has approved the methodology for pricing
inter-operating company unit power purchases.

238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
horizons. Once the planning process has identified the most economical resources that
can be used to reliably meet the aggregate Entergy system demand, the next step is to
procure the fuel necessary to operate the generating units as planned and acquire
wholesale power from the market.
PUC Docket No. 39896 Order on Rehearing Page 38 of 44
SOAH Docket No. XXX-XX-XXXX

239. Once resources are procured to meet forecasted load, the Entergy system is operated
during the current day using all the resources available to meet the total Entergy system
demand.

240. After current-day operation, the System Agreement prescribes an accounting protocol to
bill the costs of operating the system to the individual operating companies. This
protocol is implemented via the intra-system bill to each operating company on a
monthly basis.

241. ETI purchased power from affiliated operating companies per the terms of service
schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3
to affiliated operating companies are reasonable and necessary, and the FERC has
approved the pricing formula and the obligation to purchase the energy. ETI pays the
same price per megawatt hour for energy under service schedule MSS-3 as does any
other operating company purchasing energy under service schedule MSS-3 during the
same hour.

242. The Spindletop facility is used primarily to ensure gas-supply reliability and guard
against gas-supply curtailments that can occur as a result of extreme weather or other
unusual events.

243. The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can
back down gas-fired generation to take advantage of more economical wholesale power,
or use gas from storage to supplement gas-fired generation when load increases during
the day and thereby avoid more expensive intra-day gas purchases.

244. ETI's customers received benefits from the Spindletop facility during the reconciliation
period through reliable gas supplies and ETI's monthly and daily storage activity.

245. ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas
supply for the benefit of customers.

246. ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied
for the purpose of allocating its costs to its wholesale customers and retail customer
classes.
PUC Docket No. 39896 Order on Rehearing Page 39 of 44
SOAK Docket No. XXX-XX-XXXX

246A. ETI's 2010 line-loss factors should be used to reconcile ETI's fuel costs. Therefore,
ETI's fuel reconciliation over-recovery should be reduced by $3,981,271.

247. ETI's proposed loss factors are reasonable and shall be implemented on a prospective
basis as a result of this final order.

248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the
FERC's reallocation of rough production equalization costs in FERC Order No. 720-A,
and to treat such costs as eligible fuel expense.

249. Special circumstances exist and it is appropriate for ETI to recover the rough production
cost equalization costs reallocated to ETI as a result of the FERC's decision in Order
No. 720-A.

Other Issues
250. A deferred accounting of ETI's Midwest Independent Transmission System Operator
( MISO) transition expenses is not necessary to carry out any requirement of PURA.

251. ETI should include $1.6 million in base rates for MISO transition expense.

252. Deleted.

253. Transmission Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

254. Distribution Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

255. The appropriate amount for ETI's purchased-power capacity expense to be included in
base rates is $245,965,886.

256. The amount of ETI's purchased-power capacity expense includes third-party contracts,
legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
amounts for all contracts should be included in the baseline for a purchased-capacity rider
that may be approved in Project No. 39246 is an issue that should be decided in that
project.
PUC Docket No. 39896 Order on Rehearing Page 40 of 44
SOAH Docket No. XXX-XX-XXXX

III. Conclusions of Law
1. ETI is a "public utility" as that term is defined in PURA § 11.004(1) and an "electric
utility" as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.101-.111, and 36.203.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the
preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
TEX. Gov'T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act, Tex. Gov't Code Ann. Chapter 2001.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6. Pursuant to PURA § 33.001, each municipality in ETI's service area that has not ceded
jurisdiction to the Commission has jurisdiction over the company's application, which
seeks to change rates for distribution services within each municipality.

7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
municipality's rate proceeding.

8. ETI has the burden of proving that the rate change it is requesting is just and reasonable
pursuant to PURA § 36.006.

9. In compliance with PURA § 36.051, ETI's overall revenues approved in this proceeding
permit ETI a reasonable opportunity to earn a reasonable return on its invested capital
used and useful in providing service to the public in excess of its reasonable and
necessary operating expenses.

10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on
original cost, less depreciation, of property used and useful to ETI in providing service.

11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
and P.U.C. SUBST. R. 25.23 1 (c)(2)(C)(i).
PUC Docket No. 39896 Order on Rehearing Page 41 of 44
SOAH Docket No. XXX-XX-XXXX

12. Including the cash working capital approved in this proceeding in ETI's rate base is
consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
allowance for cash working capital to be included in rate base.

13. The ROE and overall rate of return authorized in this proceeding are consistent with the
requirements of PURA §§ 36.051 and 36.052.

14. The affiliate expenses approved in this proceeding and included in ETI's rates meet the
affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.-
Austin 1984, no writ).

15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
and P.U.C. SUBST. R. 25.23 1 (c)(2)(C)(i).

16. Pursuant to P.U.C. SUBST. R. 25.23 1 (b)(1)(F), the decommissioning expense approved in
this case is based on the most current information reasonably available regarding the cost
of decommissioning, the balance of funds in the decommissioning trust, anticipated
escalation rates, the anticipated return on the funds in the decommissioning trust, and
other relevant factors.

17. ETI has demonstrated that its eligible fuel expenses during the reconciliation period were
reasonable and necessary expenses incurred to provide reliable electric service to retail
customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted
for the amount of fuel-related revenues collected pursuant to the fuel factor during the
reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants
during the reconciliation period.

19. The reconciliation period level operating and maintenance expenses for the Spindletop
facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision
in a reconciliation proceeding.
PUC Docket No. 39896 Order on Rehearing Page 42 of 44
SOAH Docket No. XXX-XX-XXXX

19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to
include any issue related to the reasonableness of a utility's fuel expenses and whether
the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use
the new line-loss study to calculate Entergy's fuel reconciliation and over-recovery.

20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to
recover rough production equalization payments reallocated to ETI by the FERC.

21. ETI's rates, as approved in this proceeding, are just and reasonable in accordance with
PURA § 36.003.

IV. Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission issues
the following orders:

1. The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent
with this Order.

2. ETI's application is granted to the extent consistent with this Order.

3. ETI shall file in Tariff Control No. 40742 Compliance Tariff Pursuant to Final Order in
Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates,
Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with
this Order within 20 days of the date of this Order. No later than ten days after the date
of the tariff filings, Staff shall file its comments recommending approval, modification,
or rejection of the individual sheets of the tariff proposal. Responses to the Staff's
recommendation shall be filed no later than 15 days after the filing of the tariff. The
Commission shall by letter approve, modify, or reject each tariff sheet, effective the date
of the letter.

4. The tariff sheets shall be deemed approved and shall become effective on the expiration
of 20 days from the date of filing, in the absence of written notification of modification or
rejection by the Commission. If any sheets are modified or rejected, ETI shall file
proposed revisions of those sheets in accordance with the Commission's letter within ten
PUC Docket No. 39896 Order on Rehearing Page 43 of 44
SOAH Docket No. XXX-XX-XXXX

days of the date of that letter, and the review procedure set out above shall apply to the
revised sheets.

5. Copies of all tariff-related filings shall be served on all parties of record.

6. ETI shall prepare and file as part of its next base rate case a study regarding the
feasibility of instituting LED-based rates and, if the study shows that such rates are
feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that
case. If ETI has LED lighting customers taking service, the study shall include detailed
information regarding differences in the cost of serving LED and non-LED lighting
customers. ETI shall provide the results of this study to Cities and interested parties as
soon as practicable, but no later than the filing of its next rate case.

7. All other motions, requests for entry of specific findings of fact and conclusions of law,
and any other requests for general or specific relief, if not expressly granted, are denied.
PUC Docket No. 39896 Order on Rehearing Page 44 of 44
SOAH Docket No. XXX-XX-XXXX

5k' ^a/emkev
SIGNED AT AUSTIN, TEXAS the day of Aeteber 2012.

PUBLIC UTILITY COMMISSION OF TEXAS

U^
DONNA L. NELSON, CHAIRMAN

ROLANDO PABLOS, COMMISSIONER

I respectfully dissent regarding the utility- and executive-management-class affiliate
transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect
costs of the management of Entergy's ultimate parent should not be borne by Texas ratepayers.
Therefore, I would disallow the following: $173,867 for Project No. F3PCCPM001 (Corporate
Performance Management); $372,919 for Project No. F3PCC31255 (Operations-Office of the
CEO); and $74,485 for Project No. F3PPCOO001 (Chief Operating Officer). I join the
Commission in all other respects for this Order.

KENNETH W. ANDERSON ,^ .,COMMISSIONER

q.\cadm\orders\final\39000\398960 on reh docx

37 Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing (Oct. 16, 1997).
 SOAH DOCKET NO. XXX-XX-XXXX COMM Schedule I
PUC DOCKET NO. 39896 Revenue Requirement
COMPANY NAME Entergy Texas, Inc
TEST YEAR END 30Jun-11

Company Commission
Company Requested Adjustments Commission
Test Year Adjustments Test Year To Company Adjusted
Total To Test Year Total Electric Request Total Electric
(a) (b) (c) (d) (e) " (c) + (d)

REVENUE REQUIREMENT

Operations & Maintenance $ 1,291,684,714 $ (1,075,148,117) $ 216,536,597 $ (24,550,490) $ 191,986,107
Regulatory Debits and Credits 40700 $ (6,784,608) $ 12,030,533 $ 5,245,925 $ (324,121) $ 4,921,804
Accretion Expense $ 212,783 $ (212,783) $ - $ - $ -
Interest on Customer Deposits $ - $ 68,985 $ 68,985 $ (25,938) $ 43,047
Decommissioning Expense $ - $ - $ - $ - $
Depreciation & Amortization Expense $ 76,072,459 $ 22,558,698 $ 98,631,157 $ (6,253,316) $ 92,377,641
Taxes Other Than Income Taxes $ 63,023,906 $ (2,533,159) $ 60,490,747 $ (2,874,508) $ 57,616,241
Federal Income Taxes $ (23,407,031) $ 67,296,739 $ 43,889,708 $ 6,181,384 $ 50,071,092
Current State Income Taxes $ (127,519) $ 89,787 $ (37,732) $ 37,732 $ -
Deferred Federal Income Taxes $ 67,051,463 $ (52,089,274) $ 14,962,189 $ (14,962,189) $ -
Deferred State Income Taxes $ 812,265 $ (727,918) $ 84,347 $ (84,347) $ -
Investment Tax Credits 411.00 $ (1,611,177) $ (48,429) $ (1,657,606) $ 1,657,606 $ -
Consolidated Tax Savings Adjustment $ - $ - $ - $ - $
Return on Invested Capital $ $ 155,162,991 $ 155,162,991 $ (14,562,393) $ 140,600,598
TOTAL $ 1,488,927,266 $ (873,649,947) $ 693,377,308 $ (65.780,678) $ 637,618,730

Plus:
Addback: Purchased Power Rider 555.00 $ 244,539,884
Addback, Interruptible Services 55500 $
Total Addbacks $ 244,639,884

Total COMM Revenue Requirement $ 782,166,814

10/30R012 12:39 PM
P.W 1
 SOAH DOCKET NO. XXX-XX-XXXX COMM Schedule 0
PUC DOCKET NO. 398N O&M Expense
COMPANY NAME Enbryy Texas, Inc.
TEST YEAR END 30-Jun-1111

Cornparty Commission
Company Requested Adjustments CommNsloin
OPERATIONS AND MAINTENANCE EXPENSE Test Year Adjustments To" Year To Company Adjusted
Total To Test Year Total Electric Request Total Electric;
(a) (b) (p) (d) (a) • (p) * (d)
Acct. No
Operations & Maintenance:
Prod. Operation and Sup 500 5,338,227 52,215 5,390,442 i (98,382) 5,294.080
Fuel 501 (255,242) (255,242) 3 - (255,242)
Fuel-ON 501 684,745 (663,891) 854 i - 854
Fuel-Natural Gas 501 330,036,998 (330,038,998)
Fuel-Coal 501 49,170,094 (46,618,748) 2,561,348 (1,486) 2,549,880
Steam Expenses 502 3,900,803 40,940 3,941,743 (61,223) 3,880,520
Electric Expenses 505 2,529,473 9,518 2,538,989 884 2,539,673
Misc Steam Power Expenses 506 8.135,921 31,297 8,167,218 (74,347) 8,092,871
Rents 507 131,131 131,131 131,131
NOX Emmission Allowance Expense 509 (43,244) 43,241
NOX Seasonal Allowance Expense 509 11,904 (11,904)
Maintenance Supv and Eng 510 1,188,598 21,037 1,187,533 (18,303) 1,189,330
Maintenance of structures, 511 3,104,201 4,593 3,108,794 (8,872) 3,101,922
Maintenance of boiler plant 512 12,592,212 21,742 12,613,954 (17,587) 12,596,367
Maintenance of electric plant 513 5,491,510 729,791 6,221,301 (27,550) 6,193,751
Maintenance of misc steam plant 514 1,314,917 (18,801) 1,296,118 (15,889) 1,280,227
Hydraulic Operating Supv and Eng 535 (841) (27) (865) 9 (859)
Miso Hydro Power Generation 539 (12) (12) (12)
Maintenance Supv and Eng 541 (1,359) (32) (1,391) 14 (1,377)
Maintenance of electric plant 544 1,303 13 1.316 (28) 1,290
Malntenanca of Misc hydraulic plant 545 543 543 543
Operation Supv and Eng 546 (1,288) (12) (1,300) 23 (1,277)
Misc. Other Power Gen Exp 549 (91) (91) (91)
Purchased Power-System Companies 555 111,253,452 (111,253,452)
Purchased Power-from others 555 159,034,737 (159,034,737) 533,002 533,002
Co•Oenerstlon 555 148,858,961 (148,858,981)
Rare Plan PurPow-AmWled 555 308,886,786 (308,886,766)
Purchased Power Entergy Affiliates 555 25,558,973 (25,558,973)
Renewable Energy Credit 555 623,303 823,303
System Control It Load Dispatch 558 951,691 19;688 971,377 (19,111) 962,288
System Control & Dispatch Other 557 321,455 4,301 325,756 (6,391) 319,366
Deferred Electric Fuel Cost 557 (52,121,822) 52,121,822
Deferred TX capacity rider 557 (12,448) 12,448
Transmission Ops Supr & Engr 560 5,568,078 (117,800) 5,450,278 (31,045) 5,419,231
Load Dispatching 561 842,620 8,987 851,807 (79,413) 772,194
Load Dispatching-rsllabil8y 581 231,424 5,608 237,032 1,191 238,223
Load Dispatching-tranamission system 581 1,422,924 31,890 1,454,814 8,385 1,481,179
Load Dispatching-Trans Serv & Son 561 577,895 12,964 590,859 2,886 593,745
System Planning & Standards Day 581 385,654 7,877 393,581 1,755 395,316
Transmission Service Studies 581 52,780 1,139 53,919 242 54,181
Transmission Station Equipment 582 142,826 925 143,551 (1,813) 141,738
Trans OH Line Expense 563 483,385 66 483,461 (129) 483,322
Transmission Equalization 585 1,377,103 9,319,479 10,898,582 (8,942,785) 1,753,797
Mlso, Transmission Expenses 568 924,736 (19,401) 905,335 (11,518) 893,817
Rents 567 987,823 987,823 967,823
Maint Supv And Eng, 568 3,041,227 313,096 3,354,323 (29,859) 3,324,484
Maint Of Strictures 589 108,842 42 108,684 (6.215) 100,469
Maint Trans Computer & Telecom 569 448,842 6,215 455,067 155 455,212
Transmission Maint Station Equip 570 1,892,713 7,286 1,899,979 (14,177) 1,685,802
Transmission MaiM OH Line Exp 571 1,790,447 40 1,790,487 (79) 1,790,408
Maim. Of Misc. Transmission 573 52,814 52,814 52,814
Regional Energy Mkte-Oper Supv 575 18,998 4,034,420 4,053,418 (2,452,989) 1,600,429
DayAhead & Reel Time Mkb WPP 575 37,069 810 37,879 (397) 37,482
Maim of computer software WFP 578 3,188 3,168 3,188
Distribution Ooe Supr & Enpr 580 5,357,005 28,983 5,383,988 (68,797) 5,317,191
Distribution Load Dispatching 581 448,718 4,387 453,086 (8,488) 444.597
Distribution Slogan Expenses 582 471,978 2,931 474,909 (5,715) 489,194
Distribution OH Line Expenses 583 103,332 771 104,103 (1,511) 102,592
Underground Line Expenses 584 748,888 2,638 749,524 (5,173) 744,351
Strest Lighting & Signal Sys 585 288,809 2,296 289,105 (4,152) 284,963
Meter Expenses 588 2,088,756 13,593 2,102,349 (25,176) 2,077,173
Customer histollallons 587 470,236 3,787 474,023 (7,349) 488,874
Miscellaneous Distribution Exp 588 1,503,004 4,505 1,507,509 (19,425) 1,488,084
Rents 589 3,925,828 3,925,626 3,925,628
Distribution Maint Supr & Engr 590 1,455,811 (4,009) 1,451,802 (23,447) 1,428,155
Maint. Of Structures 591 180,488 180,488 180,488
Distribution Mairit Station Equip 592 880,084 8,188 886,270 (11,078) 855,192
Distribution MaiM OH lines 593 10,544,165 20,914 10,585,079 (43,524) 10,521,556
Underground Line Expenses 594 802,465 5,293 807,758 (10,732) 797,028
Dist Malnt Line Tmf, Regulators 596 15,851 51 15,902 (36) 15,868
MalntStrest Light & Signal Sys 596 635,209 4,178 839,385 (8,188) 831,197
Malntenancs-Non Roadway See Ltg 598 392,358 2,878 398,038 (5,252) 389,784
Maintenance of Motors 597 159,188 1,386 180,552 (2,878) 157,874
Malnt of Misc Dbtr Plant 598 449,888 1,928 451,794 (3,039) 448,755
Supervision - Customer Accts 901 258,934 2,458 281,392 (4,552) 258,840
Motor Reading Exp 902 3,843,502 8,782 3,852,284 (9,368) 3,842,898
Customer Records 903 5,250,761 71,989 5,322,750 (86,377) 5,258,373
Customer Collection 903 4,745,821 38,181 4,784,002 4,784,002
Customer Deposit Interest 9032
UncolMOble Accounts 904 2,835,831 2,051,289 4,887,120 5 (459,250) $ 4,427,870
Effective Rate 0.000000000000 0.008236108685 0.008238108886
Uncollectible Accounts-revenue ad) (307,648) (307,648) $ 307,1548 S
Uncolbctlble Accounts Elecl-Wrile Off 904 (1,108,887) $ (1,108,887) $ - $ (1,108,887)
Miscellaneous 905 $ 33,149 $ 610 33,759 $ (670) $ 33,089
Factoring Expense 426.5 3 • $
Factoring Factor 0.0000000000000 0.0000000000000 0.0000000000000
Supervision 907 3 392,505 $ (2,721) It 389,784 3 (5,629) $ 384,155

10130/2012 12:39 PM PsW 2
 Customer Assistance 908 S 9,189,838 $ (7,250,909) $ 1,938,729 $ (67,298) f 1,871,431
Customer Assistance OverlundM 908 $ 1,747,892 $ (1,747,892) $ - $ - $ -
Information 6InsVAdvertising 909 $ 937,069 f (878) $ 938,193 $ (4.056) S 932,137
Misc. Cust. Service and Information 910 $ 1,151,988 $ 4,764 $ 1,158,752 $ - $ 1,156,752
Sales Supervision 911 8 829 $ 7 $ 838 S (17.467) $ (18,831)
Demonsha8nq & SsBinp Exp 912 $ 730,161 $ 14,522 f 744,883 f (18,597) f 728,088
Advertising Expense 913 $ 110.202 $ (2,379) $ 107,823 $ (58) $ 107,785
Misc. Sales Expense 916 $ 256,775 $ 1,715 f 258,490 f (1,390) $ 257,100
f f f f

TOTAL Operations BMaintenance f 1,207,284,083 f (1,071,013,728) $ 138,250,357 $ (11,342,739) $ 124,907,818

10/3M012 12:39 PM Pg. 3
 COMM Schedule U
SOAH DOCKET NO. 47Y12-2979
O&M Expense
PUC DOCKET NO. 39M
COMPANY NAME Enbrpy Texas. Inc.
TEST YEAR END 30dun•11

Company Commission
Company Requested Adjustments Commission
Test Year Ad)ueheenb Test Yew To Company Adjusted
OPERATIONS AND MAINTENANCE EXPENSE Total Electric
Total To Tpt Year Total Electric Request
(a) (b) (c) (d) (e) (e)+(dl

Administrative & Genemt 11,172,084
920 18,405,932 f (1.480.140) $ 18,945,792 S (5,773,708) S
Admin & General Salarles $
(459,339) 6 1,130,854 $ (5,400) S 1,125,454
Office Supplies & Exp 921 $ 1,590,193 $
1.006 S 1,050,947 $ 214 $ 1,081,181
Admin Expense@ Transferred 922 $ 1,059,941 It
14,921,589 (5,431,183) $ 9,490,408 $ (89,762) $ 9,400,844
outside Services 923 $ $
1,134,432 1,287 $ 1,135.719 $ - $ 1,135,719
Property Insurance 924 $ $
3,899,996 5,060,004 $ 8,760,000 $ (491,172) $ 8,268,828
Provision for Property Insurance 924 f $
1,153,578 $ - S 1,153,576 $ - $ 1,153,576
Environmental Reserve AccftuM 924 $
1,859.858 S 7,424 $ 1,867,082 It (5,437) $ 1,881,646
Injuries & Damages 925 $
27,027,557 $ (17,961) $ 27,009,596 t (2.878,305) $ 24,331,291
Employee Pensions & 8ane8b 928 3
7,708,335 $ (1,954,403) $ 5,723,932 $ (4,150,717) $ 1,573,215
Regulatory Commission Exp 928 S
52,040 $ (65) $ 81,975 $ (343) $ 81,832
Geneml AdvefBtlng Exp 9301 $
798,138 224,312 $ 1.020,450 $ (9,181) $ 1,011,289
Miscellaneous 9302 $ $
21 - $ 21 f - $ 21
Active Development Expenses 9302 $ $
Oimclors' Fees and Expenses 9302 $ 79,476 $ (79,476) $ - $ -
3,264,425 $ 1,164 $ 3,285,589 $ - $ 3,265,589
Rents 931 $
1.857.322 2.979 $ 1.880.301 $ (3.940) $ 1.858.361
Maint. Of General Plant 935 $ $

80,288,240 (13,207,751) 87,078,489
TOTAL AdminieMaBve & General 84,420,631 ( 4,134,391)

218,638,697 ( 24,060.490) I 191,988,107
TOTAL 0 & M EXPENSE 1,291,684,714 ( 1,076,148,117)

10r.p201212:39 PM Pp 4
 SOAH DOCKET NO. XXX-XX-XXXX COMM Schedule III
PUC DOCKET NO. 39896 Invested Capital
COMPANY NAME Entarpy Texas, Inc.
TEST YEAR END 30-Jun-11
Company Commission
Company Requested Adjustments Commission
Test Ysar Adjustments Test Year To Company Adjusted
Total To Test Year Total Elaetrb Request Total Elaetrle
(a) (b) (c) (d) (a)' (a) + Jr!)

INVESTED CAPITAL

3,521,368,187 $ (251,512,491) $ 3,289,855,898 $ (335,753) $ 3,289,519.943
Plant in Service
f (1,417.946.172) f 148.061.290 $ (1,289.884.882) f S (1,289.884.882)
Accumulated Depreciation

$ 2,103,422,015 $ (103,461,201) f 1,999,970,844 $ (335,753) f 1,999,635,061
Net Plant In Service

Construction Work In Progress $ • $ - $ - $
$ - $ - $ - f S •
Plant Held for Future Use
- S (2,013,921) $ (2,889,275) $ (3,897,959) $ (6,387,234)
Working Cash Allowance $
$ 53,759,975 $ • $ 53,759,975 $ (1,066,490) $ 52,893,485
Fuel Inventories
$ 29,252,574 $ - $ 29,252,574 $ 32,847 $ 29,285.421
Materials and Supplies
$ 7,386,433 $ (148,396) $ 7,218,037 f 916,313 $ 8,134,350
Prepayments
f - $ 59,799,744 $ 59,799,744 $ - $ 59,799,744
Property Insurance Reserve
f (5,589,243) f - $ (5,569,243) $ - $ (5,589,243)
Injuries and Damages Reserve
$ 1,400,350 $ - $ 1,400,350 $ • f 1,400,350
Coal Car Maintenance Reserve
$ (53,715,841) 5 109,689,388 $ 55,973,545 $ (25,311,238) $ 30,882,309
Unfunded Pension $
$ 68,914 $ - $ 68,914 $ - 68,914
Allowances
3,412,379 $ (4,474,589) $ (1,082,190) $ $ (1.082,190)
Environmental Reserves $
f (35,872,478) $ - $ (35,872,476) f - $ (35,872,478)
Customer Deposits 15,312,795
$ - $ 28,386,859 S 28,388,859 $ (11,054,084) $
Regulatory Assets and Liabilities
$ (824,338,691) $ 389,987,144 $ (454,371,547) f 8,398.405 • . $ (447,973,142)
Accumulated DFIT
$ . $ 8,175,000 $ 6,175,000 f (8,175,000)
Rate Case Expenses
$ f $ f

1,279,186,388 481,918,046 $ 1,746,421,081 s (40,292,937) S 1,700,128,144
TOTAL INVESTED CAPITAL ( RATE BASE) f $

5.140% 8.92% 8.2700%
RATE OF RETURN

156,182,991 f 156,162,9111 f (14,662,383) $ 140,600,698
RETURN ON INVESTED CAPITAL f - S

Page 6
10/302012 1239 PM
 COMM Schedule IRA
SOAH DOCKET NO. XXX-XX-XXXX
Electric Plant In Service
PUC DOCKET NO. 398N
COMPANY NAME Entergy Tax", Inc.
TEST YEAR END 30-Jun-111
Company Commission
Company Requested Adjustments, Commission
Test Year Ad)ustmena Test Year To Company Adjusted
Total To Test Year Total Electric Request Total Electric
(b) (a) (d) N)' (c) + (it)
(a)
Electric Plant In Service
Intangible Pant 6,305,132
301 f 1,346,899 $ 4,958,233 f 8,305,132 S It
Organization
303 f 96.788.717 $ 4,199,889 $ 100.968.406 9 $ 100.988.408
Misc Intangible Plant
98,133,818 $ 9,157,922 $ 107,291,538 f $ 107,291,538
Total Intangible Plant $
Production Plant-$team $ 4,512,873
Land and Land Rights 310 S 4,512,873 $ 4,512,873 $
172,930,826 $ 1,099,019 $ 174,029,845 $ $ 174,029,645
Structures and Improve 311 $
388,477,042 f 10,838,417 $ 399,315,459 $ 399,315,459
Boiler Plant Equipment 312 $
189,175,111 $ 8,787,919 $ 197,983,030 f $ 197,963,030
Turbogenerators 314 $
98,272,189 $ 10,750,419 $ 107,022,608 $ $ 107,022,608
Accessory Equipment 315 $
Misc. Power Plant Equip 316 $ 10,848,083 S 1,864,464 $ 12,712,547 $ $ 12,712,547
Asset Retire Cosa 317 $ 419,211 $ (419,211)
218,538 $ 218,538 S $ 218,538
Accessory Elec Equip 334 f
37,269 $ 37,289 S $ 37,269
Misc. Power Plant Equip 335 S
S • $ f
882,890,942 $ 32,921,027 $ 895,811,989 $ 6 895,8/1,969
Total Production Plant $

Transmission Plant 13,827,121
3501
, $ 9,579,879 $ 4.247,242 $ 13,827,121 $ - $
Land 33,979,623
3502 $ 33,622,888 $ 356,735 It 33.979,623 $ - $
Easements 22,579,829
352 $ 21,909,777 $ 689,852 $ 22,579,629 S - S
structures and Improv, 355,298,602
353 S 344,889,139 $ 10,429,463 $ 355,298,802 f - $
Station Equipment
25,360,394 $ 54,086 f 25,424,480 $ • $ 25,424,480
Towers & Fixtures 354 f
188,583,323 If 13,724,724 It 180,288,047 $ - $ 180,288,047
Poles 8 Fixtures 355 $
188,098,991 $ 12,570,240 $ 178,689,231 f - S 178,669,231
OveTead Conductors BD 358 t
357 f - $ • $ - $ - $ -
Underground Conduit 321,717
Underground Conductor 358 $ 321 , 717 S - $ 321 , 717 f - $
202,785 $ - $ 202 , 785 $ • f 202 , 785
Roads and Trails 359 $
$ - $ - $ - $ - $ -
788,528,893 $ 42,082,342 $ 810,591,235 i - 11 810,591,235
Total Transmission Plant f
Distribution Plant 4,178,955
380.1 It 4,178,965 $ 4,178,955 $ - $
Land
380.2 If 11,759,529 $ 11,759,529 S - f 11,759,529
Easements
7,857,817 $ 157,089 $ 8,014,906 $ - f 8,014,908
Stnicturo and Improve 361 $
302 S 158,704,009 $ 7,585,189 $ 164,289,178 $ - f 164,289,178
Station Equipment
384 S 186,114,784 $ 36,287,319 f 221,402,103 f - f 221,402,103
Poles, Towers bFixtures
365 f 170,541,014 $ 44,147,418 $ 214,688,432 f - $ 214,888,432
OH Conductors 8 Devices
368 $ 22,087,426 $ 1,103,870 f 23,171,296 $ • f 23,171,296
Underground Conduit
367 f 84,221,923 $ 7,121,887 $ 91,343,590 $ $ 91,343,590
UG Con 8 Devices
368 $ 285,357,209 f 73,111,187 $ 358,468,376 f - It 358,488,376
Line Transformers
389.1 $ 41,093,559 $ 13,092,741 $ 54,188,300 If - S 54,188,300
Services-Overhead
3692 f 32,113,188 $ 4,314,456 $ 38,427,824 $ - $ 38,427,624
Services-Underground
370 $ 30,110,288 $ (1,808,489) $ 28,301,819 f - $ 28,301,819
Meters
371 S 18,132,488 $ 2,318,592 $ 18,451,078 $ • $ 18,451,078
Installations on CusPre
373 f (228,908) $ 2,378.038 $ 2,151,130 $ - $ 2,151,130
StreetLlghts
3732 f (21.854) $ (401.392) f (423.0461 f - $ (423.046)
Non Roadway Lighting
S 1,047,003,605 $ 189,387,665 $ 1,238,391,270 $ $ 1,236,391,270
Total Distribution Plant

382 $ 60,823 $ - $ 60,823 $ - f 60,823
Computer Hardware
383 $ 3,368.130 $ $ 3,368.130 f $ 3.368.130
Computer Software
f 3,428,753 $ - $ 3,428,753 $ - f 3,428,753
Total Computer

389 $ 5,147,438 $ (90,259) $ 5,057,177 f - f 5,057,177
General Plant Land & Land Rights
390 $ 53,909,613 $ 3,034,857 $ 58,944,470 t - $ 58,944,470
Structure 8 Impmveme
Office Furniture & Equip 391 1 f 994,538 $ (58,228) $ 938,310 $ - $ 936,310
391.2 $ 17,848,803 $ 1,223,920 $ 18,870,723 $ - $ 18,870,723
Information System
Data Handling Equip 391 3 f 917,840 $ 882 f 918,522 $ • $ 918,522
392 $ 91,988 $ (81,477) $ 10.511 f - f 10,511
Transportation Equip
393 $ 3,228,853 f • $ 3,226,653 f - $ 3,228,853
Stores Equipment
394 $ 7,858,828 $ 451,358 $ 8,307,984 $ - f 8,307,984
Tools. Shop & Garage E
395 f 600,637 $ (300,192) $ 300,445 $ - $ 300,445
Laboratory Equipment
Power operated Equip 398 $ 528,899 $ - $ 528,899 It - $ 526,899
3971 $ 5,107,445 $ 252,980 $ 5,360,425 $ - $ 5,380,425
Misc Comm Equipment
3972 $ 40,182,821 $ 233,697 S 40,418,318 $ - $ 40,418,318
Comm 6 Microwave Equ
Misc Equipment 398 $ 969,421 $ (28,332) $ 943,089 $ - $ 943,089
$ - $ $ - s - $ -
137,178,318 f 4,641,208 $ 141,819,528 $ • f 141,819,528
Total General Plant $

f (8,382,452) $ - $ (8,382,452) f • $ (8,382,452)
Electric Contra AFUDC
Conatr Else Cash Flow RerAses f 248,427,857 $ (248,427,858) S (1) $ • $ (1)
303 $ 64,260 i (52,768) S 11,492 i - f 11,492
Intangibles Completed no Class
Completed Construction not Class 301-349 f 23,532,587 $ (20,940.477) $ 2,592,110 $ - $ 2,592,110
35035s f 37,517,589 f 14,319,209 $ 51,838,798 $ - $ 51,838,798
Completed Construction not Class
380-373 S 152,102,938 $ (129,701,878) $ 22,401,050 f - f 22,401,080
Completed Construction not Class
Completed Construction not Class 389-399 i 5,714,248 $ (777,624) $ 4,938,622 f - $ 4,936,622
311 f 1.127,778 $ - f 1,127,778 $ $ 1,127.778
Plant Acquisition Ad)ustrnant
460,104,801 $ (385,581,394) $ 74,523,407 f - f 74,523,407
$

If 3,377,288.928 f (107411,230) f 3,289.868.898 f (335,753) $ 3,299.819,946
Total Electric PIS

Pgs 6
1030/2012 12'39 PM
 SOAH DOCKET NO. XXX-XX-XXXX COMM Schedule 1118
PUC DOCKET NO. 39N6 Depreclatlon Expense
COMPANY NAME Enosrpy Texas, Inc.
TEST YEAR END 304un•11
Company Commies"
Company Requ Adjustments Commission
Test Year Adjustments Test Year To Company Adjusted
Total To Test Year Total Electric Request Total Eleotris

(a) (b) (C) (d)M (N) • lo) (e)

Depreciation Expense
Structures & Improvements 311 $ 1,095,087 f 818,883 $ 1,711,750 f (424,581) S 1,287,169
Boiler Plant Equipment 312 $ 8,785,278 $ 845,958 f 9,611,234 f (2,028,882) f 7,582,572
TurboGenerator Units 314 S 2,482,980 f 2,045,957 $ 4,528,937 $ (1,105,324) S 3.423,613
Accessory Electric Equipment 315 $ 2,282,285 $ 395,883 $ 2,657,948 f (430,004) S 2,227,944
Misc Power Plant Equip 318 S 238,086 f 86.388 It 302,472 $ (53,873) $ 248,599
Asset Retirement Obligation 317 $ (331,958) f 331,958 S •
Misc Power Plant Equip 335 S 1,188 $ (943) $ 245 $ 245
Subtotal Production f 14,510,908 $ 4,301,880 S 18,812,588 f (4,042.444) $ 14,770,142

Land Easements 350.2 $ 483,058 $ (85,888) $ 397,392 S 397,392
Structures & Improvements 352 $ 417,724 S (315) $ 417,409 f 417,409
Station Equipment 353 S 5,379,875 $ 2,952,819 $ 8,332,494 f 8,332,494
354 S 416,785 f 46,647 $ 483,412 $ (107,489) $ 355,943
Towers and Fixtures
355 $ 4,182,575 $ 779,244 f 4,981,819 S 4,981,819
Poles and Fixtures
356 S 2,880,208 S 1,182,893 $ 4,022,901 f 4,022,901
OH Conductors & Devices
Underground Conductors & Devices 358 f 1,409 $ 5,014 $ 8,423 $ 8,423
359 $ B80 $ 2,224 S 3,084 S 3,084
Roads and Traits
Subtotal Transmission 13,722,474 $ 4,882,480 S 18,604,934 $ (107,489) $ 18,497,485
$

380.2 f 240,953 $ (30,175) $ 210,778 $ 210,778
Land Rights
361 f 127,911 $ 33,089 $ 180,980 S (9,512) $ 151,488
Structures & Improvements
362 f 3,608,715 $ 383,575 $ 3,970,290 S (399,948) $ 3,570,344
Station Equipment
8,809,464 1,438,154 S 8,247,818 $ (1,192,811) S 7,055,007
Poles, Towers & Fixtures 364 $ . $
385 S 3,800,424 S 3,244,758 $ 6,845,180 S 8,845,180
OH Conductors & Devices
436,899 32,544 $ 489,443 S 489,443
Underground Conduit 388 $ It
2,277,438 960,820 $ 3.238,058 f 3,238,058
Underground Conductors & Devices 387 S $
10,285,939 $ 3,088,781 $ 13,374,720 S (776,924) S 12,597,796
Line Transformers 368 S
369 $ 2,735,306 $ 1,272,163 $ 4,007,489 $ 280,720 $ 4,288,189
OH Services
370 S 1,020,813 $ 394,834 $ 1,415,647 f 1,415,847
Meters
371 f 556,198 $ 919 $ 557,117 S $ 557,117
Install on Customer Premises
373 S 62,665 $ (22,817) S 40,048 $ 40,048
Street Lighting and Signal
31,780,723 It 10,778,823 $ 42,537,348 $ (2,098,273) $ 40,439,073
Subtotal Distribution $

382 S 12,125 $ - $ 12,125 $ 12,125
Regional Trans & Mkt Ops Hardware
383 S 673,827 $ (801) $ 673,228 $ 873,228
Regional Trans & Mid Ops Software

390 $ 1,359,298 $ (272.045) $ 1,087,251 f - f 1,087,251
Structures SImprovements
391 $ 2,514,238 $ 3,318,559 $ 5,832,797 $ - $ 5,832,797
Office Furniture & Equipment
392 $ 955 S 44,724 $ 45,679 $ - $ 45,879
Transportation Equipment
393 $ 150,556 $ 178,112 $ 328,888 S - It 328,888
Stores Equipment
394 $ 556,547 $ 68,440 f 822,987 $ - $ 822,987
Tools, Shop, & Garage Equipment
395 $ 22,505 S 254,880 S 277,385 $ - $ 277,385
Laboratory Equipment
30,044 $ (17,172) $ 12,872 S - $ 12,872
Power Operated Equipment 396 $
397 $ 1,897,978 $ (310,501) $ 1,387,477 5 - $ 1.387,477
Communication Equipment
47,155 123,991 $ 171,148 $ - $ 171,148
MIsCEquipment 398 $ $
8,379,274 3,384,968 $ 9,764,242 $ - $ 9,784,242
Subtotal General Plant $ $

403 $ 1,980,959 $ (203,083) $ 1,777,898 f (5,130) $ 1,772,766
ESI Depreciation Expense

735,599 $ 525,428 S 1,261,027 S - S 1,281,027
Organization Expense 301 $
303 S (117,485) $ 142,841 $ 25,356 S - $ 25,358
Contra AFUDC
189,797 $ (17,552) $ 172,245 S - S 172,245
Customer Accounting 303 S
233,924 S (51,305) f 182,619 f - $ 182,619
Customer CCS 303 $
18,388 $ (1,437) f 16,949 S - S 18,949
Customer CIS 303 $
117,825 S 458 $ 118,081 $ S 118,081
Customer Service 303 f
240,345 S (88.oi1) $ 172,334 S - $ 172,334
Distribution 303 S
1835,744) $ 1,751,785 S - S 1,751,785
A&GIMISC 303 $ 2,587.529 $
531,420 $ (43,000) $ 488,420 S - $ 488,420
A&GIMISC-Labor Related 303 $
3,314 S (674) $ 2,640 S - S 2,840
Non Nuclear Prod Fuel 303 $
704,512 $ (68,483) $ 838,029 S - $ 838,029
Non Nuclear Prod Non-Fuel 303 $
413,575 S 413,575 f $ 413,575
Regional Trans & Mild (RTOIICT) 303 $
741,809 (173,180) $ 568,849 S - $ 588,849
Transmission & Distribution 303 $
831.821 $ 7,272 $ 839,093 S $ 839,093
Transmission 303 $
7,032,171 f (583,389) S 8,448,802 s - $ 8,448,802
Subtotal Amortization Expense $

78,072,459 22,566,696 $ 96,831,187 f (6,253,316) 92,377,941
Total Depreciation & Amt S

10/30(2012 12:39 PM Pa" 7
 COMM Schedule IV
SOAH DOCKET NO. XXX-XX-XXXX Taxes Other Than FIT
PUC DOCKET NO. 39898
COMPANY NAME Entergy Texas, IM
TEST YEAR END 304un•11

Company Commission
Company Requested Ad►uaunenM Commission
Adjustments Test Year To Company Adjusted
Teat Year
To Test Year Total Electric Request Total Electric
Total
(a) (a) (d) (+) '(o)+(d)
(b)
TAXES OTHER THAN FIT

Non Revenue Related 24,224,356 $ (1,380,227) ^.:,. $ 22,844,129
$ 21,831,936 $ 2,592,420 $
Ad vow" Taxes-Texas 2,078.893 $ - $ 2,076.893
2.078.BB3 $ - $
Ad Valorem Taxes-Other States 28,301,249 $ (1,380,227) $ 24,921,022
f 23,708,829 $ 2,592,420 $
Total Property

Payroll Taxes 2,154,098 S (57,923) $ 2,106,173
$ 2,287,010 $ (122,914) $
FICA 20,530 $ (519) $ 20,011
S 20,530 $ - $
FUTA 33.897 S 18.6781 f 27.219
33.897 $ - S
SUTA 2,218,523 $ (65,120) $ 2,153,403
$ 2,341,437 $ (122,914) S
Total Payroll

Franchise Taxes - 6 - $ •
408.33 f - S - f
Texas $
$ $ $ $
Other States
$ - s - $ - $ - $
Other Taxes 269.306 $ 289,306
$ 289 , 308 S
ESI Ad Valorem 1,729,218 (121,549) $ 1,B07,B69
1 , 813 , 86 $ 115,362 f $
ESIPayroll Taxes $ 40,220
40 , 220 $ - $ 40,220 $ $
ESI Franchise Taxes $ 190
190 - $ 190 $ - $
ESI Other $ $
25,399 $ 25,399
Entergy Arkansas Payroll Taxes $ 25,399 $
$ 468 $ 468
Enteryy Mississippi Payroll Taxes $ 468
$ 12 $ 12
Entergy New Orleans Payroll Taxes $ 12
$ 137 , 081 $ 137,081
Entergy Gulf States Louisiana Payroll $ ,001
115 , 362 $ 2 , 201 892 $ (121,549) $ 2,080,343
Total Other $ 2, 088
1 53 0 $

Revenue Related 11,891,004 $ (1,117,418) S 10,773,588
$ 13,427,794 $ (1,538,790) $
State Gross Receipts - Texas 0.008400949 0.02003953278
0
Effective Rate (1.358,684) (1,358,664) $ 1,356,864
$ - $ $
State Gross Receipts - Other 17,875,122 $ (1,660,958) 16,014,164
f 19,932,527 $ (2,257,405) $
Local Gross Receipts - Texas 0.0207301912547 0 02978732378
Effective Rate 0.0000000000000
S - $ (78,933) $ (78,933) S 78,933
Local Gross Receipts - Other - $
State Gross Margins - Texas $ - S - $
0 0
Effective Rate (5,227,792) 28,132,529 $ (1,344,777) $ 28,787,752
$ 33,380,321 $ $

320,528 $ 1,847,317 t (173,595) S 1,673,722
PUC Assessment - Texas $ 1,528,789 $
0 0.001887 0.00311322488
PUC Assessment Effective Rate $ 210.783 $
f $ (210.783) $ (210.783)
PUC Assessment - Other 37,188 S 1,673,722
$ 1,526,789 3 109,785 $ 1,636,554 $

S 60,490,747 $ (2,874,606) f 57,e1e,241
TOTAL TAXES OTHER THAN $ 63,023,908 $ (2,03.159)
INCOME TAXES

Peps e
10(dW2012 12:39 PM
 SOAN DOCKET NO. XXX-XX-XXXX COMM Schedule V
PUC DOCKET NO. 39898 Fadaral lneome Taxea
COMPANY NAME EnterBy Texas, Inc.
TEST YEAR END 30.1un-11

FEDERAL INCOME TAXES - METHOD I Requested Commission
At Proposed Adjustments Commission
Test Year To Company Adjusted
Total Electric Request Total Electric
(c) (d) (e)

Retum Total $ - $ 140,800,598

Less:
Interest Included in Return f - i 57,409,530
$ 1,842,645
Amortlzatbn of DFIT ( Excess) $ 238,870
Consolidated Tax Savings
Plus. S
AFUDC $ 15,544,523
Other Perinarient Differences $ (1,720,971)
Non-Normalized Timing Differences
EOIIESI Taxes $ 436,745
Current State Income Tax $ (37,732)
Deferred State Income Tax $ 84,347
FAS 109 a - S -
Amortization of Excess DFIT-Depreeiatbn S f

TAXABLE COMPONENT OF RETURN $ - E 95,818,485

TAX FACTOR (1/1-35)(35) 0.53848150 0.53848150

TOTAL FIT BEFORE ADJUSTMENTS 0 51,488,882

Adjustments:

Amortization of ITC $ (1,642,645)
Amortization of Excess DFIT - Depreciation $ (238,870)
Prior Years Current FIT
Prior Years Deferred FIT
EOUESI Taxes S 483,745
FAS 109 f - S -
S S
Other - Consolidated Tax Savings

TOTAL FEDERAL INCOME TAXES S - S 80,071,092

Pape 9
101=012 12:39 PM
 Appendix C

PURA, Chapter 36, Subchapters A and B,
and Chapter 37, Subchapter D
PUBLIC UTILITY REGULATORY ACT
Title II, Texas Utilities Code
(As Amended)

Effective as of September 1, 2013

PUBLIC UTILITY COMMISSION
OF TEXAS
 FOREWORD

The Public Utility Code was enacted by Acts 1997, 75th Leg., R.S., ch. 166, § 1 as a new
and separate code effective September 1, 2007. Title 2 of the code is properly cited as the Public
Utility Regulatory Act.

