Court Opinion

ID: 4067877
Source: CourtListenerOpinion
Date Created: 2016-09-29 23:36:53.251964+00
Date Added: 2024-06-11T14:32:43.065143
License: Public Domain

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.
PUC Docket No. 39896                         Order on Reheuing                         Page 19 or 44
SOAH Docket N o . -

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
SOAH Docket N o . -

         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
SOAH Docket No.

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
SOAH Docket N o . -

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
SOAH Docket No.

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
SOAH Docket N o . -

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
SOAH Docket N o . -

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 apply to the allocation and collection of Miscellaneous Gross Receipts
       Taxes. The company's proposed allocation of these costs to all retail customer classes
       based on customer class revenues relative to total revenues is appropriate.

182A. ETI's proposed gross plant-based allocator is an appropriate method for allocating the
       Texas franchise tax.

183.   The Average and Excess ( A&E) 4CP method for allocating capacity-related production
       costs, including reserve equalization payments, to the retail classes is a standard
       methodology and the most reasonable methodology.

184.   The A&E 4CP method for allocating transmission costs to the retail classes is standard
       and the most reasonable methodology.

185.   ETI appropriately followed the rate class revenue requirements from its cost of service
       study to allocate costs among customer classes. ETl's revenue allocation properly sets
       rates at each class's cost of service.
PUC Docket No. 39896                          Order on Rehearing                         PageJI of44
SOAH Docket No. -

186.    It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
        Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
        replacement of a functioning light with a lower-wattage bulb.

187.    It is appropriate to require ETI to prepare and fil e, as part of its next base rate case, a
        study regarding the foasi bil ity of instituting LED-based rates and, if the study shows that
        such rates are feasible, ETI should file proposals for LED-based lighting and traffic
        signal rates in its next rate case.

188.    An agreement was reached by the parties and approved by the Commission in Docket
        No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
        ratchet for existing customers in the Large Industrial Power Service (LI PS), Large
        Industrial Power Service-Time of Day, General Service, General Service-Time of Day,
        Large General Service, and Large General Service-Time of Day rate schedules.

189.    ETI's proposed tariffs in this case did not remove the life-of -contract demand ratchet
        from these rate schedules consistent with the parties' agreement in Docket No. 37744.

190.    A perpetual billing obl igation based on a life-of-contract demand ratchet, as ETI
        proposed, is not reasonable.

19 1.   ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
        agreement that was adopted by the Commission as just and reasonable in Docket
        No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact
        No. 192-1 94.

l 92.   ETI's Schedule LIPS and LIPS Time of Day§ Vl should be changed to read:
                        DETERMINATION OF BILLING LOAD

                        The kW of Billing Load will be the greatest of the fo llowing:

                        {A) The Customer's maximum measured 30-minute
                        demand during any 30-minute interval of the current billing
                        month, subject to §§ Ill , IV and V above; or

                         (B) 75% of Contract Power as defined in § Vil; or

                        (C) 2,500 kW.
PUC Docket No. 39896                        Order on Rehearing                         Page 32 of44
SOAH Docket No.

193.   ETl's Schedule LIPS and LIPS Time of Day§ VU should be changed to read:
                       DETERMINATION OF CONTRACT POWER

                       Unless Company gives customer written notice to the contrary,
                       Contract Power will be defined as below:

                       Contract Power - the highest load established under § VI(A) above
                       during the 12 months ending with the current month. For the
                       initial 12 months of Customer's service under the currently
                       effective contract, the Contract Power shall be the kW specified in
                       the currently effective contract unless exceeded in any month
                       during the initial 12-month period.

194.   The Large General Service, Large General Service-Time of Day, General Service, and
       General Service-Time of Day schedules should be similarly revised to eliminate ETI's
       life-of-contract demand ratchet.

195.   In its proposed rate design for the LIPS class, the company took a conservative approach
       and increased the current rates by an equal percentage. This minimized customer bill
       impacts while maintaining cost causation principles on a rate class basis.

196.   It is a reasonable move towards cost of service to add a customer charge of $630 to the
       LIPS rate schedule with subsequent increases to be considered in subsequent base rate
       cases.

197.   It is a reasonable move towards cost of service to slightly decrease the LIPS energy
       charges   and    increase   the    demand   charges   as   proposed    by    Staff   witness
       William B. Abbott.

198.   DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent
       Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs
       in the off-season (October through May), that can be cancelled at any time, and for load
       not lasting more than 80 hours in a year. For customers whose loads match these SIPS
       characteristics (for example, DOE's Strategic Petroleum Reserve), the 12-month demand
       ratchet provision of Schedule LIPS does not apply to demands set under the provisions of
       the SCPS rider. The monthly demand set under the SIPS provisions would be applicable
       for billing purposes only in the month in which it occurred. In short, if a customer set a
PUC Docket No. 39896                       Ortler on Rehearing                       Page 33 of 44
SOAH Docket No. -

       12-month ratchet demand in that month, it would be forgiven and not applicable in the
       succeeding 12 months.

199.   DOE's proposed Schedule SIPS ts not restricted solely to the DOE and should be
       adopted. It more closely addresses specific customer characteristics and provides for
       cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.

200.   Standby Maintenance Service (SMS) is available to customers who have their own
       generation equipment and who contract for this service from ETI.

201.   P.U.C. SUBST. R. 25.242(k)(l) provides that rates for sales of standby and maintenance
       power to qualifying faci lities should recognize system wide costing principles and should
       not be discriminatory.

202.   It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
       charge equivalent to that of the LIPS rate schedule only for SMS customers not
       purchasing supplementary power under another applicable rate; and (b) revising the tariff
       as follows:
                                       Distribution         Transmission
                         Charge
                                    (less than 69KV)     (69KV and greater)
                       Billing Load Charge ($/kW):
                       Standby            $2.46                  $0.79
                       Maintenance        $2.27                  $0.60
                       Non-Fuel Ener!!v Charge (¢/kWh)
                       On-Peak           4.245¢                  4.074¢
                       Off-Peak          0.575¢                  0.552¢

203.   ETI's Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental
       charge paid by a customer when ETI installs faci lities for that customer that would not
       normally be supplied, such as line extensions, transformers, or dual feeds.

204.   ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
       Option B, which applies when a customer elects to amortize the directly-assigned
       facil ities over a shorter term ranging from one to ten years, has a variable monthly
       charge.   There is also a term charge that applies after the faci lity has been fully
       depreciated.
PUC Docket No. 39896                         Order on Rehearing                          Page 34 of 44
SOAH Docket No.-

205.    It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.11 percent
        per month of the installed cost of all facilities included in the agreement for additional
        facilities.

206.    It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and
        the Post Term Recovery Charge as follows:

        Selected Recovery Term      Recovery Term Charge       Post Recovery Term Charge
                      1                      9.52%                        0.28%
                      2                      5. 14%                       0.28%
                      3                      3.68%                        0.28%
                      4                      2.95%                        0.28%
                      5                      2.52%                        0.28%
                      6                      2.23%                        0.28%
                      7                      2.03%                        0.28%
                      8                      1.88%                        0.28%
                      9                      1.76%                        0.28%
                      10                     1.67%                        0.28%

207.    The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the
        costs of running, operating, and maintaining the directly-assigned facilities.

208.    It is reasonable to modify the Large General Service rate schedule by increasing the
        demand charge from $8.56 to $11.43; decreasing the energy charge from $.00854 to
        $.00458; and reducing the customer charge to $260.00.

209.    Staff's proposed change to the General Service (GS) rate schedule to gradually move GS
        customers towards their cost of service by recommending a decrease in the customer
        charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is
        reasonable and should be adopted.

2 10.   ETI's Residential Service (RS) rate schedule is composed of two elements: a customer
        charge and a consumption-based energy charge. In the months November through April
        (winter), the rates are structured as a declining block, in which the price of each unit is
        reduced after a defined level of usage. ETI's proposed increase in the RS customer
        charge to $6 per month is reasonable and should be adopted. For the RS summer rate and
PUC Docket No. 39896                             Order on Rehearing                     Page 35 of 44
SOAH Docket No. -

         the first winter block rate, the 6.296¢ per kWh energy charge resulting from the increased
         revenue requirement fo r residential customers is reasonable and should be adopted.

2 11 .   ETI's Schedule RS declining block rate structure is contrary to energy-efficiency efforts
         and   ~he   Legislature's goal of reducing both energy demand and energy consumption in
         Texas, as stated in PURA § 39.905.

2 12.    Schedule RS winter block rates should be modified consistent with the goal set out in
         PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block
         differential proposed by ETI and subsequent reductions should be reviewed for
         consideration at the occurrence of each rate case filing.

213.     Other elements of Schedule RS are just and reasonable.

Fuel Rec1mci/iation
2 14.    ETI incurred $616,248 ,686 in natural-gas expenses during the reconciliation period,
         which is from July 2009 through June 2011.

215.     ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
         contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
         negotiated operational balancing agreements with various pipeline companies.

2 16.    ETI employed a diversified portfolio of gas supply and transportation agreements to meet
         its natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217.     ETI' s natural gas expenses were reasonable and necessary expenses incurred to provide
         reliable electric service to retail customers.

2 18.    ETI incurred $90,82 1,317 in coal expenses during the reconciliation period.

219.     ETI prudently managed its coal and coal-related contracts during the reconciliation
         period.

220.     ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal
         burned at the Big Cajun II, Unit 3 facility.

22 l.    ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable
         electric service to retail customers.
PUC Docket No. 39896                          Order on Rehearing                       Page36 of 44
SOAH C>ocket N o . -

222.    ETI incurred $990,04 1,434 in purchased-energy expenses during the reconciliation
        period.

223.    The Entergy System's planning and procurement processes for purchased-power
        produced a reasonable mix of purchased resources at a reasonable price.

224.    During the reconciliation period, ETI took advantage of opportunities in the fuel and
        purchased-power markets to reduce costs and to mitigate against price volatility.

225.    ETI' s purchased-energy expenses were reasonable and necessary expenses incurred to
        provide reliable electric service to retail customers.

226.    ETI provided sufficient contemporaneous documentation to support the reasonableness of
        its purchased-power planning and procurement processes and its actual power purchases
        during the reconciliation period.

227.    The Entergy system sold power off system when the revenues were expected to be more
        than the incremental cost of supplying generation for the sale, subject to maintaining
        adequate reserves.

228.    The System Agreement is the tariff approved by the FERC that provides the basis for the
        operation and planning of the Entergy system, including the six operating companies.
        The System Agreement governs the wholesale-power transactions among the operating
        companies by providing for joint operation and establishing the bases for equalization
        among the operating companies, including the costs associated with the construction,
        ownership, and operation of the Entergy system facilities.

229.    Under the terms of the Entergy System Agreement, ETJ was allocated its share of
        revenues and expenses from off-system sales.

230.    During the reconciliation period, ETI recorded off-system sales revenue in the amount of
        $376,671 ,969 in FERC Account 447 and credited 100 percent of off-system sales
        revenues and margins from off-system sales to eligible fuel expenses.

23 1.   ETI properly recorded revenues from off-system sales and credited those revenues to
        eligible fuel costs.
PUC Docket No. 39896                        Order on Rehearing                         Page 37 of 44
SOAH Docket No.-

232.   The Entergy system consists of six operating companies, including ETI, which are
       planned and operated as a single, integrated electric system under the tenns of the System
       Agreement.

233.   Service schedule MSS-1 of the System Agreement detennines how the capabi lity and
       ownership costs of reserves for the Entergy system are equalized among the operating
       companies.      These inter-system "reserve equalization" payments are the result of a
       fonnula rate related to the Entergy system's reserve capability that is applied on a
       monthly basis.

234.   Reserve capability under service schedule MSS- 1 is capability in excess of the Entergy
       system's actual or planned load built or acquired to ensure the reliable, efficient operation
       of the electric system.

235.   By approving service schedule MSS-1 , the FERC has approved the method by which the
       operating companies share the cost of maintaining sufficient reserves to provide
       reliability for the Entergy system as a whole.

236.   Service schedule MSS-3 of the System Agreement detennines the pricing and exchange
       of energy among the operating companies. By approving service schedule MSS-3, the
       FERC has approved the method by which the operating companies are reimbursed for
       energy sold to the exchange energy pool and how that energy is purchased.

237.   Service schedule MSS-4 of the System Agreement sets forth the method for determining
       the payment for unit power purchases between operating companies.             By approving
       service schedule MSS-4, the FERC has approved the methodology for pricing
       inter-operating company unit power purchases.

238.   The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
       horizons. Once the planning process has identified the most economical resources that
       can be used to reliably meet the aggregate Entergy system demand, the next step is to
       procure the fuel necessary to operate the generating units as planned and acquire
       wholesale power from the market.
PUC Docket No. 39896                          Order on Rehearing                      Page 38 of 44
SOAH Docket No.

239.   Once resources are procured to meet forecasted load, the Entergy system is operated
       during the current day using all the resources available to meet the total Entergy system
       demand.

240.   After current-day operation, the System Agreement prescribes an accounting protocol to
       bill the costs of operating the system to the individual operating companies. This
       protocol is implemented via the intra-system bill to each operating company on a
       monthly basis.

241.   ETI purchased power from affiliated operating companies per the terms of service
       schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3
       to affiliated operating companies are reasonable and necessary, and the FERC has
       approved the pricing formula and the obligation to purchase the energy. ETI pays the
       same price per megawatt hour for energy under service schedule MSS-3 as does any
       other operating company purchasing energy under service schedule MSS-3 during the
       same hour.

242.   The Spindletop facility is used primarily to ensure gas-supply reliability and guard
       against gas-supply curtailments that can occur as a result of extreme weather or other
       unusual events.

243.   The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can
       back down gas-fired generation to take advantage of more economical wholesale power,
       or use gas from storage to supplement gas-fired generation when load increases during
       the day and thereby avoid more expensive intra-day gas purchases.

244.   ETI's customers received benefits from the Spindletop facility during the reconciliation
       period through reliable gas supplies and ETI's monthly and daily storage activity.

245.   ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas
       supply for the benefit of customers.

246.   ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied
       for the purpose of allocating its costs to its wholesale customers and retail customer
       classes.
PUC Docket No. 39896                             Order on Rehearing                     Page 39 of 44
SOAH Docket N o . -

246A. ETI 's 20 I 0 line-loss factors should be used to reconcile ETI's fuel costs. Therefore,
        ETI 's fuel reconciliation over-recovery should be reduced by $3, 981,271.

247.    ETl's proposed loss factors are reasonable and shall be implemented on a prospective
        basis as a result of this final order.

248.    ETI seeks a special-circumstances exception to recover $99,715 resulting from the
        FERC's reallocation of rough production equalization costs in FERC Order No. 720-A,
        and to treat such costs as eligible fuel expense.

249.    Special circumstances exist and it is appropriate for ETI to_recover the rough production
        cost equalization costs reallocated to ETI as a result of the FERC 's decision in Order
        No. 720-A.

Ot/1er Issues
250.    A deferred accounting of ETI' s Midwest Independent Transmission System Operator
        (MISO) transition expenses is not necessary to carry out any requirement of PURA.

251.    ETI should include $1.6 million in base rates for MISO transition expense.

252.    Deleted.

253.    Transmission Cost Recovery Factor basel ine values should be set during the compliance
        phase of this docket, after the Commission makes final rulings on the various contested
        issues that may affect this calculation.

254.    Distribution Cost Recovery Factor baseline values should be set during the compliance
        phase of this docket, after the Commission makes final rulings on the various contested
        issues that may affect this calculation.

255.    The appropriate amount for ETI's purchased-power capacity expense to be included in
        base rates is $245,965,886.

256.    The amount of ETI's purchased-power capacity expense includes third-party contracts,
        legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
        amounts for all contracts should be included in the baseline for a purchased-capacity rider
        that may be approved in Project No. 39246 is an issue that should be decided in that
        project.
PUC Docket No. 39896                       Order on Rehearing                          Page 40 of 44
SOAH Docket No.

                                   III. Conclusions of Law
1.     ETI is a "public utility" as that term is defined in PURA § 11.004(1) and an "electric
       utility" as that term is defined in PURA§ 31.002(6).

2.     The Commission exercises regulatory authority over ETI and jurisdiction over the subject
       matter of this application pursuant to PURA§§ 14.001, 32.001 , 32.101, 33.002, 33.051,
       36.101- .111, and 36.203.

3.     SOAH has jurisdiction over matters related to the conduct of the hearing and the
       preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
       TEX. Gov 'T CODE ANN. § 2003.049.

4.     This docket was processed in accordance with the requirements of PURA and the Texas
       Administrative Procedure Act, Tex. Gov't Code Ann. Chapter 2001.

5.     ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
       R. 22.5 l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).

6.     Pursuant to PURA § 33.001 , each municipality in ETI's service area that has not ceded
       jurisdiction to the Commission has jurisdiction over the company's application, which
       seeks to change rates for distribution services within each municipality.

7.     Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
       municipality's rate proceeding.

8.     ETJ has the burden of proving that the rate change it is requesting is just and reasonable
       pursuant to PURA § 36.006.

9.     In compliance with PURA§ 36.05 1, ETI's overall revenues approved in this proceeding
       permit ETI a reasonable opportunity to earn a reasonable return on its invested capital
       used and useful in providing service to the public in excess of its reasonable and
       necessary operating expenses.

I 0.   Consistent with PURA § 36.053, the rates approved in this proceeding are based on
       original cost, Jess depreciation, of property used and useful to ETI in providing service.

11.    The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
       and P.U.C. SUBST. R. 25.23l(c)(2)(C)(i).
PUC Docket No. 39896                        Order on Rehearing                        Page 41 of44
SOAH Docket N o . -

12.     Including the cash working capital approved in this proceeding in ETI's rate base is
        consistent with P.U.C. SUBST. R. 25.23 l (c)(2)(B)(iii)(IV), which allows a reasonable
        allowance for cash working capital to be included in rate base.

13.     The ROE and overall rate of return authorized in this proceeding a re consistent with the
        requirements of PURA §§ 36.05 I and 36.052.

14.     The affiliate expenses approved in this proceeding and included in ETl's rates meet the
        affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
        Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.-
        Austin 1984, no writ).

15.     The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
        and P.U.C. SUBST. R. 25.23 l (c)(2)(C)(i).

16.     Pursuant to P.U.C. SUBST. R. 25.231 (b)(I)(F), the decommissioning expense approved in
        this case is based on the most current information reasonably available regarding the cost
        of decommissioning, the balance of funds in the decommissioning trust, anticipated
        escalation rates, the anticipated return on the funds in the decommissioning trust, and
        other relevant factors.

17.     ETI has demonstrated that its eligible fuel expenses during the reconciliation period were
        reasonable and necessary expenses incurred to provide reliable electric service to retail
        customers as required by P.U.C. SUBST. R. 25.236(d)(l)(A). ETI has properly accounted
        for the amount of fuel-related revenues collected pursuant to the fuel factor during the
        reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(l)(C).

18.     ETI prudently managed the dispatch, operations, and maintenance of its fossil plants
        during the reconciliation period.

19.     The reconciliation period level operating and maintenance expenses for the Spindletop
        facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

l 9A.   Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision
        in a reconciliation proceeding.
PUC Docket No. 39896                        Order on Rehe-.iring                       Page 42 of44
SOAH Docket No.

19B.   P.U.C. Sussr. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to
       include any issue related to the reasonableness of a utility's fuel expenses and whether
       the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use
       the new line-loss study to calculate Entergy's fuel reconciliation and over-recovery.

20.    Special circumstances are warranted pursuant to P.U.C. Sus sr. R. 25.236(a)(6) to
       recover rough production equalization payments reallocated to ETI by the FERC.

21.    ETI' s rates, as approved in this proceeding, are just and reasonable in accordance with
       PURA § 36.003.

                                 IV. Ordering Paragraphs
       In accordance with these findings of fact and conclusions of law, the Commission issues
the following orders:

I.     The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent
       with this Order.

2.     ETI's application is granted to the extent consistent with this Order.

3.     ETI shall file in Tariff Control No. 40742 Compliance Tari.ff Pursuant to Final Order in
       Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates,
       Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with
       this Order within 20 days of the date of this Order. No later than ten days after the date
       of the tariff filings, Staff shall file its comments recommending approval, modification,
       or rejection of the individual sheets of the tariff proposal. Responses to the Stafrs
       recommendation shall be filed no later than 15 days after the fil ing of the tariff. The
       Commission shall by letter approve, modify, or reject each tariff sheet, effective the date
       of the letter.

4.     The tariff sheets shall be deemed approved and shall become effective on the expiration
       of 20 days from the date of filing, in the absence of written notification of modification or
       rejection by the Commission.      If any sheets are modified or rejected, ETI shall file
       proposed revisions of those sheets in accordance with the Commission's letter within ten
PUC Docket No. 39896                         Order on Rehearing                         Page 43 of 44
SOAH Docket No.

       days of the date of that letter, and the review procedure set out above shall apply to the
       revised sheets.

5.     Copies of all tariff-related filings shall be served on all parties ofrecord.

6.     ETI shall prepare and file as part of its next base rate case a study regarding the
       feasibility of instituting LED-based rates and, if the study shows that such rates are
       feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that
       case. If ETI has LED lighting customers taking service, the study shall include detailed
       information regarding differences in the cost of serving LED and non-LED lighting
       customers. ETI shall provide the results of this study to Cities and interested parties as
       soon as practicable, but no later than the filing of its next rate case.

7.     AJI other motions, requests for entry of specific findings of fact and conclusions of law,
       and any other requests for general or specific reliet: if not expressly granted, are denied.
PUC Docket No. 39896                                Order on Rehearing                      Page 44 of 44
SOAH Docket N o . -

          SIGNED AT AUSTIN, TEXAS the

                                                 PUBLIC UTILITY COMMISSION OF TEXAS

                                                 ROLANDO PABLOS, COMMISSIONER

        I respectfully dissent regarding the utility- and executive-management-class affiliate
transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect
costs of the management of Entergy's ultimate parent should not be borne by Texas ratepayers.
Therefore, I would disallow the following: $ 173,867 for Project No. F3PCCPM001 (Corporate
Performance Management); $3 72,919 for Project No. F3PCC31255 (Operations-Office of the
CEO); and $74,485 for Project No. F3PPC00001 (Chief Operating Officer). I join the
Commission in all other respects for this Order.

