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

5104240

THIRD COURT OF APPEALS

AUSTIN, TEXAS

4/30/2015 2:54:51 PM

JEFFREY D. KYLE

CLERK

FILED IN

NO. 03-14-00735-CV 3rd COURT OF APPEALS

AUSTIN, TEXAS

4/30/2015 2:54:51 PM

JEFFREY D. KYLE

ENTERGY TEXAS, INC., ET AL., Clerk

Appellants,

v.

PUBLIC UTILITY COMMISSION OF TEXAS, INC., ET AL.,

Appellees.

B RIEF OF A PPELLEE

Filed by: Public Utility Commission of Texas

KEN PAXTON ELIZABETH R. B. STERLING

Attorney General of Texas State Bar No. 19171100

elizabeth.sterling@texasattorneygeneral.gov

CHARLES E. ROY

First Assistant Attorney General DOUGLAS B. FRASER

State Bar No. 07393200

doug.fraser@texasattorneygeneral.gov

JAMES E. DAVIS

Deputy Attorney General for

Civil Litigation DANIEL C. WISEMAN

State Bar No. 24042178

daniel.wiseman@texasattorneygeneral.gov

JON NIERMANN

Chief, Environmental Protection Environmental Protection Division

Division P.O. Box 12548, MC-066

Austin, Texas 78711-2548

Assistant Attorneys General: 512.463.2012

512.457.4616 (fax)

April 30, 2015

Oral Argument Requested

Table of Contents

Table of Contents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i

Index of Authorities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Glossary.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii

Statement of the Case. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi

Statement Regarding Oral Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi

Issues Presented.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii

Issue 1: Did the Commission reasonably interpret how its prior

ambiguous order in PUC Docket 37744 (the Black-box Order)

treated the Hurricane Rita regulatory asset? (Responds to

Entergy Issue 1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii

Issue 2: Does substantial evidence support the Commission’s

decision to include Entergy’s 1997 ice-storm repair expenses

when computing the utility’s insurance reserve? (Responds to

OPUC Issue). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii

Issue 3: Does substantial evidence support the Commission’s

decision that Entergy failed to prove that certain purchased-

power capacity costs were known-and-measurable changes to

those expenses in the test year? (Responds to Entergy Issue 2). . . xii

Issue 4: Does substantial evidence support the Commission’s

decision that Entergy failed to prove that predicted

transmission-equalization charges were known-and-

measurable changes to those costs in the test year? (Responds

to Entergy Issue 3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii

Statement of Facts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

I. Procedural History.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

II. Rate Setting.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

i

A. Rate Base.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1. Hurricane Rita Regulatory Asset. . . . . . . . . . . . . . . 4

2. Self-Insurance Storm Reserve and the 1997

Ice Storm.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

B. Reasonable and Necessary Expenses.. . . . . . . . . . . . . . . . 6

Summary of the Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

I. Standard of Review. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Substantial-evidence Standard.. . . . . . . . . . . . . . . . . . . . . . . . . 10

Arbitrary-and-capricious Standard. . . . . . . . . . . . . . . . . . . . . . . 11

II. The district court properly affirmed the Commission’s

decision about the amount of the Hurricane Rita

regulatory asset to include in Entergy’s rate base.

(Responds to Entergy Issue 1). . . . . . . . . . . . . . . . . . . . . . . . . . . 11

A. Factual Background. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

B. Substantial evidence supports the Commission’s

reasonable interpretation of its prior, ambiguous

order.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

1. The Black-box Order decided the Rita Asset

issue.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Securitization Docket.. . . . . . . . . . . . . . . . . . . . . . . . 16

The statute requires action in the next rate

case.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Which is the next rate case?. . . . . . . . . . . . . . . . . . . 18

ii

No objection to the regulatory asset or

amortizing it. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

All issues resolved in the Black-box Order. . . . . . 20

2. The Court should defer to the Commission’s

interpretation of its ambiguous Black-box

Order.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

III. The Commission properly included the 1997 ice-storm

recovery costs in the storm-damage reserve account.

(Responds to OPUC Issue). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

A. Background of the storm-reserve account.. . . . . . . . . . . 23

B. The Commission did not decide in earlier dockets

whether the 1997 ice-storm expenses were properly

charged against the storm-reserve account.. . . . . . . . . . 24

C. The reasonableness and prudence of the 1997 ice-

storm expenses was based on the evidence in this

case; it was not decided in Docket No. 18249.. . . . . . . . 25

D. Substantial evidence supports the expenses of

restoring service after the 1997 Ice Storm.. . . . . . . . . . . 27

E. OPUC’s additional complaints do not show error.. . . . . 29

IV. Substantial evidence supports the Commission’s

determination that Entergy failed to meet its burden to

prove that predicted purchased-power capacity costs were

known-and-measurable changes to the test-year data.

(Responds to Entergy’s Issue 2).. . . . . . . . . . . . . . . . . . . . . . . . . 31

A. The Commission uses the utility’s actual expenses

during a test year to determine what expenses to

include in rates, and they can only be changed for

known-and-measurable changes... . . . . . . . . . . . . . . . . . . 31

iii

B. Entergy sought adjustments outside the test year for

alleged future capacity expenses.. . . . . . . . . . . . . . . . . . . 33

C. Entergy failed to prove that the adjustments were

known-and-measurable changes... . . . . . . . . . . . . . . . . . 37

V. Substantial evidence supports the Commission’s

determination that Entergy failed to meet its burden to

prove that predicted transmission-equalization charges

were known-and-measurable changes to the test-year

data. (Responsive to Entergy’s Issue 3)... . . . . . . . . . . . . . . . . 38

A. Entergy recovers transmission equalization

expenses through rates... . . . . . . . . . . . . . . . . . . . . . . . . . 39

B. Entergy sought an adjustment based on anticipated

post-test-year transmission expenses... . . . . . . . . . . . . . 39

C. Entergy failed to meet its burden, and the

Commission denied its requested adjustments.. . . . . . . 42

Prayer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Certificate of Compliance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Certificate of Service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

APPENDICES

Commission Order (Docket No. 39896). . . . . . . . . . . . . . . . . . . . . . . . . . . . . A

Proposal for Decision (Docket No. 39896). . . . . . . . . . . . . . . . . . . . . . . . . . . B

Black-box Order (Docket No. 37744).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C

iv

Index of Authorities

Cases Page(s)

AEP Tex. N. Co. v. Pub. Util. Comm’n,

297 S.W.3d 435 (Tex. App.—Austin 2009, pet. denied). . . . . 22, 23

Anderson v. R.R. Comm’n,

963 S.W.2d 217 (Tex. App.—Austin 1998, pet. denied). . . . . . . . 9, 10

Cent. Power & Light v. Pub. Util. Comm’n,

36 S.W.3d 547 (Tex. App.—Austin 2000, pet. denied). . . . . . . . . 32

Cities of Abilene v. Pub. Util. Comm’n,

146 S.W.3d 742 (Tex. App.—Austin 2004, no pet.). . . . . . . . . 10, 23

Cities of Abilene v. Pub. Util. Comm’n,

854 S.W.2d 932 (Tex. App.—Austin 1993) aff’d in part, rev’d in

part on other grounds, 909 S.W. 2d 493 (Tex. 1995)... . . . . . . 21, 22

Cities of Corpus Christi v. Pub. Util. Comm’n,

2008 WL 615417 (Tex. App.—Austin Mar. 5, 2008, no pet.)

(mem. op.). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

City of El Paso v. El Paso Elec. Co.,

851 S.W.2d 896 (Tex. App.—Austin 1993, writ denied).. . . . . . . . 33

City of El Paso v. Pub. Util. Comm’n,

344 S.W.3d 609 (Tex. App.—Austin 2011, no pet.). . . . . . . . . . . . 33

City of El Paso v. Pub. Util. Comm’n,

883 S.W.2d 179 (Tex. 1994). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10, 11

Entergy Gulf States, Inc. v. Pub. Util. Comm’n,

112 S.W.3d 208 (Tex. App.—Austin 2003, pet. denied).. . . . . . . . 22

Gulf States Utils. Co. v. Pub. Util. Comm’n,

841 S.W.2d 459 (Tex. App.—Austin 1992, writ denied).. . . . . . . . 33

v

Cases cont’d Page(s)

Meier Infiniti v. Motor Vehicle Bd.,

918 S.W.2d. 95 (Tex. App.—Austin 1996, writ denied). . . . . . . . . 30

Pub. Util. Comm’n v. GTE-Sw., Inc.,

901 S.W.2d. 401 (Tex. 1995). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Pub. Util. Comm’n v. Gulf States Utils. Co.,

809 S.W.2d. 201 (Tex. 1991). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

State Agencies & Insts. of Higher Learning v. Pub. Util. Comm’n,

450 S.W.3d 615 (Tex. App.—Austin 2014, pet. filed). . . . . . . . . . . 22

Tex. Health Facilities Comm’n v. Charter Med.-Dallas, Inc.,

665 S.W.2d 446 (Tex. 1984). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10, 11

Tex. Utils. Elec. Co. v. Pub. Util. Comm’n,

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)... . . . . . . . . . 29

Statutes

Tex. Gov’t Code

§§ 2001.001–.902. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii

§ 2001.003(1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

§ 2001.174. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Tex. Util. Code

§§ 11.01–66.016.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

§§ 39.458–.463. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

§ 15.001. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

§ 36.006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4, 7, 21, 32

§ 36.051. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3, 7, 31

§ 36.064(a).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

§ 39.458(a).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

§ 39.459(c). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15, 17, 18

§ 39.462(a).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17, 18

vi

Rules

16 Tex. Admin. Code

§ 25.5(134). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . x, 7, 32

§ 25.231(a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

§ 25.231(b). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7, 31, 32

§ 25.231(b)(1)(G).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5, 6, 30

§ 25.231(c)(2)(C)(iii).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

§ 25.231(c)(2)(E). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

§ 25.239(c). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

vii

Glossary

ALJ Administrative Law Judge

APA Administrative Procedure Act, Tex. Gov’t Code

§§ 2001.001–.902.

Black-box case Tex. Pub. Util. Comm’n, Application of Entergy

Texas for Authority to Change Rates and Reconcile

Fuel Costs, Docket No. 37744. Entergy’s last rate

case before this case.

Black-box Order Tex. Pub. Util. Comm’n, Application of Entergy

Texas for Authority to Change Rates and Reconcile

Fuel Costs, Docket No. 37744, available at

http://interchange.puc.state.tx.us/WebApp/Interch

ange/Documents/37744_1449_686947.PDF (Dec.

13, 2010) (final order setting rates) (37744 Order).