This edition of the Public Utility Regulatory Act contains amendments adopted through
the 83rd Legislature, Third Called Session.

In general, the effect of amendments has been clear and the resulting text changes were
straightforward and did not require any editorial discretion. Except as explained below, editorial
discretion was exercised in reconciling multiple amendments to the same section. In the majority
of these cases, there was no irreconcilable conflict and all of the amendments could be given
effect. In some cases, an act expressly amended a provision as added or amended by another act.
In the few cases where an irreconcilable conflict was found, the act with the later date of
enactment was given effect, with the other provisions italicized below. In addition, a note
explaining the conflict is provided following the section annotation.

The annotations following each section have two components. The first annotation
shows the derivation of the section, either citing to the Public Utility Regulatory Act of 1995
(V.A.C.S. Art. 1446c-0), Acts 1997, ch. 166, or showing the section as added to the code and
citing the relevant act. The second component identifies subsequent amendments, cites the
amending act (and originating bill), provides a brief summary of each of the amendments, and,
where appropriate, provides a reference to related provisions or material.

This publication is maintained by the Commission Advising and Docket Management
Division of the Public Utility Commission of Texas. Suggestions or corrections may be
submitted to that division.

i
 CHAPTER 36. RATES

SUBCHAPTER A. GENERAL PROVISIONS

Sec. 36.001. AUTHORIZATION TO ESTABLISH AND REGULATE RATES.
(a) The regulatory authority may establish and regulate rates of an electric utility and may adopt
rules for determining:
(1) the classification of customers and services; and
(2) the applicability of rates.
(b) A rule or order of the regulatory authority may not conflict with a ruling of a federal regulatory
body.
(V.A.C.S. art. 1446c-0, Sec. 2.201.)
Sec. 36.002. COMPLIANCE WITH TITLE.
An electric utility may not charge or receive a rate for utility service except as provided by this title.
(V.A.C.S. art. 1446c-0, Sec. 2.153 (part).)
Sec. 36.003. JUST AND REASONABLE RATES.
(a) The regulatory authority shall ensure that each rate an electric utility or two or more electric
utilities jointly make, demand, or receive is just and reasonable.
(b) A rate may not be unreasonably preferential, prejudicial, or discriminatory but must be sufficient,
equitable, and consistent in application to each class of consumer.
(c) An electric utility may not:
(1) grant an unreasonable preference or advantage concerning rates to a person in a
classification;
(2) subject a person in a classification to an unreasonable prejudice or disadvantage concerning
rates; or
(3) establish or maintain an unreasonable difference concerning rates between localities or
between classes of service.
(d) In establishing an electric utility's rates, the commission may treat as a single class two or more
municipalities that an electric utility serves if the commission considers that treatment to be appropriate.
(e) A charge to an individual customer for retail or wholesale electric service that is less than the
rate approved by the regulatory authority does not constitute an impermissible difference, preference, or
advantage.
(V.A.C.S. art. 1446c-0, Secs. 2.202, 2.214 (part).)
Sec. 36.004. EQUALITY OF RATES AND SERVICES.
(a) An electric utility may not directly or indirectly charge, demand, or receive from a person a
greater or lesser compensation for a service provided or to be provided by the utility than the
compensation prescribed by the applicable tariff filed under Section 32.101.
(b) A person may not knowingly receive or accept a service from an electric utility for a
compensation greater or less than the compensation prescribed by the tariff.
(c) Notwithstanding Subsections (a) and (b), an electric utility may charge an individual customer
for wholesale or retail electric service in accordance with Section 36.007.

79
 (d) This title does not prevent a cooperative corporation from returning to its members net earnings
resulting from its operations in proportion to the members' purchases from or through the corporation.
(V.A.C.S. art. 1446c-0, Secs. 2.215(a), (b).)
Sec. 36.005. RATES FOR AREA NOT IN MUNICIPALITY.
Without the approval of the commission, an electric utility's rates for an area not in a municipality
may not exceed 115 percent of the average of all rates for similar services for all municipalities served by
the same utility in the same county as that area.
(V.A.C.S. art. 1446c-0, Sec. 2.213.)
Sec. 36.006. BURDEN OF PROOF.
In a proceeding involving a proposed rate change, the electric utility has the burden of proving that:
(1) the rate change is just and reasonable, if the utility proposes the change; or
(2) an existing rate is just and reasonable, if the proposal is to reduce the rate.
(V.A.C.S. art. 1446c-0, Sec. 2.204.)
Sec. 36.007. DISCOUNTED WHOLESALE OR RETAIL RATES.
(a) On application by an electric utility, a regulatory authority may approve wholesale or retail
tariffs or contracts containing charges that are less than rates approved by the regulatory authority but not
less than the utility's marginal cost. The charges must be in accordance with the principles of this title
and may not be unreasonably preferential, prejudicial, discriminatory, predatory, or anticompetitive.
(b) The method for computing the marginal cost of the electric utility consists of energy and capacity
components. The energy component includes variable operation and maintenance expense and marginal
fuel or the energy component of purchased power. The capacity component is based on the annual
economic value of deferring, accelerating, or avoiding the next increment of needed capacity, without
regard to whether the capacity is purchased or built.
(c) The commission shall ensure that the method for determining marginal cost is consistently
applied among utilities but may recognize the individual load and resource requirements of the electric
utility.
(d) Notwithstanding any other provision of this title, the commission shall ensure that the electric
utility's allocable costs of serving customers paying discounted rates under this section are not borne by
the utility's other customers.
(V.A.C.S. art. 1446c-0, Secs. 2.001(b), (c), (d) (part), 2.052(b), (c).)
Sec. 36.008. STATE TRANSMISSION SYSTEM.
In establishing rates for an electric utility, the commission may review the state's transmission system
and make recommendations to the utility on the need to build new power lines, upgrade power lines, and
make other necessary improvements and additions.
(V.A.C.S. art. 1446c-0, Sec. 2.051(w) (part).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7), § 23.)
Sec. 36.009. BILLING DEMAND FOR CERTAIN UTILITY CUSTOMERS.
Notwithstanding any other provision of this code, the commission by rule shall require a transmission
and distribution utility to:
(1) waive the application of demand ratchet provisions for each nonresidential secondary service
customer that has a maximum load factor equal to or below a factor set by commission rule;
(2) implement procedures to verify annually whether each nonresidential secondary service
customer has a maximum load factor that qualifies the customer for the waiver described by
Subdivision (1);
80
 (3) specify in the utility's tariff whether the utility's nonresidential secondary service customers
that qualify for the waiver described by Subdivision (1) are to be billed for distribution service
charges on the basis of:
(A) kilowatts;
(B) kilowatt-hours; or
(C) kilovolt-amperes; and
(4) modify the utility's tariff in the utility's next base rate case to implement the waiver described
by Subdivision (1) and make the specification required by Subdivision (3).
(Added by Acts 2011, 82nd Leg., R.S., ch. 150 (HB 1064), § 1.)

SUBCHAPTER B. COMPUTATION OF RATES

Sec. 36.051. ESTABLISHING OVERALL REVENUES.
In establishing an electric utility's rates, the regulatory authority shall establish the utility's overall
revenues at an amount that will permit the utility a reasonable opportunity to earn a reasonable return on
the utility's invested capital used and useful in providing service to the public in excess of the utility's
reasonable and necessary operating expenses.
(V.A.C.S. art. 1446c-0, Sec. 2.203(a).)
Sec. 36.052. ESTABLISHING REASONABLE RETURN.
In establishing a reasonable return on invested capital, the regulatory authority shall consider
applicable factors, including:
(1) the efforts and achievements of the utility in conserving resources;
(2) the quality of the utility's services;
(3) the efficiency of the utility's operations; and
(4) the quality of the utility's management.
(V.A.C.S. art. 1446c-0, Sec. 2.203(b).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7), § 24 (repealed
former subd. (1) and renumbered former subds. (2) to (5) as subds. (1) to (4)).)
Sec. 36.053. COMPONENTS OF INVESTED CAPITAL.
(a) Electric utility rates shall be based on the original cost, less depreciation, of property used by and
useful to the utility in providing service.
(b) The original cost of property shall be determined at the time the property is dedicated to public
use, whether by the utility that is the present owner or by a predecessor.
(c) In this section, the term "original cost" means the actual money cost or the actual money value of
consideration paid other than money.
(d) If the commission issues a certificate of convenience and necessity or, acting under Section
39.203(e), orders an electric utility or a transmission and distribution utility to construct or enlarge
transmission or transmission-related facilities to facilitate meeting the goal for generating capacity from
renewable energy technologies under Section 39.904(a), the commission shall find that the facilities are
used and useful to the utility in providing service for purposes of this section and are prudent and
includable in the rate base, regardless of the extent of the utility's actual use of the facilities.
(V.A.C.S. art. 1446c-0, Secs. 2.206(a) (part), (c).) (Amended by Acts 2005, 79th Leg., 1st C.S., ch. 1 (SB 20),
§ 1 (added subsec. (d)).)

81
Sec. 36.054. CONSTRUCTION WORK IN PROGRESS.
(a) Construction work in progress, at cost as recorded on the electric utility's books, may be included
in the utility's rate base. The inclusion of construction work in progress is an exceptional form of rate
relief that the regulatory authority may grant only if the utility demonstrates that inclusion is necessary to
the utility's financial integrity.
(b) Construction work in progress may not be included in the rate base for a major project under
construction to the extent that the project has been inefficiently or imprudently planned or managed.
(V.A.C.S. art. 1446c-0, Secs. 2.206(a) (part), (b).)
Sec. 36.055. SEPARATIONS AND ALLOCATIONS.
Costs of facilities, revenues, expenses, taxes, and reserves shall be separated or allocated as
prescribed by the regulatory authority.
(V.A.C.S. art. 1446c-0, Sec. 2.207.)
Sec. 36.056. DEPRECIATION, AMORTIZATION, AND DEPLETION.
(a) The commission shall establish proper and adequate rates and methods of depreciation,
amortization, or depletion for each class of property of an electric or municipally owned utility.
(b) The rates and methods established under this section and the depreciation account required by
Section 32.102 shall be used uniformly and consistently throughout rate-setting and appeal proceedings.
(V.A.C.S. art. 1446c-0, Secs. 2.151(a) (part), (d).)
Sec. 36.057. NET INCOME; DETERMINATION OF REVENUES AND EXPENSES.
(a) An electric utility's net income is the total revenues of the utility less all reasonable and
necessary expenses as determined by the regulatory authority.
(b) The regulatory authority shall determine revenues and expenses in a manner consistent with this
subchapter.
(c) The regulatory authority may adopt reasonable rules with respect to whether an expense is
allowed for ratemaking purposes.
(V.A.C.S. art. 1446c-0, Secs. 2.208(a), (e).)
Sec. 36.058. CONSIDERATION OF PAYMENT TO AFFILIATE.
(a) Except as provided by Subsection (b), the regulatory authority may not allow as capital cost or as
expense a payment to an affiliate for:
(1) the cost of a service, property, right, or other item; or
(2) interest expense.
(b) The regulatory authority may allow a payment described by Subsection (a) only to the extent that
the regulatory authority finds the payment is reasonable and necessary for each item or class of items as
determined by the commission.
(c) A finding under Subsection (b) must include:
(1) a specific finding of the reasonableness and necessity of each item or class of items allowed;
and
(2) a finding that the price to the electric utility is not higher than the prices charged by the
supplying affiliate for the same item or class of items to:
(A) its other affiliates or divisions; or
(B) a nonaffiliated person within the same market area or having the same market conditions.

82
 (d) In making a finding regarding an affiliate transaction, the regulatory authority shall:
(1) determine the extent to which the conditions and circumstances of that transaction are
reasonably comparable relative to quantity, terms, date of contract, and place of delivery; and
(2) allow for appropriate differences based on that determination.
(e) This section does not require a finding to be made before payments made by an electric utility to
an affiliate are included in the utility's charges to consumers if there is a mechanism for making the
charges subject to refund pending the making of the finding.
(f) If the regulatory authority finds that an affiliate expense for the test period is unreasonable, the
regulatory authority shall:
(1) determine the reasonable level of the expense; and
(2) include that expense in determining the electric utility's cost of service.
(V.A.C.S. art. 1446c-0, Sec. 2.208(b).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7), § 25 (amended
subsec. (d)); Acts 2005, 79th Leg., R.S., ch. 413 (SB 1668), § 1 (amended subd. (c)(2)).)
Sec. 36.059. TREATMENT OF CERTAIN TAX BENEFITS.
(a) In determining the allocation of tax savings derived from liberalized depreciation and
amortization, the investment tax credit, and the application of similar methods, the regulatory authority
shall:
(1) balance equitably the interests of present and future customers; and
(2) apportion accordingly the benefits between consumers and the electric or municipally owned
utility.
(b) If an electric utility or a municipally owned utility retains a portion of the investment tax credit,
that portion shall be deducted from the original cost of the facilities or other addition to the rate base to
which the credit applied to the extent allowed by the Internal Revenue Code.
(V.A.C.S. art. 1446c-0, Secs. 2.151(c), (d).)
Sec. 36.060. CONSOLIDATED INCOME TAX RETURNS.
(a) If an expense is allowed to be included in utility rates or an investment is included in the utility
rate base, the related income tax benefit must be included in the computation of income tax expense to
reduce the rates. If an expense is not allowed to be included in utility rates or an investment is not
included in the utility rate base, the related income tax benefit may not be included in the computation of
income tax expense to reduce the rates. The income tax expense shall be computed using the statutory
income tax rates.
(b) The amount of income tax that a consolidated group of which an electric utility is a member
saves, because the consolidated return eliminates the intercompany profit on purchases by the utility from
an affiliate, shall be applied to reduce the cost of the property or service purchased from the affiliate.
(c) The investment tax credit allowed against federal income taxes, to the extent retained by the
electric utility, shall be applied as a reduction in the rate-based contribution of the assets to which the
credit applies, to the extent and at the rate allowed by the Internal Revenue Code.
(V.A.C.S. art. 1446c-0, Sec. 2.208(c).) (Amended by Acts 2013, 83rd Leg., R.S., ch. 787 (SB 1364), § 1
(amended subsec. (a)).)
Sec. 36.061. ALLOWANCE OF CERTAIN EXPENSES.
(a) The regulatory authority may not allow as a cost or expense for ratemaking purposes:
(1) an expenditure for legislative advocacy; or

83
 (2) an expenditure described by Section 32.104 that the regulatory authority determines to be not
in the public interest.
(b) The regulatory authority may allow as a cost or expense:
(1) reasonable charitable or civic contributions not to exceed the amount approved by the
regulatory authority; and
(2) reasonable costs of participating in a proceeding under this title not to exceed the amount
approved by the regulatory authority.
(c) An electric utility located in a portion of this state not subject to retail competition may establish
a bill payment assistance program for a customer who is a military veteran who a medical doctor certifies
has a significantly decreased ability to regulate the individual's body temperature because of severe burns
received in combat. A regulatory authority shall allow as a cost or expense a cost or expense of the bill
payment assistance program. The electric utility is entitled to:
(1) fully recover all costs and expenses related to the bill payment assistance program;
(2) defer each cost or expense related to the bill payment assistance program not explicitly
included in base rates; and
(3) apply carrying charges at the utility's weighted average cost of capital to the extent related to
the bill payment assistance program.
(V.A.C.S. art. 1446c-0, Secs. 2.152(b), (c), (d), (e).) (Amended by Acts 2013, 83rd Leg., R.S., ch. 597 (SB 981),
§ 1 (added subsec. (c)).)
Sec. 36.062. CONSIDERATION OF CERTAIN EXPENSES.
The regulatory authority may not consider for ratemaking purposes:
(1) an expenditure for legislative advocacy, made directly or indirectly, including legislative
advocacy expenses included in trade association dues;
(2) a payment made to cover costs of an accident, equipment failure, or negligence at a utility
facility owned by a person or governmental entity not selling power in this state, other than a payment
made under an insurance or risk-sharing arrangement executed before the date of loss;
(3) an expenditure for costs of processing a refund or credit under Section 36.110; or
(4) any other expenditure, including an executive salary, advertising expense, legal expense, or
civil penalty or fine, the regulatory authority finds to be unreasonable, unnecessary, or not in the
public interest.
(V.A.C.S. art. 1446c-0, Sec. 2.208(d).)
Sec. 36.063. CONSIDERATION OF PROFIT OR LOSS FROM SALE OR LEASE OF
MERCHANDISE.
In establishing an electric or municipally owned utility's rates, the regulatory authority may not
consider any profit or loss that results from the sale or lease of merchandise, including appliances,
fixtures, or equipment, to the extent that merchandise is not integral to providing utility service.
(V.A.C.S. art. 1446c-0, Secs. 2.151(b) (part), (d).)
Sec. 36.064. SELF-INSURANCE.
(a) An electric utility may self-insure all or part of the utility's potential liability or catastrophic
property loss, including windstorm, fire, and explosion losses, that could not have been reasonably
anticipated and included under operating and maintenance expenses.
(b) The commission shall approve a self-insurance plan under this section if the commission finds
that:

84
 (1) the coverage is in the public interest;
(2) the plan, considering all costs, is a lower cost alternative to purchasing commercial
insurance; and
(3) ratepayers will receive the benefits of the savings.
(c) In computing an electric utility's reasonable and necessary expenses under this subchapter, the
regulatory authority, to the extent the regulatory authority finds is in the public interest, shall allow as a
necessary expense the money credited to a reserve account for self-insurance. The regulatory authority
shall determine reasonableness under this subsection:
(1) from information provided at the time the self-insurance plan and reserve account are
established; and
(2) on the filing of a rate case by an electric utility that has a reserve account.
(d) After a reserve account for self-insurance is established, the regulatory authority shall:
(1) determine whether the reserve account has a surplus or shortage under Subsection (e); and
(2) subtract any surplus from or add any shortage to the utility's rate base.
(e) A surplus in the reserve account exists if the charges against the account are less than the money
credited to the account. A shortage in the reserve account exists if the charges against the account are
greater than the money credited to the account.
(f) The allowance for self-insurance under this title for ratemaking purposes is not applicable to
nuclear plant investment.
(g) The commission shall adopt rules governing self-insurance under this section.
(V.A.C.S. art. 1446c-0, Sec. 2.210.)
Sec. 36.065. PENSION AND OTHER POSTEMPLOYMENT BENEFITS.
(a) The regulatory authority shall include in the rates of an electric utility expenses for pension and
other postemployment benefits, as determined by actuarial or other similar studies in accordance with
generally accepted accounting principles, in an amount the regulatory authority finds reasonable.
Expenses for pension and other postemployment benefits include, in an amount found reasonable by the
regulatory authority, the benefits attributable to the service of employees who were employed by the
predecessor integrated electric utility of an electric utility before the utility's unbundling under Chapter
39 irrespective of the business activity performed by the employee or the affiliate to which the employee
was transferred on or after the unbundling.
(b) Effective January 1, 2005, an electric utility may establish one or more reserve accounts for
expenses for pension and other postemployment benefits. An electric utility shall periodically record in
the reserve account any difference between:
(1) the annual amount of pension and other postemployment benefits approved as an operating
expense in the electric utility's last general rate proceeding or, if that amount cannot be determined
from the regulatory authority's order, the amount recorded for pension and other postemployment
benefits under generally accepted accounting principles during the first year that rates from the
electric utility's last general rate proceeding are in effect; and
(2) the annual amount of pension and other postemployment benefits as determined by actuarial
or other similar studies that are chargeable to the electric utility's operating expense.
(c) A surplus in the reserve account exists if the amount of pension and other postemployment
benefits under Subsection (b)(1) is greater than the amount determined under Subsection (b)(2). A
shortage in the reserve account exists if the amount of pension and other postemployment benefits under
Subsection (b)(1) is less than the amount determined under Subsection (b)(2).

85
 (d) If a reserve account for pension and other postemployment benefits is established, the regulatory
authority at a subsequent general rate proceeding shall:
(1) review the amounts recorded to the reserve account to determine whether the amounts are
reasonable expenses;
(2) determine whether the reserve account has a surplus or shortage under Subsection (c); and
(3) subtract any surplus from or add any shortage to the electric utility's rate base with the
surplus or shortage amortized over a reasonable time.
(Added by Acts 2005, 79th Leg., R.S., ch. 385 (SB 1447), § 1.)

SUBCHAPTER C. GENERAL PROCEDURES FOR RATE CHANGES
PROPOSED BY UTILITY

Sec. 36.101. DEFINITION.
In this subchapter, "major change" means an increase in rates that would increase the aggregate
revenues of the applicant more than the greater of $100,000 or 2-1/2 percent. The term does not include
an increase in rates that the regulatory authority allows to go into effect or the electric utility makes under
an order of the regulatory authority after hearings held with public notice.
(V.A.C.S. art. 1446c-0, Sec. 2.212(b) (part).)
Sec. 36.102. STATEMENT OF INTENT TO CHANGE RATES.
(a) Except as provided by Section 33.024, an electric utility may not change its rates unless the
utility files a statement of its intent with the regulatory authority that has original jurisdiction over those
rates at least 35 days before the effective date of the proposed change.
(b) The electric utility shall also mail or deliver a copy of the statement of intent to the appropriate
officer of each affected municipality.
(c) The statement of intent must include:
(1) proposed revisions of tariffs; and
(2) a detailed statement of:
(A) each proposed change;
(B) the effect the proposed change is expected to have on the revenues of the utility;
(C) each class and number of utility consumers affected; and
(D) any other information required by the regulatory authority's rules.
(V.A.C.S. art. 1446c-0, Sec. 2.212(a) (part).)
Sec. 36.103. NOTICE OF INTENT TO CHANGE RATES.
(a) The electric utility shall:
(1) publish, in conspicuous form and place, notice to the public of the proposed change once
each week for four successive weeks before the effective date of the proposed change in a newspaper
having general circulation in each county containing territory affected by the proposed change; and
(2) mail notice of the proposed change to any other affected person as required by the regulatory
authority's rules.
(b) The regulatory authority may waive the publication of notice requirement prescribed by
Subsection (a) in a proceeding that involves only a rate reduction for each affected ratepayer. The
applicant shall give notice of the proposed rate change by mail to each affected utility customer.

86
 SUBCHAPTER C. MUNICIPALITIES

Sec. 37.101. SERVICE IN ANNEXED OR INCORPORATED AREA.
(a) If an area is or will be included within a municipality as the result of annexation, incorporation,
or another reason, each electric utility and each electric cooperative that holds or is entitled to hold a
certificate under this title to provide service or operate a facility in the area before the inclusion has the
right to continue to provide the service or operate the facility and extend service within the utility's or
cooperative’s certificated area in the annexed or incorporated area under the rights granted by the
certificate and this title.
(b) Notwithstanding any other law, an electric utility has the right to:
(1) continue and extend service within the utility's certificated area; and
(2) use roads, streets, highways, alleys, and public property to furnish retail electric utility
service.
(c) The governing body of a municipality may require an electric utility to relocate the utility's
facility at the utility's expense to permit the widening or straightening of a street by:
(1) giving the electric utility 30 days' notice; and
(2) specifying the new location for the facility along the right-of-way of the street.
(d) This section does not:
(1) limit the power of a city, town, or village to incorporate or of a municipality to extend its
boundaries by annexation; or
(2) prohibit a municipality from levying a tax or other special charge for the use of the streets as
authorized by Section 182.025, Tax Code.
(V.A.C.S. art. 1446c-0, Secs. 2.256(a), (b), (c).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7), § 33
(amended subsec. (a)).)
Sec. 37.102. GRANT OF CERTIFICATE FOR CERTAIN MUNICIPALITIES.
(a) If a municipal corporation offers retail electric utility service in a municipality having a
population of more than 135,000 that is located in a county having a population of more than 1,500,000,
the commission shall singly certificate areas in the municipality's boundaries in which more than one
electric utility provides electric utility service.
(b) In singly certificating an area under Subsection (a), the commission shall preserve the right of an
electric utility to serve the customers the electric utility was serving on June 17, 1983. This subsection
does not apply to a customer at least partially served by a nominal 69,000 volts system who gave notice
of termination to the utility servicing that customer before June 17, 1983.
(V.A.C.S. art. 1446c-0, Sec. 2.256(d).)

SUBCHAPTER D. REGULATION OF SERVICES, AREAS, AND FACILITIES

Sec. 37.151. PROVISION OF SERVICE.
Except as provided by this section, Section 37.152, and Section 37.153, a certificate holder, other than
one granted a certificate under Section 37.051(d), shall:
(1) serve every consumer in the utility's certificated area; and
(2) provide continuous and adequate service in that area.
(V.A.C.S. art. 1446c-0, Sec. 2.259(a).) (Amended by Acts 2009, 81st Leg., R.S., ch. 1170 (HB 3309), § 4).

108
Sec. 37.152. GROUNDS FOR REDUCTION OF SERVICE.
(a) Unless the commission issues a certificate that the present and future convenience and necessity
will not be adversely affected, a certificate holder may not discontinue, reduce, or impair service to any
part of the holder's certificated service area except for:
(1) nonpayment of charges;
(2) nonuse; or
(3) another similar reason that occurs in the usual course of business.
(b) A discontinuance, reduction, or impairment of service must be in compliance with and subject to
any condition or restriction the commission prescribes.
(V.A.C.S. art. 1446c-0, Secs. 2.259(b), (c).)
Sec. 37.153. REQUIRED REFUSAL OF SERVICE.
A certificate holder shall refuse to serve a customer in the holder's certificated area if the holder is
prohibited from providing the service under Section 212.012, 232.029, or 232.0291, Local Government
Code.
(V.A.C.S. art. 1446c-0, Sec. 2.260.) (Amended by Acts 2005, 79th Leg., R.S., ch. 708 (SB 425), § 13.)
Sec. 37.154. TRANSFER OF CERTIFICATE.
(a) An electric utility may sell, assign, or lease a certificate or a right obtained under a certificate if
the commission determines that the purchaser, assignee, or lessee can provide adequate service.
(b) A sale, assignment, or lease of a certificate or a right is subject to conditions the commission
prescribes.
(V.A.C.S. art. 1446c-0, Sec. 2.261.)
Sec. 37.155. APPLICATION OF CONTRACTS.
A contract approved by the commission between retail electric utilities that designates areas and
customers to be served by the utilities:
(1) is valid and enforceable; and
(2) shall be incorporated into the appropriate areas of certification.
(V.A.C.S. art. 1446c-0, Sec. 2.257.)
Sec. 37.156. INTERFERENCE WITH ANOTHER UTILITY.
If an electric utility constructing or extending the utility's lines, plant, or system interferes or attempts
to interfere with the operation of a line, plant, or system of another utility, the commission by order may:
(1) prohibit the construction or extension; or
(2) prescribe terms for locating the affected lines, plants, or systems.
(V.A.C.S. art. 1446c-0, Sec. 2.262.)
Sec. 37.157. MAPS.
An electric utility shall file with the commission one or more maps that show each utility facility and
that separately illustrate each utility facility for the generation, transmission, or distribution of the utility's
services on a date the commission orders.
(V.A.C.S. art. 1446c-0, Sec. 2.254(b).)

109
 Appendix D

Entergy Gulf States, Inc. v. Public Utility Commission,
112 S.W.3d 208 (Tex. App. – Austin 2003, pet.
denied)
 Page 1

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

cost estimate were not prudent; and (4) PUC decision
not to accept utility's cost-reconciliation study did not
improperly prevent utility from establishing the pru-
Court of Appeals of Texas,
dence of costs.
Austin.
ENTERGY GULF STATES, INC., Appellant,
v. Affirmed.
PUBLIC UTILITY COMMISSION OF TEXAS,
Texas Industrial Energy Consumers, City of Beau- West Headnotes
mont, City of Bridge City, City of Conroe, City of
Groves, City of Nederland, and City of Port Neches, [1] Electricity 145 11.3(7)
Appellees.
145 Electricity
No. 03–02–00249–CV. 145k11.3 Regulation of Charges
July 11, 2003. 145k11.3(7) k. Judicial Review and Enforce-
ment. Most Cited Cases
Electric utility, cities, Office of Public Utility
Counsel (OPUC), industrial energy entity, and State Supreme Court's statement that there was exten-
petitioned for judicial review of Public Utility Com- sive evidence supporting inclusion of all costs electric
mission (PUC) order in utility rate case purportedly utility incurred in constructing a nuclear power plant
deferring issue of whether certain portion of utility's in its rate base was not law of the case as to issue of
costs in constructing nuclear power plant should be whether utility had established a prima facie case that
included in utility's rate base. The Judicial District costs were prudently incurred, where Supreme Court
Court reversed. On remand, PUC ordered certain did not comment on the weight of utility's evidence,
portion of costs excluded from rate base. Utility ap- remanded the case to the Public Utility Commission
pealed. The Judicial District Court reversed. PUC, (PUC), and granted PUC the option of accepting ad-
OPUC, and utility appealed. The Court of Appeals, ditional evidence; Supreme Court's opinion focused
883 S.W.2d 739, affirmed in part, reversed in part, and solely on disapproving of PUC's procedure in defer-
rendered. Utility appealed. The Supreme Court, 947 ring consideration of portion of costs.
S.W.2d 887, reversed. On remand, PUC found that
any costs above the adjusted definitive cost estimate
[2] Appeal and Error 30 1097(1)
were imprudent. Utility sought review. The 353rd
Judicial District Court, Travis County, Suzanne Cov-
ington, J., affirmed. Utility appealed. The Court of 30 Appeal and Error
Appeals, Lee Yeakel, J., held that: (1) statement by 30XVI Review
Supreme Court was not law of the case as to whether 30XVI(M) Subsequent Appeals
utility had established a prima facie case that costs 30k1097 Former Decision as Law of the
were prudently incurred; (2) PUC complied with Su- Case in General
preme Court's order to render a straightforward deci- 30k1097(1) k. In General. Most Cited
sion on remand; (3) substantial evidence supported Cases
PUC's determination that costs in excess of definitive

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 Page 2

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

Appeal and Error 30 1195(1) apply if the issues and facts are not substantially the
same in the subsequent trial.
30 Appeal and Error
30XVII Determination and Disposition of Cause [5] Courts 106 99(1)
30XVII(F) Mandate and Proceedings in Lower
Court 106 Courts
30k1193 Effect in Lower Court of Decision 106II Establishment, Organization, and Procedure
of Appellate Court 106II(G) Rules of Decision
30k1195 As Law of the Case 106k99 Previous Decisions in Same Case as
30k1195(1) k. In General. Most Cited Law of the Case
Cases 106k99(1) k. In General. Most Cited
Cases
The law-of-the-case doctrine provides that ques-
tions of law decided on appeal to a court of last resort Use of the law of the case is flexible, left to the
will govern the case throughout its subsequent stages. discretion of the court, and to be determined on a
case-by-case basis.
[3] Courts 106 99(1)
[6] Electricity 145 11.3(7)
106 Courts
106II Establishment, Organization, and Procedure 145 Electricity
106II(G) Rules of Decision 145k11.3 Regulation of Charges
106k99 Previous Decisions in Same Case as 145k11.3(7) k. Judicial Review and Enforce-
Law of the Case ment. Most Cited Cases
106k99(1) k. In General. Most Cited
Cases
Public Utility Commission (PUC) complied with
Supreme Court's order to render a straightforward
The law-of-the-case doctrine narrows the issues decision, on remand, as to whether costs PUC initially
in successive stages of litigation and serves the policy attempted to defer judgment on should be included in
goals of uniformity of decisions and judicial economy. electric utility's base rate, where PUC ruled, after
reviewing the entire record, that utility did not satisfy
[4] Courts 106 99(1) its burden of proof or establish its prima facie case as
to the prudence of the additional costs. V.T.C.A.,
106 Courts Utilities Code § 36.006.
106II Establishment, Organization, and Procedure
106II(G) Rules of Decision [7] Electricity 145 11.3(6)
106k99 Previous Decisions in Same Case as
Law of the Case 145 Electricity
106k99(1) k. In General. Most Cited 145k11.3 Regulation of Charges
Cases 145k11.3(6) k. Proceedings Before Commis-
sions. Most Cited Cases
The law-of-the-case doctrine does not necessarily

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 Page 3

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

To raise the price of its product, an electric utility utility incurred in constructing nuclear power plant
must participate in a rate case and bear the burden of which were in excess of definitive cost estimate were
proving that each dollar of cost incurred was reason- not prudent; pursuit of short construction schedule
ably and prudently invested. V.T.C.A., Utilities Code reduced construction productivity, and expert testi-
§ 36.006. mony failed to indicate whether price adjustments
included allowance for funds used during construction
[8] Electricity 145 11.3(6) (AFUDC). V.T.C.A., Utilities Code § 36.006.

145 Electricity [11] Administrative Law and Procedure 15A
145k11.3 Regulation of Charges 791
145k11.3(6) k. Proceedings Before Commis-
sions. Most Cited Cases 15A Administrative Law and Procedure
15AV Judicial Review of Administrative Deci-
An electric utility that seeks a rate increase enjoys sions
no presumption that the expenditures reflected therein 15AV(E) Particular Questions, Review of
have been prudently incurred by simply opening its 15Ak784 Fact Questions
books to inspection. V.T.C.A., Utilities Code § 15Ak791 k. Substantial Evidence. Most
36.006. Cited Cases

[9] Electricity 145 11.3(6) To ascertain whether an agency's decision is
supported by substantial evidence, a reviewing court
determines whether, in considering the record upon
145 Electricity
which the decision is based, the evidence as a whole is
145k11.3 Regulation of Charges
such that reasonable minds could have reached the
145k11.3(6) k. Proceedings Before Commis-
conclusion the agency must have reached in order to
sions. Most Cited Cases
take the disputed action.

Although the burden of production is initially on
[12] Administrative Law and Procedure 15A
the electric utility that seeks a rate change, the utility
791
can shift this burden upon establishing a prima facie
case of prudent investment. V.T.C.A., Utilities Code §
36.006. 15A Administrative Law and Procedure
15AV Judicial Review of Administrative Deci-
sions
[10] Electricity 145 11.3(6)
15AV(E) Particular Questions, Review of
15Ak784 Fact Questions
145 Electricity 15Ak791 k. Substantial Evidence. Most
145k11.3 Regulation of Charges Cited Cases
145k11.3(6) k. Proceedings Before Commis-
sions. Most Cited Cases
In determining whether an agency's decision is
supported by substantial evidence, the reviewing court
Substantial evidence supported Public Utility may not substitute its judgment for the agency's and
Commission's (PUC) determination that costs electric must consider only the record upon which the decision

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112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

is based. prudence of costs it incurred in constructing nuclear
power plant, where utility was afforded ample earlier
[13] Administrative Law and Procedure 15A opportunities to fully develop the record, and utility
750 supported PUC's decision not to take additional evi-
dence.
15A Administrative Law and Procedure
15AV Judicial Review of Administrative Deci- *210 John F. Williams, David C. Duggins, Clark,
sions Thomas & Winters, PC, Austin, for appellant.
15AV(D) Scope of Review in General
15Ak750 k. Burden of Showing Error. Most Daniel J. Lawton, Lawton Law Firm, Barbara Day,
Cited Cases Austin, for Cities.

The burden is on the complaining party to Rex D. VanMiddlesworth, Karen P. Whitt, Andrews
demonstrate an absence of substantial evidence to & Kurth, LLP, Austin, for Texas I.
support an agency's decision.
James Z. Brazell, Asst. Atty. Gen., Austin, for PUC.
[14] Public Utilities 317A 194
Before Justices KIDD, YEAKEL and PURYEAR.
317A Public Utilities
317AIII Public Service Commissions or Boards OPINION
317AIII(C) Judicial Review or Intervention LEE YEAKEL, Justice.
317Ak188 Appeal from Orders of Com- Appellant Entergy Gulf States, Inc. (“Entergy”)
mission appeals from a district-court judgment affirming a
317Ak194 k. Review and Determination final order of appellee the Public Utility Commission
in General. Most Cited Cases of Texas (the “Commission”).FN1 Entergy sought a
rate increase to recover additional sums from its share
It is for the Public Utility Commission (PUC) to in the construction of the River Bend Nuclear Gener-
accept or reject witnesses' testimony, and the PUC, not ating Station in St. Francisville, Louisiana (“River
the reviewing court, is the judge of the weight ac- Bend”). The Commission denied Entergy's request,
corded that testimony in a rate case. finding that Entergy failed to present a prima facie
case that the additional cost of the plant's construction
above the adjusted definitive cost estimate (“DCE”)
[15] Electricity 145 11.3(6)
was prudent. FN2 Appellees Texas Industrial Energy
Consumers and the cities of Beaumont, Bridge City,
145 Electricity
Conroe, Groves, Nederland, and Port Neches support
145k11.3 Regulation of Charges
the Commission's decision denying the rate increase.
145k11.3(6) k. Proceedings Before Commis-
We will affirm.
sions. Most Cited Cases

FN1. Entergy Gulf States, Inc. was known as
Public Utility Commission's (PUC) decision not
Gulf States Utilities at the time this contro-
to accept electric utility's cost-reconciliation study did
versy arose in 1986 and in several of the
not improperly prevent utility from establishing the
succeeding years of this litigation. Entergy

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112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

Gulf States came into being after Gulf conducted a hearing on the rate request and submitted
States's 1993 merger with Entergy Corpora- to the Commission an “Examiner's Report” (the
tion, a public utility holding company. We “Report”) and proposed order. In the 395–page Re-
will refer to appellant as Entergy throughout port, the Examiners evaluated the prudence of River
the dispute's entire history. Bend's costs by examining the parties' evidence. En-
tergy and a number of other interested parties sub-
FN2. DCE is the 1979 estimate of River mitted their own reports, each arguing the prudence of
Bend's total cost of construction. The stand- River Bend's cost. The Examiners noted that the evi-
ard of prudence, as defined by the Commis- dence demonstrated that every change in construction
sion, is: had been documented, but that the documentation was
insufficient to prove that the changes were prudent.
Regarding the examiners' opinion of Entergy's evi-
[T]he exercise of that judgment and the
dence, the Report stated:
choosing of one of that select range of op-
tions which a reasonable utility manager
would exercise or choose in the same or [Entergy] did not present any credible reconciliation
similar circumstances given the infor- of plant costs with specific causes, much less with
mation or alternatives available at the point specific regulatory changes. Even if the causes for
in time such judgment is exercised or op- change were legitimate, it did not show that the
tion is chosen. amount of money spent to meet various goals were
reasonable. It did show more generally that regula-
tory changes had a dramatic effect on the project's
STATEMENT OF THE FACTS AND PROCE-
scope and cost. Yet from the evidence one cannot
DURAL HISTORY
tell how wisely and efficiently money was spent on
Construction of River Bend began in 1977. After
design development, scope changes, and meeting
suspending construction from *211 October 1977 to
regulatory changes.
February 1979, construction resumed and the plant
achieved operational status in 1986. At that time,
River Bend began serving customers in Southeast Ultimately, the Report concluded that: (1) $274
Texas and South Central Louisiana. River Bend's million, or nine percent (later adjusted to 8.3 percent),
construction cost approximately $4.5 billion, well of the total plant cost should be excluded from En-
above the original cost estimate. As a partner in the tergy's cost of service as imprudently incurred; (2)
project, Entergy was responsible for seventy percent Entergy's decision to restart construction of River
of the construction costs. In 1986 Entergy applied to Bend in 1979, a decision that some parties criticized,
the Commission for a rate increase, seeking to include was prudent; and (3) a reasonable DCE, based on
approximately $3.15 billion of its River Bend con- information available in 1979, should have been
struction costs in its cost of service. Entergy also ini- $2.273 billion (“adjusted DCE”), instead of Entergy's
tiated a contested case to determine what portion of its construction manager's 1979 estimate of $1.729 bil-
total costs the utility might include in its rate base as lion (“original DCE”).
being a “prudent” investment. The two actions were
consolidated as Docket 7195. The Commission adopted only part of the Re-
port's recommendations. The Commission agreed with
Over a six-month period, two administrative law the Examiners that the decision to build River Bend
judges and a “hearings examiner” (the “Examiners”) was prudent and that the original DCE should be ad-
justed upward to $2.273 billion, as this sum was pru-

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112 S.W.3d 208, Util. L. Rep. P 26,862
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dently incurred; thus Entergy's seventy percent share trict-court judgment and dissolved the injunction,
of the prudently incurred cost was $1.591 billion. The allowing Docket 8702 to proceed. Public Util.
Commission, however, did not adopt the Report's Comm'n v. Coalition of Cities for Affordable Util.
recommendation to disallow only 8.3 percent of the Rates, 777 S.W.2d 814 (Tex.App.-Austin 1989),
total plant cost. Instead, the Commission deferred its rev'd, Coalition of Cities for Affordable Util. Rates v.
decision on whether Entergy prudently incurred the Public Util. Comm'n, 798 S.W.2d 560 (Tex.1990).
remaining $1.453 billion in additional costs. The The supreme court reversed this Court, holding that
Commission noted that “[t]he evidence is inadequate the doctrines of res judicata and collateral estoppel
to support a finding of either prudence or imprudence barred Entergy's relitigation in Docket 8702 of the
with regard to construction costs in excess of $2.273 issues originally reviewed in Docket 7195, and that
billion ... [and] should be excluded from plant in ser- “the PUC was powerless to defer its decision to a
vice at this time....” Therefore, the Commission ef- future proceeding.” Coalition of Cities, 798 S.W.2d at
fectively deferred a decision on the additional $1.453 564–65. The appeal in Docket 7195 then went forward
billion. in the district court, which reversed the Commission's
final order on an unstated ground and remanded the
Entergy and several other parties sued in district rate case to the Commission.
court, as authorized by the Public Utility Regulatory
Act (“PURA”), seeking*212 judicial review of the On remand, the Commission held that, because its
Commission's final order in Docket 7195. See Act of deferral of the decision on the $1.453 billion was
May 26, 1983, 68th Leg., ch. 274, § 69, 1983 Tex. invalid, the remaining portions of the order in Docket
Gen. Laws 1258, 1314 (amended 1995 & 1997) 7195 “appeared to hold that [Entergy] had failed to
(current provision at Tex. Util.Code Ann. § 15.001 meet its burden” and the $1.453 billion was properly
(West 1998)). Concurrently, Entergy filed a new excluded. Entergy appealed. The district court rejected
contested case with the Commission, Docket 8702, to Entergy's argument that the Commission's decision
address the $1.453 billion not adjudicated in Docket was statutorily infirm but reversed the Commission on
7195. two minor points. Entergy, the Commission, and
OPUC then appealed to this Court, which reversed the
Before direct judicial review began in Docket district-court ruling, effectively approving the Com-
7195, the Office of Public Utility Counsel (“OPUC”) mission's order disallowing the $1.453 billion. Gulf
and twelve municipalities sued the Commission in States Utils. Co. v. Coalition of Cities for Affordable
district court, requesting a declaration that the Com- Util. Rates, 883 S.W.2d 739 (Tex.App.-Austin 1994),
mission lacked the power to reconsider, in a separate rev'd, Gulf States Utils. Co. v. Public Util. Comm'n,
contested case, the prudence of the $1.453 billion 947 S.W.2d 887 (Tex.1997). The supreme court again
expenditure deferred in Docket 7195. Ancillary to reversed, holding that “one simply cannot read the
their suit for declaratory relief, the plaintiffs requested record of proceedings in the PUC and the PUC's order
a permanent injunction restraining the Commission and conclude that the Commission would have ex-
from conducting any further proceedings addressing cluded the $1.453 billion from [Entergy's] rate base
the prudence of the $1.453 billion. The district court, had it known that it could not defer ruling on the is-
declaring that res judicata and collateral estoppel sue.” Gulf States Utils., 947 S.W.2d at 891. The su-
barred reconsideration of those costs by the Commis- preme court noted that “[a]ll parties were entitled to a
sion, granted the permanent injunction, enjoining the straightforward decision from the [Commission] the
Commission from proceeding with Docket 8702. The first time that the case was presented.” Id. at 892.
Commission appealed. This Court reversed the dis- Finally, in remanding the case to the Commission, the