                                                 KENNETHW. ANDER~J~ISSIONER

q.\cadm\ordcrs\tinal\39000\39896<> on reh docx

          37
          Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing (Oct. 16, 1997).
SOAH DOCKET NO•• • •
PUC DOCKET NO.      3Htt
COMPANY NAMR        En!MQY Teue, Inc
TEST YEAR END       ~un-11

                                                    Tmv. .,
                                                     Toe.I
                                                      (•)
                                                                          ~   -..
                                                                           Compeny
                                                                            ...
                                                                          ToTeetv. .r
                                                                              (b)
                                                                                                    ~
                                                                                                     Compan~

                                                                                                        ....'"
                                                                                                    THIYHr
                                                                                                   Total Elec:trle
                                                                                                         (c)
                                                                                                                            Commlellon
                                                                                                                            Adj ...- .
                                                                                                                            ToC ompa~
                                                                                                                             A!!l.,..t
                                                                                                                               (d)
                                                                                                                                                CommlMlon
                                                                                                                                                  AdlllNcl
                                                                                                                                                Total El9ctflc
                                                                                                                                                (•) • (c) • (d)

MVEHUE REQUIREMENT

Ope'811ane & M a i -                            s   1.291.684.714           (1.075.l48.117)    s        218.538.597     s    (2050.490)     s      191.988.107
Revulatory ~end Credita          40700          s      (8. 784,808)   s         12,000.533     s          5,245,925     $       (324,121)   $        4 ,921.804
ACc19110n Expenee                               s         212,793     s           (212.783)    s                        s                   s
lnle1911 on Cuelomer llepo9ita     \            s                     s             68,985     s               68.985   s        (25.938)   s            43.047
 o-wniaalonlng ExpenM                           s                     s                        $                        s                   s
Depfeelallon & AmorUzatlon Expenw               s      78.072,459     s         22.558.698     s         98.631,157     s     (8,253.318)   s       92.Jn.841
Tu• Odle< Then Income T• ••                     s      63,023.906     $         (2.533. 159)   $         60.490,747     $     (2.874.508)   $       57.618,241
federal Income T -                              $     (23.407,031)    s         67,298,739     s         43.889,708     s      6,181.364    $       50.071.092
Cun9fl1 Slale Income Taxee                      s        (127.519)    s             89.787     s            (37.732)    s         37.732    s
Deferred federel lnc:ome Taxee                  s      67,051,463     s        (52.089.274)    $         14,982,189     $    (H,982.189)    s
DtfMecl S4ale 1ncCme Tuet                       $         8 12.265    s           (727.91 8)   s             84,347     s        (84.347)   s
 lrwealrnant Tax Credlla       411.00 "'" '     s      (1.8 11.177)   s            (48.429)    s         (1.857,808)    s      1.857.808    s
Coneolldated Tu S8\linga Adj..-!                s                     s                        s                        s                   s
Relum on 1"'"'80 Capital                                              !        155, 182,991    !        155,182,991     I    !14,562,3931   i      140,800,598
TOTAL                                           s   1,4el,921,2SI     s       (t73,S49,t47)    s        593,317,308     s    (Sl,790,118)   s      537,811,730

P1ut:
Addbad<: P~ Power R-                   S&S.00                                                                                               s      244,539,884
Addbeclc' lntenuptlllle Sentlcaa       55500
          TotalAddbacu
                                                                                                                                            •      2",539.-

Total COMM Rawnue it.qu....,,.nt                                                                                                            s      782,151,814

                                                                                                                                                                  •• •
SONt DOCQ1' NO.
PUC OOCKETNO.
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                                                                                                                                                                                221,«>2,103
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                                                                                                                                                                                277,385
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           C.......Acoounllng                    303              119,797                      111.m 1                      172.245       s                                         172.245
           ~cc:s                                 303              233,924                      (51 ,305)                    182.819       s                                         182.819
           ~CIS                                  303                11,389                       (1.•37)                        I 0.~8    s                                          18.949
           c. - . . -                            303              117,825                           •!Se                    118,081       s                                         118.081
           0-                                    303              240,345                       (81.0111                     172.334      s                                         172,334
           A&GIMISC                              303            2,587,529                      {035.744)                  1. 751.785      I                                       1,751. 705
           ~GIUISC~R-                            303              531.420                       (•3.000)                    408.A20       s                                         48e.420
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           _ _ PTOO....,.Fuol                    303                 3,314                         (074)                       2 ,8 40    s                                           2 ,&40
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t0f»'2012t231PM                                                                                                                                                               .....
       SOAH DOCKET NO.           XXX-XX-XXXX                                                         COMM Schedule V
       PUC DOCKET NO.               38811                                                        Fadenil Income Tax"
       COMPANY NAME                 Entltrgy Tex•, Inc.
       TEST YEAR END                30-Jun-11

       FEDERAL INCOME TAXES· METHOD 1                              Roq-ted           Commluton
                                                                  AIP_...            Adjue-           Comm...ton
                                                                   THtYHr            ToCompony          Adjueted
                                                                  TotolElectrtc       Reaunt          Toto1Elec:1rtc:
                                                                       (c)              (d)                (•)

       Retum                                              Total                                            140,600,598

       Lesa:
          lntereet Included in Retum                                                             s           57,409,530
         AIT10ltiza1ionol1TC                                                                     s            1,642,645
         Am.,.-tlon ol DFIT (Exceu)                                                              s              238,870
        ConllOlldallld Tax Savtnga                                                               s
       Plue.                                                                                     s
         AFUDC                                                                                   s           15,544,523
         Other Permanent Differences                                                             s           (1,720,971)
         NOf1-Normallzed Timing Dil'ferencee
         EOllESITaxoe                                                                                           438,745
         Current State Income Tax                                                                               (37,732)
         Deferred State Income Tax                                                                               64,347
         FAS 109
         Am.,.-tion ol Exceao DFIT-Depreclation

       TAXABLE COMPONENT OF RETURN                                                                           95,818,485

       TAX FACTOR (111· 35X 35)                                          053&46150                           0.§3&46150

       TOTAL FIT BEFORE ADJUSTMENTS                                                                          51,488,882

       Adjustments·

        Amortization of ITC                                                                                  (1,642,645)
        Amortization of Excess DFIT • Depreciation                                                             (238,870)
        Prior Yea111 Current FIT
        Prior Yea111 Deferred FIT
        EOllESITaxoe                                                                                            483,745
        FAS 109
        Other· ConlOlldated Tax Savings

       TOTAL FEDERAL INCOME TAXES                                                                            50,071,092

10/30l2012 12:39 PM                                                                                                        Pago&
APPENDIX B
                                  SOAH DOCKET NO.                                         f ')
                                     PUC DOCKET NO. 39896                                 1
                                                                                              c.     ~. -
                                                                                      -._; .           iJ   P/'J 3:
APPLICATION OF ENTERGY TEXAS,                                  §           BEFORlfTJW[1~Jf\r~ oi/NcE
INC. FOR AUTHORITY TO CHANGE                                   §
RATES, RECONCILE FUEL COSTS,                                   §                                   OF
AND OBTAIN DEFERRED                                            §
ACCOUNTING TREATMENT                                           §          ADMINISTRATIVE HEARINGS

                                      PROPOSAL FOR DECISION

                                          TABLE OF CONTENTS

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

          5.         Interest on Customer Deposits .................................................................. 8
          6.         Property (Ad Valorem) Tax Expense .......................................................9
          7.         Advertising, Dues, and Contributions .....................................................9
          8.         Other Revenue Related Adjustments .......................................................9
          9.         Federal Income Tax ...................................................................................9
          10.        River Bend Decommissioning Expense .................................................... 9
          11.        Self-Insurance Storm Reserve Expense ................................................... 9
          12.        Spindletop Gas Storage Facility ............................................................. 10
     D.   Affiliate Transactions .......................................................................................... 10
     E.   Jurisdictional Cost Allocation ............................................................................ 10
     F.   Class Cost Allocation ........................................................................................... 11
          1.         Renewable Energy Credit Rider ............................................................ 11
          2.         Class Cost Allocation ............................................................................... 11
          3.         Revenue Allocation .................................................................................. 12
          4.         Rate Design ............................................................................................... 12
     G.   MISO Transition .................................................................................................. 14
v.        RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] •..•... 14
     A.   Capital Investment [Germane to Preliminary Order Issue No. 17] ................ 14
     B.   Hurricane Rita Regulatory Asset ....................................................................... 15
     c.   Prepaid Pension Asset Balance ...........................................................................23
     D.   FIN 48 Tax Adjustment .......................................................................................26
     E.   Cash Working Capital .........................................................................................30
          1.         The Revenue Lag Component of the Lead-Lag Study ......................... 31
          2.         The Expense Lead Component of the Lead-Lag Study ....................... 39
     F.   Self-Insurance Storm Reserve [Germane to Preliminary Order Issue
          No. 5] .....................................................................................................................45
          1.         The Effect of Prior Settled Cases........................................................... .46
          2.         OPC's Proposed Adjustment ................................................................. .49
          3.         1997 Ice Storm .......................................................................................... 54
          4.         Jurisdictional Separation Plan Allocation ............................................. 57
          S.         $50,000 Reserve Threshold ..................................................................... 59
SOAH DOCKET N O . -                                 TABLE OF CONTENTS                                                         PAGEIIl
PUC DOCKET NO. 39896

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

             3.         Transmission Plant ................................................................................ 13 2
             4.         Distribution Plant .................................................................................. 141
             5.         General Plant. ......................................................................................... 155
             6.         Fully Accrued Depreciation .................................................................. 160
             7.         Other Depreciation Issues - Accumulated Provision for
                        Depreciation ........................................................................................... 162
        D.   Labor Costs ........................................................................................................ 163
             1.         Payroll and Related Adjustments ......................................................... 163
             2.         Incentive Compensation ........................................................................ 166
             3.         Compensation and Benefits Levels ....................................................... 176
             4.         Non-Qualified Executive Retirement Benefits .................................... 178
             5.         Employee Relocation Costs ................................................................... 180
             6.         Executive Perquisites ............................................................................. 181
        E.   Interest on Customer Deposits .......................................................................... 182
        F.   Property (Ad Valorem) Tax Expense ............................................................... 182
        G.   Advertising, Dues, and Contributions ............................................................. 186
        H.   Other Revenue-Related Adjustments .............................................................. 186
        I.   Federal Income Tax ........................................................................................... 186
        J.   River Bend Decommissioning Expense ............................................................ 188
        K.   Self-Insurance Storm Reserve Expense [Germane to Preliminary Order
             Issue No. 5] ...................................•............................................................••.......189
        L.   Spindletop Gas Storage Facility ....................................................................... 195
VIII.        AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue
             No. 3] ................................................................................................................... 195
        A.   Large Industrial & Commercial Sales Reallocation ....................................... 200
        B.   Administration Costs .........................................................................................202
        c.   Customer Service Operations Class .................................................................203
             1.         Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095
                        (Headquarter's Credit & Collect), F3PCR73380 (Credit Systems),
                        and F3PCR73458 (Credit Call Outsourcing) ...................................... 203
             2.         Projects F3PCR73381 (Customer Svc Cntr Credit Desk),
                        F3PCR73390 (Customer Svs Ctl - Entergy Bus), and
                        F3PCR73403 (Customer Issue Resolution - ES) ................................. 204
SOAHDOCKETNO.-                                TABLE OF CONTENTS                                                       PAGEV
PUC DOCKET NO. 39896

    D.   Distribution Operations Class .......................................................................... 205
         1.        Project FSPCDW0200 (Lineman's Rodeo Expenses) ......................... 205
         2.        Projects F3PCTJGUSE (Joint Use With Third Party - E) and
                   F3PCTJTUSE (Joint Use With Third Parties - A) ............................ 206
    E.   Energy and Fuel Management Class ............................................................... 206
         1.        Project F3PCWE0140 (EMO Regulatory Affairs) ............................. 207
         2.        Projects F3PPSPE003 (SPO Summer 2009 RFP Expense),
                   F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004
                   (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303
                   (SP02008 Winter Westn RegionRFP-IM) ........................................... 207
         3.        Project F3PCCSPSYS (System Planning and Strategic) .................... 208
    F.   Environmental Service Class ............................................................................209
    G.   Federal PRG Affairs Class ................................................................................211
         1.        Project FSPPSPE044 (PMO Support Initiative-System) .................... 211
         2.        Project F3PPUTLDER (Utility Derivatives Compliance) .................. 211
         3.        Project F3PCSYSRAF (System Regulatory Affairs-Federal)............ 212
    H.   Financial Services Class ....................................................................................215
         1.        Projects F3PCF05700 (Corporate Planning & Analysis),
                   F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000
                   (Financial Forecasting), F3PPADSENT (Analytic/Decision
                   Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-
                   Entergy) .................................................................................................. 216
         2.        Projects F3PCF20990 (Operations Exec VP & CFO) and
                   F3PCFF1001 (OCE Support) ................................................................ 217
         3.        Project F3PCR7334S (Quick Payment Center, Adm) ........................ 218
         4.        Project F3PCF23936 (Manage Cash) ................................................... 218
    I.   Human Resources Class ....................................................................................219
         1.        Project F3PCHRCCSM (HR Competitive Compensation) ................ 220
         2.        Projects (Non-Qualified Post-Retirement) and FSPPZNQBDU
                   (Non-Qual Pension/Benf-Dom Utl) ....................................................... 220
    J.   Information Technology Class.......................................................................... 221
         1.         (Evaluated Receipts Settlement) .......................................................... 221
         2.        Project F3PCFX3SSS (BOD/Executive Support) ................................ 222
    K.   Internal and External Communications Class ................................................223
SOAH DOCKET N O . -                            TABLE OF CONTENTS                                                  PAGE VI
PUC DOCKET NO. 39896

    L.    Legal Services Class ...........................................................................................224
          1.        Project F3PPCASHCT (Contractual Alternative/Cashpo) ................ 224
          2.        Project FSPCZLDEPT (Supervision & Support - Legal) .................. 224
          3.        Project F3PCF99180 (Corp. Compliance Tracking Sys) ................... 225
          4.        Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and
                    F3PPTDHY19 (Dept. of Justice Investigation) ................................... 225
          S.        Project F3PCE01601 (Ferc - Access Transmission) ...........................228
          6.        Project F3PCERAKTL (RAKTL Patent Matter) ............................... 229
          7.        Project F3PPEASTIN (Willard Eastin et al) ...................................... 230
          8.        Project F3PPTCGS11 (TX Docket Competitive Generation) ............ 231
          9.        Project FSPCE13759 (Jenkins Class Action Suit)............................... 232
          10.       Project F3PCSYSAGR (System Agreement-2001) ............................. 233
          11.       Project F3PCCDVDAT (Corporate Development Data Room) ........ 234
          12.       Project F3PPWET302 (SPO 2008 Winter Western Region) ............. 235
          13.       Project F3PPWET308 (SPO Calpine PPA/Project Houston) ............ 236
    M.    Other Expenses Class ........................................................................................236
          1.        Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and
                    F5PPKATRPT (Storm Cost Processing & Review) ............................ 237
          2.        Project F3PCC08500 (Executive VP, Operations) .............................. 237
          3.        Projects F3PPBFMESI (ESI Function Migration Relocation),
                    F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI
                    Disaster Recovery Plan Charge), FSPPBFMREL (Business
                    Function Migration Employee), FSPPBFRREL (Business
                    Function Relocation), F5PPBFRSEV (Business Function
                    Relocation Severance), FSPPDRPREL (Disaster Recovery Plan
                    Relocation), and FSPPETXRFI (2009 Texas Ike Recovery Filing) ... 238
    N.    Regulatory Services Class .................................................................................240
     O.   Retail Operations Class .....................................................................................241
          1.        Project FSPPICCIMG (ICC- "Image" Message) .............................. 241
          2.        Projects F3PPRS6640 (Wholesale - EGS-TX) and F3PPRS6920
                    (Wholesale - All Jurisdictions) .............................................................. 242
    P.    Supply Chain Class ............................................................................................243
     Q.   Transmission and Distribution Support Class ................................................244
    R.    Tax Services Class .............................................................................................. 246
SOAHDOCKETNO.-                                    TABLE OF CONTENTS                                                     PAGE VII
PUC DOCKET NO. 39896

      s.   Transmission Operations Class ........................................................................247
      T.   Treasury Operations Class ...............................................................................248
      u.   Utility and Executive Management Class ........................................................250
IX.        JURISDICTIONAL COST ALLOCATION [Germane to Preliminary
           Order Issue No. 13) ............................................................................................252
      A.   A&E 4CP ............................................................................................................253
Barb. 12CP ....................................................................................................................254
x.         CLASS COST ALLOCATION AND RATE DESIGN [Germane to
           Preliminary Order Issue No. 1] ........................................................................256
      A.   Renewable Energy Credit Rider [Germane to Preliminary Order Issue
           No. 19] .................................................................................................................257
           1.         ETl's Proposed Cost Recovery ............................................................. 257
           2.         Opposition to ETl's Proposal ............................................................... 258
           3.         ETl's Response ....................................................................................... 262
           4.         ALJs' Analysis ....................................................................................... 263
      B.   Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ••••..••.•264
           1.         Municipal Franchise Fees ..................................................................... 264
           2.         Miscellaneous Gross Receipts Taxes .................................................... 269
           3.         Capacity-Related Production Costs ..................................................... 270
           4.         Transmission Costs ................................................................................ 275
      C.   Revenue Alloc.ation ............................................................................................276
           1.         Argument for Moving Rates to Cost .................................................... 277
           2.         Argument for Gradualism .................................................................... 280
           3.         ALJs' Recommendation ........................................................................283
      D.   Rate Design [Germane to Preliminary Order Issue Nos.15, 18, and 20] .....284
           1.         Lighting and Traffic Signal Schedules ................................................ 285
           2.         Demand Ratchet. .................................................................................... 289
           3.         Large Industrial Power Service (LIPS) ............................................... 297
           4.         Schedulable Intermittent Pumping Service (SIPS) ............................ .301
           5.         Standby Maintenance Service (SMS) .................................................. .305
           6.         Additional Facilities Charge (AFC) ..................................................... 312
           7.         Large General Service (LGS) ............................................................... 314
SOAH DOCKET N O . -                                 TABLE OF CONTENTS                                                     PAGE VIII
PUC DOCKET NO. 39896

             8.         General Service (GS) ............................................................................. 317
             9.         Residential Service (RS) ....................................................................... .317
XI.          FUEL RECONCILIATION [Germane to Preliminary Order Issue
             Nos. 21-31] ..........................................................................................................321
        A.   Spindletop Gas Storage Facility ....................................................................... 326
        B.   Use of Current Line Losses for Fuel Cost Allocation .....................................327
        c.   ETl's Special Circumstances Request .............................................................328
XII.         OTllER ISSUES ................................................................................................329
        A.   MISO Transition Expenses [Germane to Preliminary Order Issue
             Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos.1-9] ..............329
             1.         Deferred Accounting .............................................................................. 331
             2.         Base Rate Recovery ............................................................................... 338
        B.   TCRF Baseline [Germane to Supplemental Preliminary Order Issue
             No. 2] ...................................................................................................................340
        c.   DCRF Baseline [Germane to Supplemental Preliminary Order Issue
             No. 2] ...................................................................................................................341
        D.   Purchased Power Capacity Cost Baseline [Germane to Supplemental
             Preliminary Order Issue No. 1] ........................................................................ 341
XIII.        CONCLUSION .................................................................................................. 343
XIV.         PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
             ORDERING PARAGRAPHS ...........................................................................344
        A.   Findings of Fact ..................................................................................................344
        B.   Conclusions of Law ............................................................................................367
        c.   Proposed Ordering Paragraphs .......................................................................369

List of Acronyms and Defined Terms

Attachment A
               List of Acronyms and Defined Terms

TERM              DEFINITION
12CP              12 Coincident Peak
A&E4CP            A verag_e and Excess, 4 Coincident Peak
A&P               Average and Single Coincident Peak
AD FIT            Accumulated Deferred Federal Income Tax
AFC               Additional Facilities Char_ge
AFUDC             Allowance for Funds Used During Construction
AUs               Administrative Law Judges
BCIJJU3           Big Cajun II, Unit 3
Brazos            Brazos Electric Cooperative, Inc.
Calpine           Calpine Energy Services
                  Contract for the purchase of 485 MW of capacity from
Carville Contract Calpine's Carville Energy Center
CAPM              Capital Asset Pricing Model
CenterPoint       CenterPoint Energy Houston Electric, LLC
CGS               Competitive Generation Service
CI                Conformance Index
                  Anahuac, Beaumont, Bridge City, Cleveland, Conroe,
                  Dayton, Groves, Houston, Huntsville, Montgomery,
                  Navasota, Nederland, Oak Ridge North, Orange, Pine
                  Forest, Rose City, Pinehurst, Port Arthur, Port Neches,
                  Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and
Cities            West Orange, Texas
Commission        Public Utility Commission of Texas
Company           Entergy Texas, Inc.
CP                Coincident Peak
CWIP              Construction Work in Pro_gress
DCF               Discounted   Cash Flow
DCRF              Distribution Cost Recovery Factor
DOE               United States Department of Energy
DOJ               United States Department of Justice
EAI               Entergy Arkansas, Inc.
EAWBL             2009 Contract between ETI and EAI for Wholesale Base
Contract          Load Resources
EGSI              Entergy Gulf States, Inc., predecessor to ETI
EGSL              Entel'gy_ Gulf States Louisiana, LLC
ELL               Entergy Louisiana, Inc.
EMI               Entergy Mississippi, Inc.
                  Long-term Gas Supply Contract between ETI and Enbridge
Enbridge Contract Pipeline, L.P.
ENOl              Entergy New Orleans, Inc.
Entergy           Entergy Coi'Q_oration
TERM             DEFINITION
ESI              Entergy Services, Inc.
ETEC             East Texas Electric CooQ_erative, Inc.
ETI              Entergy Texas, Inc.
FAS 106          F ASB Statement No. 106
FASB             Financial Accounting Standards Board
FERC             Federal Energy Regulatory Commission
FIN48            Financial Int~rpretation Number 48
GAAP             Generally Accepted Accounting Principles
GDP              Gross Domestic Product
GS               General Service
GSU              Gulf States Utilities Company
Iowa Curves      Various Known Patterns of Industrial Asset Mortality Rates
IRS              Internal Revenue Service
ISB              Intra-System Bill
                 Class action lawsuit filed in Texas district court in 2003 on
Jenkins Class    behalf of all Texas retail customers served by ETI's
Action           predecessor-in-interest, EGSI
Kroger           The Kroger Co.
kW               Kilowatt
kWh              Kilowatt-hour
LED              Light Emitting Diode
LGS              Large General Service
LIPS             Large Industrial Power Service
MFF              Municipal Franchise Fees
MGRT             Miscellaneous Gross Receipts Tax
MISO             Midwest Independent Transmission System Operator, Inc.
MSS-2            Schedule MSS-2 of the Entergy System Agreement
MW               Me_g_awatt
Moody's          Moody's Investors Service
MWh              Megawatt-hour
NARUC            National Association of Regulatory Utility Commissioners
Nelson           Nelson 6, a 550 MW Unit located in Westlake, Louisiana
O&M              Operations and Maintenance
OATT             Open Access Transmission Tariff
OPC              Office of Public Utility Counsel
PFD              Pro_Q_osal for Decision
PPCCs            Purchased Power Capacity Costs
PPR              Purchased Power Rider
PUC              Public Utility Commission of Texas
PURA             Public Utility Regulatory_ Act
Rate Year        June 1, 2012, through May 31, 2013
Reconciliation
Period           July1,2009,throughJune30,2011
TERM             DEFINITION
RECs             Renewable Energy Credits
Reserve          Strategic Petroleum Reserve
River Bend       River Bend Nuclear Generating Station Unit No. 1
ROE              Return on Equity
RRC              Railroad Commission of Texas
RS               Residential Service
RTO              Regional Transmission Or~anization
S&P              Standard & Poor's
SFAS             Statement of Financial Accounting Standards
SIPS             Schedulable Intermittent Pumping Service
SMS              Standby Maintenance Service
SOAH             State Office of Administrative Hearings
Spindletop
Facility         Spindletop Gas Storage Facility
SRMPA            Sam Rayburn Municipal Power Agency
Staff            Staff of the Public Utility Commission of Texas
State Agencies   State of Texas State Agencies
T&D              Transmission and Distribution
TCRF             Transmission Cost Recovery Factor
Test Year        July 1, 2010, through June 30, 2011
TIEC             Texas Industrial Energy Consumers
Value Line       Value Line Investment Survey
Wal-Mart         Wal-Mart Stores, LLC, and Sam's East, Inc.
Zacks            Zacks Investment Service
                                   SOAH DOCKET NO.
                                     PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS,                            §         BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE                             §
RATES, RECONCILE FUEL COSTS,                             §                           OF
AND OBTAIN DEFERRED                                      §
ACCOUNTING TREATMENT                                     §        AD1\1INISTRATIVE HEARINGS

                                     PROPOSAL FOR DECISION

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

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

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

1
   During the hearing the parties used the term "Rate Year" to refer to the period June 2012 through May
2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates
in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes
of this PFD, Rate Year will refer to the period June 2012 through May 2013.
SOAH DOCKET N O . -                        PROPOSAL FOR DECISION                                  PAGE2
PUC DOCKET NO. 39896

                               II.     JURISDICTION AND NOTICE

          The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and
this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001,
33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the
contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to
PURA§ 14.053 and Tex. Gov'tCode§ 2003.049(b). Those municipalities inETI's service areathat
have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction
over ETI' s rates, operations, and services in their respective municipalities pursuant to PURA
§ 33.001. When ETI filed its application with the Commission, it also filed the application with its
original jurisdiction cities. Pursuant to PURA§§ 32.00l(b), 33.051, and 33.053, ETI appealed the
actions of the original jurisdiction cities to the Commission and had those appeals consolidated with
this docket.

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

                                III.    PROCEDURAL HISTORY

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

          On September 2, 2011, ETI filed an application requesting authority to defer accounting
related to its proposed transition to membership in the Midwest Independent Transmission System
Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22,
2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain
SOAHDOCKETNO.-                           PROPOSAL FOR DECISION                                  PAGE3
PUC DOCKET NO. 39896

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

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

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

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

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

2
  Several other attorneys appeared on behalf ofETI. The ALJs listed only the three attorneys who appeared
throughout the hearing.
SOAH DOCKET N O . -                      PROPOSAL FOR DECISION                                PAGE4
PUC DOCKET NO. 39896

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

                              IV.     EXECUTIVE SUMMARY

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

A.     Rate Base

       1. Capital Investment

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

       2. Hurricane Rita Regulatory Asset

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

3
  Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket
No. 37744 (Dec. 13, 2010).
SOAH DOCKET N O . -                    PROPOSAL FOR DECISION                               PAGES
PUC DOCKET NO. 39896

       3. Prepaid Pension Asset Balance

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

       4. FIN 48 Tax Adjustment

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

       5. Cash Working Capital

       The AU s recommend no changes to ETI' s cash working capital.