A copy is attached as Appendix C.

Cities 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, Texas These cities are in the service area of

Entergy Texas, Inc.

Commission or PUC Public Utility Commission of Texas

Commission Staff Commission personnel acting as a party in a

contested case representing the public interest

before the PUC

Entergy Entergy Texas, Inc., the utility asking the

Commission to set rates in this case

ERCOT Electric Reliability Council of Texas

viii

ETI Acronym for Entergy Texas, Inc. that is used in the

administrative record—the same entity called

“Entergy” in this brief

FERC Federal Energy Regulatory Commission

MSS-1 Schedule MSS-1 of the Entergy System Agreement,

a tariff set by the Federal Energy Regulatory

Commission

MSS-2 Schedule MSS-2 of the Entergy System Agreement,

a tariff set by the Federal Energy Regulatory

Commission

MSS-4 Schedule MSS-4 of the Entergy System Agreement,

a tariff set by the Federal Energy Regulatory

Commission

Operating Companies Several Entergy related electric companies in Texas,

Louisiana, Mississippi, and Arkansas that operate

generation resources together under a System

Agreement filed with the Federal Energy Regulatory

Commission

OPUC Office of Public Utility Counsel, created by statute to

represent the interests of residential and small

commercial customers in proceedings before the

PUC

Order The Commission’s order on rehearing that is the

subject of this lawsuit. (AR, Item 244.)

PFD Proposal for Decision prepared by the ALJ in this

case (AR, Item 185.)

Rate Base Another term for the utility’s invested capital used

to determine how much a utility should receive in

rates

ix

Rita Hurricane Rita that hit the upper Texas coast in

2005

Rita Asset The regulatory asset included in Entergy’s rate base

that reflects Rita reconstruction costs that Entergy

did not securitize because it incorrectly anticipated

that they would be recovered through insurance

proceeds.

Securitization Order Tex. Pub. Util. Comm’n, Application of Entergy

Gulf States, Inc. for Determination of Hurricane

Reconstruction Costs, Docket No. 32907, available

at

http://interchange.puc.state.tx.us/WebApp/Interch

ange/Documents/32907_401_532588.PDF (Dec. 1,

2006) (final order granting application)

(Securitization Order). This is the docket where the

Commission allowed Entergy to securitize

Hurricane Rita reconstruction costs.

Test year “The most recent 12 months for which operating

data for an electric utility … are available and shall

commence with a calendar quarter or a fiscal year

quarter.” 16 Tex. Admin. Code § 25.5(134).

TIEC Texas Industrial Energy Consumers, a group of

industrial customers that participated as a party in

this case

x

Statement of the Case

Entergy Texas, Inc., an electric utility in the southeastern part of Texas,

together with several groups of its customers, filed administrative appeals

of the Public Utility Commission’s order setting retail rates for Entergy.

The district court affirmed the Commission’s order on all but one issue. In

this brief, the Commission responds to appeals by Entergy and the Office of

Public Utility Counsel on the other issues.

Statement Regarding Oral Argument

Based on the number of parties, the number of issues, and the

complexity of rate regulation, oral argument would help the Court.

xi

Issues Presented

Issue 1: Did the Commission reasonably interpret how its prior ambiguous

order in PUC Docket 37744 (the Black-box Order) treated the Hurricane

Rita regulatory asset? (Responds to Entergy Issue 1)

Issue 2: Does substantial evidence support the Commission’s decision to

include Entergy’s 1997 ice-storm repair expenses when computing the

utility’s insurance reserve? (Responds to OPUC Issue)

Issue 3: Does substantial evidence support the Commission’s decision that

Entergy failed to prove that certain purchased-power capacity costs were

known-and-measurable changes to those expenses in the test year?

(Responds to Entergy Issue 2)

Issue 4: Does substantial evidence support the Commission’s decision that

Entergy failed to prove that predicted transmission-equalization charges

were known-and-measurable changes to those costs in the test year?

(Responds to Entergy Issue 3)

xii

Statement of Facts

I. Procedural History

This is an administrative appeal of a Public Utility Commission order

that set retail electric rates for Entergy in PUC Docket 39896. The

Commission continues to set retail electric rates for Entergy, which is

situated outside the interconnected grid operated by the Electric Reliability

Council of Texas (ERCOT), using traditional rate-setting procedures

prescribed in Chapter 36 of the Utilities Code.

Entergy initiated the rate case (SAR, ETI Exs. 1–6),1 and after notice was

sent, many parties intervened. (AR, Item 185, Proposal for Decision (PFD)

at 3, Binder 5.) Commission Staff also participated as a party, introducing

evidence and presenting argument. (Id.)

Administrative law judges (ALJs) conducted the hearing, and then the

parties filed briefs with the ALJs. (AR, Items 152–155, 157–158, Binder 3;

159–162, 164, 167–175, Binder 4; 176–177, Binder 5.) The ALJs issued their

1

The administrative record in this case was admitted into evidence as Joint

Exhibits Nos. 1 through 13. R.R. at 5:11–5:19. Exhibits 1–3 are indices to the

administrative record. Exhibits 4–10 and 13 include seven volumes of filings, which are

referenced as “Item”; thirty-five volumes of exhibits; and one transcript. Citations to

that part of the Administrative Record will be in the form “AR, Item(s) ___,” for filings,

“AR, ___ Ex(s). ___,” for exhibits, and “AR, Tr. at ___” for transcripts. Exhibits 11 and

12 contain Entergy’s entire rate-filing package. They are two boxes containing six items

numbered 1–6. Because different documents are numbered 1–6 in the other parts of the

administrative record, citations to the Supplemental Administrative Record will be in

the form “SAR, Item(s) ___.”

1

proposal for decision (AR, Item 185 (PFD)) that discussed the evidence and

arguments and proposed findings of fact and conclusions of law. Parties

filed exceptions to the PFD, and the case was sent to the Commission. (AR,

Items 191–197, 200–206, Binder 6; AR, Items 207–208, Binder 7.)

After considering the case in open meeting, the Commission issued its

order (AR, Item 227, Binder 7), parties filed motions for rehearing (AR,

Items 228–29, 231–42, Binder 7), and the Commission granted those

motions in part and denied them in part in its order on rehearing (Order).

(AR, Item 244, Binder 7.) The Order, the Commission’s final, appealable

order, adopted much of the PFD. (AR, Order at 1.)

Entergy, the utility, filed a suit for judicial review against the

Commission. So did the following ratepayer groups: Cities, a group of

cities in Entergy’s service area; OPUC; and State Agencies, certain Texas

agencies that receive electric service from Entergy.2 The cases were

consolidated, parties filed briefs, and the district court heard argument at

its hearing on the merits.

After considering the briefing of the parties, the administrative record,

and the argument of the parties at the hearing on the merits, the district

2

Shortly before the hearing on the merits, State Agencies moved to withdraw

their appeal, and the district court granted that motion. (C.R. 2079–83, 2084.)

2

court issued its judgment that affirmed the Commission on all but one

issue.

The Commission, Entergy, and OPUC filed notices of appeal, and have

filed their appellants’ briefs. The Commission files this brief in response to

the appellants’ briefs of Entergy and OPUC.

II. Rate Setting

Ratemaking is a legislative function. Pub. Util. Comm’n v. GTE-Sw.,

Inc., 901 S.W.2d. 401, 406 (Tex. 1995). The Commission exercises

discretion when setting rates, which, pursuant to the Administrative

Procedure Act, is done in a contested case. Tex. Gov’t Code § 2001.003(1).

And the Public Utility Regulatory Act, (Tex. Util. Code §§ 11.01–66.016)

(PURA), sets out the procedure for the Commission to set rates.

First, the Commission decides how much revenue the utility needs to

recover. This revenue requirement is the rate of return multiplied by the

utility’s invested capital (rate base) plus the utility’s reasonable and

necessary operating expenses:

(rate base × rate of return) + expenses = revenue requirement.

See Tex. Util. Code § 36.051. Next, the Commission must design the

rates—determine how much should be collected from different rate classes

and what method to use to collect those amounts.

3

So there are four main components to a Commission rate case: (1) the

utility’s invested capital or rate base; (2) the reasonable rate of return the

utility should earn on its invested capital; (3) the utility’s reasonable and

necessary operating expenses; and (4) the rate design. In addition, fuel

costs are recovered through temporary rates called “fuel factors.” In all

components of a rate case, the burden of proof is on the utility. Tex. Util.

Code § 36.006.

The issues addressed in this brief concern both rate base and expenses.

A. Rate Base

Investments in physical assets are a large part of a utility’s rate base, but

it also includes other assets: regulatory assets—expenses that the

regulatory authority allows the utility to capitalize and recover over time by

amortization—and a utility’s self-insurance storm-reserve account.

1. Hurricane Rita Regulatory Asset

The issue about the Hurricane Rita regulatory asset (Rita Asset) traces

back to Entergy’s costs of reconstruction after Hurricane Rita. Those costs

were so great that the Legislature allowed utilities to recover them through

securitization—selling bonds. Tex. Util. Code §§ 39.458–.463.

4

When the Commission authorized Entergy to securitize its Hurricane

Rita reconstruction costs in PUC Docket 32907 (Securitization Order),3 the

parties agreed on the amount of Hurricane Rita reconstruction costs, and

Entergy estimated the amount of those costs it would receive through

insurance proceeds. Securitization Order, FF 24 at 4–5. The amount

securitized was reconstruction costs minus estimated insurance proceeds.

Securitization Order, FF 35 at 7. The parties agreed to true up the amount

of insurance proceeds later. Securitization Order, FF 29 at 5–6.

Four years later Entergy realized that it would receive approximately

$20 million less in insurance proceeds than it had anticipated, and asked

the Commission in its 2010 rate case, the Black-box Case, to recover that

$20 million with accrued interest as a regulatory asset. (AR, PFD at 16.)

2. Self-Insurance Storm Reserve and the 1997 Ice Storm

The 1997 ice-storm issue concerns Entergy’s self-insurance plan. The

Commission allows a utility to keep funds on hand to cover costs of natural

disasters rather than paying a third party for insurance to cover those costs.

The Commission’s rules provide that “a self insurance plan is a plan

providing for accruals to be credited to reserve accounts.” 16 Tex. Admin.

3

Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for

Determination of Hurricane Reconstruction Costs, Docket No. 32907, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/32907_401_5325

88.PDF (Dec. 1, 2006) (final order granting application) (Securitization Order).

5

Code § 25.231 (b)(1)(G). The amount in a self-insurance account is

deducted from rate base. 16 Tex. Admin. Code § 25.231(c)(2)(C)(iii).