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112 S.W.3d 208, Util. L. Rep. P 26,862
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court stated that the Commission could decide [1] By its first issue, Entergy argues that the
whether to entertain further evidence or resolve the Commission disregarded the supreme court's opinion
case on the evidence previously presented. Id. in Gulf States Utilities, 947 S.W.2d at 887, and the
law-of-the-case doctrine. Specifically, Entergy con-
On remand, the Commission opened a new tends that “[a]s a matter of law ... the Supreme Court
docket, Docket 17899. Entergy took the position that decided that [Entergy] had presented a significant
the Commission “could either: (1) decide the case ‘on amount of evidence supporting the prudence of its
the record as originally created in Docket No. 7195,’ entire investment, and that a total disallowance was
*213 or (2) receive the Company's ‘cost reconcilia- not supported by the record.” We disagree because the
tion’ study in evidence should the Commission deem supreme court's opinion in Gulf States Utilities does
such a study necessary.” The Commission determined not specifically comment on the weight of the evi-
to base its decision on the then existing record and dence for either party. See id. at 888.
requested that the parties rebrief the case; Entergy
agreed with this approach. In a 2–1 decision, the [2][3][4][5] The law-of-the-case doctrine pro-
Commission excluded the $1.453 billion from En- vides that questions of law decided on appeal to a
tergy's cost of service.FN3 Entergy sought judicial court of last resort will govern the case throughout its
review in district court, which affirmed the Commis- subsequent stages. Hudson v. Wakefield, 711 S.W.2d
sion's decision. Entergy again appeals. 628, 630 (Tex.1986). The doctrine narrows the issues
in successive stages of litigation and serves the policy
FN3. Chairman Pat Wood disagreed with the goals of uniformity of decisions and judicial economy.
majority, concluding that $103 million of the Id. The doctrine does not necessarily apply if the is-
$348 million in additional regulatory ex- sues and facts are not substantially the same in the
penses was not disputed by either party and, subsequent trial. Id. As such, use of the law of the case
therefore, should be allowed. is flexible, left to the discretion of the court, and to be
determined on a case-by-case basis. Med Ctr. Bank v.
M.D. Fleetwood, 854 S.W.2d 278, 283 n. 6
DISCUSSION
(Tex.App.-Austin 1993, writ denied).
By five issues, Entergy argues that the Commis-
sion erred in: (1) disregarding the supreme court's
opinion and judgment on remand; (2) determining that The sentence in the supreme court's opinion that
Entergy failed to present a prima facie case estab- Entergy highlights is: “There was extensive evidence
lishing the prudence of the plant investment; (3) dis- supporting inclusion of all [Entergy's] costs in its rate
allowing all of the plant's construction costs above the base and extensive contrary evidence that most of
adjusted DCE as not supported by substantial evi- these costs should be excluded.” Gulf States Util., 947
dence, which is an erroneous decision as a matter of S.W.2d at 888. Entergy interprets this language as the
law; (4) making arbitrary, after-the-fact changes to the supreme court's recognition that Entergy presented
standards governing its prudence analysis; and (5) sufficient evidence to establish its prima facie case. In
making certain adjustments to rates that were the our opinion, this sentence comments on the quantity
product of its erroneous treatment of the plant in- and not the quality of the evidence introduced. First,
vestment. We begin by examining the supreme court's this sentence appears in the section in which the court
most recent decision. delivers its recitation of the facts. There, the court
recounts that Docket 7195 included the testimony of
“over 100 witnesses for 132 days [and] the examiners
Gulf States Utilities Co. v. Public Utility Commission
issued a 395–page report.” Id. *214 Second, the su-

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112 S.W.3d 208, Util. L. Rep. P 26,862
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preme court discussed its earlier opinion, stating that utilities code requires that “[i]n a proceeding involv-
the Commission could not defer decision on disal- ing a proposed rate change, the electric utility has the
lowance of the $1.453 billion, and that “the issue burden of proving that: ... the rate change is just and
remaining for judicial review was whether the reasonable, if the utility proposes the change.” Tex.
[Commission] could effectively deny inclusion of Util.Code Ann. § 36.006 (West 1998); Coalition of
those costs in [Entergy's] rate base the way it did.” Id. Cities, 798 S.W.2d at 563. To raise the price of its
at 889, 890 (citing Coalition of Cities, 798 S.W.2d at product, the utility must participate in a rate case and
564–65). Nowhere did the court discuss whether En- bear the burden of proving that each dollar of cost
tergy had established a prima facie case or met its incurred was reasonably and prudently invested.
burden of substantial evidence. Finally, the court Public Util. Comm'n v. Houston Lighting & Power
reversed and remanded the case, granting the Com- Co., 778 S.W.2d 195, 198 (Tex.App.-Austin 1989, no
mission the option of accepting additional evidence. writ). A utility enjoys no presumption that the ex-
Id. at 892. Again, the supreme court did not comment penditures reflected therein have been prudently in-
on the quality of the evidence presented. The court curred by simply opening its books to inspection. Id. A
simply ordered the Commission to render a utility carries the burden of proof even when it does
“straightforward decision.” Id. The law-of-the-case not initiate the proceedings. Id.
doctrine is inapplicable because the supreme court did
not comment on the weight of Entergy's evidence; [9] The Commission has established that although
rather the opinion focused solely on disapproving of the burden of production is initially on the utility, the
the Commission's procedure in deferring considera- utility can shift this burden upon establishing a prima
tion of the $1.453 billion in costs.FN4 Therefore, we facie case of prudence in the rate change.FN5 In its
overrule Entergy's first issue. order on remand, the Commission *215 described
application of the burden of proof:
FN4. In Gulf States Utilities Co. v. Public
Utility Commission, the supreme court also FN5. The Commission's brief explains the
stated that “one simply cannot read the rec- reason behind the utility's prima facie case
ord of proceedings in the PUC and the PUC's requirement:
order and conclude that the Commission
would have excluded the $1.453 billion from
The Commission's prima facie procedure
[Entergy's] rate base had it known that it
is Commission-made. It is not established
could not defer ruling on the issue.” 947
by statute or prior court decision, it was
S.W.2d 887, 891 (Tex.1997). However, we
specially crafted by the Commission to aid
do not believe that this language comments
in the trial of utility prudence reviews. It is
on the weight of the evidence, but rather
a tool to assist in conducting efficient
disapproves of the Commission's procedure
hearings. It is crafted to accommodate the
in deferring its decision on whether to in-
voluminous, highly technical evidence
clude the $1.453 billion in the rate base.
required to establish the prudence of in-
vestment in electric power plants. The
The Prima Facie Case Commission's prima facie procedure al-
[6][7][8] By its second issue, Entergy contends lows the utility to establish the prudence by
that the Commission erred in ruling that Entergy had introducing evidence that is comprehen-
not established its prima facie case of prudence for sive, but short of proof of the prudence of
inclusion of the $1.453 billion in the rate base. The every bolt, washer, pipe hanger, cable tray,

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112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

I-beam, or concrete pour. review if a prima facie case had not been made. The
Commission also observed that “[t]he record in this
(Citations omitted.) case is fully developed.” Before enumerating the
findings of fact and conclusions of law, the Com-
mission concluded:
The Commission has previously recognized the
proposition that a utility's capital investments are
initially presumed to be prudent once the utility has FN6. In his dissenting statement, Chairman
presented a prima facie case in support of its ap- Wood wrote: “While the bulk of the addi-
plication. If the utility presents a prima facie case, tional costs [Entergy] sought were not shown
the burden of going forward (burden of production) by the threshold evidentiary level to be pru-
shifts to the intervenors to rebut the presumption. dently incurred, some amounts were.”
Once that presumption is rebutted, the burden falls
on the utility to prove, by a preponderance of the that [Entergy] has, by the preponderance of evi-
evidence, that the challenged expenditures were dence, supported recovery of $2.273 billion as
prudent. Applying this reasoning to this case, the prudently incurred, but [Entergy] has not presented
Commission concludes that the burden of going a prima facie case supporting recovery of any
forward did not shift to the intervenors in this case amounts in excess of that figure. Stated conversely,
because [Entergy] failed to put on a prima facie case because [Entergy] failed to prove that any expenses
to support full recovery of the River Bend expend- in excess of the adjusted DCE were prudently in-
itures. curred, the Commission concludes that the $1.453
Tex. Pub. Util. Comm'n, Application of Gulf States billion in abeyed costs cannot be included in [En-
Utils. Co. for Authority to Change Rates, Remand of tergy's] rate base.
Docket 7195, Docket No. 17899, 1998 WL 971285 Id. Although the Commission's order on remand
(Mar. 15, 1998) (order on remand) (citations omit- uses language that is less than clear concerning the
ted). Although this paragraph conveys the fact that burden of proof and burden of production, we be-
the Commission held that Entergy had not presented lieve that the Commission not only ruled that En-
the requisite level of prudence to establish a prima tergy had not presented a prima facie case, but that
facie case, other language in its final order indicates the Commission reviewed the entire record and,
that the Commission believed that Entergy did not based on this review, held that Entergy failed to
meet its overall burden of proof. The Commission's satisfy its burden of proof under the utilities code.
final order continued, stating that “[e]ven taking See Tex. Util.Code Ann. § 36.006. The Commis-
into account the intervenors' direct cases and [En- sion's repeated references to the entire record sup-
tergy's] rebuttal, [Entergy] failed to present a prima ports this view. The following findings of fact and
facie case because ... [Entergy] could not explain conclusions of law included in the Commission's
why River Bend cost so much [.]” (Emphasis add- order indicate that the Commission held that En-
ed.) Moreover, the Commission opined that Entergy tergy failed to satisfy its burden of proof and *216
“simply did not meet its burden of proof to show that the Commission made a “straightforward deci-
that expenditures in excess of $2.273 billion were sion” based on the entire record:
prudently incurred.” FN6 The Commission's Final
Order indicates that it conducted a review of the [Finding of Fact] 152: The existence of identifiable
entire record because numerous findings of fact imprudence and inefficiency in the construction and
discuss evidence offered by Entergy's opponents to management of the plant as set forth in Findings of
rebut the proposed rate increase—an unnecessary Fact Nos. 133–145 corroborates the exclusion of a

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portion of River Bend's capital costs from decision.
plant-in-service.
Docket 17899's findings of fact and conclusions
[Finding of Fact] 164: The preponderance of the of law are almost identical to those found in the
evidence in this case establishes that $2.273 billion Commission's final order in Docket 7195, which
of River Bend capital costs were prudently and culminated in the supreme court's Coalition of Cities
reasonably incurred. The evidence is inadequate to decision. See Coalition of Cities, 798 S.W.2d at 562.
support a finding that construction costs in excess of Coalition of Cities is instructive. Although the su-
$2.273 billion were prudently and reasonably in- preme court held that the Commission could not defer
curred. its decision to disallow Entergy's rate increase, after
listing Findings 164 and 164A and Conclusions 18
[Finding of Fact] 164A: [Entergy's] share of all and 18A, the court noted that the Commission “found
River Bend capital costs in excess of $2.273 billion that [Entergy] had failed to prove that any expenses in
shall be excluded from plant in service. The amount excess of $2.273 billion were prudently incurred.” Id.
which should be included in plant in service, given Later, in Gulf States Utilities the supreme court clari-
[Entergy's] 70 percent share of the plant, is $1.5911 fied its holding in Coalition of Cities: “By saying that
billion. the PUC effectively disallowed the $1.453 billion we
did not suggest that the PUC actually made that deci-
sion.” Gulf States Utils., 947 S.W.2d at 889. We rec-
[Conclusion of Law] 18: $1,453,520,982 of [En-
ognize that the statements may be dicta; however, the
tergy's] share of end-of-test-year River Bend capital
court's interpretation of the language used in the
shall be excluded from [Entergy's] rate base as in-
Commission's findings and conclusions warrants
vested capital used and useful in rendering service
consideration. In Coalition of Cities, the supreme
to the public pursuant to PURA Sections 38, 39, and
court opined that the language found in Finding 164A,
41.
“lack of sufficient evidence,” “excluded from plant
service,” and “all capital costs in excess of $2.273
[Conclusion of Law] 18A: [Entergy] has not met its
billion,” demonstrated that the Commission believed
burden of proving that the capital costs of River
that Entergy had not met its burden of proof. Coalition
Bend above a reasonable Definitive Cost Estimate
of Cities, 798 S.W.2d at 563. The supreme court then
of $2.273 billion were reasonably and prudently
noted that “[a] party who fails to meet its burden of
incurred.
proof loses.” Id. (citing Gerst v. Goldsbury, 434
S.W.2d 665, 667 (Tex.1968) (agency determination
Tex. Pub. Util. Comm'n, Application of Gulf States that applicant offered “insufficient evidence of a pub-
Utils. Co. for Authority to Change Rates, Remand of lic *217 need for the proposed [savings] association”
Docket 7195, Docket No. 17899, 1998 WL 971285 constituted “negative finding”)).
(Mar. 15, 1998). These findings and conclusions
indicate that: (1) the Commission ruled not only on
In the present action, the Commission used iden-
Entergy's failure to establish a prima facie case for
tical language in Findings 164 and 164A and Conclu-
prudence, but also that the evidence actually
sions 18 and 18A, omitting only the limiting language
showed “imprudence and inefficiency,” and (2)
“at this time” in Docket 7195's Finding 164A. Use of
Entergy failed in its statutory burden of proof. See
this language indicates, as the Coalition of Cities
id. Moreover, the findings and conclusions clearly
opinion suggests, that the Commission intended to
indicate that Entergy received a straightforward
deny inclusion of the $1.453 billion in Entergy's rate

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112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

increase. Additional findings and conclusions in the curred—they simply track cost changes
Commission's Final Order in Docket 17899 echo that and indicate that someone in [Entergy]
the entire record was reviewed in its decision: approved these changes. More is required
of [Entergy] to meet its burden of proof.
[Finding of Fact] 121: The Incremental Estimate
File (IEF) was primarily a cost tracking and ac- [Finding of Fact] 127: The OKA [O'Bri-
counting tool and was not designed to provide jus- en–Kreitzberg & Assoc.] report, although more
tification of cost increases.FN7 thorough than the PLG report, reached no conclu-
sions as to imprudence during the construction of
FN7. The IEF program reflected all changes River Bend except as regards the 50–month sched-
to the original DCE and provided traceability ule.
for the reasons cited for the project changes.
[Finding of Fact] 129: Regulatory requirements
[Finding of Fact] 122: The fact that [Entergy] had a unforeseen in 1979 may have had an impact on the
legitimate process for reviewing and approving cost of River Bend, but neither [Entergy] or any
changes in project costs does not show that those other party provided adequate evidence as to any
costs were reasonable. such impact.

[Finding of Fact] 123: The guidelines for coding [Finding of Fact] 163: The statistical analyses pre-
changes to the regulatory category in the IEF lim- sented in this docket were inadequate to prove the
ited the informative value of the IEF. reasonableness or prudence of River Bend con-
struction costs.
[Finding of Fact] 124: The PLG [Pickard, Lowe,
and Garrick] Report's analysis of the reasons for [Conclusion of Law] 20: A mere showing that sta-
growth in the cost of River Bend was cursory and tistical adjustments to plant costs are unreliable or
inadequate.FN8 that plant costs are within the range suggested by
statistical confidence intervals is inadequate to meet
a utility's burden of proof under PURA Section 40.
FN8. Commenting on the Pickard, Lowe and
Garrick (“PLG”) report, the Commission
stated: Tex. Pub. Util. Comm'n, Application of Gulf States
Utils. Co. for Authority to Change Rates, Remand of
Docket 7195, Docket No. 17899, 1998 WL 971285
The [report] summarized the results of the
(Mar. 16, 1998). A review of the Commission's
IEF and was the “centerpiece of [Enter-
Final Order in Docket 17899 indicates that the
gy's] case on the prudence and efficiency
Commission ruled, after reviewing the entire record,
of the construction of River Bend.” On this
that Entergy had not satisfied its burden of proof or
point, the Commission does not question
established its prima facie case as to the prudence of
that [Entergy] spent $1.453 billion in ex-
the additional costs. Therefore, regardless of the
cess of its share of the adjusted DCE, and
Commission's specific language, we believe that
that those costs are reflected through the
Entergy received a “straightforward*218 decision”
IEF process. Cost tracking an monitoring
that the $1.453 billion would not be included in its
programs, however, do not support a
rate base. We overrule Entergy's second issue.
finding that such costs were prudently in-

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 Page 12

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

$2.273 billion in plant costs were reasonably and
Substantial–Evidence Review prudently incurred, resulting in the adjusted DCE. But
[10][11][12][13] By its third issue on appeal, the Commission held that the evidence did not support
Entergy contends that the Commission's decision is including any portion of the additional $1.453 billion
not supported by substantial evidence. To ascertain in Entergy's rate base, as these costs were not pru-
whether an agency's decision is supported by sub- dently incurred.
stantial evidence, we determine whether, in consid-
ering the record upon which the decision is based, “the Entergy makes several arguments regarding the
evidence as a whole is such that reasonable minds lack of substantial evidence: (1) the Commission's
could have reached the conclusion the agency must failure to find any prudent costs associated with the
have reached in order to take the disputed action.” City schedule extension; (2) the Commission's failure to
of El Paso v. Public Util. Comm'n, 883 S.W.2d 179, allow recovery of the full financing costs associated
186 (Tex.1994); Lone Star Salt Water Disposal Co. v. with the River Bend investment that it found prudent;
Railroad Comm'n, 800 S.W.2d 924, 928 (3) the disallowance is contrary to undisputed expert
(Tex.App.-Austin 1990, no writ). In making such testimony and has no reasonable basis in the record as
determination, the reviewing court may not substitute a whole; and (4) the record as a whole demonstrates
its judgment for the agency's and must consider only concurrence of the expert witnesses in the prudence of
the record upon which the decision is based. Tex. certain costs in excess of the adjusted DCE.
Gov't Code Ann. § 2001.174 (West 2000); Lone Star
Salt Water Disposal, 800 S.W.2d at 928. The evidence Entergy argues that the Commission's failure to
in the agency record may actually preponderate find any additional prudent costs associated with the
against the agency's decision, but still constitute sub- 72–month construction schedule is unsupported by
stantial evidence supporting it. Lone Star Salt Water substantial evidence. Entergy contends that the evi-
Disposal, 800 S.W.2d at 928. The burden is on the dence revealed that the 72–month schedule was short
complaining party to demonstrate an absence of sub- compared with other nuclear plants constructed at that
stantial evidence. Id. time, and that the Commission's own findings reject
the notion that River Bend experienced imprudent
Entergy must demonstrate that the evidence con- delays. However, the Commission's findings and
clusively established the prudence of the $1.453 bil- conclusions are to the contrary. Findings 71 through
lion expended. See Texas Health Facilities Comm'n v. 77 state that Entergy's pursuit of the original
Charter Medical–Dallas, Inc., 665 S.W.2d 446, 453 50–month schedule was based on “false assumptions,”
(Tex.1984). In determining whether Entergy's pro- “hastily conceived,” and “imprudent.”*219 Finding
posed rate increase was appropriate, the Commission 137 states that “[p]ursuit of the 50–month schedule
examined two issues: (1) whether the decision to re- reduced construction productivity.” Additionally, the
start and complete construction of River Bend was Examiners' Report concluded that “60 months [was] a
prudent, and (2) what portion of actual construction reasonable schedule for [Entergy] to have contem-
costs was reasonably and prudently incurred. In its plated at the time of the DCE.” The O'Bri-
initial order, the Commission determined that Enter- an–Kreitzberg report concluded that “the establish-
gy's decision to restart construction was prudent. En- ment of a 50–month schedule for the project in 1979
tergy appeals the Commission's decision that no costs was unreasonable and led to the expenditure of
above the adjusted DCE were prudently incurred. $45,777,000 ... [and that] it is recommended that this
However, the Commission also held that the original expenditure and the associated AFUDC [‘Allowance
DCE was too low and that the evidence showed that for Funds Used During Construction’] be disallowed.”

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 Page 13

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)
FN9
The $243 million in contingency costs was calculated
by adding the Commission adjustments to the original
FN9. AFUDC is a fixed percentage deter- DCE, subtracting sunken costs,FN11 then multiplying
mined by the Federal Energy Regulatory the resulting “to go costs” by fifteen percent ($1.729
Commission that compensates a utility for billion [original DCE] + $301 million [Commission
carrying the costs of construction. Cities for adjustments]—$412 million [sunken costs] x 15%
Fair Util. Rates v. Public Util. Comm'n, 924 [Commission added contingency] = $243 million). To
S.W.2d 933, 935–36 (Tex.1996). Once the the extent that the equation's factors included
utility plant is operational, AFUDC is shifted AFUDC, the resulting $243 million also included
to the utility's rate base, and the utility begins AFUDC; however, where Entergy's expert testimony
to earn a return on its investment. Id. at 936. failed to indicate whether the adjustments for safety
and Three Mile Island backfits ($100 million) and
omissions ($18 million) included AFUDC, the Com-
Regarding Entergy's expenses that the Commis-
mission's added contingency of fifteen percent cor-
sion should have found as prudently incurred above
rectly excluded AFUDC.
the original DCE, Entergy argues that the Commission
did not add an amount for AFUDC. Entergy contends
that twenty-three percent of $361 million should have FN10. The PLG report described “Three
been included as AFUDC, as this is the percentage of Mile Island backfits” as required because of
AFUDC allowed in the original DCE. The Commis- the 1979 accident at the Three Mile Island
sion responds that the additional sums added to the nuclear plant in Pennsylvania. The require-
original DCE include AFUDC or that Entergy did not ments included additional plant-monitoring
present evidence to support adding AFUDC. Initially, instrumentation and control-room modifica-
we observe that Finding 19 states the original DCE tions.
included AFUDC, while Finding 22 states that the
total cost of River Bend ($4.5 billion) included FN11. “Sunken costs” are “cost[s] that
AFUDC. The Commission's adjustments to the orig- [have] already been incurred and that cannot
inal DCE were as follows: (1) schedule increase 50 to be recovered.” Black's Law Dictionary 350
60 months = $183 million; (2) safety and Three Mile (7th ed.1999).
Island backfits FN10 = $100 million; (3) omissions =
$18 million; and (4) contingency = $243 million. The *220 [14] Entergy complains that the Commis-
amount for the schedule increase included AFUDC, sion disregarded expert testimony and that the record
however, Entergy argues that the other adjustments as a whole demonstrates the prudence of costs in ex-
did not, and this $361 million, multiplied by twen- cess of the adjusted DCE. We disagree. It is for the
ty-three percent, equals an additional $83 million that agency to accept or reject witnesses' testimony, and
the Commission should have added to the adjusted the agency, not the reviewing court, is the judge of the
DCE as AFUDC. Regarding the $100 million for weight accorded that testimony. Southern Union Gas
regulatory issues and the $18 million for omissions, Co. v. Railroad Comm'n, 692 S.W.2d 137, 141
these costs were presented to the Commission by (Tex.App.-Austin 1985, writ ref'd n.r.e.). The Com-
Entergy's experts, who did not indicate whether these mission had ample evidence before it on which to base
costs included AFUDC. As the Commission argues, it its decision disallowing the costs in excess of $2.273
was Entergy's burden to show whether its figures billion.
included AFUDC, and absent such testimony, the
Commission was not required to account for AFUDC.

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 Page 14

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

Entergy's argument that all experts and all parties that the parties were demanding proof to reconcile
agreed that there were prudent costs above the ad- Entergy's cost overruns to its definitive estimate ...
justed DCE is without merit and is the same argument [y]et the record shows that [Entergy] refused to pro-
it presented to this Court in Coalition of Cities, 883 vide such evidence.”
S.W.2d at 752. Entergy had the burden to prove pru-
dence and could not shift that burden to those chal- FN12. Entergy directs this Court to the
lenging its requested rate increase. Tex. Util.Code Commission's decision in Application of
Ann. § 36.006 (utility bears burden to show prudence Texas Utilities Electric Co. for Authority to
of expenditures); see also Coalition of Cities, 798 Change Rates to support its argument that the
S.W.2d at 563 (utility enjoys no presumption that its cost-reconciliation study was not required;
expenditures were prudently incurred); Houston the Commission responds that Entergy's ac-
Lighting & Power, 778 S.W.2d at 198 (to raise rates, tion is factually distinguishable. See Tex.
utility must bear burden of proving that each dollar of Pub. Util. Comm'n, Application of Tex. Utils.
cost incurred was reasonably and prudently invested). Elec. Co. for Authority to Change Rates,
The Commission determined that the $1.453 billion Docket No. 9300, 17 Tex. P.U.C. Bull. 2057
above the adjusted DCE was not reasonably and pru- (September 27, 1991).
dently incurred and should not be included in Enter-
gy's rate base. If there is any evidence supporting
The Commission's findings of fact and conclu-
either an affirmative or a negative finding, we must
sions of law clearly indicate that Entergy did not meet
uphold the agency decision. Charter Medical–Dallas,
its burden of proof or make a prima facie case as to the
665 S.W.2d at 453.
prudence of the $1.453 billion. Moreover, the Com-
mission's order finds that “[t]he record ... is fully de-
The evidence is such that reasonable minds could veloped.” Entergy, before the decision in Docket
have reached the same conclusion as the Commission. 17899, supported the Commission's decision not to
Because there is substantial evidence to support the take additional evidence and did not submit its
Commission's decision, we overrule Entergy's third cost-reconciliation study. Moreover, Entergy had been
issue. afforded earlier opportunities to submit additional
evidence *221 to the Commission, but declined to do
The Cost–Reconciliation Study so. Entergy's argument that a later Commission deci-
[15] By its fourth issue, Entergy argues that the sion rendered the cost-reconciliation study unneces-
Commission erred by making arbitrary, after-the-fact sary obscures the fact that Entergy had ample oppor-
changes to the standards governing its prudence tunity to fully develop the record. The fact remains
analysis. Specifically, Entergy argues that the Com- that Entergy, after a review of the entire record, did
mission ruled in an earlier decision that a not meet the required burden of proof. We overrule
cost-reconciliation study was not a necessary element Entergy's fourth issue.
of a prima facie case; therefore, Entergy did not op-
pose the Commission's decision not to accept the “Flow Through” Adjustments
cost-reconciliation study as evidence in Docket By its fifth issue, Entergy posits that the Com-
17899.FN12 The Commission's order indicates that mission erred by making certain rate adjustments that
Entergy failed to “present any credible reconciliation were the product of its erroneous treatment of the plant
of plant costs with specific causes,” which Entergy investment and that a decision of this Court to order
insists it could have offered in its cost-reconciliation the Commission to determine again the prudence of
study. The Commission rejoins that Entergy “knew River Bend's cost would necessarily require a recal-

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 Page 15

112 S.W.3d 208, Util. L. Rep. P 26,862
(Cite as: 112 S.W.3d 208)

culation of these “flow through” costs. Specifically,
Entergy argues that the erroneous rate adjustments
include Entergy's payments to repurchase River Bend
from its project partner, Cajun Electric Power Coop-
erative (“Cajun”), and that the Commission denied
recovery of Entergy's payments to Cajun in proportion
to the amount of River Bend investment to which it
denied recovery. Additionally, Entergy argues that the
level of recovery of River Bend deferred costs, a cap-
ital investment item, is limited by and tied to the
amount of River Bend recovery. Because we affirm
the Commission's decision that any costs above the
adjusted DCE were imprudent, a recalculation of the
“flow through” costs is unnecessary. We overrule
Entergy's fifth issue.

CONCLUSION
We affirm the district court's judgment affirming
the Commission's decision excluding the additional
$1.453 billion from Entergy's rate base.

Tex.App.–Austin,2003.
Entergy Gulf States, Inc. v. Public Utility Com'n of
Texas
112 S.W.3d 208, Util. L. Rep. P 26,862

END OF DOCUMENT

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Appendix E

Texas Utilities Electric Company v. Public Utility
Commission, 881 S.W.2d 387 (Tex. App. – Austin
1994) aff’d in part, rev’d in part on other grounds, 935
S.W.2d 109 (Tex. 1997)
 Page 1

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

15A Administrative Law and Procedure
15AIV Powers and Proceedings of Administrative
Agencies, Officers and Agents
Court of Appeals of Texas,
15AIV(A) In General
Austin.
15Ak314 k. Bias, prejudice or other disqualifi-
cation to exercise powers. Most Cited Cases
TEXAS UTILITIES ELECTRIC COMPANY, Public
Utility Commission, Office of Public Utility Counsel, and
Adjudicators involved in administrative proceedings
Cities of Arlington, et al., Appellants,
are presumed to be honest and act with integrity but pre-
v.
sumption may be overcome by demonstrating that decision
PUBLIC UTILITY COMMISSION, Texas Utilities Elec-
maker's mind was irrevocably closed on matters at issue.
tric Company, Office of Public Utility Counsel, and Cities
of Arlington, et al., Appellees.
[2] Electricity 145 11.3(6)
No. 3–92–548–CV.
June 15, 1994. 145 Electricity
Rehearings Overruled Aug. 31 and Oct. 12, 1994. 145k11.3 Regulation of Charges
145k11.3(6) k. Proceedings before commissions.
Final order by Public Utility Commission in electric Most Cited Cases
rate case conducted under Public Utility Regulatory Act
(PURA) was reversed and remanded in part when re- Public Utility Commission chairperson's pecuniary
viewed by the 250th Judicial District Court, Travis County, interest in natural gas industry did not invalidate Com-
John K. Dietz, J. Appeals were taken. The Court of Ap- mission's decision in electric rate case which decided
peals, Bea Ann Smith, J., held that: (1) commissioner's whether costs of nuclear power plant construction should
financial interest in gas industry was not prejudicial; (2) be included in utilities' rate base costs; chairperson's pe-
Commission lacked authority to review costs associated cuniary interest was not shown to have deprived parties of
with reacquiring minority interests in nuclear power plant; impartial and fair hearing. V.T.C.A., Government Code §
(3) using hypothetical tax method was error; (4) Commis- 2001.174; Vernon's Ann.Texas Civ.St. art. 1446c, § 1 et
sion had authority to allow utility to implement bonded seq.
rates; (5) disallowing some revalidation expenses for nu-
clear power plant as imprudent was not error; and (6) set- [3] Administrative Law and Procedure 15A 314
ting rate of return on common equity at 13.2% was within
Commission's discretion. 15A Administrative Law and Procedure
15AIV Powers and Proceedings of Administrative
Reversed and remanded with instructions. Agencies, Officers and Agents
15AIV(A) In General
West Headnotes 15Ak314 k. Bias, prejudice or other disqualifi-
cation to exercise powers. Most Cited Cases
[1] Administrative Law and Procedure 15A 314
Administrative officer is not disqualified simply be-

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Page 2

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

cause officer has previously taken position, even in public, [6] Administrative Law and Procedure 15A 431
on policy issue related to particular dispute absent showing
of incapability to decide particular controversy fairly. 15A Administrative Law and Procedure
V.T.C.A., Government Code § 2001.174. 15AIV Powers and Proceedings of Administrative
Agencies, Officers and Agents
[4] Administrative Law and Procedure 15A 305 15AIV(C) Rules, Regulations, and Other Policy-
making
15A Administrative Law and Procedure 15Ak428 Administrative Construction of Stat-
15AIV Powers and Proceedings of Administrative utes
Agencies, Officers and Agents 15Ak431 k. Deference to agency in general.
15AIV(A) In General Most Cited Cases
15Ak303 Powers in General (Formerly 361k219(1))
15Ak305 k. Statutory basis and limitation.
Most Cited Cases Reviewing court has power and duty to consider
agency's interpretation and application of statute.
Administrative Law and Procedure 15A 325
[7] Electricity 145 11.3(7)
15A Administrative Law and Procedure
15AIV Powers and Proceedings of Administrative 145 Electricity
Agencies, Officers and Agents 145k11.3 Regulation of Charges
15AIV(A) In General 145k11.3(7) k. Judicial review and enforcement.
15Ak325 k. Implied powers. Most Cited Cases Most Cited Cases

Administrative agencies have only those powers that Section of Public Utility Regulatory Act (PURA) au-
are expressly conferred by statute, together with those thorizing Public Utility Commission to review changes in
necessarily implied from authority conferred or duties public utility ownership did not apply to electric utility's
imposed. repurchase of minority joint ownership interests in nuclear
power plant given that ownership of plant did not change
[5] Administrative Law and Procedure 15A 447.1 hands as result of repurchase; utility's decision to purchase
minority interest was limited to review under prudent
investment standard. Vernon's Ann.Texas Civ.St. art.
15A Administrative Law and Procedure
1446c, § 63.
15AIV Powers and Proceedings of Administrative
Agencies, Officers and Agents
15AIV(D) Hearings and Adjudications [8] Electricity 145 11.3(4)
15Ak447 Jurisdiction
15Ak447.1 k. In general. Most Cited Cases 145 Electricity
145k11.3 Regulation of Charges
Jurisdiction cannot be conferred upon administrative 145k11.3(4) k. Operating expenses. Most Cited
agencies by parties before it, but rather must emanate from Cases
statute itself.
Public Utility Commission erred in electric rate case

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Page 3

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

by calculating utility's federal income tax liability using If utility enjoys tax deduction based on interest ex-
hypothetical rather than actual-tax method; utility's rates pense, benefits of deduction must be passed on to rate-
must reflect tax liability actually incurred. Vernon's payers, rather than to shareholders. Vernon's Ann.Texas
Ann.Texas Civ.St. art. 1446c, § 1 et seq. Civ.St. art. 1446c, § 41(c)(2).

[9] Electricity 145 11.3(4) [12] Electricity 145 11.3(4)

145 Electricity 145 Electricity
145k11.3 Regulation of Charges 145k11.3 Regulation of Charges
145k11.3(4) k. Operating expenses. Most Cited 145k11.3(4) k. Operating expenses. Most Cited
Cases Cases

Electric rates must be set based on utility's actual tax Allocation of tax benefits to electric utility from in-
liability and, thus, utility's tax expense will be adjusted to terest expense and deduction between present and future
reflect tax savings which would result from filing consol- ratepayers is matter within Public Utility Commission's
idated tax return, regardless of whether utility did in fact discretion. Vernon's Ann.Texas Civ.St. art. 1446c, §
file consolidated return. Vernon's Ann.Texas Civ.St. art. 41(c)(2).
1446c, § 41(c)(2).
[13] Electricity 145 11.3(4)
[10] Electricity 145 11.3(4)
145 Electricity
145 Electricity 145k11.3 Regulation of Charges
145k11.3 Regulation of Charges 145k11.3(4) k. Operating expenses. Most Cited
145k11.3(4) k. Operating expenses. Most Cited Cases
Cases
Electric utility's income tax expense must be reduced
The Public Utility Commission's refusal to allocate to by amount of tax deductions, even if associated with dis-
electric utility tax savings resulting from affiliate's losses allowed capital expenses. Vernon's Ann.Texas Civ.St. art.
violated actual-tax doctrine, requiring that rates be based 1446c, § 1 et seq.
on utility's actual tax liability, even if utility did not bear
risks associated with tax savings attributed to affiliates. [14] Public Utilities 317A 119.1
Vernon's Ann.Texas Civ.St. art. 1446c, § 41(c)(2).
317A Public Utilities
[11] Public Utilities 317A 128 317AII Regulation
317Ak119 Regulation of Charges
317A Public Utilities 317Ak119.1 k. In general. Most Cited Cases
317AII Regulation
317Ak119 Regulation of Charges Utility may implement bonded rates in municipal ar-
317Ak128 k. Operating expenses. Most Cited eas when underlying rate increase is subject to appellate
Cases jurisdiction of Public Utility Commission. Vernon's
Ann.Texas Civ.St. art. 1446c, § 43(e).

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Page 4

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

In conducting substantial evidence review, court must
[15] Administrative Law and Procedure 15A determine whether evidence as whole is such that reason-
438(26) able minds could have reached conclusion agency must
have reached in order to take disputed action.
15A Administrative Law and Procedure
15AIV Powers and Proceedings of Administrative [17] Administrative Law and Procedure 15A 793
Agencies, Officers and Agents
15AIV(C) Rules, Regulations, and Other Policy- 15A Administrative Law and Procedure
making 15AV Judicial Review of Administrative Decisions
15Ak428 Administrative Construction of Stat- 15AV(E) Particular Questions, Review of
utes 15Ak784 Fact Questions
15Ak438 Particular Statutes and Contexts 15Ak793 k. Weight of evidence. Most Cited
15Ak438(26) k. Carriers and public utili- Cases
ties. Most Cited Cases
(Formerly 361k219(9.1)) Reviewing court may not substitute its judgment for
that of agency and must consider only record on which
Public Utilities 317A 194 agency based its decision while conducting substantial
evidence review.
317A Public Utilities
317AIII Public Service Commissions or Boards [18] Administrative Law and Procedure 15A 750
317AIII(C) Judicial Review or Intervention
317Ak188 Appeal from Orders of Commission 15A Administrative Law and Procedure
317Ak194 k. Review and determination in 15AV Judicial Review of Administrative Decisions
general. Most Cited Cases 15AV(D) Scope of Review in General
(Formerly 361k219(9.1)) 15Ak750 k. Burden of showing error. Most
Cited Cases
Public Utility Commission's interpretation of Public
Utility Regulatory Act (PURA) is entitled to great weight, Party bringing appeal bears burden of showing that
provided that interpretation is reasonable and does not decision by administrative agency lacks substantial evi-
contradict plain language of statute. Vernon's Ann.Texas dence.
Civ.St. art. 1446c, § 1 et seq.

[19] Administrative Law and Procedure 15A 791
[16] Administrative Law and Procedure 15A 791
15A Administrative Law and Procedure
15A Administrative Law and Procedure 15AV Judicial Review of Administrative Decisions
15AV Judicial Review of Administrative Decisions 15AV(E) Particular Questions, Review of
15AV(E) Particular Questions, Review of 15Ak784 Fact Questions
15Ak784 Fact Questions 15Ak791 k. Substantial evidence. Most Cited
15Ak791 k. Substantial evidence. Most Cited Cases
Cases
Agency's order must be upheld despite substantial

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Page 5

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

evidence challenge, if evidence would support either af-
firmative or negative findings. 145 Electricity
145k11.3 Regulation of Charges
[20] Electricity 145 11.3(6) 145k11.3(6) k. Proceedings before commissions.
Most Cited Cases
145 Electricity
145k11.3 Regulation of Charges Underlying findings supported finding of fact by
145k11.3(6) k. Proceedings before commissions. Public Utility Commission that some but not all costs of
Most Cited Cases complying with increased inspection standards and pro-
cedures during construction of nuclear power plant were
Substantial evidence supported decision by Public caused by imprudence, warranting exclusion from rate
Utility Commission that electric utility's imprudence base. V.T.C.A., Government Code § 2001.141(d).
caused some but not all of increased costs incurred by
revalidation and reinspection program during construction [23] Public Utilities 317A 194
of nuclear power plant; costs to respond to concerns by
federal Nuclear Regulatory Commission were necessitated 317A Public Utilities
in part because of utility imprudence and in part because of 317AIII Public Service Commissions or Boards
higher safety and inspection standards. Vernon's 317AIII(C) Judicial Review or Intervention
Ann.Texas Civ.St. art. 1446c, §§ 39, 41. 317Ak188 Appeal from Orders of Commission
317Ak194 k. Review and determination in
[21] Public Utilities 317A 124 general. Most Cited Cases

317A Public Utilities Reviewing court is bound by determinations of Public
317AII Regulation Utility Commission as to weight and credibility of evi-
317Ak119 Regulation of Charges dence as long as there is substantial evidence in record
317Ak124 k. Value of property; rate base. Most supporting Commission's decision.
Cited Cases
[24] Electricity 145 11.3(6)
Public Utilities 317A 168
145 Electricity
317A Public Utilities 145k11.3 Regulation of Charges
317AIII Public Service Commissions or Boards 145k11.3(6) k. Proceedings before commissions.
317AIII(B) Proceedings Before Commissions Most Cited Cases
317Ak168 k. Findings. Most Cited Cases
Public Utilities 317A 164
Determination that expenditure is imprudent carries
legal consequence of its exclusion from rate base and must 317A Public Utilities
be supported by underlying findings. V.T.C.A., Govern- 317AIII Public Service Commissions or Boards
ment Code § 2001.141(d). 317AIII(B) Proceedings Before Commissions
317Ak164 k. Pleading. Most Cited Cases
[22] Electricity 145 11.3(6)

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 Page 6

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

Utility's conditional request to include construction 145k11.3(4) k. Operating expenses. Most Cited
work in progress costs (CWIP) in rate base if proposed rate Cases
increase were materially disallowed provided adequate
notice of utility's intent to seek inclusion of CWIP in rate Natural gas purchase contract which set upper limit on
base in rate-making proceeding. Vernon's Ann.Texas electric utility's right to purchase gas at contract price did
Civ.St. art. 1446c, §§ 39(a), 41(a). not obligate utility to purchase gas under contract and,
thus, supported determination by Public Utility Commis-
[25] Electricity 145 11.3(4) sion in rate case that utility violated its obligation to pur-
chase fuel at lowest reasonable cost to ratepayers. Vernon's
145 Electricity Ann.Texas Civ.St. art. 1446c, § 41(c)(1).
145k11.3 Regulation of Charges
145k11.3(4) k. Operating expenses. Most Cited [28] Electricity 145 11.3(4)
Cases
145 Electricity
Public Utility Commission may either make contract 145k11.3 Regulation of Charges
by contract determination of reasonableness of contracts 145k11.3(4) k. Operating expenses. Most Cited
for purchase of alternate energy sources or group contracts Cases
together and declare them all to be reasonable when rec-
onciling fuel costs as part of rate case. Vernon's Ann.Texas Limiting electric utility's fuel inventory level based on
Civ.St. art. 1446c, § 41(c)(1). utility's actual experience over several years was not arbi-
trary and capricious, despite utility's request in rate case for
[26] Electricity 145 11.3(4) increased fuel inventory level. V.T.C.A., Government
Code § 2001.174(2)(E, F).
145 Electricity
145k11.3 Regulation of Charges [29] Administrative Law and Procedure 15A 753
145k11.3(4) k. Operating expenses. Most Cited
Cases 15A Administrative Law and Procedure
15AV Judicial Review of Administrative Decisions
Disallowing excessive price for natural gas as alter- 15AV(D) Scope of Review in General
native fuel by electric utility, during rate case, was sup- 15Ak753 k. Theory and grounds of administra-
ported by utility's accounting records indicating that pur- tive decision. Most Cited Cases
chase was made pursuant to spot contract with unreason-
ably high price, despite utility's later contention that pur- Mental processes of individual administrators are
chase was made part of separate short-term commercial immaterial to judicial review of agency order; order is
contract for which purchase price would be reasonable. reviewed in light of record on which it purports to rest.
Vernon's Ann.Texas Civ.St. art. 1446c, § 41(c)(1).

[30] Electricity 145 11.3(5)
[27] Electricity 145 11.3(4)
145 Electricity
145 Electricity 145k11.3 Regulation of Charges
145k11.3 Regulation of Charges 145k11.3(5) k. Reasonableness of charges. Most

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Page 7

881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

Cited Cases Cities of Arlington, et al.