       6. Self-Insurance Storm Reserve

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

       7. Coal Inventory

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

       8. Spindletop Gas Storage Facility

       The Spindletop Gas Storage Facility (Spindletop Facility) is a used and useful facility
providing reliability and swing flexibility to ETI' s customers at a reasonable price and should be
included in rate base.
SOAH DOCKET N O . -                     PROPOSAL FOR DECISION                                PAGE6
PUC DOCKET NO. 39896

        9. Short Term Assets

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

        10. Acquisition Adjustment

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

        11. Capitalized Incentive Compensation

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

B.      Rate of Return and Capital Structure

        The ALls recommend a return on equity (ROE) of 9.80 percent; a cost of debt of
6. 74 percent; a capital structure comprised of 50.08 percent debt and 49 .92 percent common equity;
and an overall rate of return of 8.27 percent. This is a downward adjustment to ETI' s request for a
10.60 percent ROE, and no change to ETI's 6.74 percent cost of debt and 50.08/49.92 capital
structure. It compares to Staffs proposed 9.60 percent ROE; OPC's proposed 9.30 percent ROE;
TIEC's proposed 9.50 percent ROE; Cities' proposed 9.50 percent ROE; and State Agencies'
proposed 9.30 percent ROE. No party opposed ETI's proposed 6.74 percent cost of debt or its
proposed 50.08/49.92 capital structure.
SOAHDOCKET N O . -                    PROPOSAL FOR DECISION                             PAGE7
PUC DOCKET NO. 39896

C.     Cost of Service

       1. Purchased Power Capacity Expense

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

       2. Transmission Equalization (MSS-2) Expense

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

       3. Depreciation Expense

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

       Service Lives:
       Account 364-40 R 1.
       Account 368-33 L0.5.

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

       4. Labor Costs

           »   Payroll and Related Aqjustments

       The Commission should accept: (1) the payroll adjustments proposed in theETI application;
and (2) the further payroll adjustments proposed by Staff as corrected by ETI.
SOAHDOCKETNO.-                         PROPOSAL FOR DECISION                                 PAGES
PUC DOCKET NO. 39896

           >   Incentive Compensation

       ETI should not be entitled to recover its financially based incentive compensation costs.
Thus, the AU s recommend removing $6, 196,03 7 from ETI' s requested operation and maintenance
(O&M) expenses. Additionally, an additional reduction should be made to account for the FICA
taxes that ETI would have paid as a result of those costs.

           >   Compensation and Benefit Levels

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

           >   Nonqualified Executive Retirement Benefits

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

           >   Employee Relocation Costs

       The Commission should allow ETI' s relocation expenses.

           >   Executive Perquisites

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

       5. Interest on Customer Deposits

       The AlJs recommend using the active customer deposits amount of $35,872,476 and the
2012 interest rate, which produces a recommended interest expense of $43,047 ($35,872,476
multiplied by .12 percent).
SOAHDOCKET N O . -                      PROPOSAL FOR DECISION                                PAGE9
PUC DOCKET NO. 39896

       6. Property (Ad Valorem) Tax Expense

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

       7. Advertising, Dues, and Contributions

       The AUs recommend an adjustment to remove $12,800 fromETI's costs of advertising, dues
and contributions.

       8. Other Revenue Related Adjustments

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

       9. Federal Income Tax

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

       10. River Bend Decommissioning Expense

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

       11. Self-Insurance Storm Reserve Expense

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

         12. Spindletop Gas Storage Facility

         The AU s recommend inclusion of the costs of operating the Spindletop Facility as requested
byETI.

D.       Affiliate Transactions

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

                    $356,151 (which figure includes the $112,531 agreed to by ETI) of costs
                    associated with Projects F5PCWBENQ (Non-Qualified Post Retirement)
                    and F5PPZNQBDU (Non Qual Pension/Bent Dom Utl);

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

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

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

E.       Jurisdictional Cost Allocation

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

F.     Class Cost Allocation

       1. Renewable Energy Credit Rider

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

       2. Class Cost Allocation

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

                    (a) Municipal Franchise Fees

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

                    (b) Miscellaneous Gross Receipts Tax

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

                    (c) Capacity-Related Production Costs

       The AUs recommend the use of Average and Excess 4 Coincident Peak (A&E 4CP) to
allocate capacity-related production costs, as proposed by ETI. The AUs do not find sufficient
support to allocate the reserve equalization payments differently than other capacity-related
production costs.
SOAHDOCKETNO.-                          PROPOSAL FOR DECISION                               PAGE12
PUC DOCKET NO. 39896

                   (d) Transmission Costs

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

       3. Revenue Allocation

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

       4. Rate Design

                   (a) Lighting and Traffic Signal Schedules

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

                   (b) Demand Ratchet

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

                   (c) Large Industrial Power Service

       The AlJ s recommend the adoption of a $630 customer charge for this customer class, a slight
decrease in the LIPS energy charges, and an increase in the demand charges from current rates for
this class, as proposed by Staff witness Abbott.
SOAHDOCKETNO.-                         PROPOSAL FOR DECISION                         PAGE 13
PUC DOCKET NO. 39896

                   (d) Schedulable Intermittent Pumping Service

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

                   (e) Standby Maintenance Service

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

                   (f) Additional Facilities Charge

       Schedule AFC should be changed in accordance with TIEC's recommendations and those
recommended numbers should be reduced in proportion to any authorized reduction in ETI' s
proposed rate of return, O&M expense, and property tax expense.

                   (g) Large General Service

       Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand
ratchet, and the ALls' recommendation for the elimination of ETI's LIPS demand ratchet is
applicable to this class

                    (h) General Service

       The Commission should adopt the decrease in the Schedule GS customer charge to $39.91
from the current (and Company proposed) rate of $41.09, as well as Staffs recommended decrease
in energy charges. Schedule GS also has a demand ratchet, and the ALls' recommendation for the
elimination of ETI' s LIPS demand ratchet is applicable to this class.
SOAHDOCKETNO.-                           PROPOSAL FOR DECISION                               PAGE14
PUC DOCKET NO. 39896

                   (i) Residential Service

       ETI's declining block winter rates provide a disincentive to energy efficiency. The AUs
recommend an initial 20 percent reduction, followed by 20 percent subsequent reductions of the
differential in the next three rate cases unless ETI provides sufficient evidence that such changes are
unjust and unreasonable.

G.     MISO Transition

       The Commission should deny ETI's request for deferred accounting of its MISO transition
expenses to be incurred on or after January 1, 2011. However, the Commission should authorize ETI
to include $2.4 million of MISO transition expense in base rates set in the present case, based on a
five-year amortization of $12 million in total projected expenses. Further, the Commission should
authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of
the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of
$2,452,800.

       V.     RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16]

A.      Capital Investment [Germane to Preliminary Order Issue No.17]

       ETI presented for review $408,078,600 in capital additions closed to plant in service between
July 1, 2009, and June 30, 2011; that is, from the end of the test year in the Company's last base rate
case, which was Docket No. 37744, through the Test Year presented in this case. The capital
additions were detailed in the testimony and exhibits of the following Company witnesses: Garrison
(Generation), Mcculla (Transmission), Corkran (Distribution), Stokes (Customer Service), Brown
(Information Technology), Plauche (Administrative), Cicio (System Planning and Operations),
Hunter (Supply Chain), May (Regulatory), and Sloan (Legal).4 The evidence shows that these capital

4
 ETI Ex. 27 (Garrison Direct) at 20-28 and WWG-4; ETI Ex. 32 (McCulla Direct) at 64-92 and MFM-16;
ETI Ex. 25 (Corkran Direct) at 78-108 and SBC-3; ETI Ex. 37 A (Roman Direct, adopted by Stokes) at 121-
125 and AFR-5; ETI Ex. 24 (Brown Direct) at 29-37 and JFB-3; ETI Ex. 20 (Plauche Direct) at 37-44 and
TCP-11; ETI Ex. 39 (Cicio Direct) at 71-75 and PJC-6; ETI Ex. 16 (Hunter Direct) at34-38 and JMH-7; ETI
Ex. 7 (May Direct) at 53-54 and PRM-3; and ETI Ex. 38 (Sloan Direct) at 37-43 and RDS-4.
SOAH DOCKET N O . -                      PROPOSAL FOR DECISION                                PAGE15
PUC DOCKET NO. 39896

additions were prudently incurred and are used and useful in providing service to ETI's customers.
No party challenged any of the capital additions or the costs thereof, and the AU s find no reason to
do so either.

B.      Hurricane Rita Regulatory Asset

        Hurricane Rita struck the upper Texas coast in September 2005, causing extensive property
damage. In 2006, the Texas Legislature enacted PURA Chapter 39 to authorize electric utilities such
as ETI to securitize the recovery of their reconstruction costs incurred as a result of Hurricane Rita.
Under the statute, the amount of reconstruction costs to be securitized had to be reduced by the
insurance proceeds and government grants received by a utility. If additional insurance or grant
proceeds were received after the securitization order was approved, the Commission was required to
take those amounts into account in the utility's next base rate case. This was provided in
Section 39.459(c) of PURA:

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

                (1) the utility's next base rate proceeding; or
                (2) any proceeding in which the commission considers hurricane
                    reconstruction costs.

        Docket No. 32907 was the proceeding for ETI to determine the amount of Hurricane Rita
reconstruction costs that it could securitize, net of any proceeds received from insurance or
                     5
government grants.       In that case, ETI asserted that it incurred $393,236,384 in Hurricane Rita
reconstruction costs for its Texas Retail jurisdiction. The parties reached a settlement in that case,
which set ETI's hurricane reconstruction expenses eligible for securitization at $381,236,384. In
addition, ETI estimated that it would receive $65,700,000 in future insurance proceeds that, pursuant

5
  Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket
No. 32907 (Dec. 1, 2006).
SOAH DOCKET N O . -                         PROPOSAL FOR DECISION                                  PAGE16
PUC DOCKET NO. 39896

to the settlement, was deducted from the amount to be securitized. The parties also agreed that after
ETI received all of its insurance payments, a true-up would occur to reflect the difference between
the $65,700,000 credited and the amount actually received. The settlement agreement provided that
if ETI received more insurance payments than estimated, the excess payments would be passed
through to ratepayers in the form of a rider; however, the agreement did not address how an under-
recovery by ETI would be handled. It turned out that ETI received only $46,013,904 in insurance
proceeds,6 leaving a $19 ,686,096 under-recovery by ETI, which the parties refer to as Overestimated
Insurance Proceeds. 7

          Docket No. 37744 was ETI's next base rate case after Docket No. 32907. In Docket
No. 37744, ETI requested recovery of the Overestimated Insurance Proceeds by establishing a
regulatory asset of $19,686,096, plus accrued carrying costs, to be amortized over five years. 8
Docket No. 37744 also concluded by a black-box settlement, and neither the Stipulation and
Settlement Agreement nor the Order entered by the Commission specifically addressed the proposed
regulatory asset or any other recovery for Overestimated Insurance Proceeds.

          In the present case, ETI has again sought approval of a regulatory asset to recover
$26,229,627, for the balance of Overestimated Insurance Proceeds, plus carrying costs through
June 30, 2011. 9 Cities objected to the amount of ETI's request. They argue that this issue was
resolved in Docket No. 37744 and that ETI should have been amortizing the asset since the
conclusion of that case. Staff also argues that the issue was resolved in Docket No. 37744 and
requested that ETI' s request be denied entirely; or, alternatively, that it should be considered partially
amortized and accordingly reduced. ETI argues that the issue was not resolved in Docket No. 37744
and that it should be allowed a full recovery in the present case. Alternatively, ETI argues that
Cities' proposed reduction was not calculated correctly.

6
    See Docket No. 32907, Final Order at FoF 27. Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.
    $19,686,096 = 65,700,000 - $46,013,904.
7

8
    Cities Ex. 2 (Garrett Direct) at l l.
9
    Schedule P Cost of Service Workpapers, Vol. 2, ETI Ex. 3 at AJ 15, page 15.3.
SOAHDOCKET N O . -                             PROPOSAL FOR DECISION                         PAGE 17
PUC DOCKET NO. 39896

          Cities' expert accounting witness, Mark Garrett, testified that ETI should have been
amortizing the balance of Overestimated Insurance Proceeds since the effective date of rates set in
Docket No. 37744. In addition, he argues that ETI should not have continued to accrue interest on
the balance that was added into rate base in that docket, because it would have then earned a rate of
return. Therefore, Mr. Garrett's adjustment started with the balance of $25,278,210 that ETI
requested in Docket No. 37744. He reduced that balance by $9,479,329 for amortization between
the date rates went into effect in Docket No. 37744 and the date that rates will go into effect in the
current case (22.5 months). Mr. Garrett further reduced the remaining balance by $5,678,960 to
account for additional insurance proceeds received by ETI after Docket No. 37744. By Mr. Garrett's
calculations, this left a remaining balance of Overestimated Insurance Proceeds of $11,071,3 3 8. 10
Both Mr. Garrett and Cities witness Jacob Pous also recommended that this remaining balance not be
carried as a regulatory asset but, instead, be moved to the storm insurance reserve for recovery. 11 In
their view, this would ensure that the remaining balance would be properly recovered.

          In response to ETI's argument that the Hurricane Rita Regulatory Asset was not resolved in
Docket No. 37744, Cities stress that Docket No. 37744 settled as a "black box settlement." In
Cities' opinion, such a settlement should not be interpreted as changing the status quo unless
expressly stated in the settlement agreement or final order. Cities contend that the status quo in
Docket No. 37744 was that ETI was authorized to recover its Over Estimated Insurance Proceeds,
because recovery was authorized by PURA § 39 .459(c); recovery had been previously approved in
Docket No. 32907; and no party objected to its recovery in Docket No. 37744. Therefore, Cities
state, the final order in Docket No. 37744 should be interpreted as authorizing ETI's requested
recovery of the Hurricane Rita Regulatory asset in the rates set in that docket. 12

          Cities also disagree with ETI' s alternative argument that Mr. Garrett improperly calculated
the remaining balance of the asset by deducting an amount for insurance proceeds ETI received after
Docket No. 37744 concluded. Cities state that Mr. Garrett's adjustment was correct because it began

10
     Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.
11
     Id. (Garrett Direct) at 12; Cities Ex. 5 (Pous Direct) at 64.
12
     Cities Reply Brief at 10-14.
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PUC DOCKET NO. 39896

with the balance requested in Docket No. 37744, before the additional insurance proceeds were
received. In other words, Mr. Garret did not start with the balance claimed by ETI in the present
case, 13 so he correctly applied the amount, received after Docket No. 37744 to reduce the balance
                              14
claimed in that docket.            According to Cities, Mr. Garrett began with the prior balance to properly
reflect that no carrying charges would accrue on the balance after it was included in rate base and
recovered a return through rates. 15 Cities also dispute ETI' s argument that Mr. Garrett should not
have accounted for amortization occurring between the Test Year and the Rate Year as an "invalid
                                    16
post-test year adjustment.''             In Cities' view, this was a valid known and measureable change that
should be taken into account. 17

           Staff recommends that the Hurricane Rita Regulatory Asset be removed from rate base
entirely. Staff witness Anna Givens stated that it is reasonable to assume that this asset was included
as part of the settlement in Docket No. 37744. Accordingly, she stated that it is not appropriate for
ETI to request recovery of the same asset in the present docket.                    Therefore, Ms. Givens
recommended removal of the entire requested $26,229,627 Hurricane Rita regulatory asset from
ETI' s rate base. 18

           Alternatively, Ms. Givens proposed that the Commission allow ETI a regulatory asset of
$17,486,418, to be amortized over 40 months. Ms. Givens noted that higher rates from Docket
No. 37744 first went into effect on August 15, 2010; 19 therefore, at least one-third of the regulatory
asset should have been amortized by the conclusion of the present case. Using ETI's updated
hurricane regulatory asset request of $26,229 ,627, Ms. Givens recommended a decrease of one-third
to ETI's request. This would equal an $8,743,209 reduction, resulting in her recommended

13
     Cities Initial Brief at 8.
14
     Cities Ex. 2B (Garrett Direct), Exhibit MG-2.3.
15
     Docket No. 32907, Final Order at FoF 28.
16
     ETI' s Initial Briefat 7.
17
     Cities' Reply Brief at 10-14.
18
     Staff Ex. l (Givens Direct) at 32-34.
19
     Docket No. 37744, Order, FoF 16 (Dec. 13, 2010).
SOAHDOCKETNO.-                               PROPOSAL FOR DECISION                                   PAGE 19
PUC DOCKET NO. 39896

regulatory asset of $17,486,418 ($26,229 ,627 - $8, 743,209). Ms. Givens also recommended that the
amortization period be decreased from 60 months to 40 months, which is the time remaining on
ETI's original Docket No. 37744 request. 20

          ETI disagrees with Cities and Staff, and it argues that its total requested Hurricane Rita
regulatory asset should be included in rate base in this case. First, it notes that no instruction in the
Stipulation and Settlement Agreement filed in Docket No. 37744 required ETI to begin amortizing
the asset or otherwise directed the treatment of the asset. Likewise, no Finding of Fact or Conclusion
of Law in the agreed order entered in Docket No. 37744 authorized the proposed treatment of the
asset. In contrast, ETI notes, the settlement in Docket No. 32907 does specifically address the
treatment of this asset, and it argues that its request to include the full Hurricane Rita regulatory asset
in rate base in the present case is consistent with that settlement. In ETI's opinion, it has not
previously been authorized to establish the regulatory asset, it has not amortized it, and the full
amount should be included in rate base in this case. 21

          Alternatively, if Cities' proposed amortization is accepted, ETI argues that Mr. Garrett's
calculations were wrong. First, ETI states, Mr. Garrett incorrectly assumed that the $26,229,627
Hurricane Rita regulatory asset requested in this case did not account for the $5,678,960 of insurance
proceeds that ETI received after Docket No. 37744. According to ETI, the $5,678,960 was
accounted for, as shown on WP/P AJ 15.3. Therefore, ETI states, Mr. Garrett's adjustment for this
$5.6 million would remove this amount from the asset a second time. 22 Second, ETI argues that
Mr. Garrett erred by amortizing the asset by 22.5 months. Mr. Garrett calculated the amortization
period from the time rates went into effect after Docket No. 37744 (August 15, 2010) through the
time revised rates would go into effect in this docket (June 30, 2012). ETI states that Mr. Garrett

20
   Staff Ex. 1 (Givens Direct) at 34. Ms. Givens noted that amount recommended in Docket No. 37744 was
$25,278,000, which is $951,627 less than the amount requested in the current proceeding. However, she stated
that this does not affect her recommendation, because by the time the hearing on the merits concluded, at least
another two months of amortization expense under the existing rates would be collected by the ETI and should
adequately compensate it for the difference. Staff Ex. 1 (Givens Direct) at 35.
21
     ETI Ex. 46 (Considine Rebuttal) at 19-24; ETI Initial Brief at 5-6.
22
     ETI Ex. 46 (Considine Rebuttal) at 21-22; ETI Initial Brief at 7.
SOAH DOCKET N O . -                          PROPOSAL FOR DECISION                            PAGE20
PUC DOCKET NO. 39896

made an invalid post-test year adjustment because post-test year adjustments for rate base items are
limited to plant additions recorded in FERC Accounts 101 or 102. In contrast, regulatory assets, like
the Hurricane Rita regulatory asset, are recorded in Account 182.3. Therefore, in ETI' s opinion, if it
was required to amortize this regulatory asset, it would be appropriate to amortize it for only
10.5 months, to the end of the Test Year (August 15, 2010, through June 30, 2011). These two
corrections would adjust Mr. Garrett's proposed asset balance from $10,714,557 to $21,805,940. 23

          ETI also disagrees with Mr. Pous' recommendation that the regulatory asset be removed from
rate base and placed in the storm reserve, to be amortized over 20 years. In ETI's opinion, this
approach would defeat the purpose of securitization, which is to provide ETI with cost recovery in an
expedited manner. 24

          Finally, ETI argues that Ms. Givens' analysis was flawed. It reiterated that no provision in
the Stipulation and Settlement Agreement or the final order filed in Docket No. 37744 directed the
treatment of the regulatory asset or stated that ETI would begin amortizing the asset. Further, ETI
stresses that it never sought recovery of the entire asset all at once in Docket No. 37744. Instead,
ETI requests recovery over a period of years through amortization. Thus, according to ETI, even if
Ms. Givens' argument were accepted, the entire asset should not be disallowed. 25

          This issue is a close call because the black-box settlement agreement and final order in
Docket No. 37744 did not expressly state how the Hurricane Rita regulatory asset issue was resolved.
The following factors support finding that the Hurricane Rita regulatory asset issue was resolved in
Docket No. 37744:

•     the settlement agreement and final order in Docket No. 32907 expressly provided that the
      difference between the amount of ETI's estimated insurance proceeds and the amount actually
      received by ETI would be trued up after ETI received the proceeds~

23
     ETI Ex. 46 (Considine Rebuttal) at 22; ETI Initial Brief at 7-8.
24
     ETI Initial Brief at 8.
25
     ETI Ex. 46 (Considine Rebuttal) at 21; Id. at 8-9.
SOAHDOCKETNO.-                           PROPOSAL FOR DECISION                                PAGE21
PUC DOCKET NO. 39896

•   PURA § 39 .459(c) provides that if the timing of a utility's receipt of insurance proceeds
    prevented their inclusion as a reduction to the securitized costs, the Commission "shall take those
    amounts into account ... in the utility's next base rate proceeding;"

•   Docket No. 37744 was ETI's next base rate proceeding;

•   in Docket No. 37744, ETI requested a true-up concerning the insurance proceeds, and it
    requested that a regulatory asset be established for the deficit and amortized over five years;

•   in Docket No. 37744, no party objected to ETI's proposed regulatory asset or amortization;

•   the stipulation and settlement agreement entered by the parties in Docket No. 37744 stated that
    the parties resolved all issues, except for ETr s Competitive Generation Service (CGS) proposal;
    and

•   neither the stipulation and settlement agreement nor the Order entered in Docket No. 37744
    specifically disapproved, excluded, or deferred consideration ETI' s proposed regulatory asset,
    although they did specifically exclude or disapprove other items, such as ETI' s CGS proposal
    and various proposed riders.

        On the other hand, some factors support a finding that the Hurricane Rita regulatory asset
issue was not resolved in Docket No. 37744. The stipulation and settlement agreement and the
Order entered in Docket No. 37744 did not expressly approve ETI's proposed regulatory asset,
although certain other items were expressly approved, such as River Bend Nuclear Generating
Station Unit No. 1 (River Bend) decommissioning costs, depreciation rates, and other items. Also,
utilities are typically not allowed to create regulatory assets without express approval of the
Commission.

        Thus, the difficulty with this issue is the nature of the black-box settlement of Docket
No. 37744. In the settlement, the parties agreed to an increase in base rate revenues of $59 million
effective August 15, 2010, with an additional increase in base rate revenues effective May 2, 2011.
However, there was no explanation on how this increase was determined, and there was no specific
agreement or finding on the amount of ETI' s rate base or its reasonable and necessary cost of service.
In that case, there was no objection to ETI' s proposed Hurricane Rita regulatory asset, it was
authorized by the prior settlement in Docket No. 32907, and the Commission was directed by PURA
SOAHDOCKETNO.-                            PROPOSAL FOR DECISION                                 PAGE22
PUC DOCKET NO. 39896

§ 39 .459(c) to take into account ETI' s insurance proceeds related to the Hurricane Rita securitized
costs in ETI's next rate case, which was Docket No. 37744. Moreover, when there is uncertainty
whether an undisputed issue was deferred for future consideration or was included within the rates
set in a black-box settlement, the burden should be on the utility to establish that the issue was
deferred for future consideration. When all the evidence and factors are considered, the AUs find
that that ETI's proposed Hurricane Rita regulatory asset should be considered as having been
approved in Docket No. 37744, and ETI should have amortized the asset since August 15, 2010, the
effective date of rates approved in that docket.