“The reserve accounts are to be charged with property and liability

losses which occur, and which could not have been reasonably anticipated

and included in operating and maintenance expenses, and are not paid or

reimbursed by commercial insurance.” Id. Shortages in the reserve

account increase the rate base and any surpluses in the reserve account are

subtracted from rate base. 16 Tex. Admin. Code § 25.231(c)(2)(E).

The Commission’s rules also require the utility to “maintain appropriate

books and records to permit the commission to properly review all charges

to the reserve account and determine whether the charges being booked to

the reserve account are reasonable and correct.” Id. Due to an earlier

statutory rate freeze and later settled rate cases, the Commission, for the

first time in this case, addressed charges to Entergy’s storm-damage

account based on several storm events, including reconstruction and repair

costs after a severe ice storm in 1997.

B. Reasonable and Necessary Expenses

Entergy raises two issues about expenses: the cost of purchasing

capacity and the cost of transmission services. In both, Entergy asked the

Commission to increase the amount of expenses used to set rates from the

6

amount of those expenses in the test year, and in both, the Commission

found that Entergy failed to meet its burden to prove that the post-test-year

changes were known and measurable.

Only reasonable-and-necessary expenses can be recovered in rates. Tex.

Util. Code § 36.051. Although rates are set for the future, the expenses are

based on the actual expenses the utility incurred in the test year. 16 Tex.

Admin. Code § 25.231(b). The test year is “[t]he most recent 12 months for

which operating data for an electric utility … are available and shall

commence with a calendar quarter or a fiscal year quarter.” 16 Tex. Admin.

Code § 25.5(134). The actual test-year expenses that are reasonable and

necessary will only be adjusted for known-and-measurable changes. 16

Tex. Admin. Code § 25.231(b). Because the utility bears the burden of

proof in a rate case (Tex. Util. Code § 36.006), Entergy had to convince the

Commission that any post-test-year expenses it wanted to include in rates

are known-and-measurable changes.

Summary of the Argument

The Commission’s Order should be affirmed. The Commission

reasonably interpreted its prior rate-case order, the Black-box Order, to

authorize Entergy to book and amortize a regulatory asset for unrecovered

Hurricane Rita reconstruction costs. The Black-box Order was ambiguous

7

concerning the Rita Asset. That order was based on a “black box”

settlement—one where only the amount of rates to be collected was set

forth, not all of the individual components of a rate case. Because the

Black-box Order did not explicitly state whether booking and amortizing

the regulatory asset had been authorized, it was ambiguous. Courts defer

to an agency’s interpretation of its prior, ambiguous order, and the

evidence in the record supports the Commission’s decision.

Substantial evidence supports the Commission’s decision that

$13 million should be added to Entergy’s storm reserve based on the

expenses Entergy incurred to repair equipment after a severe ice storm in

1997. A prior Commission decision that faulted Entergy for poor service

quality did not amount to a finding that Entergy could not include the

repair costs in the insurance reserve amount.

Substantial evidence supports the Commission’s decision that Entergy

failed to meet its burden of proof to increase the cost of purchasing capacity

and the cost for transmission charges from the amount of those costs

shown in the test-year amounts. The record supports the Commission’s

decision that Entergy did not meet its burden of proving that requested

changes were known and measurable.

8

For example, Entergy based its arguments about purchasing capacity on

the assumption that it would always purchase the maximum amount under

new contracts. Entergy claimed that it would have more customers in the

future. Not only is that speculative, but the utility failed to account for how

additional customers would otherwise affect its recovery through rates.

And Entergy’s arguments about transmission charges are controlled by

numerous unknown variables used in a complex formula. The

Commission’s test-year rule is created to avoid just such unknowns.

Moreover, most of Entergy’s request for post-test-year changes to

transmission costs were based on an agreement that was still waiting for

approval from the Federal Energy Regulatory Commission. That is

patently not a “known” change. Because substantial evidence supports the

Commission’s decisions, the Order should be affirmed.

Argument

I. Standard of Review

As in any lawsuit, plaintiffs bear the burden of proof. For an

administrative appeal of the Commission’s order in a contested case, those

challenging the order must show reversible error; the substantial-evidence

rule described in Section 2001.174 of the Administrative Procedure Act

controls. See Anderson v. R.R. Comm’n, 963 S.W.2d 217, 219 (Tex.

9

App.—Austin 1998, pet. denied); Tex. Util. Code § 15.001; Tex. Gov’t Code

§ 2001.174. That rule is very deferential to the agency, but the deference

owed varies depending on the type of error alleged. Issues raised by

Entergy and OPUC invoke the substantial-evidence standard and the

arbitrary-and-capricious standard.

Substantial-evidence Standard

When reviewing an agency’s fact finding, a court uses the deferential

substantial-evidence standard. It prohibits a court from substituting its

judgment for the agency’s as to the weight of evidence. Pub. Util. Comm’n

v. Gulf States Utils. Co., 809 S.W.2d 201, 211 (Tex. 1991). “A court that is

reviewing purely factual administrative findings … may determine only

whether substantial evidence supports those findings.” Cities of Abilene v.

Pub. Util. Comm’n, 146 S.W.3d 742, 748 (Tex. App.—Austin 2004, no pet.).

The true test is not whether the agency reached the correct conclusion, but

whether some reasonable basis exists in the record for the agency’s action.

Tex. Health Facilities Comm’n v. Charter Med.-Dallas, Inc., 665 S.W.2d

446, 452 (Tex. 1984). “At its core, the substantial evidence rule is a

reasonableness test or a rational basis test.” City of El Paso v. Pub. Util.

Comm’n, 883 S.W.2d 179, 185 (Tex. 1994).

10

Arbitrary-and-capricious Standard

The Texas Supreme Court has recognized the narrowness of the

arbitrary-and-capricious standard of review when applied to agency

decisions: “[W]e do not think that the legislature intended it to be

interpreted as a broad, all-encompassing standard for reviewing the

rationale of agency actions.” Charter Med., 665 S.W.2d at 454.

Courts must uphold a Commission decision if “some reasonable basis

exists in the record for the action taken by the agency.” City of El Paso,

883 S.W.2d at 185.

II. The district court properly affirmed the Commission’s

decision about the amount of the Hurricane Rita regulatory

asset to include in Entergy’s rate base. (Responds to

Entergy Issue 1)

The district court properly affirmed the Commission’s determination of

the amount of the Hurricane Rita regulatory asset (Rita Asset) that was in

Entergy’s rate base when it set rates in this case. Substantial evidence

supports the Commission’s reasonable decision that Entergy began

amortizing that amount through rates set by the Black-box Order. In

Entergy’s 2010 Black-box Case, the Commission allowed the utility to

recover nearly $20 million of Rita recovery costs by creating and

amortizing a regulatory asset. Considering the deference due to the

Commission’s interpretation of its prior ambiguous order, this Court

11

should also affirm the Commission’s decision about the amount of the Rita

Asset in rate base.

A. Factual Background

The Rita Asset was an issue in Entergy’s preceding rate case, the Black-

box Case. As explained below, because that case was resolved based on the

parties’ “black box” settlement, the Commission’s order in that earlier case

is ambiguous as to how the Rita Asset was decided.

The Commission’s Black-box Order4 contained little more detail than the

total amount to be recovered in rates and the rate design used to recover

that amount. In contrast, a typical Commission order adopting rates, like

the order in this case, spells out in some detail the amounts in each

category of invested capital (rate base)5 as well as the total rate base,6 each

part of debt and return on equity used to determine the rate of return,7 the

amounts of reasonable and necessary expenses in each category,8 and the

4

Tex. Pub. Util. Comm’n, Application of Entergy Texas for Authority to

Change Rates and Reconcile Fuel Costs, Docket No. 37744, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/37744_1449_686

947.PDF (Dec. 13, 2010) (final order setting rates) (Black-box Order). A copy is

attached as Appendix C.

5

AR, Order at Schedule III (invested capital).

6

Id. (showing $1,700,128,144 as the total invested capital).

7

AR, Order at 6–7, FF 64–71 at 18–19.

8

AR, Order at FF 72–170 at 19–29, Schedules II, IV, & V.

12

rate design listing each rate class and explaining how the rates to be paid by

each class will be determined.9 But to reach a settlement in the Black-box

Case, the parties omitted that detail.

Finding of Fact 16 of the Black-box Order explained that the parties to

that case agreed that Entergy “should be allowed to implement an initial

overall increase in base-rate revenues of $59 million for usage on and after

August 15, 2010.” Black-box Order, FF 16 at 15. And they agreed that

Entergy “should be allowed to implement an additional overall increase in

base-rate revenues of $9 million on an annualized basis effective for bills

rendered on and after May 2, 2011.” Id. The lack of detail in the Black-box

Order created an issue in the current rate case about how much of the Rita

Asset was in Entergy’s current rate base.

In this case, the parties disputed what part of the Rita Asset Entergy

recovered under the Black-box Order. Entergy argued that it had not

received any part of the Rita Asset from the Black-box Order, but in the

alternative argued that only part of the Rita Asset had been recovered

under the Black-box Order. (AR, Item 157 at 9-13, Binder 3.) Cities argued

that the rates based on the Black-box Case settlement included

amortization of the Rita Asset so that only a portion of that amount

9

AR, Order at FF 175–213 at 29–35.

13

remained to be recovered in this rate case. (AR, Item 161 at 10-12, Binder

4.) Commission Staff argued that Entergy had recovered all of the Rita

Asset through the rates set in the Black-box Order, but in the alternative

argued that only part of the Rita Asset had been recovered under the Black-

box Order. (AR, Item 164 at 10, Binder 4; AR, Staff Ex. 1 (Givens Direct) at

32, Binder 40.)

The ALJs decided that the Rita Asset had been partially amortized

through the Black-box Case rates, but found that the amount recovered

through those rates was different from the amounts proposed by any of the

parties. (AR, PFD at 4.) The Commission adopted that part of the PFD.

(AR, Order at 1.)

B. Substantial evidence supports the Commission’s

reasonable interpretation of its prior, ambiguous order.

1. The Black-box Order decided the Rita Asset issue.

The Commission approved creation and amortization of the Rita Asset

in the Black-box Order. All parties in the Black-box Case agreed that

Entergy was entitled to recover the $20 million of overestimated insurance

proceeds that it requested. And, by the terms of the Black-box Order,

Entergy’s request that the Commission approve booking and amortizing the

Rita Asset was either approved or denied in that case—it could not have

14

been ignored by the order. Thus, the Black-box Order had to have

approved amortizing the Rita Asset.