Public Utility Commission has discretion in electric David C. Duggins, Clark Thomas & Winters, Austin, for
rate case to decide whether imprudence by utility's man- Texas Utilities Elec. Co.
agement warrants reduction in overall rate of return on
common equity. Vernon's Ann.Texas Civ.St. art. 1446c, § Before CARROLL, C.J., and ABOUSSIE and B.A.
39(a). SMITH, JJ.

[31] Electricity 145 11.3(5) BEA ANN SMITH, Justice.
Texas Utilities Electric Company, the Public Utility
145 Electricity Commission, the Office of Public Utility Counsel, and the
145k11.3 Regulation of Charges Cities of Arlington, et al. appeal from a district-court
145k11.3(5) k. Reasonableness of charges. Most judgment rendered in a suit for judicial review of the
Cited Cases Commission's final order in an electric utility rate case
conducted under the Public Utility Regulatory Act (PU-
Setting electric utility's return on common equity at RA), Tex.Rev.Civ.Stat.Ann. art. 1446c (West
13.2% in rate case was not abuse of discretion. Vernon's Supp.1994).FN1 The district-court judgment reverses and
Ann.Texas Civ.St. art. 1446c, § 39(b). remands certain aspects of the Commission's final order,
and affirms the remainder. We will reverse the dis-
trict-court judgment and remand the cause to the district
*389 Roy Q. Minton, Minton Burton Foster & Collins,
court with instructions that the cause be remanded to the
Austin, for Texas Utilities Elec. Co.
Commission for further proceedings consistent with our
opinion. See Administrative Procedure Act (APA), Tex.
Dan Morales, Atty. Gen., Susan Bergen, Asst. Atty. Gen., Gov't Code Ann. § 2001.174 (West 1994).FN2
Austin, for Public Utility Com'n.

FN1. Cities of Arlington, et al. includes the mu-
Stephen Fogel, Austin, for Office of Public Utility Coun- nicipalities of Addison, Allen, Azle, Belton,
sel. Breckenridge, Bridgeport, Burkburnett, Burleson,
Carrollton, Celina, Centerville, Cleburne, Col-
*390 Geoffrey M. Gay, Buter Porter Gay & Day, Austin, leyville, Copperas Cove, Corinth, Crowley,
for Cities of Arlington, et al. Dalworthington Gardens, De Leon, Denison,
Euless, Farmers Branch, Forest Hill, Fort Worth,
David C. Duggins, Clark Thomas & Winters, Austin, for Glen Heights, Grand Prairie, Granger, Hewitt,
Texas Utilities Elec. Co. Howe, Hurst, Irving, Keller, Lindale, Luella,
McKinney, Milford, Murchison, New Chapel
Dan Morales, Atty. Gen., Steven Baron, Asst. Atty. Gen., Hill, Ovilla, Pantego, Plano, Ranger, Richardson,
Austin, for Public Utility Com'n. Roanoke, Rockwall, Rosser, Rowlett, Sherman,
Sunnyvale, The Colony, Tyler, University Park,
Venus, Waco, White Settlement, and Wichita
Yolanda L. Woods, Asst. Public Counsel, Austin, for Of-
Falls. In addition to bringing individual appeals,
fice of Public Utility Counsel.
each of the appellants is also an appellee with
respect to certain parts of the district-court
Steven A. Porter, Butler Porter Gay & Day, Austin, for

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judgment. prejudiced in favor of the gas industry. The allegations of
impermissible bias center around Meek's ties with Amer-
FN2. All citations in this opinion are to the cur- ican *391 Petrofina (“Fina”). During the rate-making
rent Administrative Procedure Act rather than the proceedings, Meek served as chairman of Fina's board,
former Administrative Procedure and Texas received retirement benefits from Fina, and held shares of
Register Act because the recent recodification did its publicly traded common stock. Fina's direct sales of
not substantively change the law. Act of May 4, natural gas to Texas Utilities from 1989 to 1991 totalled
1993, 73d Leg., R.S., ch. 268, § 47, 1993 $60,782; indirect revenue from sales to other Texas Utili-
Tex.Gen.Laws 583, 986. ties suppliers approximated $104 million. Because of his
connections with Fina, the Cities and Public Utility
Counsel claim that Meek's participation in the hearings
THE CONTROVERSY
precluded the Commission from making impartial find-
Texas Utilities filed its application for a rate increase
ings. The district court found the evidence insufficient to
in January 1990 seeking to include in its rate base costs
show that Meek's service on the Commission led to unfair
associated with Comanche Peak, a newly constructed
proceedings or prejudiced substantial rights of the parties.
nuclear power plant. The utility sought an agency adjudi-
We agree.
cation regarding what portion of its costs it could include in
its rate base as being a “prudent” investment, public in-
terest findings on its reacquisition of a 12.2 percent own- PURA provides that no commissioner may, during a
ership interest in the plant, final reconciliation of its fuel period of service with the Commission, “have any pecu-
costs and revenues for the period April 1983 to June 1989, niary interest ... in any person or corporation or other
and a reduction of its fuel factor for the period May 1990 to business entity a significant portion of whose business
April 1991. After the Commission issued its order, motions consists of furnishing goods or services to public utilities
for rehearing were filed and the Commission issued a or affiliated interests....” PURA § 6(b)(1). It is grounds for
second order on rehearing. Subsequent motions for re- removal from the Commission if a member has interests in
hearing were overruled by operation of law, and five par- violation of section 6(b) at the time of his or her appoint-
ties to the rate-making proceeding filed suit for judicial ment. PURA § 6A. However, “the validity of an action of
review in district court. See PURA § 69; APA § 2001.171. the commission is not affected by the fact that it was taken
The district court affirmed the Commission order in part when a ground for removal of a member of the commission
and reversed it in part, after which Texas Utilities, Public existed.” PURA § 6A(b). Meek resigned from the Com-
Utility Counsel, the Cities, and the Commission each ap- mission effective April 20, 1992, after the Attorney Gen-
pealed the district-court judgment.FN3 For clarity, we will eral requested that he either sever all ties with Fina or
provide additional facts germane to the various points of resign from the Commission. Although Meek was not
error throughout the opinion. removed from the Commission because of a conflict of
interest pursuant to PURA section 6A, he did resign in the
face of a perceived conflict. Meek's conflict, however, has
FN3. With one exception, the Cities and Public
no effect on the Commission's order in Docket 9300.
Utility Counsel jointly raised their points of error.
PURA § 6A(b). This Court is left, therefore, with the
power to reverse and remand the Commission's order only
CONFLICT OF INTEREST
if Meek's participation resulted in an order that prejudices
In their first point of error, the Cities and Public Utility
substantial rights of the appellants. See APA § 2001.174.
Counsel argue that the chairman of the Commission, Paul FN4
We understand appellants to contend that this Court
Meek, was biased because he had a pecuniary interest in
should reverse the Commission's order because Meek's
the outcome of the proceedings, and because he was
interests in Fina resulted in an order that is arbitrary and

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capricious and a violation of their constitutional right to a (2) finding of fact 379 relating to the reasona-
fair and impartial hearing. bleness of Texas Utilities' fuel expenditures dur-
ing the reconciliation period insofar as such ex-
FN4. APA section 2001.174 directs this Court to penditures relate to gas contracts between the
reverse and remand a cause for further proceed- utility and Fina, and (3) finding of fact 389 re-
ings only if substantial rights of the appellant lating to the reasonableness of Texas Utilities'
have been prejudiced because the administrative fuel oil expenditures during the reconciliation
findings, inferences, conclusions, or decisions period.
are: (1) in violation of a constitutional or statutory
provision, (2) in excess of the agency's statutory *392 [3] It is well established that absent a showing of
authority, (3) made through unlawful procedure, incapability to decide a particular controversy fairly, an
(4) affected by error of law, (5) not reasonably administrative officer is not disqualified simply because he
supported by substantial evidence, or (6) arbitrary or she has previously taken a position, even in public, on a
or capricious or characterized by abuse of discre- policy issue related to a particular dispute. Morgan, 313
tion or clearly unwarranted exercise of discretion. U.S. at 421, 61 S.Ct. at 1004. In Morgan, the Supreme
Court held that the Secretary of Agriculture's strong views
[1][2] In order to prevail, appellants must overcome on a particular issue did not make him unfit to exercise his
the presumption that agency members are persons of duties in administrative proceedings relating to those
conscience and intellectual discipline, capable of judging a matters. Id. Similarly, in Cement Institute the Court held
particular controversy fairly on the basis of its own cir- that members of the Federal Trade Commission were not
cumstances. United States v. Morgan, 313 U.S. 409, 421, disqualified from participating in adjudicatory proceedings
61 S.Ct. 999, 1004, 85 L.Ed. 1429 (1941). Following the simply because they had previously expressed their opin-
United States Supreme Court, we recognize a presumption ions that a pricing system at issue in the proceeding was
of honesty and integrity in those serving as adjudicators. illegal. Cement Institute, 333 U.S. at 700–01, 68 S.Ct. at
Withrow v. Larkin, 421 U.S. 35, 47, 95 S.Ct. 1456, 1464, 803–04.
43 L.Ed.2d 712 (1975). One may overcome this presump-
tion by demonstrating that the decisionmaker's mind is In this appeal, the Cities and Public Utility Counsel
“irrevocably closed” on the matters at issue. Federal Trade question Meek's impartiality because of a newspaper in-
Comm'n v. Cement Inst., 333 U.S. 683, 701, 68 S.Ct. 793, terview in which he expressed his disappointment with the
803–04, 92 L.Ed. 1010 (1948). During confirmation Commission's decision to disallow $1.3 billion of Co-
hearings conducted in May 1990, the Texas Senate fully manche Peak costs. The Supreme Court has decided,
explored the issue of Meek's conflict. At that time, aware however, that public criticism “is a practice familiar in the
of Meek's connections with Fina, the Senate satisfied itself long history of ... litigation,” and that while an adminis-
that Meek could execute his duties as commissioner im- trator may have an underlying philosophy in approaching a
partially and without prejudice in favor of the gas industry. specific case, he or she may still be assumed to be a person
Additionally, Meek promised to recuse himself from vot- of conscience and intellectual discipline, capable of judg-
ing on any contested issue regarding contracts between ing a particular controversy fairly. Morgan, 313 U.S. at
public utilities and Fina, a promise he upheld by not re- 421, 61 S.Ct. at 1004.
viewing contracts between Texas Utilities and Fina.FN5
The Cities and Public Utility Counsel argue that this
FN5. Meek recused himself from voting on three order should be invalidated, relying on American Cyana-
issues: (1) finding of fact 172 relating to the rea- mid Co. v. Federal Trade Commission, 363 F.2d 757 (6th
sonableness of Texas Utilities' fuel oil inventory, Cir.1966). In American Cyanamid, the court invalidated a

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commission order because one of the commissioners had sale of fifty percent or more of a public utility's stock.FN6
previously served as counsel for a Senate subcommittee When any one of these transactions takes place, the utility
investigating many of the same facts and issues that later *393 must file a report with the Commission, which then
came before the commission. The court found that the investigates the transaction to determine whether it is in the
commissioner's dual investigative and adjudicative expe- public interest. In making this determination, the Com-
riences with the issues involved in the hearing created a mission is to consider the reasonable value of the property,
risk that commission decisions might be based on evidence facilities or securities involved. If the Commission finds
outside the record. It was the presentation of nonrecord that the transaction was not in the public interest, it must
evidence, not the commissioner's personal viewpoints, that “disallow the effect of such transaction if it will unrea-
led the court to invalidate the order. American Cyanamid, sonably affect rates or service.” PURA § 63.
363 F.2d at 767. In this case, however, appellants base their
request for invalidation of the order on assertions that FN6. Section 63 expressly provides that it shall
Meek's personal views about the gas industry made it im- not be construed as applying to the purchase of
possible for him to decide the issues fairly. Under the units of property for replacement or to additions
circumstances of this proceeding, we cannot agree. to the public utility's facilities by construction.

We do not express any opinion regarding whether In reviewing the costs associated with the construction
Meek should have been removed from the Commission of Comanche Peak, the Commission exercised its authority
had he not resigned. This Court is limited to the judicial under section 63 to make a disallowance of $908,688,938.
review enumerated in APA section 2001.174. We conclude The Commission asserted that it had jurisdiction to make
that Meek's involvement with Fina and his opinions about disallowances pursuant to section 63 because Texas Utili-
the gas industry have not been shown by the complaining ties' repurchase of certain minority interests in the Co-
parties to have resulted in a deprivation of the right to an manche Peak project constituted the purchase of a plant or
impartial and fair hearing before the Commission, nor has unit as an operating system for consideration in excess of
it been shown that he exhibited bias such that his votes $100,000. Texas Utilities' second motion for rehearing
were necessarily arbitrary and capricious. The Cities and filed with the Commission included an assignment of error
Public Utility Counsel's first point of error is overruled. stating:

REACQUISITION OF MINORITY INTERESTS The Commission erred in concluding that PURA § 63
All appellants bring points of error related to the dis- controls this Commission's review of [Texas Utilities']
trict court's disposition of the Commission order disal- reacquisition of minority owner interests in Comanche
lowing more than $908 million spent to repurchase 12.2 Peak, for the reason that, as a matter of law, PURA § 63
percent of Comanche Peak from minority interest owners does not apply to the transfer between joint owners of
and to settle litigation arising from the joint ownership of partial, undivided interests in a plant and does not apply
the project. Section 63 of PURA permits the Commission to a plant under construction that is not operating.
to disallow certain expenses associated with transactions
involving changes in public utility ownership. The Com-
When this second motion for rehearing was overruled
mission's authority to make disallowances under section 63
by operation of law, Texas Utilities sought review in the
is limited to three specific types of transactions: (1) the
district court, and continued to maintain that the Commis-
acquisition, sale or lease of any plant as an operating unit in
sion had improperly applied section 63 to the repurchase of
the state of Texas for a total consideration in excess of
minority interests in the project. As part of its appeal to this
$100,000; (2) a public utility's merger or consolidation
Court, Texas Utilities contends in its second point of error
with another public utility operating in the state; and (3) the

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that the Commission's section 63 review was an error of terests in Comanche Peak. It instead argues that
law. the Commission should determine the prudent
cost of 100 percent of Comanche Peak, rather
[4][5] The Cities, Public Utility Counsel, and the than just 87.8 percent of the plant, in deter-
Commission each argue that Texas Utilities has waived its mining the extent to which the costs of the 12.2
right to challenge the Commission's decision to proceed percent repurchased plant are included in rate
under section 63 because it was the utility that initially base.
identified section 63 as one of the provisions giving the
Commission jurisdiction over the rate-making proceed- The Report goes on to state:
ing.FN7 Administrative agencies, however, have only those
powers that are expressly conferred by statute, together The relevant precedent [for applying § 63] ... is
with those necessarily implied from the authority conferred found in the three dockets in which the Com-
or the duties imposed. State v. Jackson, 376 S.W.2d 341, mission approved the CCN amendments re-
344 (Tex.1964) (citing Stauffer v. City of San Antonio, 162 flecting the Company's reacquisition of the
Tex. 13, 344 S.W.2d 158, 160 (1961)); Sexton v. Mount minority owners' interests: Docket Nos. 8015,
Olivet Cemetery Ass'n, 720 S.W.2d 129, 142 8236, and 8736.
(Tex.App.—Austin 1986, writ ref'd n.r.e.). Jurisdiction
cannot be conferred upon the agency by the parties before
In each of those dockets' final orders, the
it, but rather must emanate from the statute itself. See
Commission envisioned a future § 63 review of
Nueces County Water Control & Improvement Dist. v.
[Texas Utilities'] buyback of a minority owner's
Texas Water Rights Comm'n, 481 S.W.2d 924, 929
interest.... [Texas Utilities] did not file a motion
(Tex.Civ.App.—Austin 1972, writ ref'd n.r.e.) (“If the
for rehearing in any of the final orders in the
statutes do not grant the board the power to do a thing, then
CCN dockets related to the repurchases of the
it has no such power.”). If the utility's reacquisition of
minority owners' interests, even though each of
minority interests in Comanche Peak is not one of the
the final orders envisioned a future § 63 review.
specific transactions identified in section 63 of PURA, the
Commission has no jurisdiction to make disallowances
[6] This Court has the power, as well as the duty, to
based on *394 the standards set forth in that section; such
review the agency's interpretation and application of a
jurisdiction cannot be conferred on the Commission simply
statute. See Railroad Comm'n v. Lone Star Gas Co., 599
because the parties have requested or agreed to it.
S.W.2d 659, 662 (Tex.Civ.App.—Austin 1980, writ ref'd
n.r.e.) (stating that an agency's duty is to carry forward the
FN7. The Examiners' Report notes:
directives of statutes, and the courts review agency orders
to ensure that statutes are enforced). In reviewing the
In the petition and statement of intent initiating Commission's order, we are therefore obliged to determine
this docket, [Texas Utilities] requested that “the whether the repurchase of minority ownership interests is a
public interest and other findings be made fa- transaction contemplated by section 63 of PURA. If it is
vorably” with respect to its repurchases of the not, the Commission had no authority to conduct a section
minority owner interests. [Texas Utilities'] 63 review, and we may not uphold that portion of the order.
pleading also cited § 63 as one of the statutory Accordingly, we first examine the repurchase at issue in
provisions granting the Commission jurisdic- this case to determine if it falls within the scope of trans-
tion over [Texas Utilities'] application. [Texas actions the Commission is directed to review under PURA
Utilities] now contends that § 63 does not apply section 63.
to its reacquisition of the minority owners' in-

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[7] In August 1973, Texas Utilities' corporate prede- 3.01 Ownership: The Parties shall have title to
cessors, Dallas Power & Light Company, Texas Power & the Project and Fuel as tenants in common and
Light Company, and Texas Electric Service Company, shall, as co-tenants with an undivided interest
signed a memorandum of agreement to design, construct, therein, subject to the terms of this Agreement,
and operate the Comanche Peak nuclear power plant.FN8 own the Project and Fuel and have the related
Texas Utilities originally intended to own the entire plant, rights and obligations.... (emphasis added).
but was required to sell ownership interests in the project in
order to receive construction permits from the Nuclear The agreement also contains a provision
Regulatory Commission (NRC). In 1974, Texas Utilities whereby the parties to the agreement waive the
agreed to allow participation in the ownership of Coman- right to partition their interest in the project.
che Peak, thereby eliminating antitrust concerns associated
with the issuance of the construction permits. By 1979,
FN10. In exchange for the ownership interest,
Texas Municipal Power Agency and Brazos Electrical
each minority interest owner agreed to advance
Power Cooperative had acquired ownership shares of 6.2
sufficient funds to pay its ownership interest share
percent and 3.8 percent respectively. FN9 In 1982, Tex–La
of the project's construction and operation costs.
Electric Cooperative of Texas became another co-owner of
Additionally, each minority interest owner agreed
the Comanche Peak project. Because Tex–La had raised
to pay its percentage share plus interest of the
antitrust issues with the Department of Justice and had
accumulated costs of fuel and construction paid
filed a petition to intervene in the Comanche Peak antitrust
by Texas Utilities before the applicable date of
review related to its application for an operating license,
closing. The minority interest owners essentially
Texas Utilities agreed to sell Tex–La a 4.3 percent interest
agreed to assume financial responsibility for a
in the project. Before the closing, however, Tex–La re-
percentage of the cost of building the plant in
duced its purchase to 2.2 percent of the project. The joint
exchange for a corresponding percentage undi-
operating agreement was amended to reflect this sale.FN10
vided interest in the completed plant. Once the
The Commission granted certificates of public conven-
plant was operating, the minority interest owner
ience and necessity for all three sales of ownership inter-
was entitled to capacity equal to its percentage
ests in the project. FN11
share of Comanche Peak's net effective genera-
tion.
FN8. Texas Utilities Electric Company (“Texas
Utilities”) is the principal subsidiary of Texas
FN11. For example, in Docket No. 3589, the
Utilities Company (the “Holding Company”), an
Commission reviewed the transfer of a four and
investor-owned holding company. Texas Utilities
one-third percent ownership interest in Comanche
was created in 1984 after the merger of Dallas
Peak from Texas Utilities' corporate predecessors
Power & Light Company, Texas Electric Service
to Tex–La Electric Cooperative. Though PURA
Company, and Texas Power & Light Compa-
section 63 was cited as one of the statutory pro-
ny—all Holding Company subsidiaries.
visions giving the Commission jurisdiction to
review the sale, the Examiners' Report states,
FN9. Joint ownership agreements executed with “Because only a portion of [a] joint interest is
Texas Municipal Power Agency and Brazos being conveyed, it may not be necessary to com-
Electrical Power Cooperative described the ply with § 63 of the Act because it speaks to the
ownership of Comanche Peak as follows: transfer of ‘ ... any plant as an operating unit or

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system....’ ” Utilities settled with the minority interest owners by re-
purchasing their undivided interests in the project.FN12 The
*395 The joint ownership agreement began to deteri- settlement agreements ended all litigation between Texas
orate over time. In May 1985, Brazos Electrical Power Utilities and the minority interest owners. The repurchases
Cooperative ceased making its contractual payments to were approved by the Commission which, as previously
Texas Utilities. In early 1985, Tex–La Electric Coopera- noted, indicated its intention to review the repurchase of
tive made several late payments, and thereafter stopped these minority interests under PURA section 63 in the
making payments altogether. Texas Municipal Power future rate-making proceedings.
Agency continued to make payments, but it made them
under protest. Thereafter, the minority interest owners FN12. The repurchase prices were based on the
claimed that Texas Utilities had failed to meet its respon- cost of building the percentage of the plant owned
sibilities under the joint ownership agreement, resulting in by each seller. Therefore, it appears that Texas
rising costs, schedule delays, and licensing problems. The Utilities reacquired the interests by reimbursing
three minority interest owners contended that they were each minority interest owner the money each had
therefore relieved of any obligation to pay their percentage contributed to the construction and operation of
costs of the construction and operation of the project. the plant. Additionally, Texas Utilities agreed to
repurchase nuclear fuel and transmission facili-
Texas Utilities sued for breach of contract, seeking ties, and to reimburse the minority interest own-
monetary damages and a declaratory judgment affirming ers' litigation expenses. These payments together
the minority interest owners' continuing obligation to pay constitute the settlement costs paid by Texas
their share of the plant's remaining costs. The minority Utilities to the minority interest owners. The
interest owners filed counterclaims alleging mismanage- Commission reviewed these settlement costs
ment of the project, breach of contract, and deceptive trade under PURA section 63 and made the following
practices. Faced with mounting litigation costs, Texas disallowances:

Repurchase of 12.2% Ownership Interest $811,342,938
Reimbursement of Litigation Expenses $ 72,684,000
Repurchase of Nuclear Fuel $ 24,662,000
Total $908,688,938
FN13
kilowatt than was “reasonable.” Accordingly, the
As part of Docket 9300, the Commission did in fact Commission disallowed the excess purchase price
conduct the section 63 review. The Commission deter- amounting to almost $812 million. The Commission also
mined that the repurchase was in the public interest “to the disallowed the utility's reimbursement of the minority
extent that [Texas Utilities] paid a reasonable value for the interest owners' litigation costs, amounting to $72.684
repurchased capacity.” The Commission found that the million, and $24.662 million of the total consideration paid
utility had reacquired the minority interests by paying for the nuclear fuel.
$4,765 per kilowatt—the cost of building Comanche Peak.
By contrast, the Commission decided that a “reasonable FN13. It does not appear, however, that pur-
value” would be $1,865 per kilowatt, the cost of building a chasing a stand-alone coal plant was an option
stand-alone “generic coal plant” with 12.2 percent of available to the utility in its attempts to resolve the
Comanche Peak's capacity. As a result, the Commission litigation quagmire that threatened the entire
determined that Texas Utilities had paid $2,900 more per project. The utility was required to obtain a li-

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cense for the Comanche Peak power plant; it reasonable utility manager would exercise or
could not choose to license 87.8 percent of the choose in the same or similar circumstances
capacity and turn to alternative power sources for given the information or alternatives available
more capacity. The 12.2 percent was part of the at the point in time such judgment is exercised
whole project, and until the dispute with the mi- or option is chosen.
nority interest owners was resolved, the entire
plant would remain inoperative. If the Commission indeed applied a prudence
standard when evaluating the repurchase, the
The district court concluded that although review resulting findings of fact are arbitrary and ca-
under section 63 of PURA was appropriate, the Commis- pricious because they reflect consideration of a
sion made disallowances that were arbitrary and capricious factor legally irrelevant to a review of expend-
and not supported by substantial evidence. In two jointly itures under the prudent investment standard.
raised points of error, the Cities and Public Utility Counsel See Public Util. Comm'n v. South Plains Elec.
assert that the district court erred in remanding some of the Coop., Inc., 635 S.W.2d 954, 957
Commission's findings of fact and that the Commission (Tex.App.—Austin 1982, writ ref'd n.r.e.)
properly carried out its section 63 review. They do not (citing Starr County v. Starr Indus. Servs., Inc.,
challenge the propriety of the section 63 review. The 584 S.W.2d 352 (Tex.Civ.App.—Austin 1979,
Commission *396 also brings two separate points of error writ ref'd n.r.e.), for the proposition that an
relating to its section 63 review, contending that it properly agency's consideration of a non-statutory factor
applied section 63 and that its findings of fact were sup- amounts to arbitrary and capricious action re-
ported by substantial evidence. We do not address these quiring reversal); John E. Powers, Agency Ad-
points of error because our conclusion that the repurchase judications 165 (1990). The Commission dis-
of the undivided minority interests in the plant are not allowed the purchase price to the extent that it
transactions reviewable under section 63 renders moot any exceeded the cost of building a stand-alone coal
further controversy about what would constitute a proper plant with capacity equivalent to 12.2 percent
disallowance under that provision.FN14 of Comanche Peak's. Building a stand-alone
coal plant was not, however, one of the options
FN14. The Cities and Public Utility Counsel ar- available to the utility at the time it made the
gue that the standard applied by the Commission repurchase. The purpose of repurchasing the
in its section 63 review is identical to the standard minority interests was not to obtain capacity,
employed in the typical “prudence review” of a but to eliminate expensive and time-consuming
rate-making proceeding, and for that reason the litigation that jeopardized licensing of the en-
Commission's findings should be affirmed even if tire project; building or buying a coal plant
this Court determines that section 63 is inappli- would not achieve that objective.
cable to this transaction. Assuming, without de-
ciding, that the standards are the same, we would As previously noted, section 63 applies to three types
still reverse the Commission's disallowances be- of transactions: (1) the purchase, sale or lease of a plant or
cause they are arbitrary and capricious. In Docket unit as an operating system for consideration in excess of
9300, the Commission adopted the following $100,000; (2) sales of more than fifty percent of the stock
prudence standard: of a public utility; and (3) a merger or consolidation of two
public utilities. Texas Utilities' repurchase of the undivided
The exercise of that judgment and the choosing ownership interests sold to Texas Municipal Power
of one of that select range of options which a Agency, Brazos Electrical Power Cooperative, and

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Tex–La Electric Cooperative falls into none of these cat- 150. For the reasons discussed in Section VII.C. of this
egories. Rather than repurchasing a “plant or unit,” Texas Report, [Texas Utilities'] repurchases of the minority
Utilities acquired the undivided ownership interests of owners' interests in Comanche Peak are consistent with
three tenants-in-common. Under the joint ownership the public interest to the extent that [Texas Utilities] paid
agreement, the co-tenants had waived any right to partition a reasonable value for the repurchased capacity.
the interests, thereby foreclosing the possibility of identi-
fying any part of the plant as belonging specifically to any 151. For the reasons discussed in Section VII.C. of this
co-tenant. The fallacy in the Commission's analysis is its Report, all amounts in excess of the reasonable value of
assumption that the minority interests translate into a the repurchased interests should be disallowed from in-
complete and independently operable portion of Coman- vested capital as unreasonably affecting rates.
che Peak, ownership of which changed hands when the
repurchase took place.
152. For the reasons discussed in Section VII.B.2.d. and
Section VII.D. of this Report, a reasonable value of the
The Cities and Public Utility Counsel argue that ex- repurchased interests in Comanche Peak is $1,856 per
cluding the repurchase of the undivided interests from the kW.
scope of a section 63 review renders the provision mean-
ingless. They contend that it is illogical to conclude that “a
153. For the reasons discussed in Section VII.D. of this
statute concerned with transactions of at least $100,000
Report, the reasonable value of $1,856 per kW should
would not apply to a transaction 1,000 times greater than
apply to valuating the repurchased interests in Unit 1 and
that amount.” This argument fails because the element that
Unit 2.
triggers section 63 review is not the amount of money
involved in the transaction, although the legislature has set
153A. Consistent with an estimated fuel cost for Co-
a $100,000 minimum presumably to exclude transactions
manche Peak of $11 billion, the test-year-end cost of
so small that there is no real risk they will unreasonably
$5.938 billion should be used to value the repurchased
affect rates or service. Rather, section 63 is concerned with
12.2 percent interest in Unit 1 and an estimated cost of
certain types of transactions that result in changes of
$5.0 billion should be used to value the repurchased 12.2
ownership of the utility or its operating units to ensure that
percent interest in Unit 2.
the costs of transactions inconsistent with the public in-
terest are not assessed against the ratepayers. We conclude
that the Commission erred in reviewing the costs associ- 153B. The plant disallowances related to the repur-
ated with the minority interests under PURA section 63. chased 12.2 percent interest in Unit 1 is $462,764,691;
the plant disallowance related to the repurchased 12.2
percent interest in Unit 2 is $348,578,247. Taken to-
In its final judgment, the district court reversed and
gether, the total plant disallowance related to the re-
remanded for reconsideration on the existing record the
purchased 12.2 percent interest in the entire plant is
following specific *397 findings of fact related to the mi-
$811,342,938.
nority interest repurchases:

154. For the reasons discussed in Section VII.E. of this
149. For the reasons discussed in Section VII.C.2. of this
Report, the $72.684 million in minority owners' litiga-
Report, [Texas Utilities] failed to prove that the consid-
tion expenses reimbursed by [Texas Utilities] as part of
eration it paid for the repurchased 12.2 percent interest in
the settlement agreements should be disallowed.
the plant was reasonable.

******

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tion was reasonable from [Texas Utilities']
156. As modified by Findings of Fact 153A and 153B, perspective.
Section VII.F. of this Report indicates the disallowances
for Unit 1 and Unit 2, as calculated in Section VI. The Report noted that “it is clear that the mi-
(Prudence) and Section VII. (Reacquisition of Minority nority owner litigation potentially threatened
Owner Interests). The total Unit 1 disallowance is the Company's licensing efforts, which in turn
$847,004,966; the total Unit 2 disallowance is threatened further schedule delays and cost
$534,139,597. Taken together, the total disallowance is overruns on the project. At the time of the set-
$1,381,144,563. tlements with the minority owners, the project
was incurring approximately $60 to $70 million
The purpose of remanding these findings was to allow a month in case requirements and carrying
the Commission to reconsider the “reasonable value” it costs. Consequently, a settlement of the mi-
assigned the repurchased interests, presumably to make an nority owner litigation was reasonable in order
upward adjustment in its $1,856 per kilowatt valuation to to avoid the possibility of any further project
reflect the “intangible” benefits of repurchasing the mi- delay and unnecessary expenditures of these
nority interests. The district court instructed the Commis- amounts.”
sion to consider not only the “economic value” of the
property and facilities acquired, but also benefits gained FN16. We realize the Commission has already
from terminating expensive and time-consuming litigation conducted an overall prudence review of the costs
that jeopardized the entire project. We affirm the district associated with the original construction of Co-
court's rejection of these findings of fact based on our manche Peak resulting in a disallowance of ap-
conclusion that the Commission erroneously reviewed the proximately $537 million. Rather than hold that
repurchases under PURA section 63 and failed to evaluate this figure is the appropriate disallowance, we
the repurchase price in light of the relevant statutory con- note that the question on remand is not whether
siderations. We reverse that portion of the district court's the original construction costs of the 12.2% at
judgment affirming the Commission's disallowance of issue here were prudently incurred, but rather
$24,662,000 of the cost to Texas Utilities of repurchasing whether it was prudent for the utility to repur-
nuclear fuel from the minority interest owners. This pay- chase that portion of the plant at its original cost.
ment was part of the overall settlement cost and should be
reviewed under the prudent investment standard along with FEDERAL INCOME TAX EXPENSE
all other costs related to the repurchase. The Commission In points of error seven through ten, the Cities and
has already approved the utility's decision to settle the Public Utility Counsel complain that the district court erred
dispute with the minority interest owners; FN15 on remand, in affirming the Commission's calculation of the utility's
we *398 direct the Commission to consider, under the federal income tax expense. They contend that the Com-
prudent investment standard, the price paid for the repur- mission's calculation (1) improperly employed the hypo-
chase, including the litigation costs and repurchase of thetical rather than the actual-tax method, (2) failed to
nuclear fuel at its original cost.FN16 account for tax savings resulting from the utility's consol-
idated tax return, (3) did not reflect deductions for actual
FN15. Finding of fact 148 states: interest expense, and (4) failed to reflect deductions taken
for below-the-line expenses, including disallowed Co-
For the reasons discussed in Section VII.C.1. of manche Peak plant costs.
this Report, settling the minority owner litiga-

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[8] We sustain the seventh point of error complaining though it had received any tax benefits a consolidated
of the Commission's use of the hypothetical tax method. return would provide. Once the Commission determines
The mandate from the supreme court is clear: “The utility's that a consolidated filing would have been, or was, ad-
rates must reflect the tax liability actually incurred.” Public vantageous to the utility, the Commission must adjust the
Util. Comm'n v. Houston Lighting & Power Co., 748 utility's tax expense to reflect those savings. If the Com-
S.W.2d 439, 442 (Tex.1987). This Court has repeatedly mission does not reduce the utility's tax expense to reflect
affirmed that statement by consistently requiring the the utility's tax savings, it violates the actual-tax doctrine's
Commission to employ the actual-taxes-paid doctrine. See underlying principle *399 that rates must be set based on
City of Alvin v. Public Util. Comm'n, 876 S.W.2d 346, the utility's actual tax liability. GTE–SW, 833 S.W.2d at
359–60 (Tex.App.—Austin 1994, no writ h.); Cities of 166.
Abilene v. Public Util. Comm'n, 854 S.W.2d 932, 944
(Tex.App.—Austin 1993, writ requested); Public Util. [10] The Commission argues that it was not required
Comm'n v. GTE–SW, 833 S.W.2d 153, 159 to allocate any of the tax savings from the consolidated
(Tex.App.—Austin 1992, writ granted). Furthermore, filing to the utility because it specifically found that the
under the actual-taxes-paid test, “any utility tax savings consolidated filing was not advantageous to the utility. See
must benefit ratepayers.” Cities of Abilene, 854 S.W.2d at Finding of Fact 331A. In Cities of Abilene we held that no
945 (emphasis added). In this case, as well, we reject the adjustment to income tax expense is necessary under
Commission's refusal to adhere to binding precedent. PURA section 41(c)(2) if the Commission finds either (1)
that it was not advantageous to the utility to consolidate
[9] The Cities and Public Utility Counsel's eighth returns, or (2) that the Commission has computed taxes as
point of error asserts that the Commission erred when it though a consolidated return were filed and the utility has
failed to adjust its calculation of the utility's tax expense to received its fair share of the savings from the consolidated
reflect savings that resulted from the utility's filing a con- return. Cities of Abilene, 854 S.W.2d at 944. In this case,
solidated tax return. The Commission rejoins that its deci- the Commission relied on its own conclusion that the util-
sion not to allocate any of the savings to the utility was ity's fair share of the savings was zero to support its finding
consistent with PURA section 41(c)(2) and cases con- that the consolidated return was not advantageous to the
struing that statutory provision. Section 41(c)(2) states: utility. We will uphold the Commission's decision only if it
properly found that the utility's fair share of the tax savings
If the public utility is a member of an affiliated group was zero.
that is eligible to file a consolidated income tax return,
and if it is advantageous to the public utility to do so, Finding of fact 331D states:
income taxes shall be computed as though a consolidated
return had been so filed and the utility had realized its The federal income tax savings resulting from the filing
fair share of the savings resulting from the consolidated of a consolidated federal income tax return should ac-
return, unless it is shown to the satisfaction of the regu- crue to the entity that provided the tax attributes that
latory authority that it was reasonable to choose not to allowed for such savings, and [Texas Utilities] was not
consolidate returns. the entity that provided such tax attributes.

Texas Utilities argues that this statute only applies This Court has previously decided that even when it is
when the utility has not filed a consolidated return. We the utility's affiliates that have suffered losses and provided
disagree. The statute provides that, regardless of whether “the tax attributes that allowed for savings,” those savings
the utility actually filed a consolidated return, the Com- must be passed on to the ratepayers. GTE–SW, 833 S.W.2d
mission must calculate the utility's income tax expense as

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at 167. In finding of fact 331F, the Commission asserts that tion.”). We sustain the point of error to the extent that we
it would be unfair to allocate to the utility tax savings continue to require the Commission to pass through to
resulting from the affiliates' losses because the utility will ratepayers any tax benefits from interest expense deduc-
never be responsible for paying the affiliates' taxes when tions. However, the Commission must allocate those sav-
“timing differences reverse and those affiliates have taxa- ings between present and future ratepayers, and the proper
ble income.” Again, this Court has rejected that argument. allocation is within the Commission's discretion.
GTE–SW, 833 S.W.2d at 167 n. 16 (inequity resulting from
ratepayers' benefitting from tax savings not offset by ob- *400 [13] The Cities and Public Utility Counsel's
ligation to pay higher rates in the event of affiliates' gains is tenth point of error contends that the Commission erro-
a matter for the legislature to remedy by amending PURA neously excluded tax benefits resulting from be-
section 41(c)(2)). Similarly, finding of fact 331H, that low-the-line expenses, including tax deductions related to
Texas Utilities should not benefit from tax savings at- expenses disallowed as imprudently incurred. This Court
tributed to affiliates because it bears none of the risks has already decided that PURA requires that the Commis-
associated with those entities, conflicts with existing sion reduce the utility's income tax expense by the amount
caselaw. The Commission's finding that the consolidated of tax deductions, even if they are associated with disal-
tax return was not advantageous cannot rest upon its own lowed capital expenses. City of Alvin, No. 3–92–459–CV,
improper refusal to allocate any savings to the utility. slip op. at 17 (citing GTE–SW, 833 S.W.2d at 169). We
Having rejected several of the findings supporting the remain unpersuaded by the Commission's argument that
Commission's conclusion that the utility's fair share of the the actual-tax doctrine conflicts with the normalization
tax savings is zero, we are unable to uphold that conclu- rules. See City of Alvin, No. 3–92–459–CV, slip op. at 18.
sion. There is no indication that each finding is inde- We sustain the tenth point of error.
pendently sufficient to support the conclusion. We there-
fore sustain the Cities and Public Utility Counsel's eighth
BONDED RATES
point of error.
In their twenty-first point of error, the Cities challenge
the Commission's authority to allow Texas Utilities to
[11][12] The ninth point of error objects to the Com- implement bonded rates in both the municipal and
mission's failure to adjust the tax expense calculation to non-municipal sections of its service area.FN17 Disposition
reflect actual-interest-expense deductions. The Commis- of this point of error requires an interpretation of PURA
sion is required to allocate tax savings to ratepayers rather section 43(e). This appeal presents the first opportunity for
than to shareholders. The actual-tax doctrine requires that this Court to consider the bonded-rate provision of the
the ratepayers be held accountable only for “those tax statute since its amendment in 1983.
expenses that are actually incurred by a utility.” Houston
Lighting & Power, 748 S.W.2d at 442. If the utility enjoys
FN17. Public Utility Counsel does not join the
a tax deduction based on interest expense, the benefits of
Cities in bringing this point of error.
that deduction must be passed on to the ratepayers. In City
of Alvin, however, we rejected the argument that the
When an electric utility wishes to change its rates it
Commission must pass on immediately the entire savings
must follow the procedures outlined in PURA section
related to a utility's tax deductions. City of Alvin, No.
43.FN18 The utility initiates rate proceedings by filing a
3–92–459–CV, slip op. at 18 (“Section 27(e) of PURA
statement of intent to change rates with the regulatory
directs the Commission to distribute [tax savings benefits]
authority having original jurisdiction. PURA § 43(a). FN19
to all ratepayers, however, both present and future. We will
In all proceedings involving major rate changes,FN20 the
not interpret Houston Lighting as mandating that present
regulatory authority having original jurisdiction must hold
ratepayers receive all the benefits of accelerated deprecia-

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a hearing on the proposed rate schedule. PURA § 43(c). areas. The Commission, however, has a 150–day period of
Pending the hearing, the regulatory authority may suspend original jurisdiction over its portion of the rate proceeding.
implementation of the new rate schedule. If the original In addition, the Commission is allowed two days for each
proceeding involves a proposed increase in the rates day of hearings in excess of fifteen days. The practical
charged in municipal areas, the municipality holds the result of allowing the Commission a longer period of
hearing and has ninety days in which to come to a final original jurisdiction is that it can wait for the municipality
decision. If the municipality has made no final disposition to issue a final appealable order and then consolidate de
of the rate proceeding at the expiration of ninety days, the novo appellate review with its own consideration of the
proposed rate schedule is deemed to have been approved same proposed rate increase in non-municipal areas.
and the municipality loses jurisdiction over the proceeding. Therefore, the Commission typically exercises its original
PURA § 43(d). If an order is issued, any party to the pro- and appellate jurisdiction concurrently.
ceeding may seek de novo appellate review in the Com-
mission. PURA § 26(a), (g). In these consolidated rate proceedings, the Commis-
sion has 150 days plus two days for each day of hearings in
FN18. This discussion focuses on the more typi- excess of fifteen days in which to make a final determina-
cal situation in which a utility requests a rate in- tion. When the Commission is faced with a particularly
crease rather than a decrease. complex rate proceeding, protracted *401 hearings can
mean a utility's proposed rate schedule may not take effect
FN19. Original jurisdiction over rate proceedings for a long period of time.FN21 The term “regulatory lag” is
is divided between the governing body of each used to describe the economic consequences of this delay.
FN22
municipality (“the municipality”) and the Com- In order to protect utilities from the financial harm
mission. Each municipality exercises exclusive engendered by prolonged regulatory lag, PURA section
original jurisdiction over electric rates and ser- 43(e) provides that in cases in which the Commission has
vices within its corporate limits (“municipal are- failed to render a final order within 150 days of the pro-
as”), whereas the Commission exercises exclu- posed effective date of the rate increase, the utility
sive original jurisdiction over rates and services in
all other areas (“non-municipal areas”). PURA § FN21. In this case, for example, there were 203
17(a), (e). In addition, the Commission has ex- days of hearings. This means the utility might not
clusive appellate jurisdiction to review each mu- be allowed to increase its rates for as many as 526
nicipality's order in any rate proceeding. PURA § days.
17(d).
FN22. “Regulatory lag arises from the loss in
FN20. The statute defines a “major change” as an revenue experienced by a utility whose rates are
increase in rates that will augment the aggregate in need of upward adjustment during the period
revenues of the utility making the rate application between filing an application for a rate increase
by more than $100,000 or two and one-half per- and the date when relief is granted.” Railroad
cent, whichever is greater. PURA § 43(b). Comm'n v. Lone Star Gas Co., 656 S.W.2d 421,
423 (Tex.1983).
Because most utilities provide services in both mu-
nicipal and non-municipal areas, there is usually a parallel may put a changed rate, not to exceed the proposed rate,
proceeding originating in the Commission to consider the into effect upon the filing with the regulatory authority
same proposed rate increase as it affects non-municipal of a bond.... The utility concerned shall refund or credit

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against future bills all sums collected ... in excess of the nicipal areas. Section 43(e) specifically states that
rate finally ordered plus interest at the current rate as a utility may not put bonded rates into effect until
finally determined by the regulatory authority.FN23 150 days have passed. Because the municipality
loses its jurisdiction after only ninety days, a
FN23. PURA section 3(g) provides that the term utility's right to bonded rates will always arise
“regulatory authority” means either the governing after the municipality has lost its original juris-
body of any municipality or the Commission, diction over the rate proceeding.
depending upon the context in which the word is
used. Section 43(e) contains no language that limits the
bonding provisions to rates being considered under the
PURA § 43(e). This practice is known as “bonding in” Commission's original jurisdiction:
rates and is used to relieve the potential financial hardship
imposed on a utility while it awaits a final Commission If the 150–day period has been extended, ... and the
order on its requested rate increase. commission fails to make its final determination of rates
within 150 days from the date that the proposed change
[14] In Docket 9300, Texas Utilities requested the would have gone into effect, the utility concerned may
same rate increase throughout its entire service area, en- put a changed rate, not to exceed the proposed rate, into
compassing both municipal and non-municipal areas. As effect upon the filing with the regulatory authority of a
permitted by the 1983 amendments to PURA, the Com- bond....
mission reviewed the proposed rate increase in municipal
areas under its appellate jurisdiction at the same time it PURA § 43(e). In support of its contention that the
considered the increase in non-municipal areas under its utility may implement bonded rates only for those rates
original jurisdiction. When 150 days had passed without subject to the Commission's original jurisdiction, the Cities
the Commission's having reached a final determination, the rely on two pre–1983 cases holding that the former version
utility decided to implement bonded rates throughout its of section 43(e) did not permit bonded rates in areas under
entire service area, and pursuant to PURA 43(e) requested the Commission's appellate jurisdiction. See Lone Star
that the Commission approve its bond. The Cities objected Gas, 656 S.W.2d at 425; *402Arkansas Louisiana Gas Co.
to Texas Utilities' request for bonded rates in municipal (Arkla) v. Railroad Comm'n, 586 S.W.2d 643
areas, maintaining that PURA prohibits bonded rates in (Tex.Civ.App.—Austin 1979, writ ref'd n.r.e.). We con-
municipal areas once the municipality has lost its original clude that the reasoning of those cases is so closely tied to
jurisdiction over the rate proceeding. FN24 The Commission the wording of PURA before the 1983 amendments that
rejected this argument and determined that PURA's they do not support the Cities' interpretation of amended
bonding provision does not prohibit a utility from imple- section 43(e).FN25
menting bonded rates in municipal areas when the under-
lying rate increase is subject to the Commission's appellate FN25. Moreover, the supreme court expressly
jurisdiction. We conclude that the Commission's interpre- limited the effect of its decision in Lone Star Gas
tation of PURA section 43(e) is correct. to cases arising before September 1, 1983, the
effective date of significant amendments to
FN24. When considered in conjunction with other PURA. Lone Star Gas, 656 S.W.2d at 427.
provisions of PURA, the Cities' interpretation of
section 43(e) leads to the result that a utility will In Lone Star Gas the supreme court recognized the
never be able to implement bonded rates in mu- hardship created by PURA's failure to provide for bonded

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rates during an extended period of appellate review, but
commented that “any changes in the protection afforded [15] The Commission's interpretation of section 43(e)
the utility should be made by the legislature.” 656 S.W.2d is entitled to great weight, provided it is reasonable and
at 425. Perhaps responding to the court's invitation to act, does not contradict the plain language of the statute. Tar-
in 1983 the legislature significantly amended PURA and rant Appraisal Dist. v. Moore, 845 S.W.2d 820, 823
apparently cured this particular hardship. See GTE–SW, (Tex.1993). The Commission's construction of the bonding
833 S.W.2d at 173 (noting that an almost identical bonded provision is consistent with the statutory scheme embodied
rate provision in the new Gas Utility Regulatory Act cured in the 1983 amendments designed to facilitate contempo-
the problems caused by the utility's inability to implement raneous disposition of system-wide rates in a single pro-
bonded rates in municipal areas pending review de novo by ceeding. It also affords the utility protection from regula-
the Commission). tory lag through bonded rates, whether inside or outside
city limits. Nothing in the statute itself or the relevant case
Without the ability to bond in rates, a utility's only law supports the Cities' restricted reading of section 43(e).
avenue for relief from regulatory lag in city rates, tradi- We overrule the Cities' twenty-first point of error.
tionally the lion's share of its service area, would be to
request interim rates. See PURA § 26(g) (allowing the RATE BASE ALLOWANCES
Commission to authorize interim rates if “necessary to In points of error two through four, the Cities and
effect uniform system-wide rates”). This would necessitate Public Utility Counsel complain that the district court
a bifurcated process of considering the request for interim improperly upheld various aspects of the Commission's
city rates while contemporaneously implementing bonded order on rehearing relating to the prudence phase of the
rates outside city limits. Such an inefficient and unwieldy rate-making proceeding. Specifically, they contend that the
process undermines the amended statutory scheme de- Commission's disallowance of Comanche Peak costs is
signed to consolidate consideration of system-wide rates in contrary to substantial evidence and inconsistent with the
one proceeding. Furthermore, interim rates that require a Commission's factual determinations regarding the insuf-
hearing do not provide relief from regulatory lag equiva- ficiency of Texas Utilities' proof and with Texas law re-
lent to the bonding provision which permits implementa- garding the burden of proof. The Cities and Public Utility
tion of new rates without Commission approval, subject Counsel assert that reasonable minds could not reach the
only to a bond adequate to ensure possible refunds. We see decision arrived at by the Commission regarding the rea-
no suggestion in the amended version of section 43(e) that sonable cost of Comanche Peak, and that the Commission
utilities should be limited to seeking interim rates to cure failed to disallow imprudent project costs as required by
regulatory lag in areas servicing cities.FN26 statute. See PURA §§ 39, 41.