        The AUs also find that none of the amortization calculations proposed by the parties were
entirely correct. ETI's proposal to start with its requested $26,229,627 was flawed because it
included carrying costs from August 15, 2010, when the asset should have been included in rate base,
to June 30, 2011, the end of the Test Year in the present case. During that period, the asset would
have earned a rate of return as part of rate base, and accrual of carrying costs should have ceased.
Therefore, it would be more accurate to begin amortizing the Hurricane Rita regulatory asset by
using the balance requested by ETI in Docket No. 37744. That amount, according to Mr. Garrett,
was $25,278,210. However, the amortization calculation should not extend beyond the end of the
Test Year in the present case (June 30, 2011), as proposed by Cities and Staff. P.U.C. SUBST.
R. 25 .231 (c )(2)(F)( ii) provides for post-test-year reductions to rate base, and the recommendation for
a post-test-year adjustment to the Hurricane Rita regulatory asset does not fall within the scope of
that rule. The balance remaining after amortization to the end of the Test Year should be further
reduced by $5,678,960 to account for additional insurance proceeds received by ETI after Docket
No. 37744 concluded but before the end of the Test Year in the present case. ETI argues that this
reduction was already included in its request. However, as discussed above, the appropriate
calculation should begin with the balance of the asset at the conclusion of Docket No. 37744, not the
balance requested by ETI in the present case. The balance of the asset at the conclusion of Docket
No. 37744 did not account for the additional insurance proceeds paid to ETI afterwards, so it should
be deducted now. In summary, the AUs find that the appropriate amount of the Hurricane Rita
regulatory asset to be included in rate base in this case should be calculated as follows:
SOAHDOCKETNO.-                                PROPOSAL FOR DECISION                            PAGE23
PUC DOCKET NO. 39896

Beginning balance at conclusion of Docket No. 37744 (original balance+ carrying charges)   $25,278,210

Less amortization for period 8/15/10 to 6/30/11 = 10.5months160 months= 17.5%              - $4,423,687

Less additional insurance proceeds received                                                - $5,678,960

Remaining balance of Hurricane Rita regulatory asset                                       $15,175,563

          Finally, the AU s recommend that the Commission not adopt the recommendation of Cities to
move the Hurricane Rita regulatory asset to the storm insurance reserve for recovery. As noted by
ETI, one purpose of enactment of PURA Chapter 39 was to allow expedited recovery of costs
resulting from Hurricane Rita storm damage. Moving the regulatory asset to the storm insurance
reserve would defeat that purpose and negate the five-year amortization plan the parties agreed to in
Docket No. 37744.

          In summary, the AU s find that ETI' s proposed Hurricane Rita regulatory asset was an issue
resolved by the black-box settlement in Docket No. 37744. Therefore, ETI should have included the
asset in rate base at the conclusion of that docket and should have begun amortizing it over a period
of five years. The accrual of carrying charges should have ceased when Docket No. 37744
concluded, because the asset would have then begun earning a rate of return as part of rate base. The
appropriate calculation of the asset should begin with the amount claimed by ETI in Docket
No. 37744, less amortization accruals to the end of the Test Year in the present case, and less the
amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.
This produces a remaining balance of $15,175,563, which should remain in rate base as a regulatory
asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the
Hurricane Rita regulatory asset should not be moved to the storm insurance reserve.

C.        Prepaid Pension Asset Balance

          ETI included in rate base an item titled Unfunded Pension in the amount of $55,973,545. 26
The amount requested in this account represents the accumulated difference between the Statement
of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual

26
     ETI Ex. 3, Sched. B-1, Line 10.
SOAHDOCKETNO.-                                 PROPOSAL FOR DECISION                            PAGE24
PUC DOCKET NO. 39896

contributions made by the Company to the pension fund. 27 It is a debit balance, meaning that the
Company has contributed roughly $56 million more to its pension fund than the minimum required
by SFAS 87. 28 Other than Cities, no party opposes ETI' s request to include this item in rate base.

          Cities argue that ETI ought not be entitled to include this amount in rate base because it
represents amounts the ETI overpaid to its pension, resulting in little to no benefit to ratepayers.
Cities witness Mark Garrett pointed out that ETI earned only 1.37 percent on its pension assets over
the past five years, while it is seeking a rate of return of more than 11 percent. Thus, he argues, if the
asset were included in rate base, ratepayers would pay a substantial premium for the slight pension
cost savings ETI' s excess contributions may have achieved. 29

          Cities argue that the entire prepaid pension asset should be removed from rate base because
ETI has not justified its inclusion. This would reduce pro forrna rate base by $36,382,803, which is
the net amount of the prepaid balance less accumulated deferred income tax ($55,973,545 -
$19,590,740 = $36,382,803). At the same time, Cities would increase operating expense by
$498,284, to provide a 1.37 percent return on the net balance of ETI' s prepaid pension asset
balance. 30

          Alternatively, Cities contend that the Commission should treat the pension assets in the same
manner as the approach adopted by the Commission in Docket No. 33309. 31 In that docket, the
Commission allowed a pension prepayment asset, less accrued deferred federal income taxes
(ADFIT) and less the portion of the asset that is capitalized to CWIP, to be included in rate base. As
to the excluded portion, the Commission allowed the accrual of an allowance for funds used during
construction (AFUDC). Thus, Cities contend, if the Commission opts for this approach, it should
allow ETI's pension prepayment asset, less ADFIT, to be included in rate base, but excluding

27
     Cities Ex. 2 (Garrett Direct) at 7.
28
     ETI Initial Brief at 10; Cities Ex. 2 (Garrett Direct) at 8.
29
     Cities Ex. 2 (Garrett Direct) at 8-9.
30
     Id. at 10, MG-2.2; Cities Initial Brief at 10.
SOAH DOCKET N O . -                             PROPOSAL FOR DECISION                        PAGE2S
PUC DOCKET NO. 39896

$25,311,236 for the portion of the prepaid pension balance associated with CWIP, and allow
AFUDC to accrue on the excluded balance. 32

           ETI responds first by disputing Mr. Garrett's contention that it has unreasonably overpaid
into its pension fund. It contends it has made contributions to the pension fund in accordance with
contribution guidelines established by the Employee Retirement Income Security Act of 1974 and
the Internal Revenue Code of 1986, and that the contributions were within the allowable range of
contributions deductible for tax purposes. ETI also was guided in its required pension contributions
by the Pension Protection Act of 2006 rules, effective beginning with the 2008 plan year. 33

           ETI next disputes Cities' contention that the earnings associated with ETI's pension
contributions provide insufficient benefits to justify inclusion of the asset in rate base. ETI points
out that ratepayer benefits are not just limited to the level provided by the actual pension fund
earnings on investment. Rather, under FAS 87, pension costs included in the cost of service for
ratemaking purposes are intended to include the expected rate of return on assets. Thus, ETI argues
that the expected long-term rate of return on ETI' s assets is 8.5 percent, not the actual earnings as
suggested by Mr. Garrett. 34

           On behalf of ETI, Mr. Considine testified that the pension balance is no different than any
other prepayments made by the Company, which are included in rate base and earn a full return on
rate base. Furthermore, the Company would be allowed to earn a full return on rate base had the
Company invested these same dollars in Plant in Service, but the Company in this case used funds to
contribute to a still under-funded pension plan and at the same time provided a timely reduction to
formerly FAS 87 annual pension cost, thereby immediateIy benefitting ratepayers. 35 Therefore, ETI

31
  Remand ofDocket No. 33309 (Application ofAEP Texas Central Company for Authority to Change Rates),
Docket No. 38772, Order on Remand at FoF ISA (Jan. 30, 2011).
32
     Cities Initial Brief at 8-9; Cities Ex. 2 (Garret Direct) at 12.
33
     ETI Ex. 46 (Considine Rebuttal) at 22.
34   Id.
35
     Id. at 23-24.
SOAH DOCKET N O . -                          PROPOSAL FOR DECISION                            PAGE26
PUC DOCKET NO. 39896

argues it is clearly investor-supplied capital and accordingly should earn the Company's requested
return on rate base.

          ETI acknowledged the approach to this issue taken by the Commission in Docket No. 33309,
but failed to explain why it is distinguishable from the present case. 36

          The AUs conclude that the approach taken by the Commission in Docket No. 33309 was
sound and should be applied in the present case. Neither party adequately explained why the
circumstances of the present case are distinguishable.        Thus, the AUs recommend that the
CWIP-related portion of ETI' s pension asset ($25 ,311,236 out of the total asset) should be excluded
from the asset, but accrue allowance for funds used during construction.

D.        FIN 48 Tax Adjustment

          The Financial Accounting Standards Board (FASB) is the body that establishes the rules that
constitute generally accepted accounting principles (GAAP). FASB' s Interpretation No. 48 (FIN 48)
prescribes the way in which a company must analyze, quantify, and disclose the potential
consequences of tax positions that the company has taken which are legally ''uncertain." Pursuant to
FIN 48, ETI and its independent auditors are required to evaluate each of its uncertain tax positions
to determine, under the most objective, reasonable standards, which portion of each position will
most likely ultimately have to be paid to taxing authorities if challenged by the authorities. FIN 48
requires that this portion be excluded from ADFIT for financial reporting purposes and accrue
interest and, in some cases, penalties. 37

          ETI and its auditors periodically perform the FIN 48 analysis. In so doing, they have
concluded that the Company has taken a number of uncertain tax positions that the Company expects
to lose if challenged by the IRS. ETI concluded that these uncertain tax positions result in a total of
$5,916,461 in tax dollars that the Company expects it will ultimately have to pay, with interest, to the

36
     ETI Initial Brief at 10-11.
37
     ETI Ex. 70 (Warren Rebuttal) at 9-12.
SOAH DOCKET N O . -                          PROPOSAL FOR DECISION                                  PAGE27
PUC DOCKET NO. 39896

IRS. As required by FIN 48, this amount is recorded on ETI's balance sheet as a tax liability. 38 In
other words, ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (ETI's FIN 48
Liability) in reliance upon tax positions that the Company believes will not prevail in the event the
positions are challenged, via an audit, by the IRS.

           In preparing its application in this proceeding, ETI made an accounting adjustment to its Test
Year numbers by not including the $5,916,461 in its ADFIT balance. This had the effect of reducing
the Company's Test Year deferred tax balance and, therefore, increasing its rate base. 39

           Cities witness Mark Garrrett asserted that the deduction of$5,916,461-representing ETI's
FIN 48 Liability - should be added to ETI' s AD FIT balance and thus be used to reduce the
Company's rate base. Mr. Garrett pointed out that the Commission first considered this issue in a
recent Oncor docket. 40 In that docket, the Commission decided to include FIN 48 liabilities in
ADFIT because of the low likelihood that the IRS would actually audit and review the issue. 41
Mr. Garrett testified that this is a fair result because: (1) a utility with FIN 48 liabilities might never
have its underlying uncertain tax positions audited by the IRS; and (2) even if the uncertain positions
are audited by the IRS, the utility might prevail on them. In either case, the utility would never have
to pay those tax amounts. Moreover, during the time when the uncertainty exists, the utility enjoys
the use of cost-free capital (from the deferred taxes associated with the deductions) at its disposal. 42
Thus, Mr. Garrett recommends that ETI' s AD FIT balance be increased by $5,916,461 to reinstate the
FIN 48 Liability removed by the Company.43

38
     ETI Ex. 64 (Roberts Rebuttal) at 4-7.
39
     Id. at 4.
40
  Cities Ex. 2 (Garrett Direct) at 5-7. See also Application of Oncor Electric Delivery Company LLC for
Authority to Change Rates, Docket No. 35717, Order on Reh'g (Nov. 30, 2009).
41
  Id. at 18 FOF 59 ("The IRS may not audit or reverse Oncor' s position as to the tax deductions identified as
FIN 48 deductions and moved into the FIN 48 reserve.").
42
     Cities Ex. 2 (Garrett Direct) at 5-6.
43
     Id. at 7.
SOAHDOCKETNO.-                               PROPOSAL FOR DECISION                               PAGE28
PUC DOCKET NO. 39896

          ETI witnesses Rory Roberts and James Warren stated that the $5,916,461 should not be
included in the Company's ADFIT balance. Mr. Roberts explained that, because the Company
expects to lose on its uncertain tax positions, it expects that it will ultimately have to pay $5,916,461
in taxes to the IRS, plus interest. Accordingly, Mr. Garrett testified that the amount does not
represent cost-free funds available to the Company and, as such, should not be included in the
Company's ADFIT balance. 44

          Both the Cities and ETI agree that ETI' s rate base "should reflect the actual amount of cost
free capital in the ADFIT accounts at Test Year end."45 However, ETI witness Mr. Warren testified
that the FIN 48 Liability is not cost-free capital to the Company because the best available expert
opinion in the record of this case is that ETI will "most likely" ultimately have to pay the money to
                          46
the IRS, with interest.

          Moreover, Mr. Warren pointed out that, beginning with 2010 tax returns, a corporate
taxpayer is required to complete and file a Schedule UTP, on which the taxpayer must specifically
identify and describe its FIN 48 positions. Mr. Warren contended that, because ETI must now
annually file a Schedule UTP, it is more likely that the IRS will audit the Company, thereby forcing
it to pay the FIN 48 Liabilities, with interest. 47 This constitutes additional support for the notion that
the FIN 48 Liability is not cost-free capital for the Company. Mr.Warren correctly points out that, in
a recent CenterPoint Energy Houston Electric, LLC, (CenterPoint) rate case, the Commission
specifically acknowledged that filing of a Schedule UTP makes it more likely that a company will be
audited. In that case, the ALJs recommended that CenterPoint's FIN 48 Liability, totaling some
$164 million, be added to CenterPoint's ADFIT, thereby reducing its rate base. The Commission
adopted the recommendation. However, in light of its conclusion that the filing of a Schedule UTP
increases the likelihood of an audit, the Commission authorized CenterPoint to establish a deferred
tax account rider to enable it to recover any portion of its FIN 48 Liability that it might ultimately be

44
     ETI Ex. 64 (Roberts Rebuttal) at 7.
45
     Cities Ex. 2 (Garrett Direct) at 6; see also ETI Ex. 70 (Warren Rebuttal) at 6-7.
46
     ETI Ex. 70 (Warren Rebuttal) at 17.
47
     Id. at 14, 20-21.
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PUC DOCKET NO. 39896

forced to pay to the IRS, plus interest. 48 ETI does not necessarily oppose the use of a rider in this
case, but contends that it would be preferable to simply exclude ETI' s FIN 48 Liability from its
ADFIT balance, thereby increasing its rate base. 49

          In the alternative that the Commission rejects ETI' s request to exclude the full amount of the
FIN 48 Liability from the Company's AD FIT balance, ETI contends that at least any amount of cash
deposit the Company has made with the IRS that is attributable to the FIN 48 Liability should be
removed from the Company's ADFIT balance.so The Cities' witness, Mr. Garrett, agrees.st Staff
also agrees, arguing that ETI should be required to increase its ADFIT balance by the amount of its
FIN 48 Liability less the amount of any cash deposit attributable to the liability that ETI has made
with the IRS.s2 ETihas made a cash deposit with the IRS in the amount of$1,294,683. This amount
is associated with the Company's FIN 48 Liability.s3

          Consistent with prior Commission precedent from the Oncor and CenterPoint proceedings,
the AUs conclude that ETI' s FIN 48 Liability should be included in the Company's ADFIT balance.
There is, however, one caveat to this conclusion. The amount of the cash deposit made by ETI to the
IRS which is attributable to the Company's FIN 48 Liability should not be included in the ADFIT
balance. Therefore, the ALls recommend that the Commission find that $4,621,778 (representing
ETI's full FIN 48 Liability of $5,916,461 less the $1,294,683 cash deposit ETI has made with the
IRS) should be added to ETI' s ADFIT and thus be used to reduce ETI' s rate base. No party
expressly advocated the addition of a deferred tax account rider,s 4 and the AUs do not recommend
one in this case.

48
  ETI Ex. 70 (Warren Rebuttal) at 19-20. See also Application of CenterPoint Electric Delivery Company,
LLC, for Authority to Change Rates, Docket No. 38339, Order on Reh' g at 3-4 (June 23, 2011).
49
     ETI Initial Brief at 13; ETI Ex. 70 (Warren Rebuttal) at 20.
50
     ETI Ex. 64 (Roberts Rebuttal) at 8-9.
51
     Cities Ex. 2 (Garrett Direct) at 7 n. 4.
52
     Staffs Initial Brief at 11-12.
53
     ETI Ex. 64 (Roberts Rebuttal) at 8.
54
     Cities and Staff both point out that there is much less need for a deferred tax account rider in the present
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PUC DOCKET NO. 39896

E.        Cash Working Capital

          Rate base includes a reasonable allowance for cash working capital. Cash working capital
represents the average amount of investor capital used to bridge the gap in time between when
expenditures are made by ETI to provide services and when the corresponding revenues are received
by ETI. 55 Generally, an increase in revenue lag days and/or a decrease in expense lead days will
result in an increase to the amount of cash working capital included in the rate base. Conversely, a
decrease in revenue lag days and/or an increase in expense lead days will reduce the cash working
capital included in rate base. A properly prepared lead-lag study can result in either a positive cash
working capital amount (and therefore an increase to the rate base) or a negative cash working capital
amount (and a corresponding decrease to the rate base).

          Pursuant to P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), ETicalculated its cash working capital
allowance by performing a lead-lag study. ETI witness Jay Joyce prepared the lead-lag study for the
Company. Based upon the study, ETI requests a cash working capital addition to its rate base of
negative $2,013,921. 56

          Only Staff and Cities submitted evidence and argument relevant to the cash working capital
requirement.       Staff does not challenge the accuracy of the lead and lag days determined in
Mr. Joyce's study. Instead, Staff witness Anna Givens recommends that the cash working capital
calculation be updated to reflect the impacts of Staffs recommended adjustments to ETI's O&M
costs and taxes. 57 ETI agrees that the final cash working capital amount should be updated to reflect
the actual revenue requirements approved by the Commission in this case. 58

case than there was in the CenterPoint case, where CenterPoint had $164 million in FIN 48 liabilities. Cities
Reply Brief at 18; Staff Reply Brief at l 0.
55
     ETI Ex. 17 (Joyce Direct) at 4.
56
     Id. at 20 and JJJ-3.
57
     Staff Ex. l (Givens Direct) at 30-31.
58
     ETI Ex. 54 (Joyce Rebuttal) at 37; ETI Initial Brief at 14.
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PUC DOCKET NO. 39896

          Cities witness Jacob Pous asserts that Mr. Joyce's lead-lag study contains a number of errors
which understate the negative cash working capital requirements of the Company. Mr. Pous asserts
that the correct cash working capital amount for inclusion in ETI' s rate base is negative $24,000,000
(more than an order of magnitude increase of the negative amount). 59 Each of the major components
of the lead-lag study, and Cities' criticisms of same, will be discussed in tum.

           1. The Revenue Lag Component of the Lead-Lag Study

           Mr. Pous raises a number of criticisms about the revenue lag component of Mr. Joyce's lead
lag study. There are four parts to the revenue lag component: (1) the "service period lag," which
consists of the roughly 15 days from the mid-point of the month in which service is provided to the
end of that month; (2) the "billing lag," which represents the time between the date a customer's
meter is read and the date a bill is issued to the customer; (3) the "collection lag," which represents
the time between the issuance of the bill and the date the customer's payment is received; and
(4) "receipt of funds lag," which measures the delay between ETI's receipt of payment and the
bank's clearance of the payment. 60 When the four parts were combined together, Mr. Joyce
identified ETI's revenue lag as 43.86 days. 61

                       (a) Billing Lag

           Mr. Joyce identified the billing lags (i.e., the delay between when meters are read and bills
are sent to customers) as ranging from 5.4 to 5.65 days, depending upon the customer class. 62 On
behalf of the Cities, Mr. Pous asserted that this duration is too long. Mr. Pous complained that the
billing lag in ETI's lead-lag study is longer than in studies from previous ratemaking proceedings
involving ETI' s predecessor, despite the fact that, in the interim between studies, ETI has invested
substantially in electronic meter reading devices and computer systems that ought to shorten the lag
time. According to Mr. Pous, in a previous proceeding, ETI' s predecessor identified its billing lag as

59
     Cities Ex. 5 (Pous Direct) at 72.
60
     ETI Ex. 17 (Joyce Direct) at 8-10.
61
     Id. at JJJ-3.
62
     Cities Ex. 5 (Pous Direct) at 74.
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PUC DOCKET NO. 39896

only 3 .61 days. 63 Mr. Pous also pointed out that the Railroad Commission of Texas (RRC), recently
adopted a 1-day billing lag for a large gas utility, Atmos Mid-Tex, due to the utility's use of modem
electronic meter reading devices (the Atmos Mid-Tex RRC proceeding). Mr. Pous stated that the
billing lag identified by ETI would oojustly reward the Company for being inefficient in sending out
its bills because customers should not be pooished if the utility decides to manage its billing
processing and payment system less efficiently. Thus, Mr. Pous recommended a schedule of
different billing lags for different customer classes. For residential and commercial customers,
Mr. Pous recommended a 1.46 day billing lag, based since ETI' s predecessor claimed such a lag in a
prior PUC docket (Docket No. 12852). For large industrial, public authority, and street lighting
customers, Mr. Pous recommends a billing lag of 3.72 days. He calculated that the combined impact
of these adjustments would result in a 41.10-day total revenue lag (as compared to Mr. Joyce's figure
of 43.86 days). Mr. Pous then calculates that this shorter lag period results in an additional negative
cash working capital of $11.4 million. 64

           ETI responds by pointing out that the 1.46-day billing lag suggested by Mr. Pous for
residential and commercial customers was derived from a rate case by ETI' s predecessor from 1993,
whereas Mr. Joyce more properly relied on actual Test Year data. Mr. Joyce asserted that Mr. Pous,
in effect, "cherry picked" the 1.46-day figure from one page of a 4 7-page study associated with the
1993 rate case, and that the remaining pages of the study have not been located and, therefore, cannot
be evaluated. Thus, Mr. Joyce testified, "[i]t is unfair and unreasonable to use such an old document
to attempt to support a position when reasonable, contemporaneous evidence exists."65

           ETI argues that it is more appropriate in this case to rely upon ETI's actual residential and
commercial billing practices, rather than to substitute artificial and arbitrary 1.46-day and 3.72-day
periods derived from other sources. According to Mr. Joyce, it is unavoidably necessary, when
conducting a lead-lag study, to take into account the actual amount of time employed by ETI in
performing all of the activities in its billing-cycle-based meter reading and billing processes.

63   Id.
64
     Id. at 75-77.
65
     ETI Ex. 54 (Joyce Rebuttal) at 11.
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PUC DOCKET NO. 39896

Mr. Joyce complains that Mr. Pous' approach would jettison this actual data and analysis derived
from the Test Year and improperly substitute arbitrary numbers based upon a prior, dated, rate
proceeding. 66

           Mr. Joyce acknowledged that the RRC recently adopted a 1-day billing lag in the Atmos
Mid-Tex RRC proceeding. He pointed out, however, that the RRC did so simply because Atmos
Mid-Tex failed to present evidence supporting a longer billing lag. Additionally, Mr. Joyce pointed
out that the RRC promptly reversed itself in Atmos Mid-Tex's next rate case, adopting a longer
billing lag after the company provided sufficient evidence to support the longer period. 67

           ETI also provided extensive evidence regarding the details of its meter reading and billing
process. 68 ETI witness Dolores Stokes explained that the meter reading and billing cycle includes
time for extensive quality assurance activities to ensure accurate billing, thereby preventing
unnecessary frustration for the customer and additional costs to the Company that would be required
for customer service, rebilling, and account corrections. 69

           Cities questioned Mr. Joyce at the hearing about the billing lag period in this case compared
to ETI' s last rate case. Mr. Joyce explained that the total period from meter reading to collection of
billing revenues had not changed appreciably between the two cases, but due to a difference in lead-
lag methodology, the date that divides the two components of that lag - metering to billing and
billing to collection       had changed. 70 As a result, the first period - billing lag- was longer than in
the previous case but the second period - collection lag - was shorter.71 ETI introduced into
evidence a response to a Cities RFI that discussed this difference in more detail. 72 After explaining

66
     Id. at 5-7.
67
     Id.at 8-9.
68
     ETI Ex. 54 (Joyce Rebuttal); ETI Ex. 66 (Stokes Rebuttal).
69
     ETI Ex. 66 (Stokes Rebuttal) at 18.
70
     Tr. at 499-500, 502.
71
     Tr. at 499-502.
72
     ETI Ex. 73.
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PUC DOCKET NO. 39896

the change in lead-lag methodology, the RFI response concluded that "the combined billing and
collection lags are substantially similar from the prior case to this current case."73

          The AU s conclude that ETI has met its burden to show that the billing lag it utilized in the
lead-lag study is reasonable and appropriate.       Absent his own opinion, Mr. Pous does not offer
meaningful evidence to support his assertion that the Company's billing lag is too long or that the
Company's billing practices are inefficient. For example, he offered no criticism of any specific
billing practice of the Company. The only support for his charge of inefficiency is that the billing lag
in a previous ETI rate case was shorter. Mr. Joyce convincingly explained that this was merely an
artifact of changes in the methodology of the lead-lag study-the billing lag became longer, but the
collection lag became shorter.

          Mr. Pous' reliance upon an example from the RRC is unconvincing. Similarly, his reliance
upon data from a previous rate case is unpersuasive, especially because only a very limited snippet of
data from that case is available, the case occurred roughly 20 years ago, and it involved a different
company. It is not possible, from the evidence in the record, to know how different or similar ETI' s
current billing practices are to those used in the previous case.