The PFD weighed several factors to determine what the Commission

decided about the Rita Asset in the Black-box Case:

• The Securitization Order said there would be a true up after the

insurance proceeds were received.

• Utilities Code Section 39.459(c) says if the timing of receiving insurance

proceeds means that they were not included in securitization, they

should be included in the next rate case.

• The Black-box Case was the next rate case.

• In the Black-box Case, no one objected to the regulatory asset or

amortizing it.

• The Black-box Order said that it resolved all issues except the

Competitive Generation Services proposal.

• The Black-box Order did not specifically exclude the Rita regulatory

asset but did specifically exclude some other regulatory assets; some

others were expressly approved.

(AR, PFD at 20–21.) The last factor shows the ambiguity in the Black-box

Order. All the other factors weighed in favor of holding that the

15

Commission approved booking and amortizing the Rita Asset in the Black-

box Order. (Id.)

Although the Commission relied on all of these considerations, Entergy

attacks the factors individually. But as shown factor-by-factor below,

Entergy’s arguments are unavailing.

Securitization Docket

As both the Commission and Entergy note, the Securitization Order said

that there would be a true up after insurance proceeds were received. And

all agree that once Entergy showed that it would not recover $20 million of

the Rita reconstruction costs through estimated insurance proceeds, the

Commission should take action to allow Entergy to recover those costs.

That supports the idea that the Commission would act quickly—in the

Black-box Case where it was first asked—to approve booking and

amortizing the Rita Asset so that Entergy could quickly recover the

overestimated insurance proceeds.

The statute requires action in the next rate case.

That the Black-box Case was the “next” base-rate case supports the

Commission’s conclusion that it approved booking and amortizing the Rita

Asset in that case. Entergy’s argument about which statute applies is

irrelevant because all the cited statutes indicate that the utility should

16

recover its Rita reconstruction costs as soon as possible; as soon as Entergy

raised the issue in a base-rate case.

Both the statute cited by the Commission and that cited by Entergy

emphasize the need to get funds to the utility quickly. Utilities Code

§ 39.459(c), cited by the Commission states: “If the timing of a utility’s

receipt of [insurance proceeds] prevents their inclusion as a reduction to

the hurricane reconstruction costs that are securitized, the commission

shall take those amounts into account in (1) the utility’s next base rate

proceeding; or (2) any proceeding in which the commission considers

hurricane reconstruction costs.” Section 39.462(a) cited by Entergy stated

that the utility is entitled to seek recovery “in its next base rate proceeding

or through any other proceedings authorized by Subchapter C, Chapter 39.”

And a stated purpose of the hurricane-recovery statutes is “to enable an

electric utility subject to this subchapter to obtain timely recovery of

hurricane reconstruction costs.” Tex. Util. Code § 39.458(a) (emphasis

added). Thus, whichever statute applies, the Commission can reasonably

expect to address insurance proceeds in the next base-rate case or other

permitted Commission case.

The Commission’s analysis is correct, whichever statute applies: the

Commission should address questions about insurance proceeds for Rita

17

reconstruction costs when the utility raises the issue in a base-rate case.

(Since both the Black-box Case and this case are base-rate proceedings,

there is no need to address what other types of proceedings were available.)

Which is the next rate case?

The Black-box Case was the “next” base-rate proceeding. “[N]ext base

rate proceeding” (Tex. Util. Code §§ 39.459(c) & .462(a)) refers to “the

timing of a utility’s receipt of those amounts.” (Tex. Util. Code § 39.459(c)).

The statute does not refer to the next proceeding after the Commission

authorized securitization. Thus, the fact that Docket 34800 was Entergy’s

next rate case10 after securitization did not make it the appropriate docket

to address the $20 million of overestimated insurance proceeds.

The Black-box Case was the first time Entergy asked to recover the Rita

Asset. And the record indicates that the Black-box Case was the “next”

Entergy rate case after the utility knew that it would not receive the

anticipated $20 million of insurance proceeds. Entergy did not state

exactly when it finally realized that it would not receive $20 million of

anticipated insurance proceeds. But factors indicate that the Black-box

10

Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for

Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/application/dbapps/filings/pg

Control.asp?TXT_UTILITY_TYPE=A&TXT_CNTRL_NO=34800&TXT_ITEM_MATC

H=1&TXT_ITEM_NO=&TXT_N_UTILITY=&TXT_N_FILE_PARTY=&TXT_DOC_TY

PE=ALL&TXT_D_FROM=&TXT_D_TO=&TXT_NEW=true (Sep. 26, 2007).

18

Case was the next proceeding: 1) Entergy was to make the adjustment in

the next proceeding after that determination and 2) it would be in Entergy’s

interest to begin receiving additional rates to compensate for those costs.

This supports a reasonable inference that the Black-box Case—the docket

where Entergy first asked for the $20 million—was the “next proceeding”

after the utility knew that it would not receive those anticipated insurance

proceeds.

No objection to the regulatory asset or amortizing it

Entergy asked for the Rita regulatory asset in the Black-box Case and no

one in that case argued that Entergy was not entitled to recover that

amount through rates. That is another factor that supports the

Commission’s conclusion that booking and amortizing the Rita Asset was

approved in the Black-box Order.

The evidence in this case shows that no party to the Black-box Case

disputed that the $20 million needed to be included in rates. In this case,

PUC Staff Witness Givens testified that, other than a minor adjustment to

the amount that he recommended, “No other adjustments were

recommended to the Company’s request for inclusion of the regulatory

asset in rate base or the amortization expense associated with the asset.”

19

(AR, Staff Ex. 1 (Givens Direct) at 33,11 Binder 40.) And Cities witness

Garrett testified: “[E]ven though the last rate case settled, since no party

opposed the Company’s inclusion in rates of the Rita regulatory costs, the

Company should have been amortizing the Rita regulatory balance since

the last case, … .” (AR, Cities Ex. 2 (Garrett Direct) at 11, Binder 8.)

Based on that testimony, the Commission, in this case, decided that in

the Black-box Case “there was no objection to [Entergy]’s proposed

Hurricane Rita regulatory asset, it was authorized by the prior settlement in

[the Securitization Order docket], and the Commission was directed by

PURA § 39.459(c) to take into account [Entergy]’s insurance proceeds

related to the Hurricane Rita securitized costs in [Entergy]’s next rate case,

which was [the Black-box Case].” (AR, PFD at 21–22.)

All issues resolved in the Black-box Order

The Black-box Order states that the parties entered into “a stipulation

and settlement agreement that resolves all of the issues in this proceeding

except the issues related to [Entergy]’s proposal for competitive generation

service.” Black-box Order at 1 (emphasis added). No parties to this case

dispute that “[i]n [the Black-box Case], [Entergy] requested recovery of the

11

Several exhibits in the Administrative Record have multiple page numbers.

Citations are to the Bates stamped number on the bottom right of the exhibit unless

there is no such number on the page.

20

Overestimated Insurance Proceeds by establishing a regulatory asset of

$19,686,096, plus accrued carrying costs, to be amortized over five years.”

(AR, PFD at 16). And Ordering Paragraph 15 in the Black-box Order states:

“All other motions, requests for entry of specific findings of fact,

conclusions of law, and ordering paragraphs, and any other requests for

general or specific relief, if not expressly granted in this order, are hereby

denied.” Thus, if the Commission did not address the Rita Asset in that

PUC docket, the Commission denied Entergy’s request.

Entergy’s attempt to argue that the Commission approved the Rita

Asset but did not order the utility to begin recovering it through

amortization is unavailing. As explained above, evidence in this case shows

that Entergy requested both in the Black-box Case. And, the utility fails to

explain how only one part of its request could have been approved given the

language of the Black-box Order.

In this rate case, Entergy bears the burden to prove how much of the

Rita Asset is in rate base. The Utilities Code places the burden of proof in a

rate case on the utility. Tex. Util. Code § 36.006. Rate base (also called

invested capital) is one of the inputs to determine the utility’s revenue

requirement. Thus, the utility bears the burden to prove the amount of its

rate base. See Cities of Abilene v. Pub. Util. Comm’n, 854 S.W.2d 932,

21

936–37 (Tex. App.—Austin 1993) (recognizing the utility’s burden of proof

and that determining rate base is one of the three factors used to determine

a utility’s rates), aff’d in part, rev’d in part on other grounds, 909 S.W. 2d

493 (Tex. 1995). This Court recently recognized the utility’s burden to

prove the amount in its rate base when the Court cited the prudence

standard used to determine whether assets purchased by a utility should be

included in rate base. See State Agencies & Insts. of Higher Learning v.

Pub. Util. Comm’n, 450 S.W.3d 615, 635 (Tex. App.—Austin 2014, pet.

filed) (applying the prudence standard to Oncor Electric Delivery

Company’s purchase of smart meters). And in Entergy Gulf States, Inc. v.

Pub. Util. Comm’n, 112 S.W.3d 208 (Tex. App.—Austin 2003, pet. denied),

the entire case is about the utility’s burden to prove the amount of its rate

base.

Because the Rita-Asset question concerns how much is included in

Entergy’s rate base, Entergy bore the burden of proving that amount.

2. The Court should defer to the Commission’s

interpretation of its ambiguous Black-box Order.

A court generally defers to an agency’s interpretation of its prior

order. “Just as we give great weight to an agency’s interpretation of its own

rules and regulations, we give great weight to an agency’s interpretation of

its administrative orders.” AEP Tex. N. Co. v. Pub. Util. Comm’n, 297

22

S.W.3d 435, 447 (Tex. App.—Austin 2009, pet. denied). “If the Settlement

Order is ambiguous, we will affirm the Commission’s interpretation of it in

the Final Order if the interpretation is supported by substantial evidence.”

Cities of Abilene v. Pub. Util. Comm’n, 146 S.W.3d at 748.

The Court should defer to the Commission’s reasonable

interpretation of its prior, ambiguous order.

III. The Commission properly included the 1997 ice-storm

recovery costs in the storm-damage reserve account.

(Responds to OPUC Issue)

Substantial evidence shows that the expenses for the 1997 ice-storm

recovery belong in Entergy’s self-insurance storm-reserve account.

A. Background of the storm-reserve account.

In this case, Entergy showed that it had overdrawn its storm-reserve

account. In PUC Docket 16705 and in the Black-box Order, Entergy was

allowed to maintain a storm damage reserve of about $15.6 million.12 (AR,

PFD at 45.) But over the course of the 15 years prior to this case, more than

200 storms occurred. (Id.) So Entergy had charged about $101.7 million to

the reserve account in costs of restoring service (not counting securitized

12

Tex. Pub. Util. Comm’n, 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, to Set Revised Fuel Factors, and to Recover a

Surcharge for Under-Recovered Fuel Costs, Docket No. 16705 available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/98171.TIF (Oct.