FN26. It is more sensible to view interim rates In August 1972, Texas Utilities announced its plan to
and bonded rates as separate and independent build Comanche Peak, its first *403 nuclear power plant.
methods by which a utility may obtain rate relief In 1977, the utility estimated that Comanche Peak Unit 1
in its entire service area, rather than alternative would be commercially operable in 1981, and Unit 2
procedures for setting rates inside and outside city would achieve commercial operation in 1983. The total
limits. A utility might first request interim rates in estimated cost of the project was $1.7 billion, including an
order to avoid posting a large bond. If the Com- allowance for funds used during construction (AFUDC).
mission did not approve the interim rates, the However, Unit 1 did not become commercially operable
utility could then post a bond, which it would risk until August 1990. At the rate-making proceeding, the
losing entirely or in part if final rates set by the examiners attributed this substantial delay to Texas Utili-
Commission were lower than the bonded rates. ties' inability to obtain an operating license from the NRC.

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See Examiners' Report at 5.FN27 lowed based on Nielsen–Wurster's findings that the utility
acted imprudently in discrete instances during the life of
FN27. In March 1984, the NRC formed a Tech- the project. The Commission reviewed the evidence pre-
nical Review Team to identify and resolve all sented by the parties and general counsel and determined
regulatory issues raised by Texas Utilities' at- that $537.90 million of Comanche Peak costs were im-
tempt to obtain an operating license. The utility, prudently incurred and should be disallowed.
in turn, created the Comanche Peak Response
Team to assess and resolve any issues raised by To support the assertion that the Commission erred in
the Technical Review Team. In January 1985, the the prudence phase of Docket 9300, the Cities and Public
Technical Review Team issued a letter suggesting Utility Counsel make three basic points: (1) Texas Utilities
that Comanche Peak was deficient in the areas of did not sustain its burden of proof on the prudence of its
quality assurance and quality control. In response, Comanche Peak expenditures, (2) Texas Utilities did not
the utility formed the Design Adequacy Program properly quantify its imprudent Comanche Peak costs, and
and the Corrective Action Program to address the (3) the Nielsen–Wurster report does not constitute sub-
NRC's concerns and ensure that Comanche Peak stantial evidence to support the Commission's determina-
received an operating license. The NRC issued a tion of which Comanche Peak costs were imprudently
license for Comanche Peak Unit 1 in February incurred. Taken together, these points assert that the evi-
1990. dence presented during 203 days of hearings cannot sup-
port the Commission's final order with respect to disal-
Docket 9300 addressed the prudence of costs incurred lowances. See APA § 2001.174(2)(E); Texas Health Fa-
by the utility in responding to the NRC's concerns; the cilities Comm'n v. Charter Medical–Dallas, Inc., 665
utility engaged in an unprecedented revalidation and re- S.W.2d 446, 452–53 (Tex.1984).
inspection program which caused Comanche Peak costs to
nearly double. The Commission, which heard three ex- [16][17][18][19] In conducting a substantial evidence
planations for these costs, was charged with determining review, we must determine whether the evidence as a
which costs were prudent. Texas Utilities contended that whole is such that reasonable minds could have reached
the NRC unforeseeably and unreasonably applied stricter the conclusion the agency must have reached in order to
licensing standards to Comanche Peak, forcing the utility take the disputed action. Charter Medical, 665 S.W.2d at
to implement an expensive and time-consuming revalida- 453. We may not substitute our judgment for that of the
tion and reinspection program in order to obtain an oper- agency and may consider only the record on which the
ating license. The utility took the position that all of these agency based its decision. Texas State Bd. of Dental Ex-
were regulatory costs that should be included in rate base. aminers v. Sizemore, 759 S.W.2d 114, 116 (Tex.1988),
At the other end of the spectrum, the Cities and Public cert. denied, 490 U.S. 1080, 109 S.Ct. 2100, 104 L.Ed.2d
Utility Counsel argued that imprudent project management 662 (1989). The party bringing the appeal bears the burden
caused the NRC to lose confidence in Comanche Peak's of showing a lack of substantial evidence. Charter Medi-
safety, and that all post–1984 costs incurred in responding cal, 665 S.W.2d at 453. If substantial evidence would
to these concerns should be disallowed as imprudent. The support either affirmative or negative findings, we must
Commission's general counsel, supported by an evaluation uphold the agency's order, resolving any conflict in *404
conducted by the Nielsen–Wurster Group, an independent favor of the agency's decision. Auto Convoy Co. v. Rail-
auditor, concluded that Texas Utilities' inability to obtain road Comm'n, 507 S.W.2d 718, 722 (Tex.1974).
an operating license resulted from the NRC's significant,
but unfounded, quality concerns. The general counsel [20] The Cities and Public Utility Counsel essentially
maintained that certain costs should, however, be disal- argue that because the Commission was not persuaded by

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the utility's argument that all Comanche Peak costs were to utility imprudence and those that would have been
prudent, and because the utility then failed to quantify the necessary absent any imprudence. They assert that in order
impact of its imprudence by identifying costs related to to provide evidence sufficient to support the Commission's
imprudent management, the Commission was required to order, either the utility or Nielsen–Wurster was required to
disallow all of these expenditures.FN28 We do not agree. “produce a breakdown of the Company's post-March 1985
The Commission determined the evidence presented by the expenditures, disaggregated between those that were ‘re-
parties did not provide an accurate foundation on which to medial’ and those that would have been incurred even
base its disallowance decisions. It therefore turned to the absent the prolonged licensing delay.” The argument urged
report prepared by the Nielsen–Wurster Group. Niel- on appeal is that once the Commission has determined the
sen–Wurster had previously performed twelve compre- utility's evidence is insufficient to demonstrate that all
hensive prudence reviews of other nuclear plants, eight for expenditures were prudently incurred, the utility must then
commissions and four on behalf of utilities, before it was “isolate out the costs associated with its imprudent con-
retained by the Commission to evaluate the planning and duct” in order to avoid having the Commission disallow all
management of Comanche Peak. After an extensive in- the costs incurred.FN29 In support of their argument, the
vestigation, Nielsen–Wurster offered its findings in ten Cities and Public Utility Counsel direct this Court to Coa-
days of testimony presented by five expert witnesses. lition of Cities v. Public Utility Commission, 798 S.W.2d
560, 563–64 (Tex.1990), cert. denied, 499 U.S. 983, 111
FN28. The Commission rejected several of Texas S.Ct. 1641, 113 L.Ed.2d 736 (1991), in which the supreme
Utilities' attempts to justify costs associated with court stated that “[a] party who fails to meet its burden of
Comanche Peak. For example, the Commission proof loses.” In Coalition of Cities, the utility “lost” be-
found: (1) the plant cost comparisons tendered by cause neither the utility nor any other party satisfied the
the parties were not credible for purposes of es- Commission that $1.453 billion in expenditures were
tablishing a reasonable cost, (2) the cost variance prudently incurred. Nowhere does the supreme court state
analysis tendered by the utility had limited, if any, that a utility must segregate imprudent costs. When a util-
value in a prudence review of Comanche Peak, ity fails to persuade the Commission of the wisdom of all
(3) the schedule variance analysis tendered by the its expenditures, that does not preclude the Commission
utility did not credibly evaluate the post-March from considering the other evidence presented in the
1985 schedule extensions, and (4) the present rate-making proceeding. Indeed, it is the Commission that
value revenue requirements analysis and capital is charged with sifting through the evidence and deciding
cost correction analysis tendered by Texas Utili- whether imprudent conduct caused certain expenditures.
ties were improper methodologies for quantifying Having reviewed the utility's evidence and the Niel-
the impact of a seven-month delay. However, the sen–Wurster report, *405 the Commission determined that
Commission's final order shows that it did accept $90.5 million of the Comanche Peak Response Team ex-
much of Texas Utilities' and the Nielsen–Wurster penses and $79.9 million of the Corrective Action Program
Group's evidence supporting the prudence of a expenses were imprudent. The Commission made further
variety of decisions related to the overall con- disallowances for other imprudent conduct associated with
struction and management of Comanche Peak. the delay in licensing; it disallowed $54.1 million in
time-driven indirect costs and $167.3 million in AFUDC.
The Cities and Public Utility Counsel argue that the
evidence presented by Nielsen–Wurster cannot serve as a FN29. This Court has previously rejected similar
proper foundation for Commission decision-making be- arguments. In City of El Paso v. Public Utility
cause it does not provide a sufficiently detailed breakdown Commission we held:
of all Texas Utilities' expenditures identifying those related

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Requiring the Commission to adopt or reject reasonable minds could not have come to that decision
witnesses' testimony in toto, especially when based on this record. Charter Medical, 665 S.W.2d at 453.
the testimony concerns a multi-faceted issue
such as [prudence], would hobble the Com- The Cities and Public Utility Counsel also complain
mission's ability to assess each witness and that the Commission improperly applied a “sliding”
render its decision based solely on the testi- standard of prudence, assigning degrees of imprudence to
mony it found credible. utility decisions and making disallowances only when the
imprudence reached a certain level or degree. After re-
City of El Paso v. Public Util. Comm'n, 839 viewing the record we believe this criticism is unfound-
S.W.2d 895, 906–07 (Tex.App.—Austin 1992, ed.FN30 The Commission determined that the costs associ-
writ granted). ated with responding to NRC concerns were necessary in
part because of utility imprudence and in part because of
The Commission rejected Texas Utilities' claim that the NRC's application of higher safety and inspection
the costs associated with the reinspection and revalidation standards in the face of mounting concerns about the safety
program were entirely due to higher regulatory standards; of nuclear power plants in general. The Commission's
it similarly rejected the Cities and Public Utility Counsel's finding of fact 138 expresses this conclusion.FN31 The
contentions that all such costs should be disallowed as Examiners' Report notes that Texas Utilities' conduct was
imprudent. The Commission accepted the Niel- not the sole reason for the expenditures necessary to regain
sen–Wurster study as evidence that some, but not all, of the the NRC's confidence. The Commission then made partial
expenditures were imprudently incurred. The Commission disallowances for the costs of the remedial action program,
found that the NRC's Technical Review Team findings on not the wholesale disallowances recommended by the
the plant's condition were partly unfounded, although they intervenors. After a careful and thorough review of all the
did identify weaknesses in the pre–1985 quality assurance evidence presented in 203 days of hearings, the Commis-
program. The Commission also concluded that the growth sion made findings of fact and conclusions of law based on
of regulatory requirements increased the cost and extended that review. For each finding of imprudence in the con-
the construction schedule beyond Texas Utilities' control. struction and management of Comanche Peak, the Com-
These findings are supported by testimony adduced during mission *406 made a disallowance for the associated
the rate-making proceeding and provide substantial evi- costs.FN32 The Commission also made significant disal-
dence upon which the Commission could base its decision lowances for the cost of the delay in licensing, reflecting its
to examine all the costs in detail and make discrete disal- opinion that the utility's imprudence was partially respon-
lowances associated with imprudent conduct. sible for that delay.

The Cities and Public Utility Counsel vigorously as- FN30. The Cities and Public Utility Counsel base
sert that the Commission erred in not making any disal- their argument on the following statement con-
lowance for the costs of executing the Corrective Action tained in the Examiners' Report: “Although the
Program. However, the Commission determined that alt- examiners conclude that certain [Texas Utilities]
hough the imprudence of the utility was partially respon- management decisions were imprudent and un-
sible for the need to carry out the Corrective Action Pro- doubtedly contributed to the Company's licensing
gram, the changed regulatory climate would have made problems, they do not find that those practices rise
such a program necessary even in the absence of utility to the level of imprudence which would justify a
imprudence. The Commission's findings are presumed to substantial disallowance of Comanche Peak
be supported by substantial evidence, and the Cities and costs.” That the Report expresses only the view
Public Utility Counsel have failed to demonstrate that that not all costs should be disallowed because

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they were not all occasioned by utility impru- in the necessity to incur all of the post–1984
dence is clarified by the examiners' careful ex- costs.
planation of their position:
FN31. Finding of fact 138 states: “As discussed in
True, certain unreasonable conduct unques- Section VI.Q.2. of this Report, the evidence does
tionably contributed to the NRC staff's shift in not support imprudence disallowances of the
position with respect to its expectation of proof, magnitude proposed by the intervenors.”
as reflected in the Third Technical Team letter,
but other circumstances also contributed to this FN32. The Commission made the following dis-
change in position. In other words, the impru- allowances:
dent conduct of [Texas Utilities] did not result

Item Amount (Millions of Dollars)

Electrical Labor 51.3
Electrical Penetration Assemblies 16.2
Electrical Switchgear 4.1
Heating, Ventilation & Air Conditioning 60.1
Reactor Pressure Vessel Supports .4
Diesel Generators 10.6
DAP Root Cause Analysis 3.2
CPRT Start–Up Costs 90.5
CAP Start–Up Costs 79.9
Construction Permit Lapse .2
TOTAL $316.5
451. The Cities and Public Utility Counsel contend that
The Cities and Public Utility Counsel next contend findings of fact 138 through 152 are “ultimate” findings by
that the Commission's order is improper because it is not which the Commission fulfills its statutory obligation to
supported by underlying findings of fact. We understand exclude from rate base all imprudently incurred post–1985
their complaint to be that the findings of fact do not meet remedial costs, and as such they require underlying find-
the requirements of the APA. See APA § 2001.141(d) ( ings of fact. FN33
“Findings of fact, if set forth in statutory language, must be
accompanied by a concise and explicit statement of the FN33. We limit our discussion to findings of fact
underlying facts supporting the findings.”) The supreme 138, 139, and 140. The Cities and Public Utility
court has concluded that an agency's findings of fact need Counsel waive any separate attack on findings of
the additional support of findings of underlying facts only fact 141 and 142 in their brief, stating that they
when the findings are stated in terms taken directly from consist primarily of calculations that “fall out” of
the enabling legislation or when they “represent the criteria the three previous findings. We understand this to
that the legislature has directed the agency to consider in mean that if the three preceding findings are suf-
performing its function.” Charter Medical, 665 S.W.2d at ficient, there is no independent reason that find-

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ings of fact 141 and 142 are improper. Findings of the magnitude proposed by the intervenors.
fact 143 through 152 are addressed separately in
this opinion. *407 139. As discussed in Section VI.Q.2. of this Re-
port, the costs of executing the Comanche Peak Re-
[21] We first consider whether the findings of fact at sponse Team and Corrective Action Program were
issue are indeed “ultimate findings.” In City of El Paso, prudent.
this Court stated that although PURA does not expressly
require the Commission to make a finding of prudence 140. As calculated in Section VI.Q.2. of this Report, the
before including costs in rate base, once the Commission total imprudent costs incurred by [Texas Utilities]
finds a major project to have been imprudently planned or through the end of the test year is $537.9 million, which
managed, it should generally disallow project costs to the allocates $382.05 million to Unit 1 and $155.85 million
extent of the imprudence. City of El Paso, 839 S.W.2d at to Unit 2.
908.FN34 A determination that an expenditure is imprudent
carries the legal consequence of its exclusion from rate
To meet the criteria set forth in Charter Medical and
base. Such a finding must be supported by underlying
City of El Paso, these findings must be accompanied by
findings because it embodies one of the criteria the Com-
underlying findings connecting evidence to the conclu-
mission must consider in deciding whether to include the
sions expressed in the Commission's ultimate findings. In
particular expenditure in rate base.
support of finding of fact 138, the Examiners' Report ex-
plains that the utility should not be prohibited from in-
FN34. This Court held: cluding any of the costs of the remedial action program in
rate base because other factors contributed to the NRC's
The “statutory language” to which [APA § application of stricter regulatory standards. See Examiners'
2001.141(d) ] refers is the language in the Report at 169. Those other factors are also identified in the
statute that confers authority on the agency to Report: “On balance, although the inspection standards
take the complained-of action. In PURA, the and procedures applied by the Technical Review Team
legislature authorized the Commission to make were the same as those previously used by the project's
orders setting rates. A number of PURA's sec- quality control inspectors, the Technical Review Team
tions also detail the criteria the Commission is conducted its inspections and scrutinized its inspection
to consider in setting rates. Therefore, only results at Comanche Peak in a manner as never before.”
when the Commission's findings are stated in See id. at 124. These findings support the Commission's
PURA's express terms, or when they represent decision not to make the wholesale disallowances pro-
criteria the legislature has directed the Com- posed by the intervenors. Nielsen–Wurster did not rec-
mission to consider, must the Commission also ommend disallowing any costs related to the post-effective
make findings of underlying fact. date execution of the response team or the corrective action
program. See Examiners' Report at 139.FN35 Finding of fact
City of El Paso, 839 S.W.2d at 908 (citations 140 expresses the Commission's final calculation of total
omitted) (emphasis added). imprudent costs incurred by the utility through the end of
the test year. These calculations are supported by extensive
explanations in the Examiners' Report as well as specific
[22] The following findings of fact are here at issue:
findings of fact in the order on rehearing for each element
of the total disallowance. We reject the Cities and Public
138. As discussed in Section VI.Q.2. of this Report, the
Utility Counsel's contention that findings of fact 138, 139,
evidence does not support imprudence disallowances of
and 140 are not adequately supported by underlying find-

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ings of fact. After careful review and consideration of all the ar-
guments raised by the Cities and the Office of Public
FN35. The Report also provides several refer- Utility Counsel, we overrule points of error two through
ences to the administrative record including pages four.
28200–28204 of the statement of facts.
COMANCHE PEAK RESPONSE TEAM DELAY
Finally the Cities and Public Utility Counsel challenge In its first point of error, Texas Utilities complains of
the Commission's failure to impose specific disallowances the Commission's disallowance of $194.4 million repre-
flowing from its finding that the utility imprudently failed senting costs associated with an imprudent seven-month
to infuse its senior management with personnel having the delay in Comanche Peak construction. Each of the utility's
appropriate nuclear experience. During the rate-making arguments advanced under this point of error, however,
proceedings the examiners determined that it was impos- was presented to the Commission*408 during the
sible to state generally the effect of this lack of nuclear rate-making proceeding and rejected with adequate ac-
experience; rather, as in the entire prudence review, the companying findings supported by substantial evidence.
examiners proposed an examination of the utility's discrete We decline to substitute our judgment for that of the
actions and decisions throughout the project. The Com- Commission, and will overrule the point of error.
mission adopted the examiners' reasoning and made dis-
allowances for costs associated with imprudent manage- The utility first argues that there is not substantial
ment.FN36 These disallowances represent the Commission's evidence to support the Commission's finding that Revi-
exercise of its discretion in determining rate base; the sion 2 to the Comanche Peak Response Team Program
findings are not arbitrary or capricious or unsupported by Plan was not a reasonable licensing response. To the con-
substantial evidence. trary, the Commission relied on evidence that the NRC
Technical Review Team letter, issued on January 8, 1985,
FN36. For example, the Commission found that marked a distinct departure from the NRC staff's previous
Texas Utilities management's lack of nuclear position on Comanche Peak's licensability, and that the
experience caused the imprudent decision to Comanche Peak Response Team did not adequately ad-
discontinue the integrated cube schedule and im- dress the outstanding licensing issues raised by the Tech-
plement a start-up driven schedule in May 1980. nical Review Team until the issuance of Revision 3 in
This led to reduced productivity in electrical craft January 1986. Findings of Fact 105, 109. The Commission
labor from June 1980 to September 1981. See further found that Revision 2 should have included a
Findings of Fact 40, 41, 42. Accordingly, the sampling methodology equivalent to that ultimately in-
Commission disallowed $51.3 million in electri- cluded in Revision 3. Finding of Fact 111. The Commis-
cal craft labor costs. The Commission also dis- sion relies on the Examiners' Report to further explain its
allowed $90.5 in costs expended in developing an finding:
effective Comanche Peak Response Team pro-
gram plan and $79.9 million in start-up costs as- [Texas Utilities'] contention that it could not anticipate
sociated with the Corrective Action Program, the unacceptability of the Revision 2 sampling method-
having concluded that these costs arose from ology until after it filed Revision 2 is a red herring. The
management's imprudent decision to discontinue strongly worded third Technical Review Team letter
its comprehensive policy of updating original suggested a possible programmatic quality assur-
design drawings. See Findings of Fact 78, 79. ance/quality control breakdown, a position never before
expressed by the NRC staff.

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path activity during this period was not the sampling-based
Examiners' Report at 133. The utility simply failed to CPRT activities but instead was the 100 percent design
convince the Commission that, as it reasserts in its brief, “it validation of piping and pipe supports....” This Court is
had every reason to believe that the entire program under bound by the Commission's determination as to the weight
Revision 2 ... would be acceptable to the NRC.” The Ex- and credibility of the evidence. As long as there is sub-
aminers' Report outlines many of the same arguments the stantial evidence in the record supporting the Commis-
utility now makes on appeal and explains its rejection of sion's decision, we will not disturb its findings. Suburban
those arguments in light of conflicting evidence and pro- Util. Corp. v. Public Util. Comm'n, 652 S.W.2d 358, 364
posals and recommendations made by the Commission's (Tex.1983) (holding that the agency's action will be sus-
staff. tained if the evidence is such that reasonable minds could
have reached the conclusion that the agency must have
reached in order to justify its action).
[23] The utility next argues that even if there was a
delay in preparing an adequate response plan to NRC
concerns, the delay had no impact on project duration The utility next argues that the work performed pur-
because the project schedule was controlled by a design suant to Revision 2 would have *409 been necessary under
validation of piping and pipe supports that began in Revision 3, and thus failure to adopt Revision 3 until
mid–1985. Again, the Commission specifically rejected January 1986 had no effect on the project schedule. To
this argument when it was presented at the rate-making support this argument, the utility asserts: “There is no
proceeding. evidence in the record that [work performed pursuant to
Revision 2] was not necessary under Revision 3.” They
point to record evidence that work performed in accord-
[T]he examiners reject [Texas Utilities'] argument that
ance with Revision 2 during the seven-month period was
the delay in formulating an adequate Comanche Peak
productive, useful, and necessary under the subsequent
Review Team Program Plan did not delay the comple-
Revision 3. The fact that work performed was productive,
tion of Units 1 and 2. First, the Comanche Peak Review
useful, and necessary does not, however, foreclose the
Team—the initial vehicle by which the Company sought
possibility that activities dictated by Revision 3 could
to assure licensability—constituted the critical path ac-
have, and should have, been carried out contemporane-
tivity for both units during this period. Therefore, any
ously with the necessary Revision 2 activities. In other
imprudent delay in formulating an acceptable Comanche
words, nothing in the record states that the Revision 3 work
Peak Review Team Program Plan delayed fuel load....
could not have begun until all the work done under Revi-
[Texas Utilities] argues that the 100 percent design re-
sion 2 was completed. The Commission specifically found
validation of large bore pipe and pipe supports, which
that Revision 3 greatly expanded the scope of the Co-
commenced sometime in mid–1985, constituted the
manche Peak Review Team effort. This supports a finding
critical path activity with respect to Unit 1 at this time.
that the failure to expand the scope sooner caused delay in
This argument, however, is contradicted by the direct
completing the project.
testimony of [Texas Utilities] witness Mr. Manzi, who
stated the Comanche Peak Review Team's activities
paced the project's schedule through early 1987. Finally, the utility argues that even if the failure to
implement Revision 3 until January 1986 caused delay in
completing Comanche Peak Unit 1, it had no effect on the
Examiners' Report at 134 (emphasis added). Again,
completion of Unit 2. Again, we need look no further than
the Commission's decision is supported by record evi-
the Examiners' Report for references to evidence support-
dence. In its brief, the utility asserts: “The Commission
ing the Commission's decision: “Unit 2 delay costs oc-
improperly rejected the [utility's] evidence that the critical
curred in the same manner as those for Unit 1; both were

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equally affected by the licensing quagmire in which the the utility to present evidence in the rate-making pro-
entire project found itself. [Texas Utilities] witness Mr. ceeding to justify the inclusion of CWIP in rate base. FN37
Nace agreed that the licensing issues facing Unit 1 also Rule 21.69(a) provided:
faced Unit 2.” Examiners' Report at 134. The substantial
evidence standard is well established. Charter Medical, FN37. Public Utility Counsel attempts to join the
665 S.W.2d at 452. We may not reweigh the evidence in Cities in bringing this point of error. However,
order to come to a conclusion different from the Commis- because its motion for rehearing filed with the
sion's. Texas Utilities' arguments on appeal are nothing Commission does not raise this claim, it has
more than a restatement of arguments and evidence con- waived the right to raise it on appeal. APA §
sidered by the Commission and rejected in favor of other 2001.171 (requiring a party to a contested case to
evidence and recommendations. We will not presume to exhaust administrative remedies before seeking
substitute our judgment for that of the agency, but rather judicial review).
uphold its findings that are reasonably supported by sub-
stantial evidence. Texas Utilities' first point of error is
Any utility filing an application, petition, or statement of
overruled.
intent to change its rates in a major rate proceeding must
file all of its evidence, including the prepared testimony
INCLUSION OF CWIP IN RATE BASE of all of its witnesses and exhibits, on the *410 same date
[24] As part of Docket 9300, the Commission deter- that such application, petition, or statement of intent to
mined that the utility should be allowed to include some change its rates is filed with the commission.... A utility
“construction-work-in progress” (CWIP) costs in rate base. filing for a change in rates shall be prepared to go for-
The term “CWIP” refers to money dedicated to facilities ward at a hearing on the data which have been previously
that are currently under construction. Because it is a submitted and sustain the burden of proof of establishing
state-regulated monopoly, a utility has the responsibility to that its proposed changes are just and reasonable, and the
provide utility service that meets public demand. In a material submitted as the filing and supporting work
growing market, therefore, a utility must continually ex- papers shall be of such composition, scope, and format
pand to create greater capacity and must replace existing so as to serve as the utility's completed case.
facilities as they wear out or become obsolete. Although 16 Tex.Admin.Code § 21.69(a) (1993) (since amend-
these projects require huge capital outlays, PURA does not ed).FN38 The Cities argue that Texas Utilities did not in-
allow a utility to include these costs in rate base until the clude CWIP as a basis for rate relief in its request for a
completed facility becomes “used and useful in rendering rate increase filed on January 16, 1990. They assert that,
service to the public.” PURA § 39(a). Before completion in fact, the utility affirmatively disavowed an intention
of a project, the utility includes these construction costs in to request CWIP in the upcoming rate-making pro-
a separate CWIP account. A utility may be permitted to ceeding. The Cities allege that the utility's testimony
include some CWIP costs in rate base as an exceptional regarding the amount of CWIP necessary to maintain its
form of rate relief upon a showing that their inclusion is financial integrity in the face of proposed disallowances
necessary to the utility's financial integrity. PURA § 41(a). came as a complete surprise to the Cities and other par-
In its order on rehearing, the Commission allowed the ties to the proceeding and was tantamount to the utility
utility to include $695,177,625 of CWIP in rate base. In changing the basis of its request for a rate increase in
three points of error, the Cities and Office of Public Utility contravention of Rule 21.69(a).
Counsel challenge this decision.
FN38. The Commission established this rule
In its eleventh point of error, the Cities contend that pursuant to PURA section 43(a) which provides:
the Commission violated Rule 21.69(a) when it allowed

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rate increase, a very likely occurrence in any rate-making
The statement of intent [to change rates] shall proceeding. Even though the utility's conditional request
include proposed revisions of tariffs and for inclusion of CWIP in rate base appears to improperly
schedules and a statement specifying in detail treat CWIP as a means to offset the Commission's disal-
each proposed change, the effect the proposed lowance of imprudent expenditures, it nevertheless satis-
change is expected to have on the revenues of fies the notice requirement of Rule 21.69(a) by announcing
the company, the classes and numbers of utility that the utility intended to request inclusion of CWIP in
customers affected, and such other information rate base if disallowances were recommended. Though the
as may be required by the regulatory authori- utility did not indicate what level of CWIP it would seek, it
ty's rules and regulations. was hardly in a position to do so before the rate-making
proceeding began. We reject the Cities' contention that
they did not know the utility would seek inclusion of CWIP
PURA § 43(a) (emphasis added).
in rate base until the final stages of the proceeding. The
Cities' eleventh point of error is overruled.
We disagree with the Cities' characterization of the
utility's position on CWIP presented in its rate filing
In their twelfth point of error, the Cities and Public
package. Schedule C–4.1, included in the rate filing
Utility Counsel assert that the Commission rewarded the
package, stated, “The Company is not requesting any
utility's imprudence by making CWIP allowances to offset
construction work in progress in rate base, as discussed in
the disallowances of imprudent expenditures. Although the
the testimony of Mr. H. Dan Farell.” Through Mr. Farell's
utility announced its decision to seek CWIP only if its rate
testimony, the utility explains:
request was substantially disallowed, we believe the
Commission applied the proper standard for including
In this particular case ... a relatively large level of CWIP
CWIP in rate base. The Commission *411 determined that
attributable to Comanche Peak Unit 1 as of June 30,
over $2 billion of Comanche Peak Unit 2 CWIP was pru-
1989, is being transferred to rate base as electric plant in
dent and could be included in rate base to the extent nec-
service. Provided the Company's requested rate base
essary to preserve the utility's financial integrity. Finding
and cost of service levels are approved, the Company
of Fact 169. The examiners recommended that sufficient
will have a reasonable opportunity to reverse the nega-
CWIP be included in rate base to allow the utility to re-
tive trends and begin to restore the previously discussed
cover up to 80 percent of its requested rate increase. In
financial integrity measures to acceptable levels without
their report the examiners explained:
the inclusion of CWIP in rate base. However, as dis-
cussed subsequently in conjunction with the overall cost
Including CWIP in rate base may appear to offset any
of capital, any material reductions in the Company's
prudence disallowance and require the ratepayers to in-
requested rate base or cost of service will require re-
demnify the shareholders. However, in reality, the in-
consideration of the issue, and may well make inclusion
clusion of CWIP in rate base does not offset a prudence
of some level of CWIP in rate base necessary.
disallowance. Instead, it reflects a policy determination
that in order to save the Company's financial integrity so
(emphasis added). We are satisfied that the utility
that the utility may continue to provide reliable service,
provided adequate notice of its intent to seek inclusion of
the ratepayers should pay now what they would soon pay
CWIP in rate base in the rate-making proceeding. The
anyway but in greater amounts.
utility did not represent that it would not request CWIP at
all, but rather that it would seek to include CWIP in the
Examiners' Report at 218. The Commission based its
event the Commission materially disallowed its proposed
decision to allow CWIP in rate base on this reasoning

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along with the utility's testimony regarding the need for it found necessary to maintain financial integrity remains
CWIP in rate base to preserve the company's financial the benchmark in light of this reexamination. A conse-
integrity. Conclusion of Law 59. We conclude that the quence of our remand is to moot the Commission's CWIP
Commission included CWIP in rate base to accomplish its findings because they were calculated pursuant to erro-
proper purpose, consistent with the statutory requirements. neous disallowances. We do not, therefore, address the
See PURA § 41(a).FN39 Consequently, we overrule the thirteenth point of error challenging the adequacy of the
Cities and Public Utility Counsel's twelfth point of error. Commission's findings to support a CWIP allowance that
is now immaterial. Similarly, we do not address the Cities
FN39. That CWIP allowances were not made as a and Public Utility Counsel's fourteenth and fifteenth points
direct dollar-for-dollar offset of imprudence dis- of error which attack a specific finding of fact regarding
allowances is clear when comparing the total the CWIP allowance.
disallowance for Comanche Peak Units 1 and 2,
$1,381,144,563, with the amount of CWIP in- GAS RECONCILIATION
cluded in rate base, $695,177,625. This is con- [25] In their sixteenth and seventeenth points of error,
sistent with the Commission's obligation to in- the Cities and Public Utility Counsel complain of error in
clude CWIP in rate base only to the extent nec- the Commission's determination of the proper measure of
essary to ensure the utility's financial integrity. imprudent costs associated with Texas Utilities' purchases
of gas from Texas Utilities Fuel Company (the “Fuel
The thirteenth point of error asserts that the Commis- Company”).
sion failed to make proper underlying findings of fact to
support its decision to include $695,177,625 of CWIP in Part of Docket 9300 involved the reconciliation of fuel
rate base. The Commission set this figure based on its costs incurred by Texas Utilities during the period from
conclusion that the utility required a rate increase of 10.1 April 1, 1983, to June 30, 1989. Fuel reconciliation is a
percent, or $442,353,160, to maintain financial stability. term used to describe periodic adjustments to a utility's
We have already determined that this order must be re- *412 fuel costs made to account for the difference between
manded to the Commission to reconsider disallowances previously anticipated costs and actual, reasonable costs
associated with the 12.2 percent of the project repurchased incurred. The Commission makes these adjustments on a
from the minority interest owners. The Commission will periodic basis because of the practical difficulty of decid-
be required to reevaluate the utility's CWIP requirements ing a new rate case with each variation in fuel prices. In a
in light of the level of disallowance on remand. In making hearing on fuel reconciliation, the utility has the burden of
this determination, the Commission may only consider the proving that its fuel expenses during the reconciliation
financial condition of the utility at the time of the hearing; period were reasonable and necessary expenses incurred to
it may not consider subsequent positive or negative provide reliable service. See 16 Tex.Admin.Code
changes in the utility's financial integrity. Therefore, 23.23(3)(B) (1994). If the fuel is purchased from or pro-
though we agree that the Commission could properly vided by an affiliate, the utility must also show that the
consider including CWIP in rate base, we recognize that its price to the utility is no higher than prices charged by the
decision as to the appropriate amount of CWIP will supplying affiliate to its other affiliates or divisions for the
change, and is dependent upon the disallowances it makes same item or class of items, or to unaffiliated persons or
on remand. We do not, therefore, review the findings re- corporations. PURA § 41(c)(1).
lated to CWIP allowances, as they will be superseded by
the Commission's findings when it reexamines the utility's As part of the fuel reconciliation proceedings in
need for CWIP on remand. The Commission will be re- Docket No. 9300, Texas Utilities sought to establish the
quired to reconsider whether the 10.1 percent rate increase reasonableness and necessity of $7,167,233,745 in natural

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gas costs incurred during the six year reconciliation period. Report as to why the Examiners did not include
Upon reviewing the evidence, the Commission disallowed all 100 contracts reviewed by the Reed Consult-
$29,173,090 of those costs and determined that the re- ing Group in their chart.
mainder were reasonable and necessary expenditures.
There is no dispute that the gas purchase transactions re- The examiners recommend a total disallowance for un-
viewed by the Commission were affiliate transactions; the reasonable expenditures for gas purchases by [Texas
Fuel Company, an affiliate of Texas Utilities, supplies all Utilities] from its affiliate, [the Fuel Company], of
the utility's gas requirements. In addition, because Texas $78,504,776. The remainder of the Company's requested
Utilities is the Fuel Company's only customer, whether the reconcilable gas costs, $7,088,728,967, are reasonable
Fuel Company charged Texas Utilities prices commensu- and should be approved. FN41
rate with those charged to other affiliates or to unaffiliated
entities is not an issue. The Commission's only task was to
FN41. We note that a chart entitled Summary of
determine the extent to which the affiliate fuel expenses
Recommended Disallowances–Gas Contracts
were reasonable and necessary costs that could be included
appearing on page 434 of the Examiners' Report
in Texas Utilities' rate base. At issue in the Cities and
shows an additional recommended disallowance
Public Utility Counsel's sixteenth and seventeenth points
for open access transportation. The total recom-
of error is the Commission's decision to disallow only
mended disallowance on this chart is therefore
$29,173,090 in gas costs as unreasonable expenditures.
$81,504,776. Without explanation, in the sum-
mary section on page 479, the examiners dropped
The Commission arrived at this figure in the following this $3 million disallowance leaving a recom-
way. First, it heard evidence from Texas Utilities regarding mended total disallowance of $78,504,776.
the reasonableness of the approximately 900 gas contracts
subject to the reconciliation proceedings. Then it heard
Examiners' Report at 479. The chart and summary
evidence presented by the Reed Consulting Group, which
imply that the examiners accepted Texas Utilities' evi-
reviewed 100 of the 900 contracts representing eighty
dence regarding the reasonableness of all the gas contracts
percent of the gas purchases made during the reconciliation
not represented in the chart, and allowed all costs related to
period. In their report, the examiners reviewed sixty-four
those contracts in rate base.
contracts, and after considering disallowances suggested
by both Texas Utilities and the Reed Consulting Group,
In its final order, the Commission made specific
made their own recommendations for disallowances for
findings of fact for each gas contract that appeared in the
each contract. A chart included in the Examiners' Report
examiners' chart, rejecting*413 the examiners' recom-
sets forth the disallowances recommended by Texas Utili-
mended disallowance in only five instances.FN42 Like the
ties, the Reed Consulting Group, and the examiners with
examiners, the Commission only disallowed costs associ-
respect to thirty-seven production contracts, six long-term
ated with the contracts that appear in the examiners' chart.
commercial contracts, thirteen short-term commercial
The Commission allowed all costs associated with all other
contracts, and eight spot contracts. See Examiners' Report
gas contracts.
at 448–51. FN40 The Examiners' Report then includes a
summary section which states:
FN42. The Commission disallowed less than the
examiners recommended in four instances:
FN40. There is no explanation in the Examiners'

Contract No. Examiners' Recommendation Commission's Disallowance

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1690 (Empire) $19,222,738 $0
3205 (PG & E) $13,453,686 $0
3697 (Coronado) $ 1,916,756 $1,455,193
3011, 3701, 3707 (Houston $16,721,007 $0
Pipeline, Panhandle)
The Commission disallowed more than the examiners recommended in one instance:
Contract No. Examiners' Recommendation Commission's Disallowance

3076 (Amalgamated) $0 $ 527,308
gas contracts, the Cities' witness, Richard S. Morey, rec-
In points of error sixteen and seventeen, the Cities and ommended a disallowance of $452 million in gas-related
Public Utility Counsel challenge the Commission's gas expenditures. This amount represented fuel costs for the
contract disallowances on two grounds: (1) the Commis- years 1985 through 1988. The examiners determined that
sion did not review all the affiliate gas costs associated Mr. Morey's quantification technique was seriously flawed
with approximately 800 contracts making up twenty per- because it relied on comparisons with utilities not compa-
cent of Texas Utilities' gas costs and as a result included rable to Texas Utilities. The examiners recommended that
unreasonable costs in rate base, and (2) the Commission the Commission reject Mr. Morey's analysis and his rec-
did not make the specific findings required by PURA sec- ommended disallowance, which the Commission did. If
tion 41(c)(1) to support the costs it did allow. Because we that had been the whole of the evidence presented to the
find both arguments to be without merit, we overrule the Commission, it would have been within the Commission's
sixteenth and seventeenth points of error. discretion to allow all the costs requested by Texas Utili-
ties if it found they were supported by substantial evidence.
However, the Commission also considered the evidence
The Cities and Public Utility Counsel essentially ar-
presented by its own auditor and, as a result, disallowed
gue that because the Reed Consulting Group did not re-
some of the expenses associated with the larger gas con-
view the smaller and more numerous gas contracts making
tracts. While the Commission may consider evidence such
up approximately twenty percent of Texas Utilities' gas
as that presented by the Reed Consulting Group, it is not
costs, the Commission did not review the contracts. Simply
required to do so. In the absence of such evidence, it may
because the Reed Consulting Group did not include these
accept or reject the evidence presented by the utility, the
contracts in its sample does not mean that the Commission
party bearing the burden of proof of reasonableness. With
did not review those expenses or that there was no evi-
respect to the smaller *414 gas contracts, the Commission
dence that the contracts met the requirements of PURA
apparently accepted the evidence of reasonableness pre-
section 41(c)(1).
sented by Texas Utilities. If substantial evidence supports
the Commission's findings, which we conclude it does, we
Texas Utilities presented evidence as to the reasona-
must uphold the order. See Auto Convoy, 507 S.W.2d at
bleness of all of the approximately 900 gas contracts sub-
722.
ject to the reconciliation proceeding. As part of its evi-
dence of reasonableness, the utility presented testimony
FN43. Texas Utilities asserted that its three major
justifying its decisions to enter into the various gas con-
gas contracts expired between late 1980 and
tracts.FN43 Opposing the reasonableness of Texas Utilities'
1983, at a time when its forecasts showed a con-

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881 S.W.2d 387
(Cite as: 881 S.W.2d 387)

tinuing increase in the cost of natural gas and this statute demands specific findings of reasonableness for
when prices were still escalating. The utility en- each contract. We disagree. The statute allows the Com-
tered into new contracts during a sellers' market mission to address its specific findings either to “each
with the result that the new contracts were less item” or “each class of items.” The Commission may either
favorable to the utility than they would have been make a contract-by-contract determination of reasonable-
if they had entered into them at another time. ness, or it may group the contracts together and declare
Texas Utilities attributes its failure to obtain gas them all to be reasonable.
in an interstate market to a desire to remain free
from burdensome and expensive federal regula- The Commission made a specific finding that, with the
tion. exceptions set forth in findings of fact 383A–383AAA,
Texas Utilities had established the reasonableness and
The Cities and Public Utility Counsel also maintain necessity of its gas costs. We conclude that these findings
that the Commission did not make the findings of fact meet the requirements of PURA section 41(c)(1).
required by PURA section 41(c)(1) to support an allow-
ance of all gas costs related to those contracts not included AMOCO CONTRACT NUMBER 1627
in the chart. The following are the portions of the Com- [26] In its sixth point of error, Texas Utilities claims
mission order relating to its determination of gas disal- that the trial court incorrectly affirmed the Commission's
lowances: decision to disallow $447,972 as imprudent gas expendi-
tures pursuant to Amoco contract number 1627. At the
Finding of Fact 379: The Company's fuel expenditures Commission hearing, Texas Utilities initially offered evi-
during the reconciliation period of April 1983 through dence indicating that it had purchased fuel in March 1989
June 1989 should be approved to the extent of from Amoco pursuant to contract number 1627, a spot
$10,488,044,993. contract. The Commission determined that the price paid
for this gas was unreasonably high given the spot price of
Conclusion of Law 82: Except to the extent of the dis- gas at the time, and disallowed the excess purchase price
allowed reconciliation period gas costs (reflected in the from rate base. During “surrebuttal testimony,” the utility's
Findings of Fact attached to the order), Texas Utilities fourth opportunity to file testimony on fuel issues, it as-
met its burden of proof under PURA § 41(c)(1), re- serted that the gas purchase was not actually made pursu-
garding affiliate transactions. ant to a spot contract, but rather pursuant to a separate
short-term commercial contract under which the price paid
would be reasonable. The utility explained that it had made
Conclusion of Law 83: Except to the extent of the dis-
an accounting error, forgetting to reform its ledger to credit
allowed reconciliation period gas costs (reflected in the
the purchases to the short-term contract.FN44 The Com-
findings of fact attached to the order), the Company's
mission treated the gas as purchased pursuant to the spot
fuel expenditures during the reconciliation period com-
contract and disallowed the $447,972 it believed to be in
ply with the requirements of P.U.C.SUBST.R.
excess of a reasonable spot price for gas.
23.23(b)(2)(H).