          In this case, ETI has thoroughly explained its metering and billing processes and established
that those processes are reasonable. The Company is therefore entitled to establish rates based on the
actual cash working capital necessary to facilitate those policies. The AI.Js recommend rejecting
Cities' request to shorten the billing lag time identified in ETI's lead-lag study

                        (b) Collection Lag

          In his lead-lag study, Mr. Joyce identified various collection lags (i.e., the delay between the
issuance of an electric bill and the date the customer's payment is received) for different classes of
customers. As to third-party customers, the collection lag was determined using a random sample of
invoices from residential, commercial, industrial, public authority, and street light customer billings

73
     ETI Ex. 73 at 2.
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PUC DOCKET NO. 39896

during the Test Year, measuring the time between when the bills were mailed and the payment
receipt date. The collection lag for MSS-4 and Intra-System Bill (ISB) revenues was based on the
                                                                74
actual payment dates for each of the affiliate revenue types.

               >     Collection Lag for Residential Customers

          As to the residential class, Mr. Joyce determined that the collection lag was 23.73 days. On
behalf of the Cities, Mr. Pous disputed the accuracy of that estimate, complaining that it is
substantially longer than the lag identified for commercial customers. Mr. Pous contended that
Mr. Joyce determined the collection lag for residential customers by relying on a sample size that
was too small. Mr. Pous examined the month-end accounts receivable data for ETI's entire
residential class for the entire Test Year, and concluded that the collection lag for the class is actually
22.07 days (as compared to Mr. Joyce's figure of 23.73 days). Mr. Pous then calculated that this
                                                                                               75
shorter lag period results in an additional negative cash working capital of $2.4 million.

          Mr. Joyce made several points in response. First, he noted that, although Mr. Pous is
advocating reliance upon month-end accounts receivable data to calculate the collection lag in this
case, he has testified in another proceeding that such data is unusable and unreliable. For example,
in the Atmos Mid-Tex RRC proceeding, Mr. Pous argued in favor of measuring actual bill payment
practices of actual customers (i.e., the approach taken by Mr. Joyce in the present case) and against
analyzing the monthly accounts receivable balances for each month of the Test Year (i.e., the
approach now being advocated for by Mr. Pous). 76 Next, Mr. Joyce disputed Mr. Pous' assertion that
the sample size used by Mr. Joyce was too limited. According to Mr. Joyce, his sample of 100
residential customers is comparable to all of the residential collection lag calculations he has
performed during his 15 years of performing lead-lag studies. 77 Mr. Joyce also accused Mr. Pous of

74
     ETI Ex. 17 (Joyce Direct) at 10.
75
     Cities Ex. 5 (Pous Direct) at 77-79.
76
     ETI Ex. 54 (Joyce Rebuttal) at 13-15.
77
     Id. at 15-17.
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PUC DOCKET NO. 39896

inexplicably picking out a few data points, rather than relying upon the entirety of the sampling data,
in order to derive his collection lag estimate.78

           The AU s are unpersuaded by Mr. Pous' criticisms and conclude that ETI has met its burden
to show that the collection lag it utilized in the lead-lag study for residential customers is reasonable
and appropriate.

                  };>   Collection Uig for MSS-4 and ISB Affiliate Rate Classes

           As to MSS-4 and ISB rate classes, Mr. Joyce determined that the collection lags were 46.19
and 15.61 days, respectively. 79 Mr. Pous again disputed the accuracy of these estimates. Mr. Pous
pointed out that the underlying data reveals that the majority of the MSS-4 revenue lag days range
from 43 to 46 days, with only two values equaling or exceeding 50 days. Mr. Pous testified that the
two values equaling or exceeding 50 days should be deemed unrepresentative and, therefore,
excluded from the calculations for determining the average lag. Similarly, the majority of ISB
revenue lag days range from 15 to 16 days, with only a few lags running as long as 22 days. Again,
Mr. Pous contended that the longer revenue lag days should be deemed unrepresentative and
excluded from the calculations for the average. Mr. Pous also complained that the payment
deadlines for these affiliate transactions are stipulated in the Entergy System Agreement. Thus, it is
Mr. Pous' opinion that ETI unreasonably contractually agreed to "excessively long" revenue lag days
associated with the MSS-4 and ISB rate classes. Mr. Pous concluded that if what he considers to be
the unrepresentative lag days are excluded from the calculations, then the collection lag would
change for the MSS-4 class from 46.19 days to 45.14 days, and for the ISB class from 15.61 days to
14.77 days. Collectively, the lag for the two classes would be .77 days shorter, resulting in an
additional negative cash working capital of $3. 2 million. 80

78
     Id. at 17.
79
     Id. at 18.
° Cities Ex. 5 (Pous Direct) at 79-81; ETI Ex. 54 (Joyce Rebuttal) at 18.
8
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PUC DOCKET NO. 39896

          Mr. Joyce first responded by disputing Mr. Pous' contention that there are unusual outliers in
the MSS-4 and ISB payment data. He noted that the lag days for MSS-4 payments ranged from 43 to
54 days. He described this as a "relatively tight payment range and certainly within the expected
range of reasonableness." 81 Next, Mr. Joyce described Mr. Pous' assertion that outlier numbers
should not be considered in the data as nonsensical. Mr. Joyce agreed that, in cases where sampling
is used (such as was done for the residential customer class), it is appropriate to exclude data points
that are unrepresentative of the population as a whole. In the case of the MSS-4 and ISB classes,
however, Mr. Joyce determined the collection lag by reviewing the entire class populations.
According to Mr. Joyce, it is inappropriate to eliminate data points when reviewing an entire
population, unless it is necessary to make a known and measurable change. 82

          The AUs are again unpersuaded by Mr. Pous' criticisms. The AUs conclude that ETI has
met its burden as to show that the collection lag it utilized in the lead-lag study is reasonable and
appropriate.

                      (c) Receipt of Funds Lag

          In the lead-lag study, Mr. Joyce identified the receipt of funds lag (i.e., the delay between the
date the funds are received from the customers and the date the funds clear the bank and are available
toETI). As required byP.U.C. SUBST. R. 25.23l(c)(2)(B)(iii)(IV)(-d-), Mr.Joyce assumed that one
business day is needed to clear any payments by methods other than electronic transfer, while
electronic payments are available to ETI on the date received. Because 53.39 percent of customer
payments were made by methods other than electronic transfer, Mr. Joyce calculated the receipt of
funds lag to be .77 days. 83

          Mr. Pous again contended that this duration is too long.          He acknowledges that P.U.C.
SUBST. R. 25.231(c)(2)(B)(iii)(N)(-d-) mandates the assumption that funds paid by check will be

81
     ETI Ex. 54 (Joyce Rebuttal) at 19.
82
     /d.atl9.
83
   ETI Ex. 17 (Joyce Direct) at l 0. The receipt of funds lag is also sometimes referred to by the witnesses as
the "cash receipts float."
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PUC DOCKET NO. 39896

available "no later than" the following business day. However, he stated that this is merely the
maximum possible duration, and ETI should take into account that fact that many checks are cleared
(and therefore the funds are available) sooner than one day later. Therefore, the funds from all
checks received on any day other than Saturday should be assumed to be available on the date of
receipt, while the funds from checks received on Saturday should be assumed to be available two
days later. Mr. Pous was also critical of the fact that Mr. Joyce treated the funds from all "walk-in"
payments made by customers to be available the next day. Funds from walk-in payments ought to be
deemed available on the date they are received. If these two changes are adopted, Mr. Pous
contended that receipt of funds lag would be shortened from .77 days to .15 days, resulting in an
additional negative cash working capital of $2.1 million. 84

          Mr. Joyce first responded by pointing out that Mr. Pous' contention that all funds are
immediately available except for checks received on Saturdays is simply not accurate. Mr. Joyce
cited from a 2007 Report to Congress made by the Board of Governors of the Federal Reserve
System which supports the conclusion that most funds paid by check in this country are not available
on the day they are received (and a significant portion are still not available the next business day). 85
Mr. Joyce also disagreed with Mr. Pons' contention that all walk-in payments should be considered
immediately available. According to Mr. Joyce, walk-in payments are made at third-party vendor
locations, such as grocery stores and check-cashing stores. Based upon his own investigation,
Mr. Joyce determined that walk-in payments are actually available to ETI two days after receipt.
Thus, his one-day assumption for walk-in payments is conservative. 86

          The AU s conclude that ETI has met its burden as to show that the receipt of funds lag it
utilized in the lead-lag study is reasonable and appropriate. The positions taken by Mr. Pons on this
issue      were    unreasonable      and     counter    to    the    requirements   of   P.U.C.    SUBST.
R. 25.231(c)(2)(B)(iii)(IV)(-d-).

84
     Cities Ex. 5 (Pous Direct) at 81-82; Cities Ex. 5A (Errata No. l).
85
     ETI Ex. 54 (Joyce Rebuttal) at 21-23.
86
     ETI Ex. 54 (Joyce Rebuttal) at 23-24.
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PUC DOCKET NO. 39896

          2. The Expense Lead Component of the Lead-Lag Study

          For the expense lead portion of his lead-lag study, Mr. Joyce calculated different expense
lead days for numerous different categories of expenses. Each category will be discussed in tum.

                       (a) Expense Lead - Operations and Maintenance Expense

          Mr. Joyce separated O&M expenses into two groups - energy costs and "other O&M"
expenses. Each of those two groups was further divided into subgroups. 87

               ~   Energy Costs

          Fuel. Mr. Joyce explains that, during the Test Year, ETI purchased two kinds of fuel: (1)
coal and oil; and (2) natural gas. He concluded that there were 44.27 expense lead days for coal and
oil, based upon the time between the service periods and payment dates or payment due dates for all
coal and oil invoices from the Test Year. As to natural gas, he determined that there were 40.63
expense lead days, based upon a comparison of the service period and payment due dates and the
payment dates from a random sample of gas invoices. 88 No party challenged this approach, and the
AI..Js find no reason to do so either.

          Purchased Power. Mr. Joyce explained that there were two components to ETI's purchased
power energy costs in the Test Year: (1) MSS-4 Purchases; and (2) Other Purchased Power
(consisting of Joint Account Purchases, MSS-3 Purchases, Reserve Equalization, Cogeneration
Purchases, Renewable Energy Credits, and Toledo Bend Purchases). Relying upon either the entire
population or a sample from the Test Year (depending upon the category), Mr. Joyce concluded that
there were 58.76 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased
Power. 89

87
     ETI Ex. 17 (Joyce Direct) at 11.
88
     Id. at 11 and JJJ-3.
89
     ETI Ex. 17 (Joyce Direct) at 12 and JJJ-3.
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PUC DOCKET NO. 39896

           No party challenged the 35.79 day estimate for Other Purchased Power. However, on behalf
of the Cities, Mr. Pous testified that the expense lead days for MSS-4 should be lengthened from
58.76 days to 60.65 days. According to Mr. Pous, Mr. Joyce made several errors in calculating the
expense lead days for MSS-4 expenses. First, Mr. Joyce inadvertently placed the service period
month after the billing month for two MSS-4 invoices. Mr. Pous based this conclusion on the fact
that the expense leads for these two invoices are roughly 30 days shorter than the "vast majority" of
the other invoices. 90 In response, Mr. Joyce denied that he erroneously placed the service period
month after the billing month, and pointed out that Mr. Pous lacks any evidence to support his
assertion. Instead, Mr. Joyce considered the entire population of MSS-4 invoices for the Test Year.
Those invoices show payment lead days ranging from 30 to 120 days, with most points being near
30, 60, or 70 payment lead days. According to Mr. Joyce, this is reasonable and well within the
range he has experienced in other rate cases. 91

           Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4
expenses by considering only the payment due dates specified in the Entergy System Agreement,
rather than also considering the actual payment dates. According to Mr. Pous, in four instances
during the Test Year, extensions were granted to ETI to allow it to make MSS-4 payments afterthe
deadline specified in the Entergy System Agreement. Therefore, Mr. Pous stated that the expense
lead days for MSS-4 payments should have been calculated using the later of the actual payment date
or the allowable payment period.92 Mr. Joyce largely agreed with Mr. Pous on this point. That is, he
agreed that the payment lead days should be based on the later of the paid date or the due date.
However, he disagreed with some of Mr. Pous' calculations on this issue because Mr. Pous wrongly
designated several due dates of Saturday or Sunday, when he should have selected Fridays as the due
date. 93

90
     Cities Ex. 5 (Pous Direct) at 83-84.
91
     ETI Ex. 54 (Joyce Rebuttal) at 26-28.
92
     Cities Ex. 5 (Pous Direct) at 84.
93
     ETI Ex. 54 (Joyce Rebuttal) at 28-29.
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PUC DOCKET NO. 39896

          Next, Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4
expenses by erroneously concluding that one invoice had been paid on the first of the month when, in
fact, it had been paid on the 18th of the month. 94 Mr. Joyce agreed with the change. 95 Mr. Joyce
then recalculated the expense lead days for MSS-4 and revised the number of lead days from 58.76
to 59.81. 96

          The AU s conclude that ETI has met its burden as to show that there were 59.81 expense lead
days for MSS-4, and 35.79 expense lead days for Other Purchased Power.

               »   Other O&M Expenses

          This category of expenses was broken down in the lead-lag study into four groups regular
payroll costs, incentive payroll costs, affiliate service company costs, and all other O&M costs (such
as materials, services, and so on).

          Regular Payroll Costs.          The lead days for regular payroll costs were computed by
determining the average days of service being reimbursed and adding the days between the end of
each service period and the payments to employees. This amount was then adjusted to incorporate
the effects of vacation pay based upon actual ETI data. By this method, Mr. Joyce determined the
expense lead for regular payroll costs to be 20.68 days. 97 No party challenged this approach, and the
ALls agree.

          Incentive Pay Costs. ETI has an annual employee incentive program in place. Incentive
payments for the year 2010 were made in the first quarter of 2011. The lead days for incentive pay
costs were based on the weighted days between the midpoint of the service period (i.e., July 1, 2010)
and the date the incentives were paid (March 10, 2011). By this method, Mr. Joyce determined the

94
     Cities Ex. 5 (Pous Direct) at 84.
95
     ETI Ex. 54 (Joyce Rebuttal) at 29.
96
     ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.
97
     ETI Ex. 17 (Joyce Direct) at 13 and JJJ-3.
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PUC DOCKET NO. 39896

expense lead for incentive pay costs to be 251.77 days. 98      No party challenged this approach, and
the ALl s agree.

           Affiliate Service Company Costs and Other O&M. Costs. Charges from Entergy Services, Inc.
(ESI) are paid in the month following the month in which the charges were incurred. The lead days
for affiliate service company costs were based on the number of days from the mid-month to the later
of the contractual due date or the actual settlement date in the following month. By this method, Mr.
Joyce determined the expense lead for affiliate service company costs to be 39.64 days. 99

           The lead days for other O&M costs were based on a random sampling from the Test Year.
Mr. Joyce originally determined the expense lead for other O&M costs to be 47.46 days. 100
However, to correct an error on his part, Mr. Joyce subsequently revised the expense lead time for
other O&M costs down to 43.89 days. 101

           Mr. Po us testified that ETI' s "FAS 106-related expenses" were wrongly included in either the
affiliate service company costs or the other O&M costs. FASB is the body that establishes the rules
that constitute GAAP. FASB's Statement Number 106 (FAS 106) establishes the standards for an
employer's treatment of the non-cash retirement benefits it gives its employees. Based on the action
taken by the Commission in Docket No. 16705, 102 Mr. Pous believes that ETI's FAS 106 costs
should have been separately identified and accounted for in the lead-lag study. He contended that,
when those costs are properly accounted for, it results in an additional negative cash working capital
of $3.8 million. 103

98
      Id. at 14 and JJJ-3.
99
      ETI Ex. 17 (Joyce Direct) at 15, and JJJ-3.
100
      Id.at15-17,andJJJ-3.
101
      ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.
102
   Application ofEntergy Gulf States, Inc.for Approval of Its Transition to Competition Plan and the Tariffs
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to
Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, (Oct. 13, 1998).
103
      Cities Ex. 5 (Pous Direct) at 85-88.
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PUC DOCKET NO. 39896

          Mr. Joyce contended that the prior Commission decision upon which Mr. Pous relies, Docket
No. 16705, dates from 1996, is inapplicable to the facts in the present case, is outdated, and has been
superseded by subsequent Commission decisions. Mr. Pous advocated a 312.55-day expense lead
for FAS 106 expenses. However, Mr. Joyce pointed out that, during the Test Year, ETI made its
FAS 106 payments to a trust at the end of each month, resulting in a one-half month payment lead
(15.25 days). Mr. Joyce testified that his treatment of FAS 106 expenses in his lead-lag study is
consistent with the approach that was approved by the Commission in a recent Oncor ratemaking
case, Docket No. 35717 . 104

           The AIJs conclude that ETI met its burden to show that there were 39.64 expense lead days
for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.

                       (b) Expense Lead- Current Federal Income Tax Expense

           As required by P.U.C. SUBST. R. 25.23l(c)(2)(B)(iii)(IV)(-f-), Mr. Joyce calculated the lead
days for federal income taxes by measuring the days between the midpoints of the annual calendar
year service periods and the actual dates on which ETI made its estimated quarterly tax payments.
By this method, Mr. Joyce determined the expense lead for current federal income tax costs to be
38 days. He then determined that this resulted in a $1.6 million cash working capital requirement
associated with the Company's Federal Income Tax Expenses. 105

           Mr. Pous testified that the Company's cash working capital requirement for Federal Income
Tax Expenses ought to be a negative number or, at most, zero. He bases this argument on his
assertion that, during the past five years, the Company "has received in excess of a net $90 million of
refunds" on its federal income taxes. In other words, because "refunds produce cash" for the

104
      ETI Ex. 54 (Joyce Rebuttal) at 29-32.
105
      ETIEx.17(JoyceDirect)at17,andJJJ-3.
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PUC DOCKET NO. 39896

Company, Mr. Pous contends that the Company is seeking a positive cash working capital
                                                                                             106
requirement for cash transactions "that have not been made and are not being made."

          Mr. Joyce responds by disputing Mr. Pous' contention that "refunds produce cash."
Mr. Joyce points out that any refund from the IRS merely represents a return of the Company's own
cash for payments previously made. Moreover, Mr. Joyce stresses that his approach for calculating
the expense lead for current federal income taxes is perfectly consistent with: ( 1) the requirements of
P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-); (2) current IRS guidelines found at IRS
Publication 542; and (3) Commission precedent. Mr. Joyce further points out that, by contrast,
Mr. Pous' approach has been consistently rejected by the RRC. 107            The Al.Js find Mr. Joyce's
arguments to be more persuasive on this point and conclude that ETI has met its burden as to show
that the expense lead for current federal income tax costs it utilized in the lead-lag study is
reasonable and appropriate.

          The AlJ s conclude that ETI met its burden to show that there were 39 .64 expense lead days
for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.

                       (c) Expense Lead and Lag-Taxes Other than Income Taxes

          This group of taxes consists of: (1) payroll-related taxes; (2) ad valorem taxes; (3) Texas state
gross receipts taxes; (4) the PUC assessment tax; and (5) Texas state franchise taxes. Calculating
from the midpoints of the work periods to the respective payment dates of the taxes, Mr. Joyce
determined that the payroll taxes had an expense lead time of 16.45 days. As to the franchise taxes,
Mr. Joyce concluded that the Company had a collection lag of 46.42 days because the Company was
required to pay the taxes in May 2010. As to the other non-payroll-related taxes, Mr. Joyce
calculated from the midpoint of the period for which the tax was assessed to the payment date,
resulting in the following expense lead days: 213.51 days for ad valorem taxes; 74.28 days for Texas

106
      Cities Ex. 5 (Pous Direct) at 88-89.
  7
!0    ETI Ex. 54 (Joyce Rebuttal) at 33-36, JJJ-R-1.
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PUC DOCKET NO. 39896

state gross receipts taxes; and 225.50 days for the PUC tax. 108 No party challenged this approach,
and the AU s agree.

F.        Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. S]

          In Docket Nos. 16705 and 37744, the Commission authorized ETI to maintain a reasonable
and necessary storm damage reserve account of $15,572,000. 109 As of June 30, 1996, ETI had a
positive reserve balance of $12,074,581, constituting a reduction to rate base. Over the next
15 years, ETI charged $101,670,803 to the reserve related to more thart 200 storms (excluding
securitized events), but it accrued only $29,796,478 through base rates. Thus, ETI's end-of-test-year
balance for its storm damage reserve in the present case was a negative $59,799,744. 110 This
negative balance is an addition to rate base. 111

          OPC and Cities argue that ETI's current storm damage reserve negative balance should be
adjusted. OPC contends that ETI failed to prove that its storm damage expenses booked since 1996
were reasonable and prudently incurred, so it recommends disallowing all of those charges arid
refunding to customers the resulting positive balance that exceeds the authorized balance.
Alternatively, OPC suggests that ETI's negative balartce be reset to its currently authorized balance,
with no refund to customers. Cities contend that ETI's current negative storm damage reserve
balance should be reduced because it includes: unreasonable expenditures associated with a 1997 ice
storm; expenses associated with former assets in Louisiarta; and amounts that Cities claim should
have been treated as insurance deductibles. Cities also recommend transferring ETI' s Hurricane Rita
Regulatory Asset to the storm damage reserve. The parties' recommendations are summarized as
follows:

108
      ETI Ex. 17 (Joyce Direct) at 18-19, and JJJ-3.
109
      Staff Ex. 4 (Roelse Direct) at 8.
l!O   $12,074,581 + $29,796,478-$101,670,803 = ($59,799,744).
111
      P.U.C. SUBST. R. 25.23 l(c)(2)(E).
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PUC DOCKET NO. 39896

                         Party            Reserve Balance
                         ETI              ($59 ,800,000)
                         Cities           ($34,051,597)
                         OPC-1            $41,871,059
                         OPC-2            $15,572,000

        1. The Effect of Prior Settled Cases

        As with the Hurricane Rita Regulatory Asset (Section V.B.), the effect of the black-box
settlements in Docket Nos. 34800 and 37744 is a significant issue concerning the storm damage
reserve. However, the parties' positions are generally reversed from the positions taken on the
Hurricane Rita Regulatory Asset. That is, ETI now argues that its storm reserve negative balance
was resolved and approved in those settled dockets, while Cities and OPC argue that it was not.

        ETI notes that the final orders in Docket Nos. 34800 and 37744 contained "stipulated and
agreed upon" conclusions of law stating that overall total invested capital through the end of the test
year in those cases met the requirements of PURA § 36.053( a) that electric utility rates be based on
the original cost, less depreciation, of property used by and useful to the utility in providing
service. 112 Then ETI cites language in P.U.C. SUBST. R. 25.231(c)(2)(E), which provides that any
deficit in a self-insurance plan will be considered an increase to rate base, or invested capital. As a
result, ETI argues, the Commission could not make a determination that a rate base expense item
was included in rate base as used and useful without also determining that the rate base expense was
prudently and reasonably incurred. 113 Thus, ETI asserts, a Commission conclusion of law that
approved invested capital as meeting the requirements of PURA § 36.053(a) necessarily also
determined that an expense included in rate base was prudently and reasonably incurred. In other

112
   PURA§ 36.053(a) provides: "Electric utility rates shall be based on the original cost, less depreciation, of
property used by and useful to the utility in providing service."
113
   ETI cited: City ofAlvin v. Public Util. Comm'n of Texas, 876 S.W.2d 346, 353-354 (Tex. App.-Austin,
1993, no pet.); see also Application of Gulf States Utilities Company for Authority to Change Rates, Docket
Nos. 7195 and 6755, 14 P.U.C. BULL. 1943 at 1969 (May 16, 1998) ("dishonest or obviously wasteful or
imprudent expenditures constitutionally can be excluded from a utility's rate base. Such costs clearly are not
used and useful in providing serviced to the public.").
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PUC DOCKET NO. 39896

words, ETI states, the "prudent and reasonable" standard is incorporated into the "used and useful"
standard in PURA § 36.053(a). ll 4 Therefore, ETI argues that by issuing a final orders in Docket
Nos. 34800 and 37744 with conclusions of law that ETI's overall total invested capital met the
requirements of PURA § 36.053( a), the Commission implicitly approved the negative balances of its
insurance reserve in both prior dockets; consequently, those orders preclude litigation in the present
                                                                             115
case of whether those expenses were prudently and reasonably incurred.