14, 1998) (second order on rehearing at FOF 120).

23

expenses). At the same time, Entergy had accrued only about $29.8 million

in its reserve. (Id.) Thus, in this case, Entergy asked the Commission to

agree that the current amount of its storm-reserve account was about a

negative $59.8 million. (Id.)

The Commission agreed (AR, Order, FF 50) and ordered the reserve

to be replenished in increments, eventually establishing a $17.6 million

storm-reserve account. (AR, Order, FF 157-159.) The $13 million of 1997

ice-storm costs that OPUC complains about is included in the $59.8 million

negative storm reserve.

B. The Commission did not decide in earlier dockets

whether the 1997 ice-storm expenses were properly

charged against the storm-reserve account.

Although there were several Entergy rate cases before this case, none

of them determined whether expenses were properly charged against the

storm-reserve account. In fact, the Commission did not have the

opportunity to consider whether the 1997 ice-storm expenses were properly

charged against the storm-reserve account until this 2012 rate case.

No party disputes that the Commission carried the question whether

the 1997 ice-storm repair expenses were properly booked against Entergy’s

storm-reserve account for over a decade. In October 1998, the Commission

ordered Entergy to prove the reasonableness and prudence of charging the

24

ice-storm expenditures against the storm-reserve account in its next

(November 1998) rate case. But that rate case settled in June 1999 without

addressing the 1997 ice-storm expenditures.13 Entergy’s next rate case was

dismissed by the Commission in October 2004 because of a statutory rate

freeze.14 A March 2009 rate case settled without specifically addressing the

ice-storm expenditures, and the Black-box Case settled in December 2010

without addressing the expenditures. Accordingly, 15 years after the

original storm, the Commission considered the ice storm expenditures in

this case.

C. The reasonableness and prudence of the 1997 ice-

storm expenses was based on the evidence in this case;

it was not decided in Docket No. 18249.

OPUC’s reliance on the Service-quality Order is misplaced because it

is based on an incorrect premise. Both here and at the Commission OPUC

claimed that the Commission had decided that the expenses for the 1997

Ice Storm were imprudently incurred in PUC Docket No. 18249 (the

13

Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for

Authority to Change Rates, Docket 20150, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/application/dbapps/filings/pg

Search_Results.asp?TXT_CNTR_NO=20150&TXT_ITEM_NO=717 (Jun. 30, 1999)

(20150 Order).

14

Tex. Pub. Util. Comm’n, Application of Entergy Gulf States, Inc. for

Authority to Change Rates and to Reconcile Fuel Costs, Docket 30123, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/30123_112_4593

36.PDF (Oct. 20, 2004) (30123 Order).

25

Service-quality Order).15 So OPUC did not present evidence of any

imprudence in this case.

The Commission’s severed the service-quality case out of a 1996 rate

case so that the Commission could address the quality of Entergy’s electric

service to its customers after a merger in 1993. (Service-quality Order, at

39.) In the Service-quality Order, the Commission addressed maintenance

policies, Entergy’s level of spending in the area of operations and

maintenance, the experience of its personnel, and the consequent quality of

its service. (Id. at 7.) In that 1998 decision, the Commission stated that

“[t]he January 1997 ice storm was certainly a severe storm that would have

adversely affected even the best-maintained distribution system” (Id. at 18;

PFD at p. 56), but the agency also determined that Entergy’s poor service

quality and vegetation management failures aggravated the situation. (Id.

at 18-19.) In response to all the poor service-quality issues shown, the

Commission (1) reduced Entergy’s return on equity by 60 basis points, (2)

required Entergy to make refunds to its customers, and (3) imposed

significant spending requirements and quantified performance guarantees.

(Id. at 51-53.)

15

Tex. Pub. Util. Comm’n, Entergy Gulf States, Inc. Service Quality Issues

(Severed From Docket 16705), Docket 18249, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/18249_109_5520

77.PDF (Apr. 22, 1998) (order on rehearing) (the Service-quality Order).

26

In this case, the 1997 ice-storm issue was not about the general level

of service provided by Entergy in 1996 but whether the utility proved the

$13 million it spent for repairs after the ice storm was properly charged

against the storm-reserve account. The PFD states that Entergy established

that the expenses it incurred to repair damage and restore service after the

ice storm “were reasonable and necessary, and the ALJs find that they

should be included in the storm damage reserve.” (AR, PFD at 57.) Thus,

the Commission found that the statements in its 1998 order were not

enough to overcome Entergy’s showing that the actual expenditures were

reasonable, necessary, and prudent.

D. Substantial evidence supports the expenses of

restoring service after the 1997 Ice Storm.

Substantial evidence supports the determination that the expenses

Entergy incurred to restore power after the ice storm were reasonable,

necessary, and prudent. Entergy Witness Shawn Corkran testified that he

reviewed the expenses and “determined that the costs were reasonable and

necessary to reliably restore service to customers as quickly as possible

after the ice storm.” (AR, ETI Ex. 48 (Corkran Rebuttal) at 10, Binder 37,

Ex. SBC-R-1, at 22.) Entergy backed up this testimony with exhibits

containing a breakdown of expenses for labor, materials, transportation,

lodging, and other expenses. (Id.) “[O]nce the ice storm occurred,

27

[Entergy] had to take appropriate action to repair the damage and restore

service.” (AR, PFD at 57.)

Substantial evidence also supports the determination that the

expenses were not reasonably anticipated. Entergy’s Corkran provided 11

pages of testimony backed by exhibits providing a detailed breakdown of

the expenses incurred to take appropriate action to repair the damage and

restore service once the storm occurred. (AR, ETI Ex. 48 (Corkran

Rebuttal) at 4–14, Binder 37, and Ex. SBC-R-1, at 22.) Corkran established

that the ice storm was the most destructive winter storm to ever hit the

Entergy system. (Id. at 7.) The storm de-energized approximately 3,400

miles of distribution lines and 560 miles of transmission lines. (Id.) The

affected service area was within the light ice-loading zone according to the

National Electric Safety Code (“NESC”) in effect at the time, (id. at 9) and

the light ice-loading zone is defined by no ice accumulation on the

distribution lines. (Id.) The majority of the damage at issue was caused by

an accumulation of one to three inches of ice while temperatures remained

below freezing for more than two days after the storm’s initial onset. (Id.)

Corkran testified that although Entergy generally exceeds NESC

strength requirements, the ice storm put an extraordinary burden on the

facilities, causing the wires, poles, and other equipment to collapse from

28

the weight of the accumulated ice, and causing tree limbs weighed down by

ice accumulation to fall on Entergy’s lines. (Id.) Thus, the severe impact of

the ice storm was not reasonably anticipated in the NESC or by Entergy. In

conclusion, Corkran stated that the ice storm restoration and recovery

expenses were “reasonable, necessary and prudently incurred.” (Id. at 13-

14.)

OPUC’s complaint that Entergy failed to identify and quantify which

of its expenses were imprudent is unavailing. Entergy claimed all its

expenses were reasonable, and a utility is not required to identify which

expenses are imprudent. Tex. Utils. Elec. Co. v. Pub. Util. Comm’n, 881

S.W.2d 387, 404 (Tex. App.—Austin 1994) (“Nowhere does the supreme

court state that a utility must segregate imprudent costs.”), aff’d in part,

rev’d in part on other grounds, 935 S.W.2d 109 (Tex. 1997).

E. OPUC’s additional complaints do not show error.

OPUC’s further complaints are without merit. OPUC has not shown

that the Commission’s decision is arbitrary and capricious despite being

supported by substantial evidence.

The Commission was not required to make an ultimate finding of fact

in statutory language that storm-reserve expenses were “not reasonably

anticipated” as OPUC contends. Neither the Commission’s rule nor the

29

Utilities Code require such a finding of fact. See 16 Tex. Admin. Code

§ 25.231(b)(1)(G); Tex. Util. Code § 36.064(a). And, as stated above, the

Commission’s findings in the PFD show the Commission considered that it

would not have been reasonable to anticipate the devastation caused by the

1997 Ice Storm. An ultimate finding of fact in statutory language is not

required if the findings reflect that the Commission considered the required

underlying criteria. See Meier Infiniti v. Motor Vehicle Bd. 918 S.W.2d 95,

100-01 (Tex. App.—Austin 1996, writ denied).

Moreover, the Commission did not consider an irrelevant factor when

it decided to include the 1997 ice-storm recovery costs in the storm reserve.

OPUC’s assertion that the Commission improperly considered the passage

of time and “absolved the Company of its burden to prove” its expenditures

were imprudent is unfounded. (OPUC Appellant’s Brief at 38.) This is

merely a continuation of OPUC’s incorrect assertion that the utility must

identify its imprudence.

OPUC’s requested relief should be denied.

30

IV. Substantial evidence supports the Commission’s

determination that Entergy failed to meet its burden to

prove that predicted purchased-power capacity costs were

known-and-measurable changes to the test-year data.

(Responds to Entergy’s Issue 2).

Substantial evidence supports the Commission’s determination that

Entergy failed to meet its burden to prove that certain projected costs for

purchasing capacity were known-and-measurable changes from the costs

incurred during the test year. Some contracts Entergy relied upon were not

yet in place, and inputs for the variables in formulas for Entergy’s contracts

with its affiliates were unknown. Thus, the Commission determined that

Entergy failed meet its burden. The district court properly affirmed this

determination, and its judgment should be upheld.

A. The Commission uses the utility’s actual expenses

during a test year to determine what expenses to

include in rates, and they can only be changed for

known-and-measurable changes.

The Commission’s rules require the expenses included in rates to be

based on the utility’s actual expenses during a test year that ends before the

utility applies to change rates. And only expenses that are reasonable and

necessary can be recovered. Tex. Util. Code § 36.051. Although rates are

set for the future, “[i]n computing an electric utility’s allowable expenses,

only the electric utility’s historical test year expenses as adjusted for known

and measurable changes will be considered, … .” 16 Tex. Admin. Code

31

§ 25.231(b). The test year is “[t]he most recent 12 months for which

operating data for an electric utility, electric cooperative, or municipally-

owned utility are available and shall commence with a calendar quarter or a

fiscal year quarter.” 16 Tex. Admin. Code § 25.5(134). Because the utility

bears the burden of proof in a rate case (Tex. Util. Code § 36.006), that

includes the burden to prove that the post-test-year, purchased-power

agreements are known-and-measurable changes.

Courts have recognized the Commission’s broad discretion over

deciding whether to allow post-test-year adjustments. “[T]he

Commission’s authority to allow post-test-year adjustments for ‘known and

measurable changes to historical test-year data’ is discretionary.” Cent.