FN44. The utility's testimony was that it had for a
The question for this Court is whether these findings
short time credited purchases made pursuant to a
satisfy the requirements of PURA section 41(c)(1) that
short-term commercial contract with Amoco to
“[a]ny such finding shall include specific findings of the
contract number 1627 because of delay in setting
reasonableness and necessity of each item or class of items
up the short-term contract for payment. Presum-
allowed.” The Cities and Public Utility Counsel assert that
ably, the utility only realized its failure to change

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881 S.W.2d 387
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its records after the rate-making proceeding had reversed this conclusion. Because we agree with the
been under way for some time. Commission that the contract contained no take-or-pay
provision, we will sustain this point of error.
We do not agree with Texas Utilities that its testimony
of an accounting error is uncontroverted or that it neces- The pertinent contract provision provides:
sarily established that the gas was purchased under a
short-term commercial contract as a matter of law. The Delhi hereby grants [the Fuel Company] the option to
Commission, rather, was presented with conflicting evi- purchase up to fifty percent (50%) (calculated in terms
dence: the utility's own records showing the gas purchased of heating value) of the Schlensker–Texas Crude Gas,
pursuant to a spot contract and its contradictory testimony purchased by Delhi, at Delhi's cost of such gas plus 5
that in fact the gas was purchased under a short-term cents/MMBtu. Such option to purchase may be exer-
commercial contract. The utility *415 characterizes the cised by [the Fuel Company] at any time and from time
Commission's decision to rely on the utility's records rather to time during the term of Delhi's respective gas pur-
than the testimony provided by the utility as arbitrary and chase agreements for such gas in blocks of ten percent
capricious. We come to the opposite conclusion. The (10%) of Delhi's purchases, and until [the Fuel Com-
Commission is the judge of the weight to be accorded pany] has exercised completely its option to purchase
witnesses' testimony and is free to accept part of the tes- such fifty percent (50%). Each such exercise of its option
timony of one witness and disregard the remainder. to purchase by [the Fuel Company] shall be evidenced
Southern Union Gas Co. v. Railroad Comm'n, 692 S.W.2d by not less than thirty (30) days prior written notice to
137, 141–42 (Tex.App.—Austin 1985, writ ref'd n.r.e.). Delhi and shall be effective on the first day of the month
The Commission was not required to accept the utility's following that month in which the said thirty (30) day
eleventh-hour accounting error explanation, but was free to period expires.
rely on the utility's own records. It is the utility that carries
the burden of proof at a rate-making proceeding; the utility
Contrary to Texas Utilities' assertions, this contract
that submits records to the Commission that do not accu-
embodies no take-or-pay obligations. It is apparent from its
rately reflect its expenditures does so at its own peril. The
unambiguous terms that the contract gives Texas Utilities
point of error is overruled.
the option to buy, in ten percent blocks and at a fixed price,
up to fifty percent of any Schlenker–Texas crude gas
DELHI CONTRACT NUMBER 1659 purchased by Delhi. We are not persuaded by Texas Utili-
[27] In the rate proceeding, Texas Utilities asserted ties' argument that the phrase “and until TUFCO has ex-
that Delhi gas contract number 1659 contained a ercised completely its option to purchase such fifty per-
take-or-pay clause which obligated the utility to purchase a cent” means that once the utility has purchased at that level
certain amount of gas under the contract. The Commission it must continue to do so. The contract contemplates that
considered the contract and determined that it imposed no whenever Delhi purchases Schlenker–Texas crude gas the
take-or-pay obligation and that Texas Utilities had pur- Fuel Company may purchase up to fifty percent of that gas
chased gas at a price higher than necessary. The Commis- at Delhi's cost plus five cents per MMBtu. The phrase “and
sion concluded that Texas Utilities' gas purchases pursuant until [the Fuel Company] has exercised completely its
to this contract violated its obligation to purchase fuel at option to purchase such fifty percent” sets an upper, rather
the lowest reasonable cost to ratepayers and disallowed than a lower, limit on the utility's right to purchase this gas
$2,509,810 in fuel costs incurred under the contract. See at the contract price; it does not operate to convert the
PURA § 41(c)(1); 16 Tex.Admin.Code § 23.23(b)(2)(H) option to purchase gas into an obligation. We sustain the
(1993) (since amended). In its third point of error, the Commission's third point of error.
Commission contends that the district court incorrectly

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881 S.W.2d 387
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agency could conclude what the utility's future needs will
FUEL OIL INVENTORY be. If the utility could convince the Commission of the
[28] In its fourth point of error, Texas Utilities chal- need to increase that level, then such an increase would be
lenges the Commission's decision to set fuel oil inventory in order. The burden, however, was on the utility. Texas
at 1.7 million barrels. The utility contends that this finding Utilities' fourth point of error is overruled.
is arbitrary and capricious, and not supported by substan-
tial evidence. See APA § 2001.174(2)(E), (F). We disa- RETURN ON COMMON EQUITY FN45
gree.
FN45. We understand “common equity” to mean
Texas Utilities requested a fuel inventory level of the utility's common stock. We refer to the utili-
2,031,540 barrels, an increase of 331,540 barrels from the ty's common stock as “common equity” so as not
previously authorized level of 1.7 million barrels. See to deviate from the terminology used by the
*416Application of Texas Utilities Electric Company for a Commission in the proceeding below. See
Rate Increase, 10 P.U.C.Bull. at 954. The higher figure GTE–SW, 833 S.W.2d at 157 n. 3.
was based on the utility's test-year end thirteen-month
average inventory of fuel oil. The Cities argued that the In points of error eighteen through twenty, the Cities
utility needed a fuel oil inventory of only 1,279,363 bar- and Public Utility Counsel challenge the trial court's af-
rels, suggesting that access to nuclear-generated power firmance of the Commission's decision to set the utility's
from Comanche Peak Unit 1 reduced the utility's need for return on common equity at 13.2 percent. FN46 Specifically,
fuel oil. Additionally, the Cites contended that increased they contend that the Commission (1) did not identify the
levels of non-oil/gas fired generation caused a decrease, methodology it used to arrive at this figure; (2) failed to
rather than an increase, in the necessary fuel oil inventory consider the statutory factors set out in PURA section
level. Texas Utilities countered that it burned 1,201,008 39(a); and (3) did not make adequate findings of fact.
barrels of oil in December 1983 and 1,249,952 barrels
during two cold weather periods in February and March FN46. Return on equity is one element of the rate
1989. The utility hoped to demonstrate that the Cities had of return on a utility's invested capital. Other
miscalculated its needs in the event of cold weather. elements include long-term and short-term debt
and preferred stock.
The Commission rejected both the Cities' and the
utility's requests, adopting instead the examiners' recom- [29] During the rate-making proceeding, all the
mendation that the “level of fuel oil inventory established presentations regarding the appropriate return on common
in Docket No. 5640 of 1.7 million barrels should be left in equity used some form of a discounted cash-flow meth-
place.” This decision was not arbitrary and capricious or odology. Because this methodology was the only one
unsupported by substantial evidence. The examiners based presented, the Commission's adoption of any of the range
their recommendation on an evaluation of the utility's of figures presented as the appropriate return on common
actual needs since the 1.7 million barrel inventory level equity in itself entails adoption of the discounted cash-flow
was established in 1984. The examiners stated, “[I]n light methodology. The Commission's order is presumed to be
of the Company's experience, the examiners find that the based on substantial evidence and we will not require the
level of fuel oil inventory established in Docket No. 5640 Commission to make a separate finding simply to confirm
of 1.7 million barrels should be left in place by the Com- that it has based its decision on the only method of calcu-
mission.” The utility's actual experience over the past lating return on common equity presented during the
several years provides probative evidence from which the rate-making proceeding. See Charter Medical, 665 S.W.2d

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at 451; see also GTE–SW, 833 S.W.2d at 159 (holding that Fact 215 (“Staff's recommended 15–basis–point upward
a return on equity falling within the range presented by adjustment to recognize the Company's exceptional
expert testimony meets the substantial evidence test). We achievement in conservation and load management is
reject the Cities and Public Utility Counsel's attempts to reasonable.”); Finding of Fact 401 (“[Texas Utilities']
look to the transcript of the Commission's final order demand side management achievements have been re-
meeting to show that the Commission based its decision markable, commendable, and clearly far above those of
regarding return on common equity on something other other utilities.”).
than record evidence. We judge the agency order on the
basis on which it purports to rest, and the mental processes [30][31] The chief complaint appears to be the Cities
of individual commissioners are immaterial to judicial and Public Utility Counsel's perception that the Commis-
review. Pedernales Elec. Coop., Inc. v. Public Util. sion made no downward adjustment to the return on
Comm'n, 809 S.W.2d 332, 341 (Tex.App.—Austin 1991, common equity to penalize the utility for instances of
no writ); see also *417City of Frisco v. Texas Water Rights imprudent management. While the statute instructs the
Comm'n, 579 S.W.2d 66, 72 (Tex.Civ.App.— Austin Commission to consider the quality of the utility's man-
1979, writ ref'd n.r.e.) (“The thought processes or motiva- agement, it does not require that the Commission lower the
tions of an administrator are irrelevant in the judicial de- return on common equity if it finds any imprudence. We
termination whether the agency order is reasonably sus- understand the statute to leave to the Commission's dis-
tained by appropriate findings and conclusions that have cretion the decision whether the utility's management
support in the evidence.”). warrants a reduction in the overall rate of return. We also
reject the assertion that the Commission's chosen rate of
The Cities and Public Utility Counsel next argue that return is not supported by adequate findings. The utility
the Commission failed to consider the necessary statutory testified to a recommended range of return from 13 to
criteria in choosing the appropriate return on common 14.25 percent. The staff's recommendation ranged from
equity. The statute directs the Commission to consider, 12.36 to 13.4 percent. The Examiners' Report summarizes
among other things, the utility's efforts to comply with the extensive testimony supporting the various ranges spon-
statewide energy plan, its efforts and achievements in the sored by the parties and the staff. The Commission made a
conservation of resources, the quality of its services, the specific finding that a 13.2 percent return on common
efficiency of its operations, and the quality of its man- equity is reasonable and appropriate for the utility. Finding
agement. PURA § 39(b). Our examination of the order of Fact 213. This Court has already decided that a finding
reveals findings of fact and conclusions of law addressing regarding the appropriate cost of equity is not a finding set
each of these criteria. The Commission addressed the util- forth in statutory language, and therefore needs no under-
ity's operational efficiency, finding that the utility gener- lying findings. City of Alvin, No. 3–92–459–CV, slip op. at
ated electricity efficiently and reliably during the recon- 28; see also GTE–SW, 833 S.W.2d at 158 (approving a
ciliation period and that the energy efficiency plan satisfied finding on return on equity that was “the Commission's
the Commission's substantive rules. Findings of Fact 396, own estimate converted into a finding” so long as the es-
398. Conclusion of law 58 states that Texas Utilities' gen- timate was “within the range made by the testimony of the
eration, transmission, and distribution facilities are safe, various expert witnesses”). Choosing a rate of return is a
adequate, efficient, and reasonable. Regarding the quality proper exercise of the Commission's discretion in setting
of management, the Commission found that, with limited the rate of return, and we will not require any more specific
exceptions, the quality of management was adequate. findings than its selection from a range of rates all sup-
Finding of Fact 12. The Commission also considered the ported by credible expert testimony. The Cities and Public
utility's efforts and achievements in conservation and Utility Counsel's points of error eighteen through twenty
compliance with the statewide energy plan. See Finding of are overruled.

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881 S.W.2d 387
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CASH WORKING CAPITAL
Texas Utilities' fifth point of error complains of the
district court's decision to remand the Commission's cash
working capital allowance. The district court found, and
the Commission agreed, that the Commission made a
mathematical error in its calculation of the cash working
capital. On appeal, Texas Utilities argues that there is no
evidence that the Commission made a mathematical error
and that in any case the district court could not address the
issue because it was not raised in the motions for rehearing
filed with the Commission. See APA § 2001.145. We do
not address this point of error. On *418 remand the
Commission will have an opportunity to recalculate the
cash working capital and correct its mathematical error or
make other changes to cash working capital in light of its
decisions on remand.

CONCLUSION
For the reasons stated in this opinion, we reverse the
district-court judgment and remand the cause to the district
court with instructions that it be remanded to the Com-
mission for further proceedings consistent with this opin-
ion.

Tex.App.–Austin,1994.
Texas Utilities Elec. Co. v. Public Utility Com'n
881 S.W.2d 387

END OF DOCUMENT

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935 S.W.2d 109, 39 Tex. Sup. Ct. J. 267, 40 Tex. Sup. Ct. J. 238
(Cite as: 935 S.W.2d 109)

pealed).

Supreme Court of Texas. *109 Appealed From Austin Court of Appeals, Third
PUBLIC UTILITY COMMISSION OF TEXAS et al., Judicial District; Bea Ann Smith, Judge.Geoffrey M.
Petitioners, Gay, Steven A. Porter, Dan Morales, Steven Baron,
v. Susan Bergen Schultz, Elizabeth R.B. Sterling, Aus-
TEXAS UTILITIES ELECTRIC COMPANY et al., tin, for Petitioners.
Respondents.
Stephen Gardner, Ellen Greer, Stefan H. Krieger, Brad
No. 94–1071. Sutera, Patrick Gattari, Dallas, Alan Holman, James
Feb. 9, 1996. W. Checkley, Jr., Mark W. Smith, Austin, Peggy
Rehearing Overruled Jan. 10, 1997. Wells Dobbins, Coral Gables, FL, Dick Terrell
Brown, Walter Washington, Stephen Fogel, Marion
Taylor–Drew, Jack W. Smith, Mark R. Davis, Austin,
Judicial review was sought of Public Utility
William H. Burchette, A. Hewitt Rose, Washington,
Commission (PUC) order in electric utility rate case.
DC, Jonathan Day, Houston, Michael G. Shirley,
The 250th Judicial District Court, Travis County, John
Rupaco T. Gonzalez, David C. Duggins, Fernando
K. Dietz, J., reversed and remanded in part. Appeals
Rodriguez, Roy Q. Minton, John L. Foster, Austin, J.
were taken. The Austin Court of Appeals, Bea Ann
Dan Bohannan, Dallas, Walter Demond, Austin,
Smith, J., 881 S.W.2d 387, reversed and remanded
Robert M. Fillmore, Howard V. Fisher, Robert A.
with instructions. Utility applied for writ of error. The
Wooldridge, Dallas, for Respondents.
Supreme Court held that, in setting electric utility
rates, PUC is not required to recognize utility's
available tax deductions for disallowed capital costs. PER CURIAM.
This is an appeal from a final order of the Public
Utility Commission in a ratemaking proceeding initi-
Reversed in part and affirmed in part.
ated by Texas Utilities. The district court reversed the
Commission's order in certain respects and remanded
West Headnotes
the case for further proceedings. The court of appeals
reversed the district court's judgment but also re-
Electricity 145 11.3(4) manded the case to the Commission. 881 S.W.2d 387.
We find but one error in the court of appeals' opinion
145 Electricity warranting our review.
145k11.3 Regulation of Charges
145k11.3(4) k. Operating Expenses. Most The Commission refused to reduce Texas Utility's
Cited Cases income tax expenses by potential savings from con-
solidated tax returns with the Texas Utilities' affiliates,
In setting electric utility rates, Public Utility by savings from available deductions for disallowed
Commission (PUC) is not required to recognize util- capital and operating expenses, and by savings from
ity's available tax deductions for disallowed capital available deductions for interest expense. The court of
costs. Vernon's Ann.Texas Civ.St. art. 1446c (Re- appeals held that the Commission should have used an

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935 S.W.2d 109, 39 Tex. Sup. Ct. J. 267, 40 Tex. Sup. Ct. J. 238
(Cite as: 935 S.W.2d 109)

“actual taxes paid” and not a “hypothetical tax” payers. If Texas Utilities refers to assets that are not
standard in applying Section 41(c)(2) of the Public currently included in the rate base but will be in the
Utility Regulatory Act, Act of June 2, 1975, 64th Leg., future, its argument may be that related interest de-
R.S., ch. 721, § 41(c)(2), 1975 Tex.Gen.Laws (for- ductions should be allotted to future ratepayers. All
merly TEX.REV.CIV.STAT.ANN. art. 1446c, § such matters are within the Commission's discretion,
41(c)(2), recodified without change as Section which was properly exercised in this case. If Texas
41(c)(2) of the Public Utility Regulatory Act of 1995, Utilities refers to assets that will never be included in
id. art. 1446c–0, § 2.208(c)). From this the court of the rate base because they have been disallowed, then
appeals concluded that the Commission should have its argument may be that related interest deductions
reduced Texas Utility's estimated income tax expense should be treated consistently with other deductions
by: (1) the utility's “fair share” of savings from con- for disallowed capital expenses. We agree.
solidated tax returns with the utility's affiliates; (2) the
utility's available deductions for disallowed capital Because the opinion of the court of appeals con-
and noncapital expenses; and (3) available deductions flicts with our decision in GTE–Southwest, we grant
for interest expense “to the extent that we continue to Texas Utilities' application for writ of error, and
require the Commission to pass through to ratepayers without hearing oral argument, reverse the judgment
any tax benefits from interest expense deductions”, of the court of appeals to the extent that it conflicts
but not necessarily immediately. The latter saving, with this opinion. TEX.R.APP.P. 170. Texas Utilities'
*110 the court explained, must be allocated between application does not complain of any other error in the
present and future ratepayers, in the Commission's court of appeals' opinion that requires reversal. We
discretion. 881 S.W.2d at 398–400. deny the applications of the Public Utility Commis-
sion, the Office of Public Utility Counsel, and the
The appeals court's opinion preceded and con- Cities of Arlington, et al. Id. Rule 133. Thus, the
flicts with our decision in Public Utility Commission judgment of the court of appeals is, in all other re-
v. GTE–Southwest, Inc., 901 S.W.2d 401 (Tex.1995). spects, affirmed.
There we held that neither PURA § 41(c)(2) nor the
reference to taxes “actually incurred” in Public Utility Tex.,1996.
Commission v. Houston Lighting & Power Co., 748 Public Utility Com'n of Texas v. Texas Utilities Elec.
S.W.2d 439, 442 (Tex.1987), required the Commis- Co.
sion to apply an “actual-taxes-paid” methodology to 935 S.W.2d 109, 39 Tex. Sup. Ct. J. 267, 40 Tex. Sup.
estimate a utility's income tax expense. We held that Ct. J. 238
the Commission “has neither the power nor the dis-
cretion to consider expenses disallowed under section
END OF DOCUMENT
43(c)(3).” 901 S.W.2d at 411. Although we did not
directly address whether the Commission is required
to recognize available deductions for disallowed cap-
ital costs, as opposed to noncapital costs, id. at
411–12, our reasoning applies equally to both.

Regarding deductions for interest expenses,
Texas Utilities argues that the court of appeals erred
“to the extent” it required that tax deductions related to
assets not included in rate base be passed on to rate-

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
 Appendix F

PUC Docket No. 18249, Order on Rehearing
 E .
i ’jf

-.
4i
PUC DOCKET NO. 18249 L1
1,

I/
ENTERGY GULF STATES, INC. 8 PUBLIC UTILITY C0kME~SKQli
SERVICE QUALITY ISSUES 0
(SEVERED FROM DOCKET NO. 16705) 8 OF TEXAS

ORDER ON REHEARING

This Order addresses electric service quality issues relating to Entergy Gulf
States, Inc. (EGS or the Company). The Commission concludes that the quality of EGS’
electric service to its customers in Texas has been less than adequate, specifically since
Entergy Corporation acquired Gulf States Utilities, Inc., in 1993. The record evidence
reveals a lack of effective and prudent maintenance pdicies, uneven spending in the area
of operations and maintenance (O&M), cuts in experienced personnel, and consequent
deterioration in the quality of service. The management of EGS is structured in a way
that fails to link resource availability with appropriate performance accountability.

The Commission further concludes that the difficulties EGS has experienced with
its quality of service are not simply “customer perception” problems, as claimed by the
Company.’ The problems are real and must be addressed by the Company in a timely
and serious manner. To motivate the Company to revise its current approach and
promote long-term commitment toward service quality and reliability, the Commission
orders a two-part solution designed both to deal with past problems and implement
remedies for the future. First, the Company’s authorized return on equity (ROE) that
otherwise would be adopted in Docket No. 167052 will be reduced by 60-basis points and
initially refunded to distribution-level customers. Second, going forward, the Company

1
EGS Initial Brief (IB) at 4 (Dec. 2, 1997); see also, Tr. at 23 1.
2
Application of Entergy Texas for Approval of Its Transition to Competition Plan and the Tar&
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Costs, to Set
Revised Fuel Factors, and to Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705
(pending).
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 2

will have an opportunity to earn back a portion of the ROE reduction, depending on
whether its service quality meets specified benchmarks. These benchmarks will establish
service reliability standards (outage frequency and duration) and customer service
standards (billing errors, call-center performance, service installation, line extension, and
street light replacement). The margin achieved above the benchmarks will reflect the
level of improvement (or, if below, a lack thereof) and will be used to determine whether
the Company is entitled to recoup a portion of the ROE reduction.

I. Procedural History

EGS filed its transitiodrate case in Docket No. 16705 on November 27, 1996.
The Commission referred the case to the State Office of Administrative Hearings
(SOAH)on December 5, 1996. On January 24, 1997, the Commission issued a
preliminary order in Docket No. 16705 directing parties, among other things, to “address
specific service quality standards that will apply after the transition [proposed by EGS].”3

On March 7, 1997, the Commission issued a supplemental preliminary order in
Docket No. 16705 that dealt specifically with service quality issues. This order required
that Docket No. 16705 address, in addition to others, the following issues: (1) Does EGS
have an effective and prudent management policy in place that devotes sufficient
resources to ensure adequate and reliable service to its ratepayers? (2) Are there patterns
of variable service quality in EGS’ service territory, and if so, what is the cause and
potential resolution of these variations? and (3) What procedures can and should the
Commission implement to monitor service quality on EGS’ system, and to respond to
situations in which EGS’ service quality falls below the service quality benchmark
levels?

3
Preliminary Order at 12 (January 24, 1997).
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 3

Proceeding with EGS’ rate case, SOAH established a four-phased hearing
schedule to address the numerous transition and rate issues in Docket No. 16705. The
service quality issues were to be dealt with in the “Competitive Issues” phase, scheduled
to begin in early November 1997.

After EGS and interested parties had filed written testimony and exhibits: but
before the Competitive Issues phase commenced at SOAH, the Commission determined
that it would itself hear and resolve the service quality issues. Accordingly, on November
4, 1997, the Commission issued an order severing the pending service quality issues from
Docket No. 16705, establishing Docket No. 18249 to deal with those issues, and
establishing procedures by which the Commission would hear and rule on the case.

The Commission convened a hearing on the merits of EGS’ service quality on
November 20 and 21, 1997. Chairman Pat Wood and Commissioner Judy Walsh
presided over the hearing. The participating parties included the Company, the Cities, the
High Load Factor Commercial Customer Group (HLFCCG), and the General Counsel, all
of whom presented their direct cases and conducted cross-examinations. Chairman Wood
and Commissioner Walsh also directed questions to the witnesses. Observers from the
Office of Public Utility Counsel (OPUC) and the Attorney General’s Office attended the
hearing. The active parties filed initial and reply briefs on December 2 and 9, 1997,
respectively. OPUC filed a statement on December 2, 1997, supporting the briefs of the
Cities and HLFCCG, and the Attorney General’s Office filed a statement on December 9,
1997, in support of the same briefs.

The Commission issued the final order in this docket on February 13, 1998. On
March 5, 1998, EGS and General Counsel filed motions for rehearing. The replies to the
motions were due on March 16, 1998, but based on parties’ request, the Commission

4
Some of the testimony, particularly from the Company’s witnesses, was originally pre-filed for the
Revenue Requirement phase.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 4

granted an extension for filing of replies until March 25, 1998. On March 19, 1998, the
Commission ratified the extension of deadline to file replies and also extended until May
14, 1998, the time to rule on the motions for rehearing pursuant to GOV’T CODE
2001.146(e).

On March 25, 1998, the parties filed a joint reply to motions for rehearing and
motion for entry of order consistent with the parties’ stipulation and agreement (the
Stipulation). General Counsel, EGS, OPUC, and HLFCCG signed the Stipulation. At
the April 1, 1998 open meeting, the Commission granted rehearing and approved the
Stipulation. The provisions of the Stipulation are reflected in this Order.

11. Background

Entergy Gulf States, Inc., is a public utility subject to the jurisdiction of this
Commission in accordance with Public Utility Regulatory Act (PURA) $6 14.001,
31.001, 32.001, 33.122, and 36.001 through 36.156.5 EGS is a wholly-owned subsidiary
of Entergy Corporation (Entergy), a holding company incorporated in Delaware and
registered with the federal Securities and Exchange Commission in accordance with the
Public Utility Holding Company Act. Entergy acquired Gulf States Utilities, Inc., to
create EGS, effective on December 3 1, 1993.6

EGS operates in Louisiana and Texas, and is afiliated through its holding
company with investor-owned electric utilities located in Louisiana, Mississippi, and

5
Public Utility Regulatory Act, TEX.UTIL.CODEANN. 11.001-63.063(Vernon 1998).
6
Application of Entergv Corporation and Gulf States Utilities Companyfor Sale, Transfer, or Merger,
Docket No. 11292 (Mar. 25,1994).
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 5

Arkansas7 The EGS service territory in Texas is located in the southeastern part of the
state, and contains industrialized areas in the vicinity of Beaumont and Port Arthur, as
well as a coastal zone. The differing geographic and climatic characteristics of the
Company’s service territory have led to the creation of three distinct sectors: Western I
(suburban with dense trees), Western I1 (rural with fewer trees), and Gulf (both rural and
urban).

Entergy’s headquarters is in New Orleans; EGS’ principal office in Texas is
located in Beaumont. In Texas, the Company serves approximately 3 18,279 customers’
and has 11,472 miles of distribution lines. There are 394,865 poles’ in its system, with
43 1 feeders.” The transmission system--built as early as 1924, with approximately half
of the lines added in the 1950’s and 1960’s and only 12 percent of lines built or
rehabilitated after 1977--has shown generally good performance.” This Order is
concerned predominantly with the state of the Company’s distribution system.

111. Discussion and Analysis of Issues

A. General Concept of Reliability

Electricity plays a vital role in our lives. Most, if not all, aspects of our society,
including industrial production, commerce, and individual lifestyles, are built around a
reliable and adequate supply of electrical energy. People have come to depend on

7
Entergy Arkansas (including the Arklahoma Corporation), Inc., Entergy Louisiana, Inc., Entergy
Mississippi, Inc., and Entergy New Orleans, Inc. These companies, together with EGS, form the
“Operating Companies.”
8
Ice Storm ‘97Field Investigations, Project No. 16301, at V-25 (June 24, 1997).
9
General Counsel Ex. 5 , Burrows Direct Testimony at 33, Attachment JDB-2.
10
General Counsel Ex. 24.
I1
General Counsel Ex. 1, Ethridge Direct Testimony at 6.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 6

electricity being available when they need it. In fact, for most customers, delivery of
electrical power and reliability of its delivery have become two inseparable expectations.
Electric utilities generally recognize and accept this dependence and have responded to it
by constructing and operating generation and delivery systems of superior reliability.l2
State law formalizes the utilities’ obligation to provide reliable service in PURA
0 37.151. Reliability, however, is not a static concept. As customer bases grow and
systems age, utilities face new challenges that must be acknowledged and resolved to
maintain reliable service.

In addition to sufficient generating capacity, transmission and distribution
facilities are built so that a specified degree of reliability is achieved. The goal is to
provide required amounts of energy with no, or few, interruptions, while maintaining a
reasonable cost of the overall system. Smooth and continuous interaction of the various
elements of the electrical system results in reliable performance of the overall system.
For consumers, this reliability is reflected in uninterrupted power supply, the degree of
which may be measured by the frequency, duration, and magnitude of adverse effects on
consumer service.

B. Legal Standards

PURA imposes various obligations on utilities and the Commission regarding the
provision of electric service to Texas consumers. Specifically, PURA 0 37.151 requires
that a regulated utility provide continuous and adequate service in its certificated service
territory. PURA 6 38.001 directs utilities to furnish service, instrumentalities, and
facilities that are safe, adequate, efficient, and reasonable. Parallel responsibilities rest
with the Commission. In accordance with PURA 0 36.052(3), the Commission must
consider the quality of a utility’s services in establishing a reasonable return on invested

12
NORTHAMERICAN
ELECTRICRELIABILITYCOUNCIL,
RELIABILITY
CONCEPTS1-2 (Feb. 1985).
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 7

This same section of PURA directs the Commission to consider the quality of
~apita1.l~
the utility’s management and the efficiency of its operations when establishing a
reasonable return. Moreover, PURA tj 38.071 authorizes the Commission to order an
electric utility to provide “specified” improvements in its service.

C.Analysis of Issues

The Commission’s analysis of the issues in this case is divided into five general
topics: (1) physical facilities, maintenance, and monitoring; (2) vegetation management;
(3) emergency preparedness, response, outage restoration, and treatment of storm data;
(4) personnel levels, management practices, and spending levels; and (5) pockets of
unreliable service and overall customer service. The following narrative lays out
essential points of the relevant issues; with additional, specific information contained in
the Findings of Fact in Section IV.

1. Physical Facilities, Maintenance, and Monitoring

a. Condition of Poles
As stated above, EGS’ transmission system does not pose serious concerns since
it has performed adequately over the last few years, during which only a minimal number
of transmission-related outages or circuit-breaker operations occurred. EGS’ inspection
and treatment programs relating to its transmission system seem to be working

13
There are several precedent cases in which the Commission reduced ROE to address inadequate quality
of service. See, e.g., Application of General Telephone Company of the Southwest for Authority to
Zncrease Rates, Docket No. 3094, Final Order, 6 P.U.C. BULL.92, 123 (Aug. 8, 1980) (imposing penalty
on company for inadequate service quality); Application of General Telephone Company of the Southwest
for Authority to Zncrease Rates, Docket No. 3690, Final Order, 7 P.U.C. BULL.11, 39 (June 18, 1981)
(sustaining penalty due to persistence of poor service); Application of General Telephone Company of the
Southwest for Authority to Zncrease Rates, Docket No. 4132, Final Order, 7 P.U.C. BULL. 646, 648 (Jan.
14, 1982) (lifting penalty after service was shown to improve for a sufficient period of time); Application
ofHouston Lighting and Power Company, Docket No. 4540, Final Order, 8 P.U.C. BULL75 (Dec. 6, 1982)
(reducing company’s ROE because of service quality and reliability concerns).
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 8

14
satisfactorily, with transmission line rights-of-way (ROW) appearing generally clear.
For these reasons, the Commission concludes that the physical state of the Company’s
transmission system is adequate. The remainder of this Order will address the
Company’s distribution system and related services.

Primary evidence for the condition of EGS’ distribution system, including wires,
poles, pole appurtenances, and transformers, comes from the Osmose Wood Preserving
Company (Osmose) inspections conducted in 1995 and 1996, a report filed by Drash
Consulting Engineering, Inc. (Drash), and limited Staff survey^.'^ In general, most of the
poles in the Texas portion of the Company’s distribution system are in good condition.
There are, however, numerous poles with physical deficiencies or in need of extensive
and comprehensive vegetation clearing.16

The Osmose inspectors, contracted by EGS in 1995 and 1996, examined
approximately 37,000, or 10 percent, of the poles and crossarms and found that on
average 17.9 percent of poles in eight different areas showed structural decay.17 The
actual percentages, however, varied greatly, with one area having more than 37 percent of
the poles with some decay, a condition clearly impermissible for any transmission and
distribution (T&D) system.” While the Osmose inspections were not random, and in
fact, as the Company asserts, focused on particularly troubled spots, the results show that
there are many poles in unsatisfactory condition.

14
General Counsel Ex. 1,Ethridge Direct Testimony at 6 4 4 1-43.
15
General Counsel Ex. 1, Ethridge Direct Testimony at 15; General Counsel Ex. 4; General Counsel Ex. 5,
Burrows Direct Testimony, Attachment JDB-3.
16
Id. at 5 .
17
General Counsel Ex. 5 , Burrows Direct Testimony at 17.
18
Id, Appendix Workpapers at 2.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 9

The purpose of the Drash report, contracted for by the Commission, was to collect
data regarding the condition of EGS' overhead distribution system. The survey was
based on a sample of 33 uniformly distributed substations from the Texas portion of EGS
distribution system.'' The Drash inspectors examined 582 poles on various feeders
originating at these substations.20 The Drash survey found 59 poles with structural
deficiencies and 72 poles with ROW encroachments.21 During the hearing, EGS raised
questions about the accuracy and statistical reliability of the Drash report. The
Commission concludes that the Drash study lacked specific evaluation criteria and
necessary randomness to draw conclusions about the entire EGS Texas system. The
Commission, however, does not reject the Drash report, as requested by the
rather, the Commission relies on the report to the extent that its findings have been
confirmed by the Osmose inspections and Staff surveys. Considered together, the
collected data persuasively indicate that numerous poles show decay, are in need of repair
or replacement, and that vegetation growth poses a serious problem on some ROW.

b. Pole InsDection Promam
The Company conceded that it does not have a traditional pole inspection
program in place.23 Since the Osmose inspections in 1996, there have been no pole or
crossarm inspections on Texas territory.24 Post-merger, EGS reduced the number of
inspections; for example, in 1995,29,294 poles and 43,941 crossarms were inspected, but
in 1996, only 7,939 poles and 11,908 crossarms underwent inspection^.^^ The Company

19
Id. at 19.
20
Id. at 20.
21
Id. at 21-22.
22
Tr. at 552-60,606-15.
23
Tr. at 176, 751-52.
24
Tr. at 170, 177-78.
25
General Counsel Ex. 19 at Bates Stamp 0 194741.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 10

is now planning to hire Osmose to carry out a ten-year inspection program that will cover
the entire system (35,000 poles inspected annually).26 Evidence presented in the case
makes it clear that EGS’ pole inspection and repair work cycles have not been sufficiently
rigorous, continuous, or frequent to maintain all of its facilities in the condition required
to meet its reliability and service obligations under PURA.

c. Maintenance Practices
A review of maintenance records shows that line maintenance and vegetation
control are reactive in nature:7 there is a lack of written, specific, and preventive
maintenance policies:’ and priority is given to capital additions to the detriment of
adequate maintenance pra~tices.2~
For example, total line-miles actively maintained by
the Company’s employees dropped 30 percent from 1994 to 1996.30 The Company’s
internal risk assessment study points to an absence of a strategic plan, and consequent
inadequacies in resource sharing and work planning.31 Based on the evidence, the
Commission concludes that EGS has failed to establish and carry out distribution
maintenance policies in a manner sufficient to ensure adequate and reliable delivery of
electric service.

d. Data Collection
The Company presented a variety of data to support its claim of good
performance; however, the accuracy of its data collection practices came under a great
deal of scrutiny during the hearing, bringing into question the ability of the Company to

26
Tr. at 75 1-52.
27
General Counsel Ex. 4, Gonzalez Direst Testimony at 6-8, Drash Report at 45-46.
28
Tr. at 59; HLFCCG Ex. 1, Patton Direct Testimony, Entergy Internal Audit and Risk Assessment.
29
General Counsel Ex. 1, Ethridge Direct Testimony at 19-20; General Counsel Ex. 8; General Counsel
Ex. 19.
30
Tr. at 737.
31
General Counsel Ex. 30 at 2.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 11

monitor its performance fairly. The parties debated at length the merits and mechanics of
various system monitoring tools and reporting standards. These include: (1) System
Average Interruption Frequency Index (SAIFI), a measure of the number of interruptions
per year for the average (2) System Average Interruption Duration Index
(SAIDI), a measure of the total interruption time experienced by the average ~ustorner:~
(3) Customer Average Interruption Duration Index (CAIDI), defined as the ratio of
SAIDI/SAIFI;34 (4) Distribution Interruption System (DIS), a database to capture
reliability performance and indices for individual feeders:5 (5) Average System
Availability Index (ASAI),36 a measure of the total time of service availability to the
average customer; and (6) TACTICS, which captures data on every device down to the
transformer level to measure each device's operational performance and impact on
customers.37 In addition, the Company utilizes a System Control and Data Acquisition
device (SCADA) to measure data for large interruptions such as feeder breaker outages:'
and the new Automatic Mapping and Facilities Management System (AM/FM),
developed in order to determine where an outage occurred and what device caused it,
which will be completed by the year 2000.39

General Counsel, Cities, and HLFCCG argued that the number of customers
affected by outages and the duration of such outages are difficult to determine because

32
HLFCCG Ex. 1, Patton Direct Testimony at 9-12.
33
Id. at 10.
34
Id.
35
Id. at 11.
36
General Counsel Ex. 3, Eckhoff Direct Testimony at 20.
31
Tr. at 448-450.
38
Tr. at 238,443.
39
Tr. at 429-30.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 12

EGS excluded relevant information between 1994 and 1996.40 For example, for the first
six months of 1996, the Company reported 35 to 40 percent fewer outages than were
reported on average during the first six months of the years 1991-94.41 In trying to
explain the discrepancies in the data, Company officials described changing data
collection standards applied to the various outage-causing events. At different times, the
Company excluded outages caused by equipment failures; outages affecting feeders with
fewer than 500 customers; storms, generation or transmission outages; or trees falling
into the ROW (“non-preventable” trees).42 The Company data is generally confusing
and comparisons over a period of several years are diMicult to make because of changing
standard^:^ in addition, the inaccuracies are further compounded because, for example,
outages on feeders with fewer than 500 customers can nevertheless result in very long
outage durations, especially when those feeders are energized last.44

The evidence shows that Company linemen sometimes made subjective
determinations as to the cause, duration, or effect of an outage, thus causing the
Company’s SAIFI and SAID1 numbers to be unreliable.45 The evidence also revealed
that most historically deficient feeders serve rural customers.46 This observation is
supported by EGS’ testimony that it prioritizes restoration of feeders serving the greatest
numbers of customers, thus leaving those in lower-density areas (most likely rural) to
experience recurring and longer service reliability problems.47

~ ~~

40
See HLFCCG Ex. 2, Entergy Southwest Reliability Report 1994-1996; Tr. at 41-43.
41
HLFCCG Ex. 3 at slide 9.
42
Tr. at 41-44,54,62-66.
43
Id; HLFCCG Ex. 2 at Bates Stamp 0232514.
44
Tr. at 67.
45
Tr. at 47-48.
46
Tr. at 707, 821
47
The Rebuttal (redacted) Testimony of Dereck Hasbrouck on behalf of the Company contains this quote:
“One important fact to keep in mind when considering a customer or group of customers who consistently
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 13

General Counsel, Cities, and HLFCCG asserted that the Company has
manipulated information to show better perf~rmance.~’A significant problem with the
Company’s use of performance and reliability indices is that they reflect outage
frequency and duration on a system-wide rather than feeder-by-feeder basis which can
mask poor performance of individual feeders.49 For example, EGS reported a system-
wide SAIDI of 133 minutes for 1996;’ but this measure failed to reveal that 83 feeders or
primary circuits experienced outage times in excess of 200 minutes.51 The average
customer on these circuits experienced an outage duration of 3.3 hours.52 More notably,
customers on feeder Tamina encountered 41.3 hours of outage time in one year.53 It is
apparent that system-wide averages used by the Company cannot be relied on to disclose
many of the localized service difficulties.

The historic data presented by the Company is not accurate and consistent as the
Company itself admitted to not collecting all relevant data,54changing the standards for
data collection, and submitting inconsistent data for ASAI and S A I F I . ~Even
~ the

receive less reliable service than the average customer is that there are geographic and environmental
conditions beyond the utility’s control. These conditions, in combination with the construction cost
considerations may effectively limit the realistic reliability expectations for customers in certain areas. In
EGS Texas’ service territory, the Bolivar Peninsula and Sabine Pass may be examples where these
constraints come into play .” EGS Ex. 11, Hasbrouck Rebuttal Testimony at 39.
48
Tr. at 278-79, General Counsel Ex. 3, Eckhoff Direct Testimony at 54.
49
General Counsel Ex. 3, Eckhoff Direct Testimony at 18, Appendix H and I; Tr. at 41-67; HLFCCG Ex.
1, Patton Direct Testimony at 12-14.
50
General Counsel says SAIDI in 1996 was 157 mbutes. General Counsel Ex. 22; HLFCCG Ex. 1,
Patton Direct Testimony at 13.
51
HLFCCG Ex. 1, Patton Direct Testimony at Exhibit ADP-3.
52
Id.
53
General Counsel Ex. 3, Eckhoff Direct Testimony, Appendix H..
54
Tr. at 706.
55
General Counsel Ex. 3, Eckhoff Direct Testimony at 54.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 14

Company’s internal audit revealed that reporting of outages has not been c o n s i ~ t e n t . ~ ~
EGS cannot correctly measure how many individual customers lose service because of an
outage affecting parts of a feeder.57

The Commission concludes that the types of information monitoring and
reporting tools relied on by the Company are useful, but they must be employed
uniformly and consistently to be meaningful measures of service quality. The
Commission finds that the level of EGS’ service quality and reliability, as documented
through the Company data, is unreliable because the data fail to record and report all
events accurately and consistently. Pockets of inadequate service are ignored by system-
wide measures, and such measures do not identify recurring individual-feeder problems.