          Cities reject ETI' s contention that the storm damage reserve balance was approved in Docket
Nos. 34800 and 37744. Cities point out that in order to comply with PURA, all final orders in rate
cases must include a conclusion of law stating that the overall total invested capital through the end
of the test year meets the requirements of PURA§ 36.053( a). However, Cities contend, pursuant to
the parties' agreements in Docket Nos. 37744 and 34800, no determination was made as to what was
included in ETI' s total invested capital in those cases. Cities explain that in Docket Nos. 37744 and
34800 Cities claimed that certain expenses were not properly included in the storm reserve balance,
while ETI argues that they were.             However, neither Cities nor ETI's recommendation was
specifically approved as part of the base rate settlement and neither of their recommended balances
may be considered as the basis for setting rates in those dockets. 116 Thus, Cities argues, in such
"black box" settlements no specific storm reserve balance is approved unless expressly stated. Cities
also argues that the final orders in Docket Nos. 37744 and 34800 could just as logically be
interpreted as denying ETI' s request to include objectionable expenses in the storm damage reserve,
because both orders specified that the revenue requirement approved in those cases did not include
any prohibited expenses. Finally, Cities states that adoption of ETI' s arguments would make black-
box settlements impossible in the future. 117

114
     ETI cited Docket No. 7195, 14 P.U.C. BULL. at 1969 ("the prudent investment test is embodied in
traditional ratemaking principles as expressed through PURA Sections ... 41."). PURA Section 4l(a) is the
predecessor to current Section 36.053.
115
      ETI Initial Brief at 20-22; ETI Reply Brief at 17.
116
   Docket No. 37744, Final Order at Ordering Paragraph 14; Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 at Ordering Paragraph 12.
117
      Cities Reply Brief at 22-26.
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PUC DOCKET NO. 39896

          OPC makes arguments similar to Cities, and notes that no storm damage reserve amount was
either agreed to by the parties or approved by the orders in either Docket No. 34800 or Docket
No. 37744. 118

          The ALls find that the Commission did not implicitly approved all of ETI's storm damage
expenses and its storm damage reserve balances in the final orders in Docket Nos. 34800 and 37744.
Although the orders in those settled cases contained conclusions of law the that overall total invested
capital through the end of the test year met the requirements of PURA § 36.053(a), the orders made
no findings of what the total invested capital included, and specifically there were no findings or
conclusions approving the amount of the storm damage reserve. As pointed out by Cities, in those
dockets the intervenors disputed various items in ETI' s requested storm damage reserve, but the
"black box" settlement did not specifically address those issues; consequently, it is as logical to
conclude that objectionable expenses were excluded from the storm damage reserve and from the
total invested capital as it is to conclude that the objectionable expenses were included. In
Section V .B., the ALl s conclude that ETI' s Hurricane Rita regulatory asset should be considered as
being   inclu~ed   in the black-box settlement and final order in Docket No. 37744, even though the
settlement and order did not expressly state how the Hurricane Rita regulatory asset issue was
resolved. However, that issue involved unique circumstances and is distinguishable because PURA
§ 39.459(c) required the Commission to consider the insurance payments for the Hurricane Rita
restoration expenses in ETI' s next rate case, which was Docket No. 37744; ETI requested a true-up
in that docket of the insurance proceeds it received concerning the regulatory asset; and no party
objected to ETI' s proposed regulatory asset or its proposed amortization. In contrast, intervenors in
Docket Nos. 34800 and 37744 did object to ETI' s proposed storm damage reserve and, under those
circumstances, it is not possible to determine how the issues concerning the storm damage reserve
were resolved by the black-box settlement. Therefore, the ALl s find that the black-box settlements
and final orders in Docket Nos. 34800 and 37744 neither approved nor disapproved the
reasonableness and necessity of ETI' s storm damage expenses incurred since 1996 or ETI' s current
storm damage reserve negative balance.

118
      OPC Reply Brief at 7-8.
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PUC DOCKET NO. 39896

          2. OPC's Proposed Adjustment

          OPC witness Nathan Benedict testified that ETI failed to prove that any of its $101,670,803
in storm damage expense booked since 1996 was prudently incurred, so he recommended
disallowing all of those charges and refunding to customers the resulting positive balance that
exceeds the authorized balance. Removing those charges would leave ETI with a current positive
storm reserve balance of $41,871,059 (beginning balance of $12,074,581 + accruals of $29,796,478).
This balance exceeds the currently approved storm reserve balance of $15,572,000 by $26,299,059,
and Mr. Benedict proposed that this surplus be refunded to rate payers at a rate of $1,314,953 per
year for 20 years. Mr. Benedict acknowledged that some storm damage expenses incurred by ETI
since 1996 likely were reasonable and necessary. Therefore, as an alternative proposal, Mr. Benedict
suggested that ETI' s current storm balance reserve be set at the last approved amount of $15,572,000
(i.e., without any surplus or deficit). This proposal would result in a $75,363,744 reduction to ETI's
current storm damage reserve negative balance and rate base. 119

          As discussed above, OPC disagrees with ETI's argument that the Commission implicitly
approved these expenses in the final orders in Docket Nos. 34800 and 37744. 120 Therefore, OPC
argues that ETI had to prove in the present case that the expenses were prudently incurred.
Concerning ETI's burden of proof, OPC acknowledges that, although a utility has the ultimate
burden to prove that its proposed rates are just and reasonable, once the utility establishes a prima
f acie case of prudence of a rate change, the burden shifts to the other parties to produce evidence to
rebut that presumption. Then, if the other parties rebut the presumption, the burden shifts back to the
utility to prove by a preponderance of the evidence that the challenged expenditures were prudent.
However, OPC notes, if the utility fails to establish a prima facie case, the burden of going forward
with evidence never shifts to the other parties. 121 In OPC's opinion, ETI never established a prima
facie case because ETI' s spreadsheet of storm damage expenses was excluded from evidence and

119
      OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 19.
120
      OPC Reply Brief at 7-8.
121
  OPC Reply Brief at 2-3, citing, Entergy Gulf States, Inc. v. Public Utility Comm'n, 112 S.W.3d 208 (Tex.
App. - 2003, pet. denied).
SOAHDOCKET N O . -                          PROPOSAL FOR DECISION                                  PAGE SO
PUC DOCKET NO. 39896

ETI witness Greg Wilson acknowledged on cross examination that he made no analysis of whether
ETI' s storm damage costs were reasonable and necessary. 122

          ETI complains that Mr. Benedict simply sought a global rejection of more than $100 million
of expenses without any evidence to support his position, and it stressed that even Mr. Benedict
acknowledged that some of ETI' s expenses were prudently incurred. ETI also states that, in any
event, it met its burden of proof with regard to expenses booked to the storm damage reserve.

          Concerning its proof, ETI states that its burden was to make a prima facie case supporting the
prudence of its invested capital, 123 and once it made that showing, the burden shifted to the opposing
parties to overcome the presumption of prudence by presenting evidence that reasonably challenged
the expenditures. 124 This is the same position as OPC. ETI argues that it met its burden to prove a
                    125
primafacie case.          ETI notes that it provided storm cost data accompanied by narrative testimony
that supported the reasonableness of ETI's self-insurance plan; storm preparedness and response;
service quality; and cost of labor, materials, and services used to carry out distribution activities
(including system restoration). For instance, ETI states, it presented its proposed storm reserve
balance through the direct testimony of Mr. Greg Wilson 126 and in the Commission's rate filing
package. 127 Mr. Wilson also explained the function of ETI' s self-insurance program, described the
$50,000 threshold to exclude minor weather events, and provided work papers detailing the nominal
and trended losses for each storm booked to the reserve since 1986, as well as annual and total loss
levels. 128

122
      OPC Reply Brief at 1-5.
123
   ETI Initial Brief at 22, citing, Application of Texas Utilities Electric Company for Authority to Change
Rates, Docket No. 9300, 17 P.U.C. BULL. 2057, 2148, Order on Rehearing (Sept. 27, 1991).
124
      Docket No. 9300, 17 P.U.C. BULL. at 2148.
125
     Although ETI contended that the storm damage reserve has been approved in prior dockets, it argued that
its evidence also supported storm damage charges going back to July l, 1996. ETI Initial Brief at 23, n. 147.
126
      ETI Ex. 14 (Wilson Direct) at 11.
127
      ETI Ex. 3 (Schedules) at Schedule B-1, line 7; Schedule WP_B-1, page 7.
128
      ETI Ex. 14 (Wilson Direct) at 5-7; WP GSW-3_1.
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PUC DOCKET NO. 39896

            Further, ETI witness Shawn Corkran presented testimony regarding subject matters that
directly support the ability of the system to withstand storms, and ETI's ability to reasonably and
efficiently respond to storm events, thereby supporting the conclusion that reasonable and necessary
costs are booked to the storm reserve balance. This evidence included ETI' s distribution operations,
industry-recognized comprehensive storm plans, annual storm drills, storm response and restoration
processes, distribution maintenance and asset improvement processes, service quality and continuous
improvement programs, and vegetation management practices. ETI points out that Mr. Corkran also
described how it prepares for emergency situations, 129 and Mr. Corkran explained how charges to the
storm reserve are captured and recorded. 130 Mr. Corkran also noted that ETI has received either the
Edison Electric Institute' s Emergency Assistance Award or Emergency Response Award every year
since 1998, which recognize ETI' s exemplary storm restoration response. 131 Likewise, Mr. Corkran
discussed ETI' s reliability statistics since 2000, which demonstrated a high quality of service, 132 and
he provided four exhibits demonstrating that, on both per-kilowatt-hour (kWh) and per-customer
bases, ETI' s distribution O&M costs compared favorably to the costs of other utilities. 133 In ETI' s
opinion, because it carried out its distribution activities in the same efficient and cost-effective
manner while performing routine activities as during storm restoration, those metrics and reliability
statistics support the reasonableness of costs booked to the reserve. 134

           ETI also argues that it supported the reasonableness of the costs booked to its storm reserve
through the direct testimony of its supply chain witness, Mr. Joseph Hunter. Mr. Hunter explained
that ETI' s procurement policies and procedures are designed to streamline the acquisition of
materials and services through the use of strategic supply networks in order to achieve the lowest

129
      Id. at 28.
130
      Id. at 93.
131
      Id. at 29.
132
      Id. at 12-29.
133
      Id., Exhibits SBC-2A, SBC-2B, SBC-2C, and SBC-20.
134
      ETI Initial Brief at 22-24.
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PUC DOCKET NO. 39896

reasonable cost. 135 Mr. Hunter also described how the centralization of the supply chain function on
a system-wide basis provides greater leverage and buying power in the procurement of materials and,
                                                              136
thus, lower costs than could be achieved by ETI alone.              Furthermore, Mr. Hunter specifically noted
that the standardization of supply chain activities "makes possible a smoother day-to-day operation
                                                                       137
as well as rapid response to major storms or emergencies."

          Finally, ETI stated that it provided an extensive amount of storm reserve data through the
discovery process, which provided a basis for any interested party to investigate the reasonableness
of any particular storm response or expenditure booked to the reserve. It stressed that OPC witness
Benedict acknowledged that ETI provided 420 pages and over 22,220 lines of detail reflecting every
charge to the storm reserve over the last 15years, 138 which specified the month, year, state, project
code, work order type, function, storm name, account number, resource code, resource code
description, and amount. 139 Therefore, ETI argues that it made a primafacie case regarding its storm
reserve through the presentation of narrative testimony, schedules, work papers, and expense detail
and, accordingly, the burden shifted to parties seeking to disallow the expenses allocated to the storm
damage reserve to present evidence that reasonably challenges their prudence. 140 Yet, ETI contends,
OPC did not challenge any specific expenditure booked to the reserve other than the 1997 ice storm
expenses discussed later. Therefore, ETI argues that it met its prima facie burden and OPC's
                                                                                            141
proposed disallowance of either $101,670,803 or $75,363,744 should be denied.

          Although it is a close call, the ALls find thatETI established aprimafaciecasethat its storm
damage expenses incurred since June 30, 1996, were prudently incurred. A prima facie case is a low
burden. It is not the same as a preponderance of the evidence. Rather, as stated in Town of Fairveiw

135
  ETI Ex. 16 (Hunter Direct) at 5, 9-10, and Exhibits JMH-l(Entergy Companies' Procurement Policy) and
JMH-3 (Entergy Companies' Approval Authority Policy).
136
      ETI Ex. 16 (Hunter Direct) at 17.
137
      Id. at 18 (emphasis added).
138
      Tr. at 1703.
139
      Tr. at 1704.
140
      Docket No. 9300, 17 P.U.C. BULL. at 2147.
141
      ETI Initial Brief at 22-26; ETI Reply Brief at 16-19.
SOAHDOCKETNO.-                                PROPOSAL FOR DECISION                            PAGE53
PUC DOCKET NO. 39896

v. City ofMcKinney, prima facie evidence "is merely that which suffices for the proof of a particular
fact until contradicted and overcome by other evidence." 142 Similarly, Black's Law Dictionary
defines a prima facie case as sufficient evidence "to allow the fact-trier to infer the fact at issue and
rule in the party's favor." 143

          Except for expenses incurred with the 1997 ice storm, ETI did not present any testimony that
explicitly stated that the expenses included in its storm damage reserve were prudently incurred.
However, ETI did present sufficient other evidence that at least allows the ALJs to infer that the
expenses were prudently incurred. As noted above, a reasonable inference from the evidence
presented is sufficient to establish a prima facie case. ETI witness Gregory Wilson presented
testimony about the background of the storm damage reserve and about ETI' s yearly major storm
damage losses, although OPC is correct that he did not explicitly evaluate or determine whether
ETI' s expenses were reasonable and necessary. 144 In addition, OPC witness Benedict provided
testimony that ETI has booked $101,670,908 to the storm damage reserve since 1996, 145 and that
ETI' s $50,000 threshold is a means of excluding from the reserve small storm-related expenses that
ETI could anticipate as routine O&M expense and which should be excluded from the storm damage
reserve. 146 ETI presented testimony that it had not recorded storm damage expense to both the storm
damage reserve and to O&M expense, 147 and Mr. Benedict agreed that he had no information to
                     148
contradict this            or that any securitized costs were charged to the storm damage reserve. 149
Although the document itself was excluded from evidence, Mr. Benedict testified that ETI provided
him with a 420-page spreadsheet covering all of ETI's storm damage expenses back to 1996,
including the month, year, state, project code, project name, work order type, function, storm name,

142
      271 S.W.3d 461, 467 (Tex. App.       Dallas 2008 pet. denied).
143
      Black's Law Dictionary, 8th Ed. (2004).
144
      ETI Ex. 14 (Wilson Direct) at Ex. GSW-3.
145
      OPC Ex. 6 (Benedict Direct) at 7-8.
146
      Tr. at 1694.
147
      ETI Ex. 72 (Wilson Rebuttal) at 2-3.
148
      Tr. at 1695-1696.
149
      Tr. at 1698.
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PUC DOCKET NO. 39896

account number, resource code, resource code description, and amount. 150 In addition, ETI provided
other testimony described previously concerning its distribution operations, storm plans, storm
response operations, purchasing procedures, and the like.

          ETI did not present a witness who specifically testified that all of its storm damage expenses
booked to the storm damage reserve were prudently incurred, except for expenses related to the 1997
ice storm. Such testimony would have been more helpful than the evidence ETI relied upon.
Nevertheless, the burden of establishing a primafacie case does not require such direct testimony, if
a fact can be reasonably inferred from other evidence presented. The AU s reiterate that it is a close
call, but they find that ETI did present sufficient evidence to infer that the expenses charged to the
storm damage reserve were prudently incurred. At that point, the burden shifted to OPC to produce
evidence to challenge specific expense items included in the storm damage reserve, but OPC did not
present any such evidence except for the items discussed below. Therefore, the AUs recommend
that the Commission not adopt either of 0 PC's recommended denials of expenses contained in ETI' s
storm damage reserve.

          3.   1997 Ice Storm

          ETI's proposed negative storm reserve balance includes $13,014,379 in expenditures
associated with a 1997 ice storm. Cities and OPC contend that this expense should be excluded from
the storm balance reserve.

          Cities witness Pous explained that ETI first requested to include the 1997 ice storm expense
in the storm damage reserve as a post test year adjustment in its 1995-1996 test-year rate case,
Docket No. 16705. The Commission denied the requested post test year adjustment and stated that
the expense should be considered in ETI's next rate case. Thereafter, ETI had a series of rate cases
(Docket No. 20150       1998 rate case; Docket No. 30123 -2004 rate case; Docket No. 34800-2007
rate case; Docket No. 37744-2009 rate case) in which intervenors challenged the 1997 ice storm
expenses, but those cases all settled or were otherwise concluded without any express decision

150
      Tr. at 1704.
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concerning the prudence of ETI' s 1997 ice storm expenses. 151 Mr. Po us testified that these expenses
are now appropriately at issue in the present case, and he recommended that the entire balance be
excluded from the storm damage reserve. He pointed out that in Docket No. 18249, the Commission
found that ETI' s poor quality of service exacerbated the extent of damage caused by the storm, and it
found that the response efforts were uneven and delayed and could have been more effective if ETI
had a better communication and management program in place. 152 Mr. Pous also contended that in
the present case ETI failed to prove that any portion of the 1997 Ice Storm expenses were
reasonable. 153

          Thus, Cities argue that the Commission has already determined that ETI' s negligence was a
major factor in the extent and duration of the outages, 154 so no expenses associated with the 1997 ice
storm should be eligible for recovery from customers through the storm damage reserve. In response
to ETI's argument that it was already penalized for these issues in Docket No. 18249 through a
reduction to the allowed ROE, Cities argue that the Commission did not absolve ETI from
responsibility for damage caused by ETI's poor service quality, and ETI's customers should not be
ordered to pay for expenses that were caused by ETI's negligence. 155

          OPC makes the same arguments as Cities concerning the 1997 ice storm expenses. 156

          ETI argues that, due to quality of service issues related to the 1997 ice storm, the
Commission reduced Entergy Gulf States, Inc.' s (EGSI) ROE by 60 basis points in Docket
No. 18249 and subjected EGSI to significant spending requirements and quantified performance
guarantees. In ETI's opinion, it would be inequitable to now penalize ETI a second time for the

151
      Cities Ex. 5 (Pous Direct) at 49-55.
152
      Entergy Gulf States, Inc. Service Quality Issues Severed From Docket No. 16705, Docket No. 18249, Final
Order at FoF 97, 98, & 102 (Apr. 21, 1998).
153
      Cities Ex. 5 (Pous Direct) at 56-59; see Cities Initial Brief at 18-19.
154
    Cities Initial Brief at 18 ("The Company's failure to clear the limbs before the storm was a major factor in
the number and duration of outages experienced by customers.").
155
      Cities Reply Brief at 28-30.
156
      OPC Ex. 6 (Benedict Direct) at 12; OPC Initial Brief at 16; OPC Reply Brief at 7-10.
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same issues. Moreover, ETI argues that it established that its expenses were reasonable and
necessary. ETI witness Shawn Corkran testified that the 1997 ice storm was the most destructive
winter storm ever to hit the EGSI/ETI system, with about 3,400 miles of distribution lines and
560 miles of transmission lines de-energized during the storm's peak. A large part of the restoration
effort involved clearing broken and fallen trees and tree limbs from lines. Mr. Corkran reviewed all
of the costs incurred in response to the 1997 ice storm and stated that they were reasonable and
necessary to reliably restore service to customers as quickly as possible after the storm. He provided
an exhibit with a detailed breakdown of labor, materials, transportation, lodging, and other expenses
incurred.     In his opinion, all of these costs charged to the storm damage reserve, totaling
$13,014,379, were reasonable, necessary, and prudently incurred. 157

          The ALls recommend that the Commission authorize ETI to include in the storm damage
reserve its $13,014,379 in expenditures associated with the 1997 ice storm. ETI established that
those expenses were reasonable and necessary to repair the damage and restore power to its
customers. ETI witness Mr. Corkran provided detailed testimony concerning the seriousness of the
storm and the resulting expenses incurred for repair work and restoration of power to customers. 158

          In contrast, Cities and OPC did not challenge any specific item in these restoration expenses.
Instead, they relied upon the Commission's findings in Docket No. 18249 that ETl's deficient
maintenance exacerbated the amount of damage caused by the storm. However, in that docket the
Commission also reduced ETI' s ROE by 60 basis points due to poor service issues, including
deficient preventative maintenance. The Commission made the reduction in ROE retroactive and
required ETI to make refunds to customers. Likewise, in that docket the Commission found that the
ice storm was severe and that significant damage would have occurred even with exemplary
vegetation management and other preventative measures. It is not feasible to accurately determine
now what portion of ice storm damage that occurred 15 years ago was caused by preventative
maintenance issues.

157
      ETI Ex. 48 (Corkran Rebuttal) at 2-12.
158
      ETI Ex. 48 (Corkran Rebuttal) at 2-12 and Ex. SBC-R-1.
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       The Al.Js conclude, however, that the Commission's retroactive reduction ofETI's ROE in
Docket No. 18249 in part compensated ratepayers for the poor service issues that exacerbated the
storm damage. Nevertheless, once the ice storm occurred, ETI had to take appropriate action to
repair the damage and restore service. ETI has established the expenses incurred in those efforts
were reasonable and necessary, and the Al.Js find that they should be included in the storm damage
reserve. Therefore, the AUs recommend that the Commission deny Cities and OPC's proposed
adjustment.

       4. Jurisdictional Separation Plan Allocation

       Cities complained that ETI's storm damage reserve deficit includes $12,498,325 in costs that
belong to Louisiana jurisdiction customers but were incorrectly transferred to Texas customers
during implementation of the Jurisdiction Separation Plan.         Cities explain that before the
jurisdictional separation of EGSI into ETI and Entergy Gulf States Louisiana, LLC (EGSL), the
transmission investment and expense associated with maintaining the transmission system, including
storm restoration costs, was allocated between the Texas and Louisiana retail jurisdictions. In the
jurisdictional separation of EGSI into ETI and EGSL, the transmission system investment was split
between each company based upon a situs basis. The transmission facilities in Texas were
transferred to ETI and the transmission facilities in Louisiana were transferred to EGSL. After the
jurisdictional separation, ETI and EGSL were each responsible for future O&M expense, including
storm restoration expense, associated with their respective transmission investments.

       Cities claim that in the present case ETI has attempted to reverse the allocation of expenses
incurred on behalf of Louisiana customers before the jurisdictional separation and to charge those
expenses to Texas customers through the storm damage reserve. In Cities' opinion, any expense that
was allocated to Louisiana customers prior to the jurisdictional separation was properly charged to
Louisiana customers. Cities argue that ETI may not now reverse expenses allocated to Louisiana
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customers and charge them to Texas customers solely on the basis that ETI acquired the transmission
investment located in Texas. 159

          In response, ETI witness Considine explained that an analysis of storm reserve charges was
preformed prior to the jurisdictional separation to determine if storm charges were incurred for Texas
or Louisiana property. The reclassification of certain charges was made as a result of that analysis,
which is in evidence, to properly reflect the state in which the storm charges were incurred. The
largest charge assigned to ETI through this analysis was a $10,652.130 charge related to project
"E2PPSJ8291 Trans EGSI-TX Hurricane Rita 9-24-05," which expressly related to damages to the
Texas portion of the former EGSI transmission system. Similarly, costs were assigned from ETI to
EGSL for projects such as "E2PPSJ8296 Trans. Hurricane Katrina - EGSl-La" and "E2PPSJ8302
Trans EGSI-LA Hurricane Rita 9-24-05," that clearly related to assets located in Louisiana. In other
words, prior to the separation, the Texas portion of the storm damage reserve could include charges
for restoration work performed on assets located in Louisiana, and vice versa. The analysis
conducted pursuant to the separation re-aligned the charges to the jurisdiction where the assets are
located. In that way, ETI argues, neither jurisdiction has charges in its storm reserve balance for
assets located in the other jurisdiction. In short, ETI argues that the assets and liabilities following
the separation have been properly assigned and no improper cost shifting occurred. 160

          The ALJ s recommend that the Commission deny Cities' proposed adjustment. ETI offered
evidence to explain how its reclassification study reassigned various costs from the Texas
jurisdiction to Louisiana, as well as from the Louisiana jurisdiction to Texas. This study resulted in
more expenses from Louisiana being reassigned to the Texas jurisdiction than from Texas to
Louisiana, but Cities offered no evidence to explain why the study was flawed or why the
reassignments were in error. The ALJs found ETI's evidence to be credible and that it supported the
jurisdictional allocation of these expenses as proposed by ETI.

159
      Cities Ex. 5 (Pous Direct) at 59-60; Cities Initial Brief at 19-20.
160
    ETI Ex. 46 (Considine Rebuttal) at 25 and Ex. MPC-R-3 at 25; ETI Initial Brief at 19-36; ETI Reply Brief
at 20-21.
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          5. $50,000 Reserve Threshold

          Cities witness Pous also proposed a $10,950,000 reduction to ETI' s negative storm damage
reserve balance due to ETI including in the reserve the first $50,000 of expense for each separate
storm event. Mr. Pous asserted that this amount is equivalent to a deductible for insurance purposes
and should have not been charged to the reserve. Cities note that P. U. C. SUBST. R. 25 .231 (b)( 1)(G)
requires that a storm reserve only collect for "property and liability losses which occur, and which
could not have been reasonably anticipated and included in operating and maintenance expenses."
Because of ETI's low $50,000 threshold, Cities contend, ETI has recorded to. the storm reserve
expenses associated with 219 different weather events in the past 15 years. This equates to
approximately 14.6 weather events per year, or 1.2 weather events per month, on average. In Cities'
view, ETI' s booking to the storm damage reserve of all expenses associated with a weather event
exceeding $50,000 - including the first $50,000 - is inconsistent with P.U.C.                  SUBST.