Power & Light v. Pub. Util. Comm’n, 36 S.W.3d 547, 563 (Tex.

App.—Austin 2000, pet. denied); see also Cities of Corpus Christi v. Pub.

Util. Comm’n, No. 03-06-00585-CV, 2008 WL 615417 (Tex. App.—Austin

Mar. 5, 2008, no pet.) (mem. op.) (“The Commission may decide in its

discretion whether to incorporate ‘known and measurable’ changes to the

test-year data.”) (citing Office of Pub. Util. Counsel v. Pub. Util. Comm’n,

185 S.W.3d 555, 566 n.14 (Tex. App.—Austin 2006, pet. denied); 16 Tex.

Admin. Code § 25.231(a)).

32

B. Entergy sought adjustments outside the test year for

alleged future capacity expenses.

Entergy sought adjustments for the capacity costs it alleged would be

incurred outside the test year. Capacity costs, generally, are those “costs

associated with providing the capability to deliver energy (primarily the

capital costs of facilities).” Gulf States Utils. Co. v. Pub. Util. Comm’n, 841

S.W.2d 459, 461 (Tex. App.—Austin 1992, writ denied). “‘Capacity costs’

refers to one element of the price charged by a seller of electric power—an

element that represents the seller’s fixed costs in generating the power.”

City of El Paso v. El Paso Elec. Co., 851 S.W.2d 896, 898 (Tex.

App.—Austin 1993, writ denied). These costs, unlike fuel expenses, are

generally recovered through base rates. See City of El Paso v. Pub. Util.

Comm’n, 344 S.W.3d 609, 614 (Tex. App.—Austin 2011, no pet.).

In this case, during the test year, Entergy had purchased-power

capacity costs of $245.4 million. But Entergy sought to recover an

additional $31 million based upon what it believed would be the purchased-

power agreements in place during the “rate year,” the first year of new rates

set by the case. Commission Staff and several intervenors opposed

Entergy’s request to recover the additional $31 million and offered

testimony and argument against Entergy’s proposed adjustment.

33

Staff and intervenors pointed out several problems with Entergy’s

proposed post-test-year adjustments, arguing that these additional costs

are mere projections. For example, Entergy relied on projections, rather

than known actual payments, when estimating what it would pay under

third-party contracts in the future. Indeed, many of the contracts do not

contain fixed-price terms, and Entergy’s costs will fluctuate based on

factors such as required availability and performance. (PFD at 101-02

(citing AR, Tr. at 704-05).) Nevertheless, Entergy “simply assumed it

would pay the maximum amount possible under each of its third party

contracts, and disregarded any of the contractual factors that might reduce

its Rate Year payments.” (AR, PFD at 102 (citing AR, Tr. at 704-05).)

Likewise, the expenses requested under Entergy’s contractual

agreements with its affiliates rest on several assumptions. The contracts do

not definitively fix prices or quantities, which will fluctuate based on the

specific operational conditions experienced in the future. (AR, PFD at 102

(citing AR, Tr. at 606).) The ultimate determination of payments will be

based on a formula set out in a Federal Energy Regulatory Commission

tariff, schedule MSS-4. Entergy could not know what variables should be

inserted in that formula. Instead, to project its costs, Entergy made

assumptions about each of the several variables contained in the formula.

34

(Id.) Intervenors argued that this was too speculative to constitute a known

and measurable change.

To illustrate their position that Entergy’s proposed costs were

inherently speculative, the intervenors pointed to a new Entergy contract

(the EA WBL Contract). That contract, which was executed only days

before the SOAH hearing, accounted for more than a third of Entergy’s

proposed $31 million increase in expenses. Not only would pricing under

the contract be determined pursuant to the complex formula in MSS-4, but

also how much capacity Entergy ultimately purchased would be based on

an allocation percentage between Entergy and other companies that had

not yet been determined. Moreover, the contract itself might never go into

effect because it is subject to Entergy receiving regulatory approval from

the Federal Energy Regulatory Commission. Even if the contract became

effective in the future, it would still be subject to at least two further

revisions before any power could be received under the contract. (AR, PFD

at 102-03 (citing AR, ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, Binder 37,

and AR, Tr. at 628-29).)

Changes Entergy proposed based on estimated payments under

another FERC tariff, the MSS-1, also required several assumptions about

the future. To calculate its obligations under MSS-1, Entergy had to

35

forecast not only its own future loads, but the future loads of all the other

Operating Companies16 in the Entergy family of companies. If those

assumptions regarding future loads are incorrect, Entergy’s projected costs

could be significantly different. (AR, PFD at 103 (citing AR, Tr. at

651–52).) The intervenors pointed out the inconsistency in Entergy’s

position on the measurability of future load growth, noting that elsewhere

in the case, Entergy took the position that future projected loads should not

be considered known and measurable. (AR, PFD at 103 (citing AR, Tr. at

1907; see also AR, Item 164 at 28, Binder 4; AR, Item 159 at 27-28, Binder

4.) (emphasis added).) The ALJs also noted the following testimony of

Entergy Witness Phillip May regarding the certainty of Entergy’s MSS-1

projections:

Q: Do you think that the projection . . . of rate year sales that

is implicit in the calculation of MSS-1 costs . . . is a known

and measurable change?

A: I think there is some uncertainty with regard to that

projection, yes, sir.

(AR, PFD at 103-04 (citing AR, Tr. at 1918-19).)

The intervenors also argued that it was inappropriate to impose the

future costs of securing capacity to serve a larger, future load on existing

16

Entergy is one of several related electric companies in Texas, Louisiana,

Arkansas, and Mississippi. Those are called “operating companies” in this case.

36

customers without taking into account increased customer growth and

sales revenue. The result, they argued, would violate the “matching

principle” whereby “the attendant impacts on all aspects of a utility’s

operations (including revenue, expenses, and invested capital) can with

reasonable certainty be identified, quantified, and matched.” (AR, PFD at

104 (citing AR, Cities Ex. 6 (Nalepa Direct) at 12, Binder 9, citing 16 Tex.

Admin. Code § 25.231(c)(2)(F)(i)(IV).) “The argument, essentially, is that

the various new or expanded contracts that [Entergy] has entered into were

executed so that, in whole or part, [Entergy] would be able to meet future

demand, but that [Entergy] is seeking to recover the costs of those new

contracts from its existing customers.” (AR, PFD at 104 (citing AR, Cities

Ex. 6 (Nalepa Direct) at 11, Binder 9; see also AR, Item 161 at 38, Binder 4;

AR, Item 164 at 30, Binder 4; AR, Item 159 at 35-39, Binder 4.).)

C. Entergy failed to prove that the adjustments were

known-and-measurable changes.

Weighing all the evidence, the ALJs “conclude[d] that [Entergy]

failed to meet its burden to prove that the adjustment it seeks to its Test

year [Purchase Power Capacity Contracts] is known and measurable.” (AR,

PFD at 108.) And the ALJs found that the intervenors had “presented

substantial evidence that all of the components of [Entergy]’s purchased

37

power capacity contain significant variability and uncertainty in costs.” AR,

PFD at 109.)

The Commission agreed.17 It denied Entergy’s request for post-test-

year costs, as set out in Findings of Fact 72 through 86. (AR, Order, FF

72–86.) In its briefing, Entergy cites particular provisions of various

contracts and argues that it was unreasonable for the Commission to deny

all of the proposed expenses. But Entergy bore the burden to prove that

these adjustments were known and measurable. Both because whether to

allow post-test-year adjustments is within the Commission’s discretion,

and because these findings are supported by substantial evidence,

Entergy’s complaint should be rejected.

V. Substantial evidence supports the Commission’s

determination that Entergy failed to meet its burden to

prove that predicted transmission-equalization charges

were known-and-measurable changes to the test-year data.

(Responsive to Entergy’s Issue 3).

As with the purchased-power capacity costs, substantial evidence

supports the Commission’s determination that Entergy failed to meet its

burden to prove that transmission-equalization expenses that the utility

alleged it would incur outside the test year were known and measurable.

17

However, after Entergy pointed to an additional $522,002 of purchased

power capacity costs incurred during the test year, the Commission modified the ALJs’

proposal to allow for a total recovery of $245,965,886.

38

A. Entergy recovers transmission equalization expenses

through rates.

The Entergy-system transmission grid is a large, integrated network

that is operated for the mutual benefit of all of the Entergy Operating

Companies. The costs of operating this system are allocated among the

Operating Companies pursuant to Service Schedule MSS-2, a FERC tariff,

under which each Operating Company contributes its just and reasonable

share of the costs. Those costs are referred to as “transmission

equalization” payments, and Entergy recovers them as expenses in rates.

As the ALJs explained, “In any given month, some of the Operating

Companies might be ‘long’ on the amount of transmission capacity they

own (meaning that they own more capacity than they need) while others

might be ‘short’ on capacity (meaning they own less capacity than they

need). In such a month, the long Operating Companies would receive

MSS-2 payments from the short Operating Companies for use of their

transmission facilities.” (AR, PFD at 110 (citing AR, Tr. at 731, 735).)

B. Entergy sought an adjustment based on anticipated

post-test-year transmission expenses.

Entergy sought to recover $9 million more for transmission expenses

that it incurred in its test year. During the test year, Entergy was short and

paid more than $1.7 million in MSS-2 payments to other Operating

39

Companies. (AR, PFD at 110 (citing AR, Tr. at 723-24, 737; AR, Cities

Ex. 28 (ETI response to Cities RFI 3-3), Binder 9.).) Entergy does not

dispute that this $1.7 million represents its total transmission-equalization

costs incurred during the test year. But, Entergy asked for post-test-year

adjustments based on its estimates of transmission construction projects

expected to be completed after the test year. These projects would result in

changes to the relative transmission-line-ownership ratios among the

Operating Companies, with the apparent result that Entergy would be

increasingly short and its payments under MSS-2 would grow.

Commission Staff and other parties opposed including these post-

test-year expenses, arguing that they were not sufficiently known or

measurable to include in rates set in this case. Payments under MSS-2 are

calculated using a complex mathematical formula involving many

variables, such as the amount of investments in transmission facilities

made by each Operating Company, the costs of capital for each Operating

Company, the size of the load demanded by each Operating Company, and

the amount of state and federal tax paid by each Operating Company.

Changes in any of these variables would change the amount Entergy would

owe—or be due—under the formula. (AR, PFD at 111 (citing AR, ETI Ex. 39

(Cicio Direct) at PJC-1 at 38-43, Binder 36; AR, Tr. at 454-55.).) TIEC

40

Witness Pollock testified that any attempt to estimate these many variables

“is susceptible to a host of uncertainties.” (AR, TIEC Ex. 1 (Pollock Direct)

at 29, Binder 41.)