2. Vegetation Management

Vegetation management is the catch-all description for programs involving the
removal of trees, bushes, or vines that overhang, grow into, or toward conductors strung
along the Company’s ROW. The purpose of vegetation management is to ensure, to the
greatest extent possible, that vegetation in, or near, the ROW does not come into contact
with the conductors and thereby cause wire breakage or ground faults.58 During the
hearing, Company witnesses referred to scheduled tree trimming, carried out on a three-
year cycle in urban areas and a six-year cycle in rural areas. The evidence presented,
however, was not clear on whether EGS actually followed the stated cycles.59
Nonetheless, the Company argued that its vegetation management has been adequate and

56
Cities Ex. 1, Lawton Direct Testimony at 12.
57
Tr. at 445-46.
58
Tr. at 176-178.
59
Tr. at 602,728.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 15

consistent with industry practice.60 In fact, EGS asserted that it had improved vegetation
management and introduced efficiencies when compared to the pre-merger period.61

General Counsel, Cities, and HLFCCG presented extensive evidence to document
serious neglect of vegetation management and consequent heightened risk to the
distribution system. The majority of incidents included in the evidence involve three
types of vegetation-related damage: wires expanding down into vegetation due to
increased load or lack of under-clearance; overhanging limbs breaking or growing into
wires in non-inclement weather; and limbs or trees bending or breaking onto wires due to
wind, ice build-up, or other adverse weather conditions. These parties also argued that
the ROW surveyed were in need of extensive clearing and that vegetation encroachments
posed unacceptable risks.62 Cities claimed that neglected vegetation management
multiplied the severity of the ice storm in January 1997.63 The number and duration of
vegetation-caused service interruptions almost doubled in the last four and
vegetation-related SAIDI and SAIFI have worsened since the merger.65

The author of a vegetation management study, commissioned by the Company,
observed that there were areas where maintenance clearing had been deferred until brush
reached the conductors.66 The study proposed specific and comprehensive ways for

60
EGS Ex. 10, Ervin Rebuttal Testimony at 55, 59. EGS states that more than 80 percent of the
Company's vegetation management expenditures are allocated to trimming, which is above the industry
norm.
61
EGS Ex. 8, Ervin Supplemental Direct at 22.
62
General Counsel Ex. 4, Gonzalez Direct Testimony at 6-8; General Counsel Ex. 1, Ethridge Direct
Testimony at 8-1 1.
63
Tr. at 305-08.
64
HLFCCG Ex. 1, Patton Direct Testimony, Exhibits ADP-IO, ADP-13 (illustrating values for system-
wide SAIDI for Texas increased from 21.17 in 1994 to 40.36 in 1997, and SAIFI doubled, from .31 in
1994 to .63 in 1997).
65
General Counsel Ex. 37.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 16

ROW maintenance, but the Company presented no evidence that the study’s findings had
been implemented. An e-mail sent in August of 1997 by an EGS network manager in
Beaumont identified trees touching conductors as one of the preventable root causes of
several recent outages.67

The Commission concludes that the level of the Company’s vegetation
management is unacceptable and has significantly affected the reliability of the
distribution system in recent years. While such a deficiency may not in itself impact a
typical system severely, this deficiency is magnified when the inadequacy of the
infrastructure and the nature of the weather in the Company’s service area are taken into
account.68 The lack of preventive vegetation control efforts by the Company and neglect
of regular vegetation clearing have led to the creation of unnecessary risks. The
Commission does not suggest that “ground-to-sky” tree trimming is necessary, but the
Company clearly has significant room for improvement. The recent hiring of 30 new
vegetation clearance crews, while welcome, confirms the existence of an unacceptable
backlog in vegetation control.69 As will be discussed below, the Commission is also
concerned that managers in Texas have no clear line of authority or resources necessary
to implement effective vegetation management policies.

66
General Counsel Ex. 27, Environmental Consultants, Inc., Report on Distribution Line Clearance
Program (Jul. 1994) at 1-2-3.
61
HLFCCG Ex. 6.
68
Tr. at 308.
69
Tr. at 730-3 1,787.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 17

3. Emergency Preparedness, Response, Outage Restoration, and Treatment of
Storm Data

a. January 1997 Ice Storm
In midJanuary 1997, many parts of Texas experienced a severe ice storm;
disruptions of electric service were sustained by most utilities in the state.70 The impact
on EGS’ territory was particularly hard. At one time, up to 120,000 of EGS’ customers
were without power and it took seven days to complete the restoration process.71
Utilizing help from other utilities and contract workers, EGS had more than 2,700
personnel working to restore service.72 In assessing the Company’s performance, EGS
officials compared it to that of other utilities and concluded that its efforts were not only
adequate, but even “very They blamed most of the damage on excessive ice.74

This view was not shared by the other par tie^.^' HLFCCG played excerpts from
taped conversations conducted by the Company’s dispatchers during the storm, which
highlighted insufficient numbers of personnel and initially inadequate efforts to repair the
damage?6 The Cities asserted that they had to use their own employees for repairs,
including the handling of live wires,77and that in some instances they were unable to
reach Company employees at all.78 One of the Cities’ exhibits was a letter, dated August

~ ~~

70
General Counsel Ex. 2B, Hughes Workpapers, Ice Storm ‘97 Field Investigations Project 16301 at 11-1.
71
EGS Ex. 8, Ervin SupplementalDirect Testimony at 53.

72 Id.
73
Id. at 74.
74
Id. at 74-75.
75
Tr. at 379; Cities Ex. 1, Lawton Direct Testimony at 12.

76 Tr. at 87-92.
77
Tr. at 376.
78
Cities Ex. 2, Kimler Direct Testimony at 2.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 18

17, 1995, from several fire chiefs in EGS’ service territory to the Company describing
various problems with emergency procedures, such as not being able to reach the
Company’s 1-800 telephone number, and, apparently, this problem persisted.79 Some
other cities’ representatives testified, however, that the Company’s restoration efforts
were good.” The significant disparities in the Company’s response to the damage caused
by the ice storm suggest a need for greater and clearer communication between the
Company and all cities, including development of contacts before an emergency occurs.

The Company has an emergency plan on file with the Commission; the plan
contains no obvious deficiencies.’l As is industry practice, EGS also has agreements
with other utilities for emergency cooperation; those agreements, however, are not in
writing.’2

The January 1997 ice storm was certainly a severe storm that would have
adversely affected even the best-maintained distribution system. EGS’ distribution
system, however, is not the best-maintained. A major cause of the outages during the
storm were broken or bowed ice-laden tree limbs overhanging the wires. Tree limbs in
ROW overhanging distribution lines pose a threat to system reliability, and are largely
within EGS’ control. The Company’s failure to clear the limbs before the storm was a
major factor in the number and duration of outages experienced by cu~tomers.’~While
Company’s initial efforts to mobilize and deploy additional non-EGS personnel were
slow and cause ~oncern,’~
vegetation management failures greatly aggravated the

79
Cities Ex. 2, Kimler Direct Testimony at 7.
80
Tr. at 377, 381,391.
81
General Counsel Ex. 2, Hughes Direct Testimony at 2 1.
82
Tr. at 676-77.
83
General Counsel Ex. 2, Hughes Direct Testimony at 17.
84
Tr. at 379.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 19

situation. The Company has experienced major storms in 1994, 1995, and 1997.85 The
weather, however, cannot be an excuse for poor service. While the Commission does not
expect 100 percent reliability, the system must be built and maintained taking the local
geographic and weather conditions into account.

b. Treatment of Storm Data
The Commission has required utilities to report the causes of interruptions,
including the extreme storms. EGS, however, excludes outage duration and frequency
data from its SAID1 and SAIFI reports if the data are attributable to a “major storm.”86
As defined currently by the Commission, major storms include situations in which there
is a loss of power to 10 percent or more of customers in a region over a 24-hour period
and full restoration is not achieved within 24 hours.87 EGS’ definition of a major storm
counts any event in which 10 percent or more of a region’s customers are interrupted for
24 hours or more, and is similar to the Commission7sdefinition.”

HLFCCG argued that interruptions associated with major storms should be
included in the computation of reliability indices. HLFCCG maintains that the design
and maintenance of lines, and therefore their condition under the stress of severe weather,
is within the control of the utility.89 Exclusion of major-storm interruptions from
reliability indices could encourage reduced preventive maintenance, including vegetation
management, and reductions in force needed for restoration efforts.”

85
Tr. at 214,377.
86
Tr. at 54.
87
EGS Ex. 10, Ervin Rebuttal Testimony at 30.
88
Id.
89
HLFCCG Ex.1, Patton Direct Testimony at 14.
90
Id. at 15.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 20

The Commission is reluctant to allow the Company to exclude major-storm data
from its overall reports because such reports may be incorrectly perceived as an
indication that overall service quality is better than it actually is. Also, leaving major-
storm data out may obscure the fact that poor management and maintenance, and not just
the severity of the weather, contribute to or cause a weather event to become serious
enough to be classified as a “major storm.” Despite a great deal of controverting
testimony by customer groups, the Company continues to assert that the acknowledged
problems during the 1997 ice storm were a “storm-of-the-century” aberration.”
Allowing the Company to carve out major storms from its outage-reporting data would
mask the seriousness of service quality problems that occur on its system under all
conditions.

The Commission understands that if a truly major storm affects the system, the
Company cannot be expected to restore power and respond to increased customer calls as
fast as it would in a more “normal” or day-to-day situations. Therefore, the Commission
will allow the segregation of major from non-major storm data in outage frequency and
duration reports. The major storms, defined by the severity of the weather conditions,
rather than by the outage duration, will be reported and evaluated separately, as discussed
in the “Remedies” section below.

4. Personnel Levels and Management Practices; Spending Levels

a. Personnel Levels
All parties agreed that post-merger personnel cuts were executed, ostensibly, in
order to save costs. The Company asserted that cuts were possible because of increased
efficiencies and that the permanent employees were simply replaced with contract
workers.92 The other parties maintained that cuts were not only too extensive, but

91
Tr. at 225; EGS Ex. 10, Ervin Rebuttal Testimony at 32-35.
92
Tr. at 160,236; EGS Ex. 8, Ervin Supplemental Direct at 19; EGS Ex. 10, Ervin Rebuttal Testimony at
51.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 21

resulted in a loss of many years of worker experience that could not be compensated for
by contract workers who may lack knowledge of the system or loyalty to the Company.
For example, General Counsel witness Ethridge cited the forced departure of 66
employees with an average of 18 years of experience each?3 A precise number of lost
employees was not conclusively proven: the Company maintained that total net loss was
only By4but HLFCCG, for instance, asserted that in the space of three years, the jobs of
67 linemen were eliminated.95

A related issue concerned the Company’s ability to evaluate contract workers’
performance: while the Company felt confident about increased efficiency of its hiring
practices, it did admit to not having performance measures for contract workers.96
General Counsel presented Company documents showing that controls over contract
worker management were not effective.97 An internal risk assessment audit, conducted
by the Company, also concluded that no formal and consistent process existed to monitor
contractor performance, that management employees did not generate necessary reports
to allow proper monitoring, and that distribution contracts were not competitively bid.98
An additional concern presented by Cities dealt with the decrease in the number of
operational staff while regulatory staff increased; this led Cities to conclude that the
Company had insufficient focus on system maintenance matters. 99

93
General Counsel Ex. 1, Ethridge Direct Testimony at 37.
94
Tr. at 236; EGS Ex. 10, Ervin Rebuttal Testimony at 52.
95
HLFCCG IB at 6 (referring to General Counsel Ex. 16 at 2, and Ex. 17 at 2).
96
Tr. at 249-50.
97
General Counsel IB at 14 (referring to HLFCCG Ex. 13, Entergy Internal Audit and Risk Assessment).
98
HLFCCG Ex. 1, Patton Direct Testimony, Risk Assessment Attachment at 3-4,6.
99
Cities Ex. 1, Lawton Direct Testimony at 12; Tr. at 164.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 22

The Commission concludes that, post-merger, EGS cut many experienced
employees, some of whom were consequently replaced by contract workers. The
Commission, however, will not prescribe what personnel levels the Company should
maintain. It is up to EGS to make sure it has enough workers to carry out proper
maintenance and necessary emergency responses, along with having well-defined
performance measures for both regular and contract employees.

b. Management Practices
Because the various operational entities under the holding company are split both
along functional and geographic lines, tracing management structure poses some
difficulties. According to Company witness Johnny Ervin, a network manager is located
in Beaumont, along with a reliability supervisor.”’ There are two levels of customer
service managers located in Beaumont; the vice president of customer service is located
in Jackson, Mississippi. During the hearing, however, the Company presented its director
of performance measurement, located in Little Rock, Arkansas, to speak on customer
service issues. The network manager and reliability supervisor report to a franchise
director (in Beaumont) and reliability director (in New Orleans, Louisiana), respectively.
Both of these directors report to a senior vice president of distribution operations, who is
located in New Orleans and is actually employed by Entergy Services, Inc. The senior
vice president answers to a utility group president, who has above him the chief operating
officer and, finally, the chief executive officer of Entergy. According to Mr. Ervin, this
reflects a new and “flatter” organizational structure, designed to promote better
communication.101 None of the managers in Beaumont reports to the EGS president, who
has oflices in Beaumont and Austin, Texas.

100
Tr. at 789-794; the entire description of the management structure is taken from these pages of the
transcript.

lo’ Id.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 23

The Commission has concerns regarding the Company’s management structure.
It is not clear from the evidence that managers actually have the authority and matching
resources to supervise their specific areas.’02 Those responsible for system reliability
have little control over the vegetation management area, even though vegetation
management has a major impact on how well the T&D system functions. The
Company’s internal audit concluded that there was no overall strategic plan in place to set
performance strategies, and that hindered management in accomplishing business
objectives and goals.lo3 While EGS’ representatives explained that recent changes in
management structure were aimed at increasing communication, they also revealed that
there was no structured way for the management to track and resolve problems reported
by the emp10yees.I~~
In addition, managers’ bonuses are tied in part to cost-cutting which
may conflict with efforts to improve system performance.lo5

The Commission concludes that those who are responsible for the reliable
performance of the Company’s distribution system in Texas must also have the necessary
authority and resources at their full disposal to maintain the system. The managers in the
Texas territory must have clearly delineated powers and should be accountable to a
unified higher management. The current, bifurcated management structure, under which
local Texas supervisors report to multiple supervisors, is an obstacle to effective and
reliable operation of EGS’ Texas system.

c. SDending Levels

An issue addressed at length in this docket involved the Company’s record of
investment in the T&D system, particularly in maintenance. While there is hardly a

102
Tr. at 791-92.
103
HLFCCG EX. 1, Patton Direct Testimony, Internal Audit and Risk Assessment at 4.
104
Tr. at 204-05.
105
Tr. at 475, 847. General Counsel Ex. 20. Also, EGS internal risk assessment studies for vegetation
management and distribution maintenance list cost-cutting as a major business goal.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 24

substitute for sufficient O&M expenditures, the Commission will not prescribe a specific
level of spending that may guarantee adequate service quality, and, at present, is not
keenly interested in past expenditure levels. The Commission is primarily interested in
results. As noted in the March 7, 1997 Supplemental Preliminary Order in Docket No.
16705, the Commission recognizes “that there may be a point of diminishing returns
above which the dollars or resources allocated to service quality become unreasonable
and fail to be cost effective.”lo6 That crossover point is not set in this docket, and it is not
intended to be set. EGS is responsible for determining sufficient spending levels and for
the appropriate allocation of resources to O&M, distribution capital additions, and other
categories in order to meet its obligation to provide adequate service quality.

In the hearing, EGS witnesses maintained that the Company had increased T&D
spending since the 1993 merger; that inspection and measurement standards had
improved; and that its spending on service quality programs equaled or even exceeded
that of other ~ti1ities.l’~It is not certain, however, that EGS actually increased spending
because expenses were not categorized clearly. Increased spending, if any, shows just
that--increased spending; it does not measure how the quality of service has improved, or
whether the service is adequate in accordance with PURA. Nonetheless, EGS is required
to provide continuous and adequate service in accordance with traditional reasonable and
necessary cost standards.”’

In a memo dated October 31, 1995, a Company official discusses vegetation
maintenance spending in the Southern Region and points to a recently implemented 20
percent reduction in allocations which, he expresses, cannot be sustained by any region

106
Supplemental Preliminary Order at 2, Docket No. 16705 (Mar. 7, 1997).
107
Tr. at 760; EGS IB at 7-10.
108
The Commission would expect some increases in spending since the 1993 merger because GSU, facing
bankruptcy, would have presumably reduced even the necessary expenses.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 25

without an adverse effect on customer ~ervice.’~’The parties generally agreed that
spending on O&M decreased, while distribution capital additions slightly increased. lo

The Internal Audit department of the Company in its distribution risk assessment study
identified the budget process which allocated dollars to the regions based on past history
rather than system needs as one of the problems that needed to be resolved.l 1

After evaluating the record evidence, the Commission concludes that expenditure
levels for O&M are confusing and unclear, and pose a problem regarding tracking and
accountability. While the Commission declines to state specific amounts to be spent,
proper tracking and accounting of expenditures, both by type and jurisdiction, are
essential. For example, the Company was unable to explain a 50 percent increase in the
miscellaneous Federal Energy Regulatory Commission (FERC) Account 588.lI2 It is
virtually impossible to ascertain how much of the O&M budget is actually spent in the
Texas jurisdiction or for distribution capital additions as compared to system
maintenance.

The Commission concludes that expenditures for O&M must be readily available
and verifiable. The same applies to the oft-mentioned, but never specified or quantified,
“increased efficiencies” used to justify cutting cost^."^ For such claims to have any
weight, the Company must have a ready and reasonable explanation together with
supporting documentation.

109
General Counsel Ex. 28 at 2.
110
Tr. at 134, 248; 353-54; General Counsel Ex. 1, Ethridge Direct Testimony at 20, 27; Cities Ex. 1,
Lawton Direct Testimony at 8.
111
General Counsel Ex. 30 at 7.
112
Id. at 9; Tr. at 153-54.
113
EGS Ex. 8, Ervin Supplemental Direct at 16, 19-20.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 26

5. Pockets of Unreliability; Customer Service

a. Pockets of Unreliability
One of the issues identified in the Supplemental Preliminary Order in Docket No.
16705 involves pockets of particularly unreliable ~ervice,"~
such as the feeder Tamina,
which had 41.3 hours of outage time in one year."' Rural customers are more likely to
experience outages and wait longer for restoration. The Company admits to areas of
lower reliability' l6 and agrees that "outliers" must be impr~ved."~ The Company's
practice--seemingly logical--of first restoring and clearing areas with most customers has
led to the same customers experiencing repeated lower-quality service. In addition, the
Company maintains a list of "politically sensitive" accounts, which suggests that some
customers may receive preferential treatment. '
The Commission concludes that there should be a high standard of service for all
customers, including a set minimum standard below which no customer would fall, and
that the Company needs to bring all of its worst performing poles and feeders into
compliance with that minimum standard.

b. Customer Service
The Company has maintained, from the outset of this case, that its service is not
deficient, but that it simply faces a "customer perception" problem. The Company knows
that it has a large number of customers who are not satisfied with their electric ~ervice."~

114
Supplemental Preliminary Order at 3, Docket No. 16705 (March 7, 1997); see also, General Counsel
Ex. 7 at 36.
115
General Counsel Ex. 3, Eckhoff Direct Testimony, Appendix H.
116
Tr. at 122,223,652.
117
Tr. at 223-24.
118
Tr. at 396-97.
119
Tr. at 219. The Company's internal customer survey showed declining satisfaction levels from 1995 to
1996, Tr. at 198-200.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 27

Based on the record, the Commission concludes that EGS customers’ perceptions are
justified. The same concerns were reflected in the testimony of city officials charged
with protecting the health and safety of their citizens. Of particular note was the evidence
that a municipality was compelled to call upon its volunteer firefighters to disconnect live
electric wires because the Company’s personnel were not available to perform this highly
dangerous task. 120

The Company’s inadequate service quality is not necessarily an outgrowth of a
lack of “money” or “expenditures.” The Company has available funds that should be
sufficient to provide higher-quality service, as may be gathered from the fact that the
entire O&M budget was not spent.121It should be noted that the internal risk assessment
study on distribution line construction and service restoration lists as the first priority
improvement in customer perception of energy delivery and improvement in reliability
only as a second priority.122

EGS’ customers and the Commission believe that the Company has an obligation
to provide continuous and adequate service, and that significant improvements in EGS’
performance are needed. Section D, below, outlines the outcomes EGS must attain for
the Commission to be satisfied that those improvements have been made. An
improvement in EGS performance will eventually lead to more favorable perceptions and
evaluations by the Company’s customers.

120
Tr. at 376.
121
Tr. at 468-70.
122
General Counsel Ex. 30 at 1
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 28

D. Remedies

Based on the foregoing analysis, the Commission concludes that the Company’s
service quality must be improved. The following incentive plan lays out remedies to help
EGS achieve such improvements. The five essential components of the plan are as
follows:

1. A reduction in the return on equity divided into two parts: an adjustment
component that recognizes EGS’ current service quality is not adequate, with
amounts to be refunded to customers, and an incentive-pool component to
encourage future improvements in service quality;
2. Adoption of minimum and target levels for SAID1 and SAIFI as
recommended in General Counsel’s testimony, including improvement in the
worst- feeder performance; establishment of standards for major-storm data;
and reporting requirements;
3. Partial adoption of customer service performance benchmarks as
recommended in General Counsel’s testimony;
4. Establishment of a quality assurance requirement to ensure improved
performance through the hiring of an independent consultant consistent with
the amended, non-unanimous stipulation; and, to guarantee the accuracy of
all data, hiring by the Company of an independent auditor to review all
reports. 123
5. A customer information and notification requirement.

1. Reduction in the Return on Equity and Incentive Pool

Drawing from the recommendation in the testimony of Cities’ witness Lawton,
the Company will be assessed a 60-basis point reduction in its ROE adopted in Phase I1
of Docket No. 16705. This reduction shall be implemented in recognition of the
historically inadequate performance of EGS’ distribution system. The Company will be
required to refund current overcollections, including all appropriate taxes, for the period

123
EGS had filed an amended, non-unanimous stipulation regarding the hiring of an independent
consultant to assess Company’s distribution system, including a review of the service quality processes.
The Commission approved the stipulation with modifications on January 15, 1998.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 29

starting with June 1, 1996, the effective date of any rate reductions ordered in Docket No.
16705, up to the effective date of this order.’24

Going forward, the Company will collect the amount equal to one-half of the 60-
basis point reduction, plus appropriate taxes, and deposit that amount in an interest-
bearing escrow account to create an incentive pool. The Company may earn this
escrowed amount back by achieving specific performance targets. The other one-half of
the 60-basis point reduction, plus appropriate taxes, will be retained by the ratepayers.
The performance evaluation year will be a 12-month period, commencing on November
1, and ending on October 3 1. For SAIDI and SAIFI minimum level compliance, SAIDI
and SAIFI target level compliance, and compliance with the billing-error rate and call
center performance targets, the initial evaluation period shall commence on November 1,
1997, and end on October 31, 1998. For service installation, line extension, and light
replacement customer service performance measures, the initial evaluation period shall
commence on May 1, 1998, and end on October 31, 1998. Thus, EGS’ performance
during the initial measurement year for these three performance measures shall be based
on only six months of customer service performance. During subsequent years, EGS’
performance shall be based on twelve months of customer service performance. At the
end of each performance evaluation period, if the Company fails to achieve stated
performance benchmarks in any of the three areas (SAIDI and SAIFI minimum levels,
SAIDI and SAIFI target levels, and customer service), a corresponding portion of the
incentive pool will be refunded to distribution-level customers, divided on a pro-rata
basis within each customer class, except as noted below. If the Company successfully
reaches all of the benchmarks, the full amount of the incentive pool will revert back to
EGS.

124
The effective date of this &der for the purposes of the requirements set forth herein is the date on
which this Order is no longer subject to rehearing.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 30

The performance evaluation year is intended to coincide with the filing
requirements of the Commission’s Electric System Service Quality Report (ESSQR)
forms. If the Commission were to change the ESSQR form time periods to a calendar-
year basis, the performance evaluation periods discussed above for EGS shall change to
be consistent with the Report form periods.

Performance will be evaluated, and the incentive pool will be divided, according
to three measures: (1) improvement in the minimum performance levels for SAIDI and
SAIFI for worst feeders; (2) improvement in the target performance levels for SAIDI and
SAIFI for average feeders; and (3) improvement in customer service performance, which
has five components: (a) billing-error rate, (b) connection rate at the call center, (c)
timeliness in completing service and meter installations, (d) timeliness in completing line
extensions, and (e) timeliness in replacing andor repairing service and street lights.

For the purposes of determining what amount, if any, the Company will earn
back, the portions of the incentive pool will be represented by the following benchmarks:
SAIDI and SAIFI minimum value improvements for the “worst” feeders (described
below) will count as one-third of the pool; SAIDI and SAIFI target value improvements
will count as one-third of the pool; and customer service improvements will count as one-
third. Failure to achieve a measure will result in refunds to the affected customers based
on the requirements for that specific measure. SAIDI and SAIFI will be calculated on a
feeder-specific basis.

The Company has stated it does not have the ability to measure customer-specific
feeder performance, and thus cannot calculate customer-specific refunds. For the first
measure, however, refunds shall be provided to all customers taking service from a feeder
that fails to meet the SAIDI and SAIFI minimum acceptable levels as recorded over a
one-year period. These refunds are more customer-specific than currently contemplated
by the Company, but because only a small number of feeders is expected to fall into this
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 31

category, the refund calculations should not pose an insurmountable pr~blem.’~’
For the
second measure, if the Company fails to achieve the specified SAIDI and SAIFI target
level improvements, refunds shall be made to all Texas, distribution-level customers. For
the third measure, failure to meet the standard for any of the customer service
components will result in pro-rata refunds to each of the distribution-level customers.
Distribution-level customers are meant to be those Texas, retail residential and small
commercial ratepayers whose contract demands are less than or equal to 100 kW.

Feeder-specific refunds shall be distributed in a single billing period in proportion
to and limited by each customer’s total annual electric usage (i.e., no customer shall
receive a refund greater than the total amount paid by that customer for the service in that
year). If any money remains in the pool, the amount shall be refunded to all distribution-
level customers on a pro-rata basis. All r e h d s shall be labeled “Service Quality
Refund” on the customer’s bill and shall be directed to the current customer receiving
service at a given premise.

2. Minimum and Target Performance Levels

a. Frequency and Duration of InterruDtions
The performance benchmarks are drawn from General Counsel’s testimony with
some adjustments. General Counsel proposed that the Company measure the duration of
interruptions using the Average System Availability Index (ASAI). The ASAI index and
the SAIDI index are closely related. Since the Company is required to report SAIDI
under the Commission’s service quality rules, that index will be used as the duration
measure. General Counsel, HLFCCG, and Cities agree that performance should be
measured feeder-by-feeder rather than through a system average. EGS has accepted a
feeder-by-feeder approach for outage frequency.126 General Counsel’s proposal for

125
The Company states that it does not have the ability to tie specific feeders to specific customers; it is
expected, however, that the number of feeders involved is such that manual calculations will be possible or
the Company can use its TACTICS program. Tr. at 445-46.
126
Tr. at 228.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 32

feeder-by-feeder SAIFI and SAIDI targets is presented in Table 1, where the SAIDI
targets are converted from the ASAI values recommended by General C0unse1.l~~The
Commission adopts the following performance targets for use by EGS as its reliability
performance standards.

Table 1: General Counsel’s Proposal for Interruption Performance Measures
Index Value Minimum Acceptable Value Target Value
(annual) (annual)
SAIFI 3.8 interruptions 2.6 interruptions
SAIDI 315 minutes (5.25 hours) 158 minutes (2.63 hours)
Source: Eckhoff Direct Testimony at 7.

General Counsel’s testimony indicates that distribution feeders serving
approximately 90 percent of EGS’ Texas customer meters met the minimum acceptable
values for SAIDI and SAIFI in 1996.12* Distribution feeders serving approximately 75
percent of EGS’ Texas customer meters met the target values in 1996.’29

b. Minimum Performance Benchmark
General Counsel presented testimony to show that a certain percentage of EGS’
feeders fall below the minimum acceptable values for SAIDI and SAIFI. As part of the
remedial plan, the Company must achieve 95 percent compliance with the minimum
acceptable values in 1998, so that no more than 5 percent of distribution feeders serving
EGS’ Texas customer fail to meet the minimum acceptable values for SAIDI and SAIFI.

127
General Counsel Ex. 3, Eckhoff Direct Testimony at 7. HLFCCG recommends an annual feeder-by-
feeder standard for SAIFI of 3 interruptions and for SAIDI of 200 minutes. HLFCCG Ex. 1, Patton Direct
Testimony at 29.
128
General Counsel reported that feeders serving 89.97 percent of EGS’ Texas customer meters met the
SAIFI minimum value, and 90.84 percent met the ASAI minimum value. General Counsel Ex. 3, Eckhoff
Direct Testimony at 33-34.
129
General Counsel reported that feeders serving 75.6 percent of EGS’ Texas customers met the SAIFI
target value, and 76.86 percent met the ASAI target value. Id.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 33

For the following year, the compliance level will be raised to 98.5 percent. In addition, in
year 2 and thereafter, EGS must also meet the following conditions: (1) two or more
feeders served by the same substation may not fail to attain any minimum acceptable
value; (2) no feeder may fail to attain the minimum acceptable value for two or more
consecutive years; and (3) 98.5 percent of all meters must receive service at a level
meeting or exceeding both minimum acceptable values. Feeders with 5 or fewer meters
shall not be considered in determining whether EGS has met these compliance standards.
The Company will maintain or exceed the 98.5 percent compliance with these standards
in the subsequent years.

To document and track this improvement, the Company shall identifl the worst-
performing feeders as discussed herein. EGS shall file SAIDI and SAIFI performance
data for all feeders in the following way: (1) exclusive of storm effects and using the
SAIDI and SAIFI definitions of major events as contained in the Commission’s Electric
System Service Quality Report filing (PUC Project No. 15013), and (2) inclusive of all
such storm effects and defining major weather events as an ice accumulation of at least
one inch of ice within the period of 24 hours, or winds greater than 80 miles-per-hour.
Further, EGS shall rank all of its 431 Texas distribution feeders from best to worst
according to SAIFI numbers calculated as described above. A list of the worst 10 percent
shall be submitted as a part of the June 15, 1998 ESSQR filing. Because the report asks
for data on the worst 5 percent of the feeders, the Company shall supplement its filing for
the purposes of this docket. If the Company fails to meet the minimum acceptable value
benchmark or the major-storm restoration measure for that year, as described below, one-
third of the incentive pool amount, plus appropriate taxes, will be refunded to customers
served by all non-complying feeders.

c. Target Performance Benchmark
In 1998, for all feeders, the Company must achieve 85 percent compliance with
General Counsel’s recommended target levels for SAIDI and SAIFI to retain the
corresponding portion of the incentive pool (i.e., the Company must improve up to the
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 34

target levels an additional 10 percent of its feeders, from 75 to 85 percent). In the
following year, SAIDI and SAIFI compliance with the target levels will be raised to 90
percent of feeders, and this level will be maintained or exceeded in the future. If the
Company fails to meet the target performance benchmark, one-third of the incentive pool,
plus appropriate taxes, will be refunded to all Texas distribution-level customers.

d. Treatment of Maior-Storm Data
The record shows that extreme weather events can cause major outages. For the
purposes of record-keeping and performance evaluation, it is necessary to define extreme
events according to actual weather conditions rather than the effect weather has on the
T&D system. For the purposes of its supplemental filing, EGS shall define extreme
weather as an ice accumulation of at least one inch of ice within the period of 24 hours, or
winds greater than 80 miles-per-hour. The Company shall keep its records in a way that
includes all weather events, and a separate set that includes only the major-weather
events. The determination of the Company’s performance regarding SAIDI and SAIFI
benchmarks shall be calculated based on the all-inclusive data. In addition, the
Commission adopts as the performance measure for major-weather events the complete
restoration of all customers’ electric service no later than 120 hours after the initiation of
such an event (i.e., when an accumulation of one inch of ice or 80 mph wind have been
recorded). Failure to achieve this measure will preclude the Company’s recovery of the
one-third of the incentive pool, plus appropriate taxes, associated with the SAIDI and
SAIFI minimum acceptable level compliance for that year.

If an extreme-weather event occurs on the system, and the Company believes it
has a detrimental effect on the overall performance for that year, the Company may
submit a good cause exception filing for the Commission’s consideration on whether to
include such an event in the annual evaluation of compliance with set benchmarks.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 35

e. Reporting Requirements
As discussed above, the Company shall file collected data regarding performance
measures on a semi-annual basis, which filings shall coincide with the filing dates of the
Commission’s ESSQR form. In addition to that filing, on March 1 of each year
beginning in 1999, the Company shall file a proposed reconciliation statement showing
the level of achievement with the established benchmarks to qualifL for any part of the
incentive pool. The filing shall be audited by an independent auditor prior to filing, and
the auditor’s report shall be filed with the proposed reconciliation statement. If and when
the Commission approves the filing, the Company shall retain the appropriate portion of
the pool or refund the corresponding portion, plus appropriate taxes, to its Texas
distribution-level customers, as directed by the Commission. SAID1 and SAIFI
performance data shall be reported according to the following schedule: May through
October data due on December 15; November through April data due on June 15 of each
year.

3. Customer Service Performance Benchmarks

The performance measures listed below in Table 2 are drawn from General
Counsel’s recommendations, with the exception of security and street light replacement,
which is based on a recommendation made by the Company.’3o In its reply brief, EGS
adopted many of the components of General Counsel’s recommended performance
measures for customer service.’31 For the purposes of this remedial plan, each customer
service measure will be computed for the time interval noted in Table 2, and reported to
the Commission every six months, consistent with the filing dates for the service quality
reports, as a separate Customer Service Report. If all five targets are achieved by EGS in
one given year, the customer service portion of the incentive pool will be retained by the

____

130
General Counsel Ex. 7, Goodman Direct Testimony; General Counsel Ex. 5 , Burrows Direct
Testimony, Attachment JBG-8.
131
EGS Reply Brief at 17-21.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 36

Company for that year; otherwise, that portion of the incentive pool, plus appropriate
taxes, will be refimded to distribution-level customers on a pro-rata basis.

Table 2: Performance Targets for Customer Service Measures
Customer Performance Target
Service Measure
Billing-error rate The Texas system average monthly rate of actual customer over-billing errors per
1000 customers shall not exceed five.
Call center Seven days a week, 24 hours per day, on a monthly basis, in every EGS call
performance center, 85 percent of the time, calls shall be answered within 30 seconds.
Service In any distribution substation service area, 90 percent of applications for new
installation electric service and meters not involving line extensions or new facilities shall be
filled within five working days, excluding those orders in which a later date is
specifically requested by the customer. Service installation compliance will be
measured on a quarterly basis.
Lineextensions In any distribution substation service area, 85 percent of requests for line
extensions or new facilities shall be completed within 60 working days, excluding
those orders in which a later date is specifically requested by the customer. This
standard includes orders for new service and other services, installations, moves,
or changes, but not complex services. Line installation compliance will be
measured on a quarterly basis.
Light In any distribution substation service area, 90 percent of all customer reports of
replacements security and streetlight outages shall be corrected within 48 hours. Light
replacement compliance will be measured on a quarterly basis.
Note: Definitions of specific terms are adopted from J.B. Goodman Direct Testimony, Attachment JBG-8.

After EGS files its first annual customer service report on December 15, 1998, the
Commission Staff will work cooperatively with any party who requests it to review
performance data collected by EGS relevant to the performance targets, established in
Table 2 for new service installations, line extensions, and street lights, in order to
determine whether the targets should be adjusted and, if so, in what manner. No earlier
than April 1, 1999, any party may petition the Commission to revise these three customer
service measures and targets. In its December filing each year, EGS shall, for the
purposes of this docket, provide an annual, audited summary of customer service
performance data.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 37

4. Quality Assurance Proposal; Independent Consultant; and Independent Auditor

According to the terms of the amended, non-unanimous stipulation, the Company
shall hire an independent consultant to assess the distribution system, develop strategies
for improvement, revise data collection practices, and set up evaluation criteria
procedures spelled out in the order approving that stipulation as modified.’32 Testimony
in this docket exposed inconsistencies in EGS’ collection, recording, and reporting of
service quality indices, including SAID1 and SAIFI. The Company shall develop a
quality assurance program that guarantees accurate and consistent reporting of all
collected data. The Company shall file its quality assurance proposal no later than
August 16, 1998.’33 The deadline shall be extended one day for every day the
consultant’s report addressing the EGS distribution system is filed beyond July 16, 1998.
This proposal shall be developed with the input and in conjunction with the work done by
the independent consultant hired under the terms of the amended, non-unanimous
stipulation. To guarantee that all data and reports collected by EGS and filed with the
Commission are accurate and consistent, the Company shall hire annually an independent
auditor to review such data and reports.

5. Customer InformatiodNotification

The final component of the incentive plan is the information and notification
requirement. Following its annual reconciliation statement filed with the Commission,
the Company shall include an insert in bills to its customers that explains the service
quality requirements, the Company’s performance during the preceding annual period,
and the amount of the refund to distribution-level customers. The insert shall contain

132
On December 17, 1997, EGS, OPUC, HLFCCG, Cities, and General Counsel, jointly filed a
supplementary motion for entry of an order consistent with proposed amendments to a previously filed
non-unanimous stipulation.
133
The quality assurance requirement appears consistent with the amended non-unanimous stipulation
related to hiring a service quality consultant filed by EGS and other signing parties, on December 17, 1997.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 38

instructions to customers on who to contact to report broken or malfunctioning street
lights. The proposal for the scope and content of the bill inserts shall be included in the
Company’s annual reconciliation filing.

IV. Findings of Fact and Conclusions of Law

The preceding discussion explains the Commission’s factual and legal
conclusions with regard to the issues presented in this docket. In accordance with TEX.
GOV’TCODEANN. 3 200 1.141, the Commission separately states the following findings
of fact and conclusions of law.

A. Findings of Fact

Procedural History

1. On November 27, 1996, EGS filed with the Commission its transitionhate case in
Docket No. 16705.

2. The Commission referred the case to SOAH on December 5, 1996. The
preliminary order issued by the Commission on January 24, 1997, in Docket No. 16705
directed that the docket “address specific service quality standards that will apply after
the transition [proposed by EGS].”

3. On March 7, 1997, the Commission issued a supplemental preliminary order in
Docket No. 16705 that focused specifically on service quality issues. That order
delineated three questions which must be addressed: (1) Whether EGS has an effective
and prudent management policy in place that devotes sufficient resources to ensure
adequate and reliable service to its ratepayers; (2) Whether there appear patterns of
variable service quality in EGS’ service territory, and if so, what is the cause and
potential resolution of these variations; (3) Whether the Commission should implement
procedures, and if so, what procedures can it implement, to monitor service quality on
EGS’ system, and to respond to situations in which EGS’ service quality falls below the
benchmark levels.

4. SOAH segmented the hearings in Docket No. 16705 (SOAH Docket No. 473-96-
2285) into four phases to address numerous transition and rate issues separately. The
service quality issues were scheduled for hearing in early November 1997, in the
“Competitive Issues” phase of the case.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 39

5. At the November 4, 1997 Open Meeting, Chairman Pat Wood, 111, and
Commissioner Judy Walsh voted to sever the service quality issues from Docket No.
16705 and determined that the Commission itself would hear and resolve these issues.

6. An order issued on November 4, 1997, established Docket No. 18249 to address
the service quality issues. The order also established procedures by which the
Commission would hear and rule on the service quality issues directly.

7. Chairman Wood and Commissioner Walsh convened and presided over a public
hearing on the merits on November 20 and 21, 1997, to address EGS’ service quality
issues. EGS, Cities, HLFCCG, and General Counsel submitted their testimony and
exhibits into evidence and conducted cross-examination. The Chairman and
Commissioner Walsh also directed questions to the witnesses.

8. EGS, Cities, HLFCCG, and General Counsel filed post-hearing briefs in this
docket on December 2, 1997. Reply briefs were filed by these same parties on December
9, 1997. The Office of Public Utility Counsel and the Attorney General’s Office filed
statements on December 2 and 9, 1997, respectively, supporting the briefs of the Cities
and HLFCCG.

9. The Commission issued its Final Order in this docket on February 13, 1998.

10. On March 5, 1998, General Counsel and EGS filed motions for rehearing.

11. At the March 19, 1998 open meeting, the Commission granted extensions to rule
on the motions for rehearing until May 14, 1998, and to file replies until March 25, 1998.

12. On March 25, 1998, a joint reply to motions for rehearing and motion for entry of
order consistent with the parties’ stipulation and agreement (the Stipulation) was filed
and signed by General Counsel, EGS, HLFCCG, and OPUC.

13. The Commission granted rehearing at the April 1, 1998 open meeting and also
approved the Stipulation.

Notice

14. Hearings held on November 20 and 21, 1997, were properly noticed in accordance
with TEX.GOV’TCODEANN.$0 551.041,551.043,2001.051, and 2001.052.

15. This matter was scheduled for discussion in open meetings convened on
December 17, 1997, January 14, 1998, and April 1, 1998, for which notice was given
pursuant to TEX.GOV’TCODEANN. $3 551.041 and 551.043.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 40

16. EGS is a public utility subject to the jurisdiction of this Commission in
accordance with PURA $3 14.001,31.001,32.001,33.122, and 36.001 through 36.156.

17. EGS is a wholly-owned subsidiary of Entergy, a holding company incorporated in
Delaware and registered with the federal Securities and Exchange Commission in
accordance with the Public Utility Holding Company Act.

18. Entergy acquired Gulf States Utilities, Inc., to create EGS, effective as of
December 3 1, 1993.

19. EGS operates in Louisiana and Texas, and through its parent holding company is
affiliated with investor-owned electric utilities located in Louisiana, Mississippi, and
Arkansas. Entergy ’s headquarters is located in New Orleans, Louisiana.

20. EGS’ Texas service territory covers the southeastern part of the state. EGS’
principal office in Texas is located in Beaumont.

Management Structure

21. In Beaumont, EGS employs, among others, a network manager and a reliability
supervisor. These managers report to a franchise director, also located in Beaumont.

22. The network manager’s and reliability supervisor’s responsibilities include
managing and dealing with system reliability, outages, restoration, and vegetation
management.

23. The network managers report to the franchise director located in Beaumont, who
reports to the senior vice president of distribution operations, employed by Entergy
Services, Inc., and located in New Orleans.

24. In New Orleans, the vice president of distribution operations answers to a utility
group president, who reports to a chief operating officer, and ultimately the chief
operating officer of Entergy.

25. The network manager, reliability supervisor, and franchise director do not report
to the EGS president, who has offices both in Austin and Beaumont.

26. The Company management structure is ill-suited to assure best supervision of the
T&D system in the Texas territory. The supervisors in Texas answer to multiple directors
in Louisiana, do not have all the necessary resources at their disposal, and their bonus
incentives are tied in part to successful cost-cutting.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 41

Transmission System

27. The construction of EGS’ transmission system started in 1924. Half of the
transmission lines currently in service were added in the 1950’s and 1960’s. Since 1977,
12 percent of the lines have been newly built or rehabilitated.

28. The Commission finds that the physical state of EGS’ transmission system is
adequate; few transmission-related outages or circuit breaker operations occurred.