R. 25.23l(b)(l)(G). Cities argue that ETI may not reasonably claim that such a recurring expense is
"not reasonably anticipated" to qualify it for the storm reserve. Cities proposed adjustment is based
on $50,000 for each of the 219 storm events, for a total of $10,950,000. In addition, based on the
nature of ETI's recurring storm expense, Cities also recommend that the deductible amount be
increased to $500,000, which Cities stated is consistent with the storm reserve treatment afforded to
other utilities in Texas. 161

          ETI witness Gregory Wilson testified that Mr. Pous misconstrued the $50,000 trigger when
he treated it as a deductible. Mr. Wilson explained that if a storm causes $50,000 or less in damage,
the expenses are not charged to the storm damage reserve. However, if a storm causes more than
$50,000 in damage, all of the expenses are charged to the reserve. He noted that if the $50,000 were
treated as a deductible, then that amount would still be charged to O&M whenever storm damage
exceeded the $50,000 threshold. But, under the current arrangement, when storm damage exceeds
$50,000 all of the expenses are charged to the storm damage reserve, and the first $50,000 is not
charged to O&M. Therefore, no double recovery occurs. Moreover, ETI argues that Cities'
proposed retroactive removal of these amounts from the reserve would constitute a disallowance of

161
      Cities Ex. 5 (Pous Direct) at 61-63; Cities Initial Brief at 20-21.
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costs without any finding of imprudence, as well as impermissible retroactive ratemaking. ETI also
contends that even if the Commission were to implement Mr. Pous' s recommendation prospectively,
it would require a corresponding increase in ETI' s O&M costs. Therefore, ETI disagreed with
Cities' recommendation to reduce the current balance of the storm damage reserve by $10,950,000 or
to change the current level of the threshold. 162

          The AlJs find that Cities' proposed adjustment to ETI's storm damage reserve is not
warranted. ETI explained that the $50,000 threshold amount was included in the storm damage
reserve whenever storm restoration expenses exceeded the threshold, but that amount was not
included in O&M expense. Accordingly, no double recovery has occurred, and Cities presented no
other valid reason to disallow the allocation of these expenses to the storm damage reserve.
Therefore, the A1J s recommend that the Commission deny Cities' proposed $10,950,000 adjustment
to ETI's current storm damage reserve balance. As a policy matter, the Commission may choose to
increase ETI' s threshold on a prospective basis to some higher amount, as recommended by Cities,
but the evidence presented by the Cities on this issue was not sufficient for the A1J s to make such a
recommendation.

          6. Hurricane Rita Regulatory Asset

          As discussed in Section V.B., Cities recommend an adjustment to the Hurricane Rita
regulatory asset, and they recommended the adjusted balance be moved to the storm damage reserve.
For the reasons stated in Section V .B., the AlJs recommend that the Commission not adopt Cities'
proposal to move the Hurricane Rita regulatory asset to the storm damage reserve.

          7. Conclusion

          In conclusion, the AlJs find that ETI's storm damage expenses since 1996 and its storm
damage reserve balance were not approved by the Commission as a result of the black-box
settlements in Docket Nos. 34800 and 37744. The AlJs also find that ETI established aprimafacie
case concerning the prudence of its storm damage expenses incurred since 1996 and that intervenors'

162
      ETI Ex. 72 (Wilson Rebuttal) at 2-3; BIT' s Initial Brief at 27-28; ETI Reply Brief at 21-22.
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proposed adjustments should be denied. Therefore, the ALJ s recommend that the Commission
approve ETI's test-year-end storm reserve balance of negative $59,799,744.

G.            Coal Inventory

              ETI is the partial owner of two coal-fired power generating facilities. It owns a 29. 75 percent
interest in Nelson 6, a 550 megawatt (MW) unit located in Westlake, Louisiana (Nelson), and a
17 .85 percent interest in Big Cajun II, Unit 3, a 588 MW unit located in New Roads, Louisiana
(BCIUU3). EGSL is the majority owner and operator of Nelson and is responsible for the supply and
delivery of coal to that facility. A third party, LaGen, is a co-owner of BCIUU3, and is the operator
of the plant. Pursuant to a joint operating agreement between the co-owners, LaGen is responsible
for the acquisition and delivery of coal to BCIUU3. The coal for both units comes, via train, from
minefields in Wyoming. 163

              Entergy has adopted a "Coal Inventory Policy" at Nelson to ensure that a sufficient coal
inventory is always maintained on-site to help mitigate transportation and unit operating risks. The
policy calls for, among other things, a 12-month average inventory target of a 43-day supply of coal.
Because Entergy is not the operator of BCIUU3, it does not have ultimate control over the coal
inventories at that unit. Pursuant to the joint operating agreement for that unit, however, each year
ETI nominates for the next calendar year the level of coal to be delivered for its account at BCIUU3.
ETI' s nomination process is targeted to ensure an end-of-year inventory target of a 43-day supply of
        164
coal.

              In its application, ETI includes a coal inventory amount in its rate base that is based upon the
average inventories at Nelson and BCIUU3 for the 13 months ending in June 2011. 165 The average
coal inventory at Nelson was 384,860 tons, representing approximately 48 days of inventory,

163
      ETI Ex. 33 (Trushenski Direct) at 3-4.
164
      ETI Ex. 33 (Trushenski Direct) at 30-31.
165
    ETI Ex. 68 (Trushenski Rebuttal) at 2. Notably, the amount ETI is seeking in its Rate Base is calculated
upon a 13-month average ending June 2011 (the last month of the Test Year), even though that amount is
slightly less than the 12-month average for the Test Year.
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assuming an average daily burn rate of 8,000 tons. The total proposed dollar amount for the coal
inventories at both facilities is $9,846,037. Of that total, the Nelson portion is $6,040,926, and the
BCIUU3 portion is $3,805,111. 166 ETI witness Ryan Trushenski, the Manager of the Solid Fuel
Supply Group for ESI, testified that the coal inventory levels that were maintained at Nelson and
BCII/U3 during the test year were reasonable and the costs 'incurred to maintain those levels were
reasonable. 167

          Cities do not challenge the reasonableness of the Company's 43-day inventory targets.
Rather, Cities point out that the size of the actual inventory that was maintained on-site at Nelson
during the Test Year exceeded the Company's inventory target level. Therefore, Cities contend that
customers should not be forced to pay for inventory levels exceeding a 43-day supply (the amount
that the Company determined, through its Coal Inventory Policy, to be a reasonable and necessary
inventory to maintain on-site). According to Cities' witness, Karl Nalepa, a 43-day inventory of coal
at Nelson would equate to 340,000 tons. He recommends that the value of a 43-day supply of coal
be included in the rate base, but that $1,451.415 be excluded from the rate base to account for
inventory at Nelson that was in excess of the 43-day supply. 168

          The evidence shows that the Company's inventory "target" was a 43-day supply, while actual
inventories during the Test Year averaged around a 48-day supply. Mr. Trushenski pointed out, and
the A1J s concur, that the 43-day "target" was never intended to represent a hard and fast figure from
which no deviations could be allowed. Rather, the target merely represents an operational planning
tool. Moreover, there are many real-world factors - such as train cycle times, coal burn rates, and so
on - that can cause the actual coal inventory to fluctuate over time. 169 The ALls conclude that the
48-day coal inventory was acceptably close to the 43-day target and was not unreasonable. The total
proposed dollar amount for this coal inventory is $9,846,037. The ALls conclude that the full value
of the coal inventory was reasonable and should be included in rate base.

166
      ETI Ex. 68 (Trushenski Rebuttal) at 2, and 3 at WP/P RB 4.2.
167
      ETI Ex. 33 (Trushenski Direct) at 30-31.
168
      Cities Ex. 6 (Nalepa Direct) at 28-29, 6C and 6E.
169
      ETI Ex. 68 (Trushenski Rebuttal) at 4.
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H.        Spindletop Gas Storage Facility

           ETI relies upon a variety of fuel types to generate electricity. A major fuel component is
natural gas. However, energy generated from natural gas typically has the highest marginal cost and,
therefore, it is most often the last resource deployed to generate electricity. The fluctuation of natural
gas demand resulting from the changes in instantaneous demand is known as "swing." Although a
portion of the system's base load requirement is met with natural gas, the primary role of natural gas
                                      170
is as a swing fuel on the system.

           Since 2004, ETI has owned and used the Spindletop Facility. ETI, through a third-party
operator, uses the Spindletop Facility to maintain a natural gas inventory that can be used to supply
ETI's Sabine Station and Lewis Creek power generating facilities. Spindletop consists of two
                                                                                                171
salt-dome storage caverns (and associated equipment) located near Sabine Station.                     The
Spindletop Facility serves a function similar to that of a city water tower - it enables ETI to buy
natural gas at one point in time, store it, and use it at some future point when supplies are not
available elsewhere or when peak needs cannot otherwise be met. ETI maintains that the primary
benefit of the Spindletop Facility is that it provides: (1) supply reliability; and (2) swing flexibility.
"Supply reliability" means that the facility can provide a reliable supply of gas for Sabine Station and
Lewis Creek during potential gas supply curtailments, such as can occur during hurricanes, freezes,
or other unusual events. In a worst-case scenario, the Spindletop Facility is capable of providing
100 percent of the fuel requirements for all five units at Sabine Station and one Lewis Creek unit for
four days at 70 percent of capacity. The Spindletop Facility also allows the Company to avoid
almost all intra-day gas purchases for Sabine Station. This is important because intra-day purchases
tend to be more expensive than longer-term purchases. 172

           Because major supply disruptions are more likely to occur during hurricane season and
during the winter, ETI manages its gas inventories conservatively during the period from June

170
      ETI Ex. 28 (Mcllvoy Direct) at 7.
171
      Id. at 31.
172
      ETI Ex. 28 (Mcllvoy Direct) at 32-33; ETI Initial Brief at 39, n. 264.
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through March in order to ensure that it can provide a reliable supply of fuel to meet peak generation
loads for four consecutive days. During the remainder of the year, ETI will consider withdrawing
gas from the Spindletop Facility when the current day spot market price is higher than the
replacement cost for the gas, as determined by future market indicators. Conversely, ETI injects gas
into the Spindletop Facility when the cost of gas in the current market is less than the price of gas in
the futures market. 173 For these various reasons, ETI witness Karen Mcllvoy, who is employed as
the manager of ESI' s Gas & Oil Supply Group, testified that that Spindletop Facility is used and
useful for providing reliable, economical service to ETI' s customers. 174 ETI witness Devon Jaycox,
who is employed as the manager of ES I's Operations and Planning Group, testified that the Company
is always evaluating how much reliability the Spindletop Facility can provide as compared to other
options. He explained that, at Sabine Station, there is no other option that can provide ETI with the
same level of reliability and flexible swing service that the Spindletop Facility provides. 175

           Cities are critical of the Spindletop Facility, contending that the costs of operating it outweigh
the benefits gained from it. No other party challenged ETI' s use of the Spindletop Facility. Cities'
witness Karl Nalepa testified that it costs ETI $13,219 ,097 per year to operate the gas storage facility,
whereas the Company could achieve the same supply reliability and swing flexibility benefits it gets
from the Spindletop Facility through other gas supply options at a cost of only $1,724,659, thereby
saving its customers $11,494,438. Thus, Mr. Nalepa stated that it is imprudent for ETI to continue
operating the Spindletop Facility. 176

           Mr. Nalepa testified that no other Entergy operating company owns or leases its own gas
storage facility, yet those other companies are able to satisfy their needs for supply reliability and
swing flexibility through other methods, such as existing gas supply and transportation contracts, at
much lower costs. According to Mr. Nalepa, those other companies obtain supply reliability and
swing flexibility through the use of monthly, daily, and intra-day natural gas supply contracts. In

173
      ETI Ex. 28 (Mcllvoy Direct) at 33-34.
174
      Id. at 37.
175
      Tr. at 966.
176
      Cities Ex. 6 (Nalepa Direct) at 18-20; Cities Ex. 6B (Errata No. 2).
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support of this claim, he pointed to one of the operating companies, EGSL, as an example. He
pointed out that EGSL has no firm transportation contracts, no firm supply contracts, and no fuel oil
back-up at its generating plants. Thus, Mr. Nalepa stated that the only cost incurred by EGSL for
reliability and flexibility is the commodity cost of the natural gas it purchases. Mr. Nalepa testified
that EGSL achieves the same level of service as ETI without incurring the large cost of the
Spindletop Facility. 177

          Mr. Nalepa asserted that the long-term gas supply contract that ETI recently entered into with
Enbridge Pipeline, L.P. (the Enbridge Contract) will help provide the Company with increased
supply reliability because the gas supplied by Enbridge will come from production areas that are less
susceptible to hurricane-related disruptions. Mr. Nalepa also noted that ETI could meet its swing
flexibility requirements through use of spot gas purchases, its operational balancing agreement with
the TETCO pipeline, and other pipeline companies, such as the Copano Pipeline that serves Lewis
Creek. 178

          Mr. Nalepa also disputed ETI's contention that the Spindletop Facility serves as a valuable
protection against extreme events such as hurricanes, by noting that the Spindletop Facility was out
of service for almost two weeks in 2005 following Hurricane Rita. 179

          As noted above, Mr. Nalepa testified that it cost ETI $13,219,097 to operate the Spindletop
Facility in the Test Year. Mr. Nalepa estimated that the sum of the Test Year withdrawals of gas
from the Spindletop Facility equaled 8,560,604 MMBtu. He then divided his total estimated cost of
the facility ($13,219,097) by his total estimated withdrawals of gas (8,560,604 MMBtu) to calculate
an "all-in per unit rate" of $1.54 per MMBtu. He asserted that, by contrast, transportation costs on
various gas pipelines connected to Sabine and Lewis Creek ranged from $0.025 to $0.22 per
MMBtu. Mr. Nalepa estimated $0.18 per MMBtu as the average replacement cost that ETI would
incur in transportation contracts if it were to stop using the Spindletop Facility and achieve the same

177
      Cities Ex. 6 (Nalepa Direct) at 22-23.
178
      Cities Ex. 6 (Nalepa Direct) at 25.
179
      Id. at 23-24.
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level of supply reliability and swing flexibility through the use of gas supply contracts. By
multiplying $0.18 times 8,560,604 MMBtu, he estimated that the benefits of the Spindletop Facility
could have been achieved through other means at a cost of only $1,724,659. Thus, Mr. Nalepa
recommended that $7,794,202 should be removed from ETI's base rate, and $5,424,895 should be
excluded as an eligible fuel expense. 180

          ETI disagrees with essentially all of Mr. Nalepa' s points and responds to his testimony on a
number of fronts. Perhaps foremost, ETI points out that Mr. Nalepa's main premise - that ETI's
customers pay all the costs of the Spindletop Facility while the other Entergy operating customers
avoid those costs - is simply incorrect. According to ETI witnesses, 57.50 percent of the costs
associated with the Spindletop Facility are billed to EGSL as part of the MSS-4 billing process
between ETI and EGSL for its "legacy plants," 181 and another 2.4 percent of the costs are passed on
to other Entergy operating companies through the MSS-3 agreement. Only 40.1 percent of the
Spindletop Facility costs are borne by ETI customers. 182 Thus, Mr. Nalepa's calculations greatly
overstate the costs of the Spindletop Facility that are borne by ETI customers and greatly understate
the costs that are borne by EGSL customers. ETI witness Considine also pointed out that the
Commission has consistently and repeatedly concluded that the Spindletop Facility is used and useful
and, therefore, has allowed ETI and its predecessors to recover the costs associated with the
Spindletop Facility. 183

          Ms. Mcllvoy also testified that, contrary to Mr. Nalepa's testimony, the conditions under
which the other Entergy operating companies operate are so different from the conditions under
which ETI operates that it makes no sense to assume they have similar supply reliability and swing
flexibility needs. For example, EGSL and ETI both own roughly the same generating capacity from

180
      Id. at 24-27; Cities Ex. 6B (Errata No. 2).
181
   The legacy plants are the four power generating plants that were owned by Entergy Gulf States, Inc. -
Lewis Creek, Sabine Station, Nelson, and Willow Glen. When EGSI was broken into ETI and EGSL in 2007,
ETI became the owner of Lewis Creek and Sabine Station, while EGSL became the owner of Nelson and
Willow Glen. ETI Ex. 60 (Mcllvoy Rebuttal) at 5-6; ETI Ex. 46 (Considine Rebuttal) at 3.
182
      ETI Ex. 46 (Considine Rebuttal) at 3-4; ETI Ex. 60 (Mcllvoy Rebuttal) at 18-19.
183
      ETI Ex. 46 (Considine Rebuttal) at 3-4.
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gas-powered plants - 2,378 MW for EGSL versus 2,295 MW for ETI. However, the ETI plants are
operated at a much higher capacity than the EGSL plants. During the Reconciliation Period, EGSL
burned much less natural gas than did ETI- 63,420,554 MMBtu burned at the EGSL plants versus
144,538,535 MMBtu burned at the ETI plants. Moreover, EGSL has four gas-powered plants while
ETI has only two. Of EGSL's four plants, two (Calcasieu and Ouachita) use combined cycle gas
turbine technology. This gives them a quick-start and shut-down capability, allowing them to be
operated primarily only at peak demand times. Thus, according to Ms. Mcllvoy, Mr. Nalepa's
premise - that because EGSL is able to reliably operate its gas-fired facilities without gas storage,
ETI should be able to do so as well - makes no sense. Because ETI bums a vastly larger amount of
natural gas than EGSL, its need for supply reliability and swing flexibility is much greater. 184

          Ms. Mcllvoy also disputed Mr. Nalepa' s assertion that ETI could use the Enbridge Contract
and call options to provide the Company with sufficient supply reliability. She noted that the
maximum amount of gas deliverable under the Enbridge Contract is insufficient to run the ETI plants
even at minimum load. By contrast, the Spindletop Facility is capable of supplying all Sabine
Station units and one unit at Lewis Creek for four days at 70 percent capacity.       Moreover, the
Enbridge Contract will expire, whereas the Spindletop Facility can be operated indefinitely.
Ms. Mcllvoy explains that the use of call options is not viable because a call option must be
delivered "ratably," meaning the gas must be delivered at a constant, even rate throughout the
delivery period. In order to have gas available to meet peak needs in the absence of the Spindletop
Facility, ETI would have to exercise call options for a maximum delivery, but it would not need all
of the gas delivered at off-peak times of the day. 185

          ETI witness Jaycox disputed Mr. Nalepa's premise that ETI could use call options to ensure
reliability.    According to Mr. Jaycox, "call options are cheaper than storage, but there's no
comparison" between the amount of reliability that they provide as compared to the Spindletop
Facility. 186 Mr. Jaycox also explained that, due to their geographic location and the limited import

184
      ETI Ex. 60 (Mcllvoy Rebuttal) at 3-8.
185
      ETI Ex. 60 (Mcllvoy Rebuttal) at 8-12.
186
      Tr. at 969.
                                           ··-~~------------------------

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capability to the ETI service area, Sabine Station and Lewis Creek are considered particularly
                                                                         187
critical, thereby increasing the need for reliability at those plants.

          When Mr. Nalepa calculated ETI' s cost of achieving supply reliability and swing flexibility
without the use of the Spindletop Facility, he estimated it would cost only $1,724,659. He did so, in
part, by assuming that a five-day 35,000 MMBtu/day call option would cost ETI $26,250.
Ms. Mcllvoy asserted that it is not reasonable to assume that all options would cost as little as
$26,250. Based upon her calculations, ETI would have to purchase 14 five-day 35,000 MMBtu/day
call options per month to achieve supply reliability. She posited that, based upon the laws of supply
and demand, the more call options ETI has to purchase, the higher the cost of those options would
be. She also pointed out that Mr. Nalepa' s proposed use of call options would require ETI to spend
hundreds of thousands of dollars each month to purchase call options that it would never exercise.
According to Ms. Mcllvoy, it is unclear from Commission precedents whether ETI would be entitled
to recover the costs of these un-exercised options. 188

          The evidence establishes that the Spindletop Facility is critical to providing reliability and
swing flexibility to ETI' s Texas plants. The AU s conclude that the Spindletop Facility is a used and
useful facility providing reliability and swing flexibility to ETI' s customers at a reasonable price, and
Cities' arguments to the contrary lack merit.

I.        Short Term Assets

          In its application ETI requested that, as short term assets, the following amounts be included
in the rate base: prepayments in the amount of $7 ,218,037; materials and supplies in the amount of
$29,252,574; and fuel inventory in the amount of $53,759,975. These amounts were derived using
13-month averages ending June 2011. 189 Staff witness Anna Givens agrees with the approach of
using 13-month averages to determine the appropriate amounts for short term assets. However, she

187
      Tr. at 975, 986-87.
188
      ETI Ex. 60 (Mcllvoy Rebuttal) at 12-15.
189
      ETI Ex. 3 at Sched. B-1.
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recommends using the 13-month period ending December 2011, because it is the most recent
information available. Using this approach, Ms. Givens recommends that, as short term assets, the
following amounts be included in the rate base: prepayments at $8,134,351 ($916,313 more than
ETI's request); materials and supplies at $29,285,421 ($32,847 more than ETI's request); and fuel
inventory at $52,693,485 ($1,066,490 less than ETI's request). 190 ETI does not oppose Staff's
recommendation on this issue. No party has a criticism of Staffs estimates as to prepayment,
materials and supplies, and fuel inventory, nor do the ALls. Accordingly, the ALls recommend
adopting the numbers proposed by Staff.

J.         Acquisition Adjustment

           In its application, ETI included an adjustment of $1,127,778 for an "electric plant
acquisition." 191 The proposed adjustment, which relates to costs incurred by ETI when it acquired
the Spindletop Facility, consists of closing costs of $211,209 and legal and internal costs of
$916,568. 192 ETI witness Considine explained that, prior to December 2009, the same amounts were
included in the Electric Plant in Service (FERC Account 101). On January 11, 2010, FERC issued
Opinion No. 505 in FERC Docket No. ER07-956-00 and ordered the Company to transfer the
amounts above from Account 101 to FERC Account 114, Electric Plant Acquisition Adjustments.
He also pointed out that the costs were included in ETI's filed rate base amounts in Docket Nos.
34800 and 37744. 193 Mr. Considine contended that these amounts should remain in rate base
because they represent costs incurred by ETI for the purchase of a viable asset that benefits its retail
customers. He pointed out that the amounts have previously been included in the Company's rate
base, but the only thing that has changed is that the amounts were previously allocated to a different
account. ETI argues that the fact that the costs were approved as part of rate base in two previous
ETI dockets verifies that they were "reasonable, prudently incurred, and properly capitalized." 194

190
      Staff Ex. l (Givens Direct) at 3 l-32.
191
      ETI Ex. 3 at Sched. C-l.
192
      ETI Ex. 46 (Considine Rebuttal) at 4.
193
      Id. at 4-5.
194
      ETI Initial Brief at 43.
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Thus, ETI contends it would be inappropriate to penalize it because of an accounting technicality
                                    195
imposed upon it by FERC.