Aside from the difficulties involved in estimating several variables for

several companies, the transmission projects involved had not yet come

into service and were still in the planning or construction phase. Entergy

acknowledged that if the projects were not completed on schedule, then its

projected MSS-2 costs would be inaccurate. (AR, PFD at 112 (citing AR, Tr.

at 800-801).) TIEC argued that it would be bad policy for the Commission

to rely on “speculative construction end dates to form the basis of a known

and measurable change to test year costs.” (AR, PFD at 113 (citing AR,

Item 159 at 47, Binder 4).) The intervenors argued that Entergy had

offered scant evidentiary support for some of its estimates, and contended

that it would be unfair to allow Entergy to immediately begin recovery of

MSS-2 payments that would not be incurred for many months. (AR, PFD

at 113.)

Cities pointed out an additional uncertainty: Entergy and the various

Operating Companies had announced a plan to sell all of their transmission

assets to a third party. If that transaction took place, it would be

impossible to know what transmission equalization expenses—if

41

any—Entergy would incur. (AR, PFD at 113 n.370 (citing AR, Item 171 at

67-68, Binder 4; AR, Tr. at 113-14; AR, Cities Ex. 4 (Goins Direct) at 20-21,

Binder 8).) In addition, TIEC noted that there are cost-recovery

mechanisms available in the event that Entergy’s rate-year costs deviate

substantially from its test-year costs.18 Therefore, Entergy’s proposed post-

test-year transmission costs were unnecessary.

C. Entergy failed to meet its burden, and the Commission

denied its requested adjustments.

Entergy did not convince the ALJs that the utility’s proposed

expenses were known-and-measurable changes to the test-year expenses.

The ALJs concluded “that [Entergy] failed to meet its burden to prove that

its proposed Rate Year MSS-2 costs are known and measurable.” (AR, PFD

at 116.) The ALJs noted that the MSS-2 formula requires assumptions

about a great number of variables. “Changes to any of the variables could

occur during the Rate Year, thereby altering the amount paid by (or

received by) [Entergy] during the Rate Year.” (Id.) Moreover, “projects

that underlie [Entergy]’s Rate Year request are largely not yet built, and

might never be built.” (Id.) And estimates provided by different parties

18

Specifically, a Transmission Cost Recovery Factor under 16 Tex. Admin. Code

§25.239(c) could allow the utility to “recover its reasonable and necessary costs for

transmission infrastructure improvement and changes in wholesale transmission

charges to the electric utility under a tariff approved by a federal regulatory authority to

the extent that the costs or charges have not otherwise been recovered.”

42

varied widely. That “illustrat[ed] the problem of deviating from actual Test

year data in an area that involves so many future contingencies and

unknowns.” (Id.)

And the ALJs were persuaded by the intervenors’ evidence which

demonstrated that Entergy’s estimate of its rate-year MSS-2 costs are not

known and measurable. (Id.)

The Commission agreed that Entergy had not met its burden to

demonstrate its estimated expenses were known and measurable and

determined that Entergy’s recoverable expenses should be limited to those

incurred during the test year. (AR, Order, FF 87-94.) Substantial evidence

supports these findings, and Entergy’s complaint should be overruled.

Prayer

The Commission asks the Court to affirm the district court’s

judgment on the issues raised by Entergy and OPUC, but to reverse the

district court’s judgment to the extent that it found error in the

Commission’s order. The Commission asks the Court for such other relief

as it may be entitled.

Respectfully submitted,

KEN PAXTON

Attorney General of Texas

43

CHARLES E. ROY

First Assistant Attorney General

JAMES E. DAVIS

Deputy Attorney General for Civil Litigation

JON NIERMANN

Division Chief

Environmental Protection Division

/s/ Elizabeth R. B. Sterling

Elizabeth R. B. Sterling

Assistant Attorney General

Texas State Bar No. 19171100

elizabeth.sterling@texasattorneygeneral.gov

Douglas B. Fraser

Assistant Attorney General

State Bar No. 07393200

doug.fraser@texasattorneygeneral.gov

Daniel C. Wiseman

Assistant Attorney General

State Bar No. 24042178

daniel.wiseman@texasattorneygeneral.gov

Environmental Protection Division

Office of the Attorney General

P.O. Box 12548, MC-066

Austin, Texas 78711-2548

512.463.2012

512.457.4616 (fax)

COUNSEL FOR PUBLIC UTILITY

COMMISSION OF TEXAS

44

Certificate of Compliance

I certify that the foregoing computer-generated document has 9144

words, calculated using the computer program WordPerfect 12, pursuant to

Texas Rule of Appellate Procedure 9.4.

/s/ Elizabeth R. B. Sterling

Elizabeth R. B. Sterling

45

Certificate of Service

I hereby certify that on this the 30th day of April 2015, a true and

correct copy of the foregoing document was served on the following counsel

electronically, through an electronic filing service and by email:

/s/ Elizabeth R. B. Sterling

Elizabeth R. B. Sterling

Counsel for Appellant Entergy Texas, Inc.:

Marnie A. McCormick

Patrick J. Pearsall

Duggins, Wren, Mann & Romero, LLP

P. O. Box 1149

Austin, Texas 78767-1149

512.744.9300

512.744.9399 (fax)

mmccormick@dwmrlaw.com

ppearsall@dwmrlaw.com

Counsel for Appellants Cities of Anahuac, et al.:

Daniel J. Lawton

The Lawton Law Firm, P.C.

12600 Hill Country Blvd, Ste. R-275

Austin, TX 78738

512.322.0019

855.298.7978 (fax)

dlawton@ecpi.com

46

Counsel for Appellant Office of Public Utility Counsel:

Sara J. Ferris

Senior Assistant Public Counsel

Office of Public Utility

P.O. Box 12397

Austin, Texas 78711-2397

512.936.7500

512.936.7520 (fax)

sara.ferris@opuc.texas.gov

Counsel for State Agencies:

Katherine H. Farrell

Assistant Attorney General

Administrative Law Division

Energy Rates Section

Office of the Attorney General

P.O. Box 12548, MC 018-12

Austin, Texas 78711-2548

512.475.4237

512.320.0167 (fax)

katherine.farrell@texasattorneygeneral.gov

Counsel for Texas Industrial Energy Consumers:

Rex VanMiddlesworth

Benjamin Hallmark

Thompson & Knight LLP

98 San Jacinto Blvd., Ste. 1900

Austin, Texas 78701

512.469.6100

512.469.6180 (fax)

rex.vanm@tklaw.com

benjamin.hallmark@tklaw.com

47

APPENDIX A

r.' ,.... .........

:

,_, -

'-: T)

PUC DOCKET NO. 39896 2012 NOV -2 M1 9: 24

SOAH DOCKET NO

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION

INC. FOR AUTHORITY TO CHANGE §

RATES, RECONCILE FUEL COSTS, § OF TEXAS

AND OBTAIN DEFERRED §

ACCOUNTING TREATMENT §

ORDER ON REHEARING

This Order addresses the application of Entergy Texas, Inc. for authority to change rates,

reconcile fuel costs, and defer costs for the transition to the Midwest Independent System

Operator (MISO). In its application, Entergy requested approval of an increase in annual base-

rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff

schedules, including new riders to recover costs related to purchased-power capacity and

renewable-energy credit requirements, requested final reconciliation of its fuel costs, and

requested waivers to the rate-filing package requirements.

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

judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase

for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781

million. The ALJs also recommended approving total fuel costs of approximately $1.3 billion.

The ALJs did not recommend approving the renewable-energy credit rider and the Commission

earlier removed the purchased-power capacity rider as an issue to be addressed in this docket. 1

On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the

exceptions and replies of the parties.2 Except as discussed in this Order, the Commission adopts

the proposal for decision, as corrected, including findings of fact and conclusions of law.

Parties filed motions for rehearing on September 25 and October 4, 2012 and filed replies

to the motions for rehearing on October I 5, 2012. The Commission considered the motions for

1

Supplemental Preliminary Order at 2. 3 (Jan. 19, 2012).

2

Letter from SOAHjudges to PUC (Aug. 8, 20 12).

PUC Docket No. 39896 Order on Rehearing Page 2 of 44

SOAH Docket No.

rehearing at the October 25, 2012 open meeting. The Commission granted Commission Staffs

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 pwnping 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 178 and 170 should be modified to more

accurately reflect the procedural history. The Commission modifies findings of fact 178 and

170 to state that Entergy agreed to extend time to provide the Commission sufficient time to

consider the issues in this proceeding on two occasions-at the July 27 and August 30, 2012

open meetings.

I. Discussion

A. Prepaid Pension Asset Balance

Entergy included in rate base an approximately $56 million item named Unfunded

Pension. 3 This amount represents. the accumulated difference between the annual pension costs

calculated in accordance with the Statement of Financial Accounting Standards (SF AS) 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. 201 2) (PFD).

4

PFD at 23-24.

s Application of AEP Texas Central Company f or Authority to Change Rates, Docket No. 33 309, Order on

Rehearing (March 4, 2008).

PUC Docket No. 39896 Order on Rehearing Page J or 44

SOAH Docket N o . -

6

(AFUDC). The ALJs concluded that this approach was sound and should be followed in this

7

case. 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

Commi ssion 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 AD FIT.

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 $5,916,46 1. 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 lRS 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 AOFIT balance and thus

6

Remand of Docket No. 33309 {Application of AEP Texas Central Company for Authority to Change

Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011 ).

7

PFO at 26.

8

Id. at 24-26.

9

PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (c iting Rebuttal Testimony

of Roberts, Entergy Ex. 64 at 8).

PUC Docket No. 39896 Order on Rehearing Page 4 of 44

SOAH Docket N o . -

10

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

tax-account rider because no party expressly advocated the addition of such a rider. 11

The Commission adopts the proposal for decision regarding the adjustment to Entergy's

ADFIT for the amount attributable to Entergy's FIN 48 liability. However, the Commission also

follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the

proposal for decision on this point. In CenterPoint's Electric Delivery Company's last rate case,

Docket No. 38339, 12 the Commission found that tax schedule UTP-on which companies must

describe, list, and rank each uncertain tax position-would provide the IRS auditors sufficient

information to quickly determine which uncertain tax positions are of a magnitude worth

investigating and that an IRS audit would be more likely to occur on some uncertain tax

positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome,

the utility would not be able to earn a return on the amount paid to the IRS until the next rate

case.

Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable

FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on a prospective basis

an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN-

48 unfavorable-tax-position audit. The return will be applied prospectively to FIN-48 amounts

disallowed by an IRS audit after such amounts are actually paid to the federal government. If

Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position

decision by the IRS, then any amounts collected under rider related to that overturned decision

shall be credited back to ratepayers.

The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent

with its decision to authorize the deferred-tax-account tracker.

10

PFD at 29.

11

/d.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 or 44

SOAH Docket No•. . _

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, 20 I 0 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) fo r

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 T IEC's methodology to also calculate the amount of capitalized incentive compensation

that is financiall y 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

17

methodology is that only $335,752.96 should be disallowed from capital costs.

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 I, 2009 through June 30, 2010. However, the

Commission finds that a consistent methodology should be used to calculate the amount to be

13

PFD at 171.

14

Id at 72.

15

Id. at 174; see also Entergy's Exceptions to the Proposal for Decision at 25-26 (July 23, 2012).

16

Entergy's Exceptions to the Proposal for Decision at 25-26.

17

Id. at 25-26.

PUC Docket No. 39896 Order on Rehearing Page 6 of 44

SOAH Docket No.

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

detennination.

As noted by Commission Staff, this disallowance to plant-in-service alters the expense

for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad

valorem taxes is $24,921 ,022, 18 an adjustment of $1 ,222,106 to Entergy's test year amount.

Finding of fact 15 l is modified to reflect this adjustment to property taxes.

D. Rate of Return and Cost of Capital

The A Us 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 effe·ct 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 detennined 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 O~ket No. 39896 Order on Rehearing Page 7 of 44

SOAH Docket N o . -

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 fai led 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

deci sion.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, 196,03 7, representing Entergy's financially-based incentives paid

27

in the test-year, should be removed from Entergy' s O&M expenses. 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.

15

Id

26

Entergy's Exceptions to the Proposal for Decision at 51 .

27

PFD at 175.

28

Id at 175-76.

PUC Docket No. 39896 Order on Rehearing Page 8of 44

SOAH Docket N o . -

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. AffiJiate 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: ( l ) $46,490 for Project El OPCR56224 - Sales and Marketing - EGSI Texas;

(2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 fo r

Project F3PPMMALl2 - Middle Market Mkt. Development. The remainder, $1,992,475, should

be assigned to (l) 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 l64A 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.

JI Application of Central Power and light Company for Authority to Change Rates, Docket No. 14965,

Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997).

32

Direct Testimony of Carol Szerszen, OPUC Ex. I at Schedule CAS-7.

PUC Docket No. 39896 Order on Rehearing Page 9 or 44

SOAH Docket No.

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

3 1, 2010, which falls in the middle of the two year fuel reconciliation period- July 2009 through

June 20 I I- 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. SussT. 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 ,27 1 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 uti lized in Entergy's fuel reconciliation. The Commission finds that

Entergy' s 20 l 0 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 l 9A and 198 are added to reflect the

Commission's finding that the 2010 line-loss factors be used to reconcile Entergy's fuel costs.

33

Cities' Exceptions to the Proposal for Decision at 20-21 (July 23, 2012) .

4

.1 PFD at 327-328.

PUC Docket No. 39896 Order on Rehearing Page lO of 44

SOAH Docket No.

I. MISO Transition Expenses

During the Commission' s consideration of the proposal for decision, the parties that

contested the amount of Entergy's MISO transition expenses and how the transition expenses

should be accounted for reached announced on the record that they had reached an agreement on

these issues.35 Those parties agreed that the MISO transition expenses would not be deferred and

that Entergy' s base rates should include $1.6 million for MISO transition expense. 36 The

Commission adopts the agreement of the parties and accordingly modifies finding of fact 251

and deletes finding of fact 252.

J. Purchased-Power Capacity Cost Baseline

The Commission modified the amount of purchased-power capacity expense in the

test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the

change to the proper test-year purchased-power capacity expense.

K. Other Issues

New findings of fact 17A, 17B, 17C, 170, 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 l 82A is added.

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

II. Findings of Fact

Procedural History

1. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a

retail service area located in southeastern Texas.

" Open Meeting Tr. at 138 (Aug. 17, 201 2).

36 Id.

PUC Docket No. 39896 Order on Rehearing Page 11 of 44

SOAH Docket No.

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 ETl ' s wholesale electric operations.

3. On November 28, 2011, ETI fi led an application requesting approval of: (I) 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, 201 l; 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, 20 11 (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, 201 1, 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.

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. -

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

2012.

l7A. On August 7, 2012, the SOAH ALJs tiled a letter with the Commission recommending

changes to the PFD.

l 7B At the July 27, 20 12 open meeting, ETI agreed to extend time to August 31, 20 12 to

provide the Commission sufficient time to consider the issues in this proceeding.

l 7C. The Commission considered the proposal for decision at the August 17, 2012 and August

30, 2012 open meetings.

170. At the August 30, 20 12 open meeting, ETI agreed to extend time to September 14, 20 12

to provide the Commission sufficient time to consider the issues in this proceeding.

l 7E. 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 shou ld 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 N o . -

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 (SF AS) 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 $8,858,93 3. 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 (F ASB) 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 IS of 44

SOAH Docket No•• •

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 liabi lities, meaning ETI has, thus far,

avoided paying to the IRS $5,916,46 1 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 liabi lity.

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 ETl'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 FfN 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 FfN 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 tederal 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•. . _

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 ETl 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 N o -

52. The Spindletop gas storage facility (Spindlctop 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 facil ity in rate base.

55. Staff recommended updating ETI' s balance amounts for short-term assets to the 13-

month period ending December 20 11 , 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, 134,35 1; materials and supplies at $29,285,42 1; 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.

6 1. 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.

customers. ETl' 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 l , 2009 (the end of the prior test-year) through June 30, 2010

(the commencement of the current test-year).

Rate ofReturn and Cost of Caoital

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.

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71. ETl 's overall rate ofreturn should be set as follows:

CAPITAL WEIGHTED A VG

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%

Ope,ating 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 ETl's projections of its purchased

capacity expenses during a period beginning June I, 2012 and ending May 31 , 20 13 (the

rate-year).

74. ETl'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 affili ate 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.

80. The MSS-4 fonnula for rate-year af1iliate 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

speculati ve because it depends on a number of variables, including future transmission

investments, deterred 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 Rthtuing Page 21or44

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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 it-; 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. Ell'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. ETl'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. 25.23 l(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.

I 00. The retirement (actuarial) rate method, rather than the interim retirement method, should

be used in the development of production plant depreciation rates.

l0 I . 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 of44

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I02. The net salvage rate of negative IO 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.

I06. 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.

I 07. 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.

I 08. A service life of 40 years and a dispersion curve of RI for ETI's distribution poles,

towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and

should be approved.

I09. 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.

I I 0. A service life of 35 years and a dispersion curve of R l.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

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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.

11 3. The net salvage rate of negative five percent for ETI's distribution structures and

improvements (FERC Account 36 1) is the most reasonable of those proposed and should

be adopted.

114. The net salvage rate of negative 10 percent for ETl's distribution station equipment

(FERC Account 362) is the most reasonable of those proposed and should be adopted.

11 5. The net salvage rate of negative seven percent for ETl'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 ETl'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 ETl's distribution overhead services

(FERC Account 369. l) 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 ETl' s general structures and

improvements (FERC Account 390) is the most reasonable of those proposed and should

be adopted.

121. It is reasonable to convert the $21.3 million deficit that has developed over time in the

reserve for general plant accounts to General Plant Amortization.

122. A ten-year amortization of the deficit in the reserve for general plant accounts is

reasonable and should be adopted.

PUC Docket No. 39896 Order on Rehearing Page 24 of 44

SOAH Docket No.

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 ES I 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 $5,3 76,975 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 financia l measures and, therefore, should be disallowed.

133. In total, the amount of incentive compensation that should be disallowed is $6, 196,037

because it was related to financial measures that are not reasonable and necessary for the

provision of electric service. An additional reduction should be made to account for the

FICA taxes ETI would have paid on the disallowed financially based incentive

compensation.

134. The amount of incentive compensation that should be included in the cost of service is

$7,991, 707.

135. To attract and retain highly qualified employees, the Entergy companies provide a total

package of compensation and benefits that is equivalent in scope and cost with what other

comparable companies within the utility business and other industries provide for their

employees.

136. When using a benchmark analysis to compare companies' levels of compensation, it is

reasonable to view the market level of compensation as a range rather than a precise,

single point.

137. ETI' s base pay levels are at market.

138. ETI's benefits plan levels are within a reasonable range of market levels.

139. ETI's level of compensation and benefits expense is reasonable and necessary.

140. ETI provides non-qualified supplemental executive retirement plans for highly

compensated individuals such as key managerial employees and executives that, because

of limitations imposed under the Internal Revenue Code, would otherwise not receive

retirement benefits on their annual compensation over $245,000 per year.

PUC Docket No. 39896 Order on Rehearing Page 26 of 44

SOAH Docket No•. . . _

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 proforma 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 proforma 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 or44

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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. SuesT.

R. 25.231(b)(l)(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 ESL 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.

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.

l 64A. 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: ( I) $46,490 for Project

EIOPCR56224 - 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:

( I) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;

(2) Project F3 PCS PETE I (Entergy-Tulane Energy Institute) in the amount of $14,288;

and (3) Project F5PPKATRPT (Stonn Cost Processing & Review) in the amount of $929.

166. The $356,151 (which figure includes the $112,53 1 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 nonnally-recurring costs and should not be recoverable.

PUC Docket No. 39896 Order on Rehearing Page 29 of44

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168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are

related to ESl's operations, it is more immediately related to Entergy Louisiana, Inc. and

Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.'

169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy

Management for ESI) are research and development costs related to energy efficiency

programs. As such, they should be recovered through the energy efficiency cost recovery

factor rather than base rates.

170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate

transactions were reasonable and necessary, were allowable, were charged to ETI at a

price no higher than was charged by the supplying affiliate to other affiliates, and the rate

charged is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation

171. ETI has one full or partial requirements wholesale customer - East Texas Electric

Cooperative, Inc.

172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this

docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set

the wholesale load results in a retail production demand allocation factor of

95.3838 percent.

173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used

by the FERC to allocate between jurisdictions.

174. Using l 2CP 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 Allocg/ion and Rate Design

175. There is no express statutory authorization for ETI's proposed Renewable Energy Credits

rider (REC rider).

176. REC rider constitutes improper piecemeal ratemaking and should be rejected.

PUC Docket No. 39896 Order on Rehearing Page JO of 44

SOAH Docket No.

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 appl

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