29. Transmission line ROW appear to be clear.

30. The EGS transmission system appears to provide adequate, continuous, and
reliable service.

Physical Condition of Distribution System and Pole Inspection Program

3 1. EGS serves approximately 3 18,279 customers in Texas. The distribution system
in the state is comprised of 11,472 miles of electric lines; 394,865 poles; and
approximately 43 1 feeders.

32. EGS contracted with Osmose Wood Preserving Company to perform inspections
of EGS poles and crossarms in Texas for the years 1995 and 1996.

33. In 1995 and 1996, Osmose field inspectors inspected a total of 37,233 wood poles
in eight different areas. The poles reviewed account for 9.4 percent of the total number of
poles in EGS’ Texas system.

34. Although the Osmose inspections focused on particularly troubled spots of the
distribution system in Texas, certain areas revealed a number of deficient poles that was
excessive by any measure.

35. Osmose survey results show wide fluctuations in percentages of poles with decay,
from 8 to 37 percent, with the average percentage being 17.9 percent.

36. EGS proposes to implement a new pole inspection program, through which
approximately 35,000 poles will be inspected annually, so that all poles in the Texas
jurisdiction will be inspected by the end of the 10th year.

37. General Counsel selected Drash Consulting Engineering Inc. to survey 33
uniformly distributed substations from the Texas portion of the EGS distribution system.

38. General Counsel recommended that Drash inspect a representative sample of 591
poles on feeders originating from these 33 substations, of which Drash visually surveyed
582, or 98.42 percent, of poles.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 42

39. The Drash report picked for inspection approximately every 5th, loth, or 15th
pole from the substation. The age of the poles was determined by visual inspection.

40. Drash filed its report on August 11, 1997, in which it identified 59 of 582 poles
with structural deficiencies, such as rot, decay, or leaning, and 72 poles with
encroachments by tree limbs and vegetation build-up.

41. The Drash survey did not use specific criteria by which to evaluate the condition
of the poles, but relied on the inspectors’ experience.

42. Beginning on May 12, 1997, the Commission Staff performed limited, random
inspections of EGS’ poles in the Vidor, Orange, Bridge City, Port Arthur, and Port
Neches areas. The Staff inspections also encompassed the northern portion of the system
to the western limits of EGS’ service area.

43. By August 1997, the Commission Staff surveyed 60 poles, and found that 6.7
percent had equipment deficiencies and 63 percent had ROW problems.

44. In general, the distribution system is in adequate condition; however, there are
numerous poles with decay, in need of repair or replacement, and many lines and poles
that need vegetation clearing.

45. The inspection program carried out by the Company has not been sufficiently
extensive or adequate to hlfill its purpose of securing reliable service.

46. The Company’s distribution system maintenance practices have failed to assure
continuous and adequate service to EGS ’ customers.

Reliability Indices and Performance Standards

47. EGS uses the following standards and systems to collect and record performance
measures: System Average Interruption Frequency Index (SAIFI); System Average
Interruption Duration Index (SAIDI); Distribution Interruption System (DIS); TACTICS;
and a System Control and Data Acquisition devise (SCADA). General Counsel also used
the Average System Availability Index (ASAI) as an outage measure.

48. EGS begins to record a specific outage only after a customer calls in to the
Company to complain. Timing of the outage duration starts after the customer alerts the
Company.

49. System-wide, the average customer in EGS’ Texas territory experienced outages
totaling 133 minutes (as recorded in SAIDI) in 1996. The system-wide SAIFI in Texas
for 1996 was 2.648 interruptions.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 43

50. Fifty of 43 1 feeders (1 1.6 percent) in the EGS’ Texas system were below the
minimum ASAI standard recommended by General Counsel (99.94 percent or 157
minutes), while 37 (8.58 percent) feeders missed the minimum SAIFI standard of 3.8
interruptions per year.

5 1. Eighty-three feeders or primary circuits experienced outage times in excess of 200
minutes during 1996.

52. Eighteen feeders, serving 9,457 meters, are “historically deficient”’34for SAIFI,
and seventeen feeders, serving 10,835 meters, are “historically deficient” for ASAI.

53. Nine percent of the meters did not meet minimum ASAI standards. Similarly, 10
percent of the meters fell below minimum SAIFI benchmarks.

54. Customers on several feeders suffered significantly more interruptions than the
average customer, and with lengthier outages: feeders Tamina and China recorded SAIDI
scores of 2,477 minutes and 934 minutes, respectively, while feeder Dobbin reached a
SAIDI value of 699 minutes. Feeder Pleasure scored 10.2 interruptions, feeder Crystal
had a SAIFI of 8 interruptions, and Cordrey scored 7.56 interruptions.

55. Sixty-five feeders with approximately 58,000 customers have a SAIFI rating less
than the 10-year Company average.

56. EGS testified that it restores first those feeders with the highest numbers of
customers. Likewise, it clears vegetation first on the feeders with the most customers.

57. EGS excluded certain data in calculating its reliability indices. In 1994, the
Company ceased counting outages in areas with less than 500 customers. For the first six
months of 1996, the Company reported 35 to 40 percent fewer outages than were reported
on average during the first six months of the 1991-94 time-frame.

58. The average outage duration during the first three years after the merger went up
to 2.4105 hours, from the average of 1.8220 hours during the seven years preceding the
merger.

59. By September 1996, the number of outages reported increased by 80 percent from
1995, due to a greater number of small outages recorded.

60. EGS prepared a Reliability Report for the Southwest Region, issued in May 1994,
that summarized reliability performance for the year, compared actual performance with
Company goals, identified problem areas, and reported corrective actions.

134
Historically deficient feeders are those with consistently poor performance over a period of several
years.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 44

61. Equipment failures were excluded from the May 1994 Reliability Index, as were
outages attributed to public damage, non-preventable trees, load curtailment, transmission
line outages, instantaneous outages, and planned outages. EGS began reporting these
types of outages again in September 1995.

62. EGS excluded from its performance measures and reliability indices data
collected during episodes of extreme weather conditions in February 1994 and January
1997.
63. The measure of outage duration does not take into account either the number of
customers who fail to alert the Company to an outage, or the length of time a customer
has suffered an outage prior to notifying the Company.

64. Linemen working for or on behalf of EGS make subjective determinations as to
the cause, duration, or effect of an outage, which may hinder true and accurate reporting
of the outage causes.

65. EGS records and reports its reliability and performance data based on system-
wide measures. This method of reporting overlooks recurring individual feeder problems
and pockets of disproportionately low service quality.

66. EGS is not technically equipped at the present time to measure SAID1 and SAIFI
performances at the individual customer level. The Company, however is able to
calculate performance indices on a feeder-by-feeder basis.

67. The Company’s data and compiled indices are unreliable because of changing
data collection standards, failure to report all relevant information, and manipulation of
the data.

Vegetation Management

68. The purpose of vegetation management is to ensure to the extent possible that
vegetation in or near ROW does not come into contact with the conductors and either
break the wires or cause ground faults.

69. Many of the outages in EGS’ service territory result from trees or tree limbs
falling into EGS’ ROWS or distribution lines.

70. EGS stated that it has a six-year, rural tree-trimming cycle; it calls for a 20-foot
clearance. Trees in urban areas, according to the Company, are trimmed on a three-year
cycle. The Company did not offer persuasive evidence that these cycles were actually
followed.

71. The Company stated that 80 percent of EGS’ vegetation management
expenditures are allocated to cyclical tree trimming.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 45

72. Texas vegetation management expenses in the post-merger period were $4.99
million in 1994, $5.09 million in 1995, and $4.735 million in 1996. The decrease in
spending between 1995 and 1996 is attributed by the Company to unexplained efficiency
gains.

73. The total line-miles actively maintained by the Company dropped approximately
30 percent in 1996 from the 1994-1995 levels; EGS witnesses did not explain this
decrease.

74. Vegetation management spending increased by 34 percent in 1997, a significant
part of which went towards the January 1997 ice storm cleanup costs.

75. Vegetation-related SAIDI and SAIFI values have worsened since the merger.
System-wide SAIDI values for Texas have increased from 21.17 in 1994 to 40.36 in
1997. SAIFI values have also increased from 0.31 in 1994 to 0.63 in 1997. As of
September 1997, the SAIDI level for 1997 exceeded the SAIDI value for the entire year
in 1996.

76. Network managers in EGS’ Texas territory have the responsibility to ensure
adequate service reliability. Network managers, however, do not directly supervise or
fully control the vegetation management program.

77. A 1994 study by Environmental Consultants, Inc., (ECI) proposed specific
recommendations for EGS’ vegetation management to include herbicide and tree
trimming based on plant species, equipment scheduling in the planning process,
aggressive pursuit of tree removals, and performance measures for contractors. EGS has
not implemented the recommendations proposed by ECI.

78. Entergy ’s Internal Audit department conducted a comprehensive risk assessment
study of the vegetation management program in 1996, and concluded that sufficient
strategic planning had not occurred to ensure that Entergy met its objectives. The study
also found that the Alliance Agreement between Entergy and vegetation management
contractors was not being consistently applied in the various regions, and did not meet
business objectives.

79. Power lines cannot be shielded 100 percent from all contact with vegetation;
however, the Company’s inability to develop and carry out prudent vegetation
management policies has resulted in major service disruptions.

80. EGS’ management structure does not provide those responsible for ensuring
service reliability with direct authority to address or prevent vegetation-related outages.

81. The Company does not have a strategic plan to guide vegetation management
efforts.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 46

82. Neglect and backlog of vegetation management projects has posed unacceptable
risks of increasing and recurrent service outages, especially during major storms.

83. The Commission finds that the Company’s vegetation management efforts have
not been adequate, have led to a backlog in vegetation clearing, and have resulted in an
unacceptably high risk to the system.

Emergency Preparedness, Resoonse, and Outage Restoration

84. In June 1996, EGS conducted a drill simulating an emergency situation in order to
test its emergency response and restoration plans.

85. EGS’ emergency plan and procedures are on file with the Commission, and were
reviewed by the Commission Staff after the ice storm in January 1997.

86. In Docket No. 16301, Ice Storm ‘97 Field Investigations Project, the Commission
Staff concluded that EGS had a good emergency plan in place before the ice storm of
January 1997.

87. The Commission defines “major storm” as a weather-related event in which there
is a loss of power to 10 percent or more of the customers in a region over a 24 hour
period and with all customers not restored within 24 hours.

88. EGS defines major storm as any event in which 10 percent or more of a region’s
customers are interrupted for 24 hours or more.

89. Many parts of Texas experienced an ice storm of significant magnitude that began
early on January 12,1997, and lasted through the afternoon of January 13,1997.

90. Most utilities in Texas experienced disruptions in service during the January 1997
ice storm.

91. EGS should have been better prepared to deal with the January 1997 ice storm,
given that it had experienced major weather events in 1994 and 1995, and that it had
successfully conducted emergency drills in 1996.

92. During the ice storm in January 1997, up to 120,000 of EGS’ Texas customers
were without power. Restoration took seven days to complete, with temporary
emergency crews mobilized from Louisiana, Mississippi, and Arkansas.

93. By January 16, 1997, EGS had more than 2,700 personnel deployed to restore
service on various parts of its Texas system.

94. At the public hearing on November 20, 1997, city officials from the towns of Port
Neches, Orange, and Nederland described numerous episodes in which the numbers of
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 47

EGS workers, equipment, and materials were insufficient to deal adequately with
emergency situations. Other officials from Cleveland, Dayton, and Port Arthur gave
favorable reports of EGS’ performance during the January 1997 ice storm.

95. Mr. Dick Nugent, representing the city of Nederland, testified that after several
attempts to reach EGS personnel, city officials had to retrieve an EGS supervisor from his
house in Nederland to help them with power restoration efforts.

96. Mr. A.R. Kimler, from the city of Port Neches, testified that local firefighters
were deployed to cut down live power lines because EGS stated there were not enough
employees to respond at the time.

97. The impact of the January 1997 ice storm was greatly exacerbated by the
Company’s failure to maintain its ROW clear of excessive vegetation.

98. While the Company has emergency plans in place, not all personnel are familiar
with the plans, a fact that may have accounted for the Company’s uneven and delayed
restoration efforts during the January 1997 ice storm.

99. It may be uneconomic for EGS to build, operate, or maintain a 100 percent storm-
proof system. The January 1997 ice storm, however, revealed that EGS must implement
a better preventive maintenance program and faster customer response initiatives.

100. Segregation of major-storm data from non-major storm data in outage duration
and frequency reports provides a more accurate method to evaluate EGS’ performance on
a day-to-day basis, as well as during crisis events.

101. The standard for classifying major storms is to be defined in terms of the severity
of the weather-related event, rather than in terms of the impact on the T&D system.
Feeders subject to major storms can be defined as those experiencing an accumulation of
one inch of ice or more within a 24-hour period, or those exposed to winds of at least 80
mph.

102. EGS’ outage restoration efforts during the January 1997 ice storm would have
been more effective if: (1) EGS had been more diligent in its preventive vegetation
management practices; and (2) it had a better communication and management program
in place to deal with emergency situations.

103. The effect and incidence of lightning strikes did not materially affect the quality
of service offered by the Company.

Spending Levels

104. System-wide transmission spending followed a generally increasing trend since
1992. No data was presented for transmission O&M expenditures on the Texas portion
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 48

of the system.

105. Between 1994 and 1996, distribution maintenance spending decreased by $4
million each year. Half of these cuts ($2 million each year) came from the overhead line
maintenance spending.

106. Miscellaneous distribution expenses recorded in Federal Energy Regulatory
Commission (FERC) Account 588 increased from just under $3 million in 1991-1993, to
$10.3 million in 1995, and $12.4 million in 1996, an increase EGS could not explain.

107. FERC has designated Account 588 for mapping, records, communications, and
other miscellaneous expenses such as clerical, stenographic, and janitorial work at
buildings.

108. EGS decreased its level of spending for pole and appurtenance replacements by
50 percent during the years 1995 and 1996.

109. EGS’ O&M spending has been uneven, lacks clear accounting, and
proportionately more is spent on distribution capital additions than on distribution system
maintenance.

110. In 1995, most of the spending for distribution capital additions was in the
Louisiana area.

111. Efficiency savings have not been identified nor proven in areas where spending
levels had been reduced.

112. The Company witness could not explain whether any of the savings from the
unspent T&D budget were credited according to the Entergy/GSU merger agreement
(PUC Docket No. 11292).

Personnel Levels

113. The Company has carried out substantial cuts in the number of employees
assigned to T&D operations: 95 distribution employees in 1995-1996 and 26 in 1997.
EGS has increased its use of contract workers during the same periods for a total net
decrease of 42 permanent linemen and servicemen since the merger.

114. Since the merger, most the terminated T&D employees were replaced with
contract workers. Sixty-six of the terminated T&D employees had on average of 18 years
experience with the Company.

115. The Company has no performance measures to evaluate contract-worker
efficiency.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 49

116. The ratio of contract employees to permanent linemen and servicemen is now 2: 1.
The Commission does not oppose the use of contract employees. The present ratio of
contract employees to permanent staff, however, is high, particularly in light of the
extensive experience lost when many of the permanent employees were laid-off.

117. EGS is expected to structure its line maintenance and vegetation management
programs in such a way that adequate numbers of properly trained and supervised
employees are promptly available.

118. EGS hired 30 additional contract crews in October 1997, specifically to remedy a
backlog of vegetation management projects.

119. The Company lacks a clearly stated strategic plan for vegetation management, and
priorities are driven primarily by budget considerations.

Customer Service

120. An EGS customer survey reveals that satisfaction results decreased among all
classes of ratepayers and for all components of service from 1995 to 1996, as more
customers classified EGS service as “fair” or “bad” than “very good” or “helpful.”

121; EGS did not track customer complaints prior to 1995, nor did it track customer
service performance standards. EGS began a complaint management system in January
1997 to document every complaint called in to the Company.

122. The Company’s automated voice response unit, substituted for live employees,
has not led to increased customer satisfaction.

123. EGS has failed to implement sufficient customer service procedures and has a
high number of dissatisfied customers.

124. The Company also has, by its own admission, pockets of particularly inadequate
service.

125. In a letter dated September 19, 1997, State Representative Mark Stiles wrote to
the Commission expressing concern over an increase in the number of EGS customers
who contacted him to complain of poor service by EGS.

126. EGS acknowledges that it has a large number of customers who remain
unsatisfied with their customer service.

127. EGS’ customer service quality is clearly deficient based on the numerous
complaints to the Commission and Texas Legislature, and as indicated in the Company’s
own survey data.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 50

Stipulation

128. In the Stipulation, filed by parties on March 25, 1998, and approved by the
Commission at the April 1, 1998 open meeting, the parties, among other provisions,
agreed to: (1) lower the compliance level for SAID1 and SAIFI minimum acceptable level
to 98.5 percent; (2) make the reporting and evaluation periods consistent with the Electric
System Service Quality Report form; (3) provide for a possible review of customer
service targets; (4) change the selection process of the auditor; and (5) change the due
date of the quality assurance proposal to August 16, 1998.

129. The Stipulation addressed only some of the issues raised by the parties in the
motions for rehearing. However, at the April 1, 1998 open meeting, the EGS
representative indicated that if the Commission adopted the Stipulation as drafted, the
parties would not appeal the Order.

B. Conclusions of Law

1. Entergy Gulf States, Inc., (EGS) is a public utility as defined in PURA
'3 31.002(1).
2. The Commission has jurisdiction over issues addressed in this Order in
accordance with PURA $3 14.001,31.001,32.001,33.122,36.001-36.151, and 38.071.

3. The Commission has jurisdiction over all matters relating to the conduct of a
hearing in this case, in accordance with PURA 3 14.051.

4. This Order is issued in accordance with TEX.GOV'TCODEANN.3 2001.141.

5. PURA 3 37.15 l(2) requires that EGS provide continuous and adequate service in
its certificated service territory.

6. EGS is obligated, pursuant to PURA 3 38.001, to furnish service,
instrumentalities, and facilities that are safe, adequate, efficient, and reasonable.

7. EGS has failed to provide continuous and adequate service to many of its
customers, as required by PURA $3 37.151(2) and 38.001.

8. In establishing a reasonable return on invested capital, the Commission is
required, among other things, to consider the quality of the utility's service. PURA
3 36.052(3).
9. The Commission, after notice and hearing, may order an electric utility to provide

A
specified improvements in its service and in a specified area if (a) service in the area is
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 51

inadequate or substantially inferior to service in a comparable area; and (b) requiring the
company to provide the improved service is reasonable. PURA 5 38.071.

10. The remedies proposed in the Stipulation are tailored to achieve the desired result
as contemplated in the Final Order; implementation of such remedies is in the public
interest.

V. Ordering Paragraphs

1. Upon issuance of a final order in EGS' pending rate case in Docket No.
16705, the Company shall calculate the revenues equal to 60-basis points,
and appropriate taxes, of the ROE established in Docket No. 16705.

2. Within 30 days after issuance of the final order in Docket No. 16705, the
Company shall submit to the Commission its calculation of the revenues
equal to 60-basis points, and appropriate taxes, for Commission review and
approval.

3. If a rate reduction is ordered in Docket No. 16705, the Company shall refund
to its customers an amount equal to 60-basis points of its ROE authorized in
Docket No. 16705, plus appropriate taxes, for the period from June 1, 1996,
through the effective date of this Order.'35

4. As of the effective date of this Order, the Company shall reduce collections
from customers by an amount equal to 30-basis points, and appropriate
taxes, of the ROE authorized in Docket No. 16705.

5. As of the effective date of this Order, the Company shall establish an
interest-bearing escrow account into which it shall deposit, on an on-going
basis, the amount equal to 30-basis points, and appropriate taxes, of its ROE
authorized in Docket No. 16705.

6. The Company shall hire an independent consultant, according to the
conditions set out in the amended, non-unanimous stipulation regarding the
hiring of consultants, as approved with modifications by the Commission in
this docket. The consultant shall assess the distribution system, develop
strategies for improvement, revise data-collection practices, establish
evaluation criteria, and perform any additional work as set out in the
amended, non-unanimous stipulation.

135
If the final order in Docket No. 16705 does not mandate any refunds to customers, there will not be a
refund of 60-basis points to customers based on this Order for the period from June 1, 1996, up to the
effective date of this Order.

A
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 52

7. The Company shall file a quality assurance proposal governing the
collection, recording, and reporting of SAIDI and SAIFI, and any other
relevant service quality measures by August 16, 1998. This filing deadline
shall be extended one day for every day the consultant’s report addressing
the EGS distribution system is filed beyond July 16, 1998.

8. Twice annually, and starting on June 15, 1998, the Company shall file the
Electric System Service Quality Report, including its supplemental filing, to
document SAIDI and SAIFI feeder-by-feeder data for each six-month
period, calculated in the manner discussed in this Order. The Company shall
also submit a listing of the worst performing 10 percent of the Company’s
feeders, twice annually along with their performance data. Beginning on
December 15, 1998, and twice annually thereafter, at the same time as the
Electric System Service Quality Reports, the Company shall file its
Customer Service Reports, relating to service installations, line extensions,
and light replacements. Initial Customer Service Reports related to the
remaining customer service measures (billing-error rate and call center
performance) shall be due on June 15, 1998. In its December filing each
year, the Company shall provide an annual, audited summary of customer
performance data.

9. Beginning in 1999, and no later than March 1 of that and each subsequent
year, the Company shall file with the Commission its reconciliation proposal
for the funds held in escrow according to this Order for the prior calendar
year. The Company’s annual filing shall be audited by an independent
auditor, and the audit shall be filed with the reconciliation proposal.

10. If the Commission determines that the Company has achieved the
performance standards set out in this Order for a minimum acceptable level
of improvement for SAIDI and SAIFI for the 10 percent of worst feeders
and, if applicable, major-storm restoration process, the Company may retain
one-third of the amount in escrow for that year; otherwise, the Company
shall refund that amount, plus appropriate taxes, to its Texas distribution-
level customers taking service from the non-complying feeders, as explained
in section D( 1) and D(2)(b) of this Order. If the Commission determines that
the Company has achieved the performance standards set out in this Order
for the target level improvement for SAIDI and SAIFI, the Company may
retain one-third of the amount in escrow for that year, otherwise, the
Company shall refund that amount, plus appropriate taxes, to all its Texas
distribution-level customers, divided on a pro-rata basis within each
customer class. If the Commission determines that the Company has
achieved the performance standards set out in this Order for customer
service, the Company may retain one-third of the amount in escrow for that
year; otherwise, the Company shall refund that amount, plus appropriate

A
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 53

taxes, to its Texas distribution-level customers divided on a pro-rata basis
within each customer class.

11. In conjunction with its annual reconciliation filing, the Company shall
submit a proposal for customer notification. At a minimum, the proposal
shall include the content and format for a billing insert that explains the
service quality requirements, the Company’s performance for the preceding
year, street light reporting instructions and telephone number, and the
amount of the escrow pool retained by the Company andor refunded to
customers.

12. The Company shall develop and implement, within the six months of the
effective date of this Order, a media campaign to inform and educate
customers in its Texas service territory about the importance and proper
procedure for reporting to the Company malhctioning or broken street
lights.

13. The provisions of the Stipulation are approved as reflected in this Order.

14. The entry of an order consistent with the Stipulation of the parties does not
indicate the Commission’s endorsement of approval of any principle or
methodology that may underlie the Stipulation of the parties. Neither should
entry of an Order consistent with the h l l settlement of the parties be
regarded as a binding holding or precedent as to the appropriateness of any
principle or methodology underlying the Stipulation of the parties.

15. All other motions, requests for entry of specific findings of fact and
conclusions of law, and any other requests for general or specific relief, if
not expressly granted herein, are hereby denied for want of merit.
PUC DOCKET NO. 18249 ORDER ON REHEARING Page 54

This Order reflects the opinion of Chairman Wood and Commissioner Walsh.
Commissioner Curran was not present at the adjudicatory hearing conducted in this
docket, and did not participate in the final order and order on rehearing deliberations.

SIGNED AT AUSTIN, TEXAS, the J/&ay of April 1998.
ILITY COMMISSION OF TEXAS
PUBLICfi

OOD, 111, CHAIRMAN
n

MDY
W A ~ S HCOMMISSIONER
,
 Appendix G

Excerpt from: PUC Docket No. 16705,
Proposal for Decision
 Appendix H

Excerpts from: PUC Docket No. 16705,
Second Order on Rehearing
 Appendix I

16 Tex. Admin. Code § 25.231
16 TAC § 25.231 Page 1

Tex. Admin. Code tit. 16, § 25.231

plant used by and useful to the electric utility
in providing such service to the public.
Payments to affiliated interests for costs of
Texas Administrative Code Currentness
service, or any property, right or thing, or for
Title 16. Economic Regulation
interest expense shall not be allowed as an
Part 2. Public Utility Commission of Texas
expense for cost of service except as pro-
Chapter 25. Substantive Rules Applicable to
vided in the Public Utility Regulatory Act §
Electric Service Providers
36.058.
Subchapter J. Costs, Rates and Tariffs
Division 1. Retail Rates
§ 25.231. Cost of Service (B) Depreciation expense based on original
cost and computed on a straight line basis as
approved by the commission. Other methods
(a) Components of cost of service. Except as provided
of depreciation may be used when it is de-
for in subsection (c)(2) of this section, relating to
termined that such depreciation methodology
invested capital; rate base, and § 23.23(b) of this title,
is a more equitable means of recovering the
(relating to Rate Design), rates are to be based upon an
cost of the plant.
electric utility's cost of rendering service to the public
during a historical test year, adjusted for known and
measurable changes. The two components of cost of (C) Assessments and taxes other than income
service are allowable expenses and return on invested taxes.
capital.
(D) Federal income taxes on a normalized
(b) Allowable expenses. Only those expenses which basis. Federal income taxes shall be com-
are reasonable and necessary to provide service to the puted according to the provisions of the
public shall be included in allowable expenses. In Public Utility Regulatory Act § 36.060.
computing an electric utility's allowable expenses,
only the electric utility's historical test year expenses (E) Advertising, contributions and donations.
as adjusted for known and measurable changes will be The actual expenditures for ordinary adver-
considered, except as provided for in any section of tising, contributions, and donations may be
these rules dealing with fuel expenses. allowed as a cost of service provided that the
total sum of all such items allowed in the cost
(1) Components of allowable expenses. Allowa- of service shall not exceed three-tenths of
ble expenses, to the extent they are reasonable and 1.0% (0.3%) of the gross receipts of the
necessary, and subject to this section, may in- electric utility for services rendered to the
clude, but are not limited to the following general public. The following expenses shall be in-
categories: cluded in the calculation of the three-tenths
of 1.0% (0.3%) maximum:

(A) Operations and maintenance expense
incurred in furnishing normal electric utility (i) funds expended advertising methods
service and in maintaining electric utility of conserving energy;

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16 TAC § 25.231 Page 2

Tex. Admin. Code tit. 16, § 25.231

the preceding sentence shall be ex-
(ii) funds expended advertising methods pressly included in the cost of service
by which the consumer can effect a established by the commission's order.
savings in total electric utility bills;
(ii) In the event that an electric utility
(iii) funds expended advertising methods implements an interim rate increase, in-
to shift usage off of system peak; and cluding an increase filed under bond, an
incremental change in decommissioning
funding shall be included in the increase.
(iv) funds expended promoting renewa-
ble energy.
(iii) An electric utility's decommission-
ing fund and trust balances will be re-
(F) Nuclear decommissioning expense. The
viewed in general rate cases. In the event
following restrictions shall apply to the in-
that an electric utility does not have a
clusion of nuclear decommissioning costs
rate case within a five-year period, the
that are placed in an electric utility's cost of
commission, on its own motion or on the
service.
motion of the commission's Office of
Regulatory Affairs, the Office of Public
(i) An electric utility owning or leasing
Utility Counsel, or any affected person,
an interest in a nuclear-fueled generating
may initiate a proceeding to review the
unit shall include its cost of nuclear de-
electric utility's decommissioning cost
commissioning in its cost of service.
study and plan, and the balance of the
Funds collected from ratepayers for de-
trust.
commissioning shall be deposited
monthly in irrevocable trusts external to
(iv) An electric utility shall perform, or
the electric utility, in accordance with §
cause to be performed, a study of the
25.301 of this title (relating to Nuclear
decommissioning costs of each nuclear
Decommissioning Trusts). All funds
generating unit that it owns or in which it
held in short-term investments must bear
leases an interest. A study or a redeter-
interest. The level of the annual cost of
mination of the previous study shall be
decommissioning for ratemaking pur-
performed at least every five years. The
poses will be determined in each rate
study or redetermination should consider
case based on an allowance for contin-
the most current information reasonably
gencies of 10% of the cost of decom-
available on the cost of decommission-
missioning, the most current information
ing. A copy of the study or redetermina-
reasonably available regarding the cost
tion shall be filed with the commission
of decommissioning, the balance of
and copies provided to the commission's
funds in the decommissioning trust, an-
Office of Regulatory Affairs and the
ticipated escalation rates, the anticipated
Office of Public Utility Counsel. An
return on the funds in the decommis-
electric utility's most recent decommis-
sioning trust, and other relevant factors.
sioning study or redeterminations shall
The annual amount for the cost of de-
be filed with the commission within 30
commissioning determined pursuant to
days of the effective date of this subsec-

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16 TAC § 25.231 Page 3

Tex. Admin. Code tit. 16, § 25.231

tion. The five year requirement for a new
study or redetermination shall begin (i) OPEB expense shall be included in an
from the date of the last study or rede- electric utility's cost of service for rate-
termination. making purposes based on actual pay-
ments made.
(G) Accruals credited to reserve accounts for
self-insurance under a plan requested by an (ii) An electric utility may request a
electric utility and approved by the commis- one-time conversion to inclusion of
sion. The commission shall consider ap- current OPEB expense in cost of service
proval of a self insurance plan in a rate case for ratemaking purposes on an accrual
in which expenses or rate base treatment are basis in accordance with generally ac-
requested for a such a plan. For the purposes cepted accounting principles (GAAP).
of this section, a self insurance plan is a plan Rate recognition of OPEB expense on an
providing for accruals to be credited to re- accrual basis shall be made only in the
serve accounts. The reserve accounts are to context of a full rate case.
be charged with property and liability losses
which occur, and which could not have been
(iii) An electric utility shall not be al-
reasonably anticipated and included in oper-
lowed to recover current OPEB expense
ating and maintenance expenses, and are not
on an accrual basis until GAAP requires
paid or reimbursed by commercial insurance.
that electric utility to report OPEB ex-
The commission will approve a self insur-
pense on an accrual basis.
ance plan to the extent it finds it to be in the
public interest. In order to establish that the
(iv) For ratemaking purposes, the tran-
plan is in the public interest, the electric util-
sition obligation shall be amortized over
ity must present a cost benefit analysis per-
20 years.
formed by a qualified independent insurance
consultant who demonstrates that, with con-
sideration of all costs, self-insurance is a (v) OPEB amounts included in rates
lower-cost alternative than commercial in- shall be placed in an irrevocable external
surance and the ratepayers will receive the trust fund dedicated to the payment of
benefits of the self insurance plan. The cost OPEB expenses. The trust shall be es-
benefit analysis shall present a detailed tablished no later than six months after
analysis of the appropriate limits of self in- the order establishing the OPEB expense
surance, an analysis of the appropriate annual amount included in rates. The electric
accruals to build a reserve account for self utility shall make deposits to the fund at
insurance, and the level at which further ac- least once per year. Deposits on the fund
cruals should be decreased or terminated. shall include, in addition to the amount
included in rates, an amount equal to
fund earnings that would have accrued if
(H) Postretirement benefits other than pen-
deposits had been made monthly. The
sions (known in the electric utility industry as
funding requirement can be met with
“OPEB”). For ratemaking purposes, expense
deposits made in advance of the recog-
associated postretirement benefits other than
nition of the expense for ratemaking
pensions (OPEB) shall be treated as follows:

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.231 Page 4

Tex. Admin. Code tit. 16, § 25.231

purposes. The electric utility shall, to the bership in social, recreational, fraternal, or
extent permitted by the Internal Revenue religious clubs or organizations;
Code, establish a postretirement benefit
plan that allows for current federal in- (F) funds promoting increased consumption
come tax deductions for contributions of electricity;
and allows earnings on the trust funds to
accumulate tax free.
(G) additional funds expended to mail any
parcel or letter containing any of the items
(vi) When an electric utility terminates mentioned in subparagraphs (A)-(F) of this
an OPEB trust fund established pursuant paragraph;
to clause (v) of this subparagraph, it
shall notify the commission in writing. If
(H) payments, except those made under an
excess assets remain after the OPEB
insurance or risk-sharing arrangement exe-
trust fund is terminated and all trust re-
cuted before the date of the loss, made to
lated liabilities are satisfied, the electric
cover costs of an accident, equipment failure,
utility shall file, for commission ap-
or negligence at an electric utility facility
proval, a proposed plan for the distribu-
owned by a person or governmental body not
tion of the excess assets. The electric
selling power within the State of Texas;
utility shall not distribute any excess
assets until the commission approves the
(I) costs, including, but not limited to, inter-
disbursement plan.
est expense, of processing a refund or credit
of sums collected in excess of the rate finally
(2) Expenses not allowed. The following ex-
ordered by the commission in a case where
penses shall never be allowed as a component of
the electric utility has put bonded rates into
cost of service:
effect, or when the electric utility has other-
wise been ordered to make refunds;
(A) legislative advocacy expenses, whether
made directly or indirectly, including, but not
(J) any expenditure found by the commission
limited to, legislative advocacy expenses in-
to be unreasonable, unnecessary, or not in the
cluded in professional or trade association
public interest, including but not limited to
dues;
executive salaries, advertising expenses, le-
gal expenses, penalties and interest on
(B) funds expended in support of political overdue taxes, criminal penalties or fines,
candidates; and civil penalties or fines.

(C) funds expended in support of any politi- (c) Return on invested capital. The return on invested
cal movement; capital is the rate of return times invested capital.

(D) funds expended promoting political or (1) Rate of return. The commission shall allow
religious causes; each electric utility a reasonable opportunity to
earn a reasonable rate of return, which is ex-
(E) funds expended in support of or mem- pressed as a percentage of invested capital, and

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.231 Page 5

Tex. Admin. Code tit. 16, § 25.231

shall fix the rate of return in accordance with the
following principles. (ii) Equity capital. For companies with
ownership expressed in terms of shares
(A) The return should be reasonably suffi- of stock, equity capital commonly con-
cient to assure confidence in the financial sists of the following classes of stock.
soundness of the electric utility and should be
adequate, under efficient and economical (I) Common stock capital. The cost
management, to maintain and support its of common stock capital shall be
credit and enable it to raise the money nec- based upon a fair return on its
essary for the proper discharge of its public market value.
duties. A rate of return may be reasonable at
one time and become too high or too low
(II) Preferred stock capital. The cost
because of changes affecting opportunities
of preferred stock capital is the ac-
for investment, the money market, and
tual cost of preferred stock at the
business conditions generally.
time of issuance, plus an adjustment
for premiums, discounts, and re-
(B) The commission shall consider efforts by funding and issuance costs.
the electric utility to comply with the
statewide integrated resource plan, the efforts
(2) Invested capital; rate base. The rate of return is
and achievements of the electric utility in the
applied to the rate base. The rate base, sometimes
conservation of resources, the quality of the
referred to as invested capital, includes as a major
electric utility's services, the efficiency of the
component the original cost of plant, property,
electric utility's operations, and the quality of
and equipment, less accumulated depreciation,
the electric utility's management, along with
used and useful in rendering service to the public.
other applicable conditions and practices.
Components to be included in determining the
overall rate base are as set out in subparagraphs
(C) The commission may, in addition, con- (A)--(F) of this paragraph.
sider inflation, deflation, the growth rate of
the service area, and the need for the electric
(A) Original cost, less accumulated depreci-
utility to attract new capital. The rate of re-
ation, of electric utility plant used by and
turn must be high enough to attract necessary
useful to the electric utility in providing ser-
capital but need not go beyond that. In each
vice.
case, the commission shall consider the
electric utility's cost of capital, which is the
(i) Original cost shall be the actual
weighted average of the costs of the various
money cost, or the actual money value of
classes of capital used by the electric utility.
any consideration paid other than mon-
ey, of the property at the time it shall
(i) Debt capital. The cost of debt capital
have been dedicated to public use,
is the actual cost of debt at the time of
whether by the electric utility which is
issuance, plus adjustments for premi-
the present owner or by a predecessor.
ums, discounts, and refunding and is-
suance costs.
(ii) Reserve for depreciation is the ac-

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.231 Page 6

Tex. Admin. Code tit. 16, § 25.231

cumulation of recognized allocations of than one-eighth of total annual op-
original cost, representing recovery of erations and maintenance expense,
initial investment, over the estimated excluding amounts charged to op-
useful life of the asset. Depreciation erations and maintenance expense
shall be computed on a straight line basis for materials, supplies, fuel, and
or by such other method approved under prepayments.
subsection (b)(1)(B) of this section over
the expected useful life of the item or (II) For electric cooperatives, river
facility. authorities, and investor-owned
electric utilities that purchase 100%
(iii) Payments to affiliated interests shall of their power requirements,
not be allowed as a capital cost except as one-eighth of operations and
provided in the Public Utility Regulatory maintenance expense excluding
Act § 36.058. amounts charged to operations and
maintenance expense for materials,
(B) Working capital allowance to be com- supplies, fuel, and prepayments will
posed of, but not limited to the following: be considered a reasonable allow-
ance for cash working capital.
(i) Reasonable inventories of materials,
supplies, and fuel held specifically for (III) Operations and maintenance
purposes of permitting efficient opera- expense does not include deprecia-
tion of the electric utility in providing tion, other taxes, or federal income
normal electric utility service. This taxes, for purposes of subclauses (I),
amount excludes appliance inventories (II), and (V) of this clause.
and inventories found by the commis-
sion to be unreasonable, excessive, or (IV) For all investor-owned electric
not in the public interest. utilities a reasonable allowance for
cash working capital, including a
(ii) Reasonable prepayments for oper- request of zero, will be determined
ating expenses. Prepayments to affiliat- by the use of a lead-lag study. A
ed interests shall be subject to the lead-lag study will be performed in
standards set forth in the Public Utility accordance with the following cri-
Regulatory § 36.058. teria:

(iii) A reasonable allowance for cash (-a-) The lead-lag study will use the
working capital. The following shall cash method; all non-cash items,
apply in determining the amount to be including but not limited to depre-
included in invested capital for cash ciation, amortization, deferred tax-
working capital: es, prepaid items, and return (in-
cluding interest on long-term debt
and dividends on preferred stock),
(I) Cash working capital for electric
will not be considered.
utilities shall in no event be greater

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.231 Page 7

Tex. Admin. Code tit. 16, § 25.231

(-b-) Any reasonable sampling (-g-) If the cash working capital
method that is shown to be unbiased calculation results in a negative
may be used in performing the amount, the negative amount shall
lead-lag study. be included in rate base.

(-c-) The check clear date, or the (V) If cash working capital is re-
invoice due date, whichever is later, quired to be determined by the use
will be used in calculating the of a lead-lag study under the pre-
lead-lag days used in the study. In vious subclause and either the elec-
those cases where multiple due tric utility does not file a lead lag
dates and payment terms are offered study or the electric utility's lead-lag
by vendors, the invoice due date is study is determined to be so flawed
the date corresponding to the terms as to be unreliable, in the absence of
accepted by the electric utility. persuasive evidence that suggests a
different amount of cash working
(-d-) All funds received by the capital, an amount of cash working
electric utility except electronic capital equal to negative one-eighth
transfers shall be considered avail- of operations and maintenance ex-
able for use no later than the busi- pense including fuel and purchased
ness day following the receipt of the power will be presumed to be the
funds in any repository of the elec- reasonable level of cash working
tric utility (e.g., lockbox, post office capital.
box, branch office). All funds re-
ceived by electronic transfer will be (C) Deduction of certain items which in-
considered available the day of re- clude, but are not limited to, the following:
ceipt.
(i) accumulated reserve for deferred
(-e-) For electric utilities the balance federal income taxes;
of cash and working funds included
in the working cash allowance cal- (ii) unamortized investment tax credit to
culation shall consist of the average the extent allowed by the Internal Rev-
daily bank balance of all enue Code;
non-interest bearing demand de-
posits and working cash funds.
(iii) contingency and/or property insur-
ance reserves;
(-f-) The lead on federal income tax
expense shall be calculated by
(iv) contributions in aid of construction;
measurement of the interval be-
tween the mid-point of the annual
(v) customer deposits and other sources
service period and the actual pay-
of cost-free capital;
ment date of the electric utility.

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.231 Page 8

Tex. Admin. Code tit. 16, § 25.231

insurance plan is approved by the commis-
(D) Construction work in progress (CWIP). sion, any shortages to the reserve account
The inclusion of construction work in pro- will be an increase to the rate base and any
gress is an exceptional form of rate relief. surpluses will be a decrease to the rate base.
Under ordinary circumstances the rate base The electric utility shall maintain appropriate
shall consist only of those items which are books and records to permit the commission
used and useful in providing service to the to properly review all charges to the reserve
public. Under exceptional circumstances, the account and determine whether the charges
commission will include construction work being booked to the reserve account are
in progress in rate base to the extent that: reasonable and correct.

(i) the electric utility has proven that: (F) Requirements for post test year adjust-
ments.
(I) the inclusion is necessary to the
financial integrity of the electric (i) Post test year adjustments for known
utility; and and measurable rate base additions (in-
creases) to historical test year data will
be considered only as set out in sub-
(II) major projects under construc-
clauses (I)-(IV) of this clause.
tion have been efficiently and pru-
dently planned and managed.
However, construction work in (I) Where the addition represents
progress shall not be allowed for plant which would appropriately be
any portion of a major project which recorded:
the electric utility has failed to
prove was efficiently and prudently (-a-) for investor-owned electric
planned and managed; or utilities in FERC account 101 or
102;
(ii) for a project ordered by the com-
mission under § 25.199 of this title (re- (-b-) for electric cooperatives, the
lating to Transmission Planning, Li- equivalent of FERC accounts 101 or
censing and Cost-recovery for Utilities 102.
within the Electric Reliability Council of
Texas), if the commission determines (II) Where each addition comprises
that conditions warrant the inclusion of at least 10% of the electric utility's
CWIP in rate base, the project is being requested rate base, exclusive of
efficiently and prudently planned and post test year adjustments and
managed, and there will be a significant CWIP.
delay between initial investment and the
initial cost recovery for a transmission
(III) Where the plant addition is
project.
deemed by this commission to be
in-service before the rate year be-
(E) Self-insurance reserve accounts. If a self gins.

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.231 Page 9

Tex. Admin. Code tit. 16, § 25.231

(IV) Where the attendant impacts on (-c-) CWIP (mirror CWIP is not
all aspects of a utility's operations considered CWIP); or
(including but not limited to, reve-
nue, expenses and invested capital) (-d-) an attendant impact of another
can with reasonable certainty be post test year adjustment.
identified, quantified and matched.
Attendant impacts are those that
(II) Plant that has been removed
reasonably follow as a consequence
from service, mothballed, sold, or
of the post test year adjustment be-
removed from the electric utility's
ing proposed.
books prior to the rate year.

(ii) Each post test year plant adjustment
Source: The provisions of this § 25.231 adopted to be
will be included in rate base at:
effective March 1, 1999, 24 TexReg 1377; amended to
be effective April 13, 2005, 30 TexReg 2055.
(I) the reasonable test year-end
CWIP balance, if the addition is
16 TAC § 25.231, 16 TX ADC § 25.231
constructed by the electric utility;
or,
Current through 40 Tex.Reg. No. 866, dated February
20, 2015, as effective on or before February 27, 2015
(II) the reasonable price, if the ad-
dition represents a purchase, subject
Copr. (C) 2015. All rights reserved.
to original cost requirements, as
specified in Public Utility Regula-
tory Act § 36.053. END OF DOCUMENT

(iii) Post test year adjustments for
known and measurable rate base de-
creases to historical test year data will be
allowed only when clause (i)(IV) of this
subparagraph and the criteria described
in subclauses (I) and (II) of this clause
are satisfied.

(I) The decrease represents:

(-a-) plant which was appropriately
recorded in the accounts set forth in
clause (i)(I) of this subparagraph;

(-b-) plant held for future use;

© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.