          Staff advocates the removal of the entire electric plant acquisition adjustment from rate base,
contending that, "[a]s a rule, the rate base component for plant in service includes only the original
cost, net of accumulated depreciation." 1% Cities similarly contend, without citing to any legal
authority, that acquisition adjustments are not legally permitted as an addition to rate base for
ratemaking purposes or as a depreciable asset for regulatory ratemaking purposes. 197 Staff disputes
ETI' s contention that the fact that the costs were approved as part of rate base in two previous ETI
dockets proves that they were reasonable, prudently incurred, and properly capitalized. Staff points
out that those two prior dockets were settled rate cases and, therefore, "provide no illumination on
this issue." 198 Finally, Staff argues that ETI failed to prove either element of the Commission's two-
part Hooks test for the determination of whether the acquisition adjustment should be included in
rate base. Pursuant to the Hooks test, in determining whether an acquisition adjustment should be
included in rate base, "the Commission should consider whether or not the purchase price was
excessive and whether or not specific and offsetting benefits have accrued to ratepayers." 199
According to Staff, ETI' s acquisition adjustment should be disallowed because the Company failed
to meet it burden of proof on these two issues. 200

           The AU s are unpersuaded by the arguments of Staff and Cities. Their primary argument
(i.e., that acquisition adjustments are simply not allowed as an addition to rate base for ratemaking
purposes) is incorrect. Indeed, the Hooks decision, the precedent on which Staff relies for its
fallback argument, suggests that, more often than not, acquisition adjustments should be included in

195
      ETI Ex. 46 (Considine Rebuttal) at 5.
196
      Staff Ex. I (Givens Direct) at 35.
197
      Cities Initial Brief at 26.
198
      Stafflnitial Brief at IL
199
   Application of Hooks Telephone Company for a Rate Increase within Bowie County, Docket No. 2150,
Examiner's Report at 2 (Mar. 28, 1980)(Hooks).
200
      Staff Reply Brief at 12.
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rate base: "Amortization of an acquisition adjustment need not be allowed as an expense in all
cases."201

          Moreover, the evidence demonstrates that ETI met is burden under the Hooks test. As
discussed more fully in Section V.H. of this PFD, above, there is ample evidence in the record to
demonstrate that the Spindletop Facility is used and useful and provides specific and offsetting
benefits to ratepayers in a cost-effective manner. The evidence further shows that the acquisition
adjustment represents costs that were actually incurred by ETI in the furtherance of acquiring the
Spindletop Facility, and not a mere mark-up in original cost. For these reasons, the ALls conclude
that the $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of the
Spindletop Facility was reasonable, necessary, and properly incurred. Accordingly, the ALl s agree
that it should be included in ETI' s rate base.

K.        Capitalized Incentive Compensation

          In the application, some of the incentive payments ETI made to its employees were
capitalized into plant in service accounts and ETI asks to include those amounts in rate base.202 A
portion of those capitalized accounts represents payments made by ETI for incentive compensation
tied to financial goals (financially-based incentive compensation). Cities contend that, consistent
with Commission precedent, ETI ought not be allowed to include in rate base the portion of its
capitalized incentive compensation that is attributable to financially-based               incentive
compensation. 203 The issue of whether financially-based incentive compensation is recoverable as a
portion of Operating Expenses is discussed at length in Section VII.D.2. of this PFD. ETI makes the
same arguments in favor of recoverability in that section that it makes here as to the inclusion of
financially-based incentive compensation in rate base. The discussion of that issue need not be
repeated here, but the analysis is the same. In summary, the ALls conclude that ETI should not be
entitled to recover its financially-based incentive compensation costs. Thus, for the same reasons

201
      Hooks (emphasis added).
202
      Cities Ex. 2 (Garrett Direct) at 52.
203
      Id. at 52-53.
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discussed in Section VIl.D.2, the Al.Js agree with Cities' contention that the portion of ETI's
incentive payments that are capitalized and that are financially-based should be excluded from ETI' s
rate base.

          On the other hand, the Al.Js disagree with Cities as to the amount of that exclusion. Cities
argue that $9,835, 111 (Cities' estimate of ETI' s financially-based incentive payments that are
capitalized each year into plant in service) should be removed from rate base. 204 Broadly speaking,
ETI has two categories of incentive compensation programs - annual incentive programs, and long-
term incentive programs. To arrive at the figure of$9,835,1 l l, Cities' witness Garrett assumed that:
(1) 100 percent of the costs of the long-term incentive programs were financially-based and,
therefore, should be excluded from rate base; and (2) his calculated percentage of the annual
incentive programs were financially-based and, therefore, should be excluded from rate base. He
then applied those percentages to the incentive costs that ETI capitalized in 2008, 2009, and the
portion of 2010 prior to the Test Year. 205

          As explained in Section VII.D.2., the AUs agree that Mr. Garrett was correct to recommend
removing 100 percent of the cost of ETI' s long-term incentive programs. However, as to the annual
incentive programs, he defined what qualifies as "financially based" much too broadly, and therefore
wrongly assumed that his calculated percentage of the costs of those programs should be excluded.
Instead, the Al.J s conclude that the actual percentages should be used to determine the amount that is
financially based. 206

           Finally, ETI challenges Mr. Garrett's attempt to disallow capitalized incentive costs from
2008 through June 30, 2009.

           Much of the rate base that Mr. Garrett seeks to disallow (namely, costs from 2007
           through June 30, 2009) is not presented for review in this rate case. Rather those
           costs were presented for review in the Company's last rate case, Docket No. 37744,

204
      Id. at 52-53; Cities Initial Brief at 27.
205
      Cities Ex. 2 (Garrett Direct) at 53 and MG-2.10.
206
      See discussion in Section VII.D.2.
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          in which the Company presented capital additions for the period of April 1, 2007,
          through June 30, 2009 .... Even though Docket No. 37744 was a settled case, the
          final order concluded that '[b ]ased on the evidence in this docket, the overall total
          invested capital through the end of the test year meets the requirements in PURA §
          36.053(a) that electric utility rates be based on original cost, less depreciation of
          property used and useful to the utility in providing service.' This conclusion goes
          beyond merely settling issues without deciding anything and should be construed as
          to be conclusive as to the reasonableness of capital costs at issue in that prior case. 207

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

       VI.    RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4and11]

A.        Capital Structure

          ETI's capital structure is 50.08 percent debt and 49.92 percent equity. No party has taken
issue with ETI's capital structure. Therefore, the ALls recommend that the Commission enter an
order finding that the appropriate capital structure for ETI is 50.08 percent debt and 49.92 percent
equity.

B.        Return on Equity

          The United States Supreme Court has set forth a minimum constitutional standard governing
equity returns for utility investors:

          From the investor or company point of view it is important that there be enough
          revenue not only for operating expenses but also for the capital costs of the business.
          These include service on the debt and dividends on the stock. By that standard the

207
      ETI Initial Brief at 44, quoting Docket No. 37744, Order at CoL 10 (Dec. 13, 2010).
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        return to the equity owner should be commensurate with returns on investments in
        other enterprises having comparable risks. That return, moreover, should be
        sufficient to assure confidence in the financial integrity of the enterprise, so as to
        maintain its credit and to attract capital. 208

Thus, a utility must have a reasonable opportunity to earn a return that is: (1) commensurate with
returns on equity investments in enterprises having comparable risks; (2) sufficient to ensure the
financial soundness of the utility's operations; and (3) adequate to attract capital at reasonable rates,
thereby enabling it to provide safe, reliable service. The allowed ROE should enable the utility to
finance capital expenditures at reasonable rates and to maintain its financial flexibility during the
period in which the rates are expected to remain in effect.

        1. Proxy Group

        Because ETI is not a publicly traded company, it is necessary to establish a group of
companies that are publicly traded and that are comparable to ETI in certain fundamental business
and financial respects to serve as its "proxy" in the ROE estimation process. Both financial theory
and legal precedent support the use of comparable companies within a proxy group to determine a
utility's ROE, and all of the ROE witnesses in this case have relied on proxy groups to estimate a
required ROE for ETI.

        ETI witness Hadaway started with all the vertically integrated electric utilities that are
included in the Value Line Investment Survey (Value Line). To improve the group's comparability
with ETI, which has a senior secured bond ratings of BBB+ (Outlook Negative) from Standard &

208
    Federal Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591, 603, 64 S. Ct. 281, 288 (1944); see also
Bluefield Waterworks &Improvement Co. v. Public Serv. Comm'n ofW. Va., 262 U.S. 679, 692-93, 43 S. Ct.
675, 679 (1923) ("A public utility is entitled to such rates as will pennit itto earn a return on the value of the
property which it employs for the convenience of the public equal to that generally being made at the same
time and in the same general part of the country on investments in other business undertakings which are
attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are
realized or anticipated in highly profitable enterprises or speculative ventures. The return should be reasonably
sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient
and economical management, to maintain and support its credit and enable it to raise the money necessary for
the proper discharge of its public duties.").
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Poor's (S&P) and Baa2 (stable) rating from Moody's Investors Service (Moody's), Dr. Hadaway
imposed the following restrictions:

•   comparable companies had to have senior secured bond ratings of at least BBB by S&P or Baa
    by Moody's;

•   comparable companies had to derive at least 70 percent of revenues from regulated utility sales;

•   comparable companies had to have consistent financial records not affected by recent mergers or
    restructuring; and

•   comparable companies had to have a consistent dividend record with no dividend cuts or
    resumptions during the past two years.

Those selection criteria resulted in a 23-utility proxy group.

        State Agencies witness Miravete excluded Entergy from his proxy group, but otherwise his
proxy group was identical to ETI' s.        Cities witness Parcell ran his calculations using both
Dr. Hadaway' s 23-utility proxy group and another 8-utility proxy group, but they produced similar
ROE results. TIEC witness Gorman used the same 23 utility proxy group as ETI witness Hadaway
used.

        Staff witness Cutter was the only witness to use a different proxy group. He used a 13 utility
proxy group for his discounted cash-flow (DCF) analysis. To arrive at this proxy group, Mr. Cutter
started with all of the domestic electric-utility companies tracked by Value Line because Value Line
is the most widely used, independent investment service in the world.        Then he eliminated the
utilities that did not meet the following criteria:

•   Value Line Financial Strength ratings of A+, A or B++;

•   A capital structure including less than 45 percent, or more than 55 percent, debt;

•   Total capitalization in excess of five billion dollars;

•   No recent dividend cuts or omissions;
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•   No recent or potential merger activities or other major capital expansion; and

•   No Value Line appraisal of being outside the norm.

On his final analysis, Mr. Cutter eliminated three of his 13 utility proxy group, referring to those he
eliminated as "outliers." ETI points out, however, that one of the remaining ten companies, Con Ed,
is not comparable to ETI because it is a delivery company as opposed to a vertically integrated
utility. ETI' s essential criticism of Mr. Cutter's proxy group analysis is that he should have used a
larger proxy group and that he admitted a better comparison to ETI could be obtained from using a
larger proxy group.

       2. DCF Analysis

       To analyze ETI's cost of equity capital, all of the testifying experts first performed a DCF
analysis. The DCF approach is based on the theory that a stock's current price represents the present
value of all expected future cash flows. In its most general form, the DCF model is expressed as
follows:

                                                D1           D2     D 00
                                     Po   = (1 + k) + (1 + k) + (1 + k)

Where Po represents the current stock price, D1 • ••• Doo are all expected future dividends, and k is
the expected discount rate, or required ROE. That equation can be simplified and rearranged to
ascertain the required ROE:

                                                D(l   + g)
                                           k=                +g
                                                     Po

Where Po represents the current stock price, Dis expected future dividends, g is the growth rate, and
k is the expected discount rate, or required ROE.

       This is commonly referred to as the "Constant Growth DCF' model in which the first term is
the expected dividend yield and the second term is the expected long-term growth rate. The
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Constant Growth DCF model requires assumptions of: (1) a constant growth rate for earnings and
dividends; (2) a stable dividend payout ratio; (3) a constant price-to-earnings multiple; and (4) a
discount rate greater than the expected growth rate.

          ETI witness Hadaway' s DCF analysis was based on three versions of the DCF model. In the
first version of the DCF model, he used the constant growth format with long-term expected growth
based on analysts' estimates of five-year utility earnings growth. In the second version of the DCF
model, for the estimated growth rate, Dr. Hadaway used only the long-term estimated gross domestic
product (GDP) growth rate. In the third version of the DCF model, Dr. Hadaway used a two-stage
growth approach, with stage one based on Value Line's three-to-five-year dividend projections and
stage two based on long-term projected growth in GDP. The dividend yields in all three of the
annual models are from Value Line's projections of dividends for the coming year and stock prices
are from the three-month average for the months that correspond to the Value Line editions from
which the underlying financial data are taken. 209

          The DCF results for Dr. Hadaway' s comparable company group using the traditional constant
growth model indicated an ROE of 9. 90 percentto 10.00 percent. Dr. Hadaway then recalculated the
constant growth results with the growth rate based on long-term forecasted growth in GDP. With the
GDP growth rate, the constant growth model indicates an ROE range of l 0.40 percent to
10.70 percent. Although the GDP growth rate is higher than the average of analysts' growth rates,
Dr. Hadaway testified that his GDP estimate is within the analysts' range and slightly below the
6.00 percent 3-to-5 year average growth rate projection from Value Line. Finally, Dr. Hadaway's
multistage DCF model indicated an ROE range of 10.20 percent to 10.30 percent. The results from
the DCF model, therefore, indicate an ROE range of 9. 90 percentto 10. 70 percent.210 In his rebuttal,
Dr. Hadaway updated his ROE analysis using current market conditions but employing the same
methodologies that he used in his previous analysis. After making adjustments to the proxy group to

209
      ETI Ex. 6 (Hadaway Direct) at 33-44.
210
      Id. at 44, Exhibit SCH-4.
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stay consistent with his selection criteria, Dr. Hadaway' s indicated DCF range was 10.00 percent to
10.20 percent. 211

           The principal argument against Dr. Hadaway's analyses is that he used unsupported and
excessive growth rates. According to the intervenors, these excessive growth rates exaggerate future
cash flows, which results in an inflated ROE.

           Intervenors argue that Dr. Hadaway' s Analysts' Constant Growth DCF model produces
excessive return estimates.212 In rebuttal, Dr. Hadaway's analysts' growth model produced a
10.1 percent group average ROE and a 10.0 percent group median ROE. 213 The intervenors contend
that the group average long-term growth rate on which his DCF study was based was 5.62 percent,
which is far too high to be sustainable in the long-term (as required as an input in the Constant
                           214
Growth DCF model).               According to intervenors, the excessive level of his growth rate is apparent
by comparison to current analysts' projected growth for U.S. GDP, which range from 4.5 percent to
5.0 percent. 215 Dr. Hadaway's growth rate is more than 60 basis points above the most generous
expected growth of the U.S. economy. Intervenors contend that that nominal GDP should be the
ceiling of a reliable proxy for a utility dividend growth rate. Because the evidence shows that
nominal GDP as projected by consensus analysts, the Executive Branch, and the Congressional
Budget Office is 5 percent, Dr. Hadaway' s 5.62 percent growth rate is excessive and undermines the
reasonableness of his models.

           Intervenors criticize Dr. Hadaway's decision on rebuttal to exclude Edison International in
                     216
his proxy group.           Dr. Hadaway did so because Edison International's ROE of 5.2 percent was
below a 5.07 percent cost of debt based on an average of Triple B utility rates for the time period

211
      Id. at 44.
212
      TIEC Ex. 2 (Gorman Direct) at 39.
213
      ETI Ex. 52 (Hadaway Rebuttal) at Ex. SCH-R-6.
214
   Id. at Ex. SCH-R-6; TIEC Ex. 2 (Gorman Direct) at 39; Cities Ex. 3 (Parcell Direct) at 36-37; OPC Ex. 1
(Szerszen Direct) at 23-24.
215
      TIEC Ex. 2 (Gorman Direct) at 19; Cities Ex. 3 (Parcell Direct) at 37.
216
      ETI Ex. 51 (Hadaway Rebuttal) at Ex. SCH-R-6.
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January 12-March 12, plus 100 basis points. 217 Intervenors contend that this rationale is tenuous, and
that had Dr. Hadaway included Edison International (or even excluded Hawaiian Electric, the utility
in his proxy group that had the highest ROE) his own analysis (even with its excessive growth rates)
would have resulted in a 9.85 percent average ROE.

            Finally, Dr. Hadaway conceded that he used the same methodology for calculating GDP in
this case as he did in the Oncor rate case. 218 Intervenors contend that Dr. Hadaway's GDP
projections are not credible proxies for investor's expected dividend growth rates because they are
not based on published analysts' or government GDP forecasts. Rather, Dr. Hadaway forecasts
future GDP growth using his own personal calculation that forecasts GDP by examining historic
GDP growth over the last 10, 20, 30, 40, 50, and 60-year periods and weighting those averages. 219
Intervenors note that this approach was rejected by the Commission in the Oncor rate case. 220

            Staff witness Cutter used the DCF model to project ETI' s cost of equity. Under Mr. Cutter's
view, the theory underlying the DCF model is that the price of a share is equal to the present value of
all future earnings. Unless the stock is sold for a profit (or loss) from the price it was originally
purchased, the only way to determine earnings on a share is to determine its future dividends. This
requires, in Mr. Cutter's opinion, an understanding of investors' current expectations of growth of
those dividends. The issue is the growth expectation that investors have embodied in the current
price of the stock. According to Mr. Cutter, the best way to arrive at a reliable growth estimate of
those dividends is to use the growth estimates of investment advisory firms rather than the estimates
of a single, independent analyst. 221

            Mr. Cutter used both Value Line and Zacks Investment Service (Zacks) in ascertaining
long-term earnings growth rates. He used Value Line because it is the most widely used independent

211   Id.
218
      Tr. at 227-228.
219
      ETI Ex. 6 (Hadaway Direct) at Ex. SCH-3; Tr. at 218.
220
  Application of Oncor Electric Delivery Company, UC, for Authority to Change Rates, Docket No. 35717,
PFD at 72-73.
                                                                                      ~   ·---------------

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investment service in the world and Zacks because it compiles consensus earnings forecasts from
                                              222
groups of professional security analysts.

          Mr. Cutter's DCF analysis resulted in range from 7.46 percent to 10. 71 percent, with a point
estimate for cost of equity being 9.3 percent.

          TIEC witness Gorman' s first DCF model was a constant growth model using consensus
analysts' growth rates that resulted in an average constant growth DCF of 9 .32 percent and a median
constant growth DCF of 9.84 percent. The average analysts' growth rate was 4.94 percent. 223
According to TIEC, ETI does not claim that a constant growth model using analysts' growth rates is
inappropriate and argues that Dr. Hadaway failed to offer any rebuttal testimony criticizing
Mr. Gorman's Analysts' Growth DCF model.

          Mr. Gorman also performed a constant growth DCF model using sustainable growth rates.
His average sustainable growth rate for the proxy group was 4.54 percent and produced a proxy
group average and median DCF result of 8.91 percent and 8.9 percent, respectively. 224 According to
TIEC, a sustainable growth rate is based on the percentage of a utility's earnings that are retained and
reinvested in utility plant and equipment. 225

          Mr. Gorman also performed a multi-stage DCF model to reflect changing growth
expectations that would reflect the possibility of non-constant growth for a company over time.
Mr. Gorman's multi-stage model reflected three growth periods: (1) a short-term growth period of
five years; (2) a transition period for years six through ten; and (3) a long-term growth period,
starting in year 11 through perpetuity. For the short-term period, Mr. Gorman relied on the
consensus analysts' growth projections from his constant growth DCF model (i.e., 4.94 percent). For

221
      Staff Ex. 6 (Cutter Direct) at 10-15.
222
      Staff Ex. 6 (Cutter Direct) at 13.
223
      TIEC Ex. 2 (Gorman Direct) at Ex. MPG-4.
224
      TIEC Ex. 2 (Gorman Direct) at 18.
225
      TIEC Ex. 2 (Gorman Direct) at 17.
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the second stage (i.e., the transition period), growth rates are reduced or increased by an equal factor,
which reflect the difference between the analysts' growth rates and the GDP growth rate. For the
long-term period, he assumed the maximum sustainable growth rate for a utility company as proxied
by the consensus analysts' projected growth rate for the U.S. GDP (i.e., 5.0 percent). The result of
his multi-stage growth DCF model was an average ROE of 9.37 percent and a median of
9.48 percent. 226

           Cities witness Parcell calculated the DCF results for each company in his proxy group by
using and considering five indicators of growth expectations consisting of: (i) 2007 -2011 earnings
retention; (ii) five-year historical average earnings per share, dividends per share, and book value per
share; (iii) projected earnings retention; (iv) projected EPS, DPS, BVPS; and (v) projected EPS as
reported by Yahoo Finance. Using this in his DCF model resulted in an ROE of 9.0 percent to
9 .5 percent. 227

           OPC witness Szerszen' s DCF analysis used the same group of 23 comparable companies
included in Dr. Hadaway's DCF analysis.                Dr. Szerszen's DCF analysis was framed with
consideration of ETI' s financial integrity as discussed by the major bond rating agencies, the current
and projected interest rate environment, and investment analyst views of the regulated utility
sector. 228 Interest rates are currently very low, as reflected in the yields to maturity and interest rates
on various fixed income investments. OPC contends, in contrast to Dr. Hadaway, that utility stocks
have been less volatile than the stock market in general.2 29 This is confirmed by Value Line's
December 23, 2011, observation that "electric utility stocks have long been viewed as a safe haven in
volatile markets, due in large part to their generous dividend yields."230 Dr. Szerszen also took
exception to Moody's characterization of ETI as having above average business and regulatory risk.
Moody's assessment is primarily based on the lack of pass-through regulatory lag-reducing cost

226
      TIEC Ex. 2 (Gorman Direct) at 19, Ex. MPG-9.
227
      Cities Ex. 3 (Parcell Direct) at 24, 33.
228
      OPC Ex. l (Szerszen Direct) at 8-17.
229
      Id. at 15.
230   Id.
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recovery mechanisms in Texas compared to Entergy's Louisiana and Mississippi jurisdictions. Dr.
Szerszen testified that ETI may not have a formula rate plan similar to the Louisiana and Mississippi
Entergy operating companies, but it does have a Distribution Cost Recovery Factor (DCRF) and
Transmission Cost Recovery Factor (TCRF) available that "will allow ETI to charge ratepayers for
additional distribution and transmission investments outside of a traditional rate request filing."231
None of Entergy' s other operating companies have TCRF and DCRF riders. OPC notes that Cities
witness Parcell agrees that the availability of such recovery mechanisms affects ETI' s level of risk;
he testified that a combination of ETI' s fuel factor rider, TIC rider, energy efficiency rider, hurricane
cost recovery rider, rate case expense rider, proposed increased customer service charge, and DCRF
and TCRF riders results in about 30 percent of ETI' s total overall requested revenue requirement
being subject to revenue risk and regulatory lag. 232

          Dr. Szerszen incorporated two different dividend yield calculations in her DCF model. The
first calculation estimated a dividend yield using 2011 average stock prices and 2012 projected
dividend rates for each company, and the second calculation incorporated more recent March 5,
2012, closing prices for the comparables. The average dividend yield using 2011 average stock
prices was 4.66 percent and, using March 5, 2012, closing prices, was 4.32 percent.233

          Dr. Szerszen provided some practical examples of how blind reliance on analyst earnings
growth projections can lead to questionable DCF growth rates. At least five of the comparable utility
companies had five-year earnings growth rate projections that ranged from 8.5 percent to 11 percent.
Dr. Szerszen stated that she was unaware of any regulated utility company that has consistently
achieved such high earnings growth rate over the past 28 years, and that it is reasonable to assume
such performance is unlikely in the longer term future. Dr. Szerszen's review of the comparable
company past and projected growth rates resulted in a reasonable dividend growth rate expectation of
3.9 percent to 5 percent. Depending on whether 2011 average stock prices are used or the updated

231
      Id at 11-13.
232
      Cities Ex. 3 (Parcell Direct) at 16-18.
233
      OPC Ex. 1 (Szerszen Direct) at 17.
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2012 stock prices are used, Dr. Szerszen's DCF analysis resulted in an ROE ranging from
8.32 percent to 9.32 percent.234

           State Agencies' witness Miravete's DCF analysis used calculations for three averaging
periods, 30, 90 (the reference period), and 180 days ending on March 2, 2012, respectively. For the
commonly used 90 day averaging period, the capitalization-weighted average ROE is 9.23 percent.
Evaluating the averaging period at either 30or180 days produces ROE estimates of9.24 percent and
9.34 percent, respectively. Dr. Miravete weighed the computations by the capitalization of each firm
to correct the effect of each variable according to the relative market value of the corresponding
utility. According to Dr. Miravete, this approach avoids the distortion caused by adding numerous,
but possibly irrelevant, firms that may produce biased estimates. Dr. Miravete conceded that the
effect of ignoring differences in scale of utilities in the determination of the ROE is substantial. He
acknowledged that if he had ignored the differences in size of these electric utilities, his DCF ROE
estimate would have been 9 .68 percent. 235

           3. Risk Premium Analysis

           Dr. Hadaway's risk premium studies are divided into two parts. First, he compared electric
utility authorized ROEs for the period 1980-2010 to contemporaneous long-term utility interest rates.
The differences between the average authorized ROEs and the average interest rate for the year is the
indicated equity risk premium. He then added the indicated equity risk premium to the forecasted
and current triple-B utility bond interest rate to estimate ROE. 236

           In calculating the equity risk premium, Dr. Hadaway adjusted for the inverse relationship
between equity risk premiums and interest rates (when interest rates are high, risk premiums are low
and vice versa). Dr. Hadaway provided regression analyses of the allowed annual equity risk
premiums relative to interest rate levels. The negative regression coefficients confirm the inverse

234
      Id. at 22.
235
      State Agencies Ex. 1 (Miravete Direct) at 12-13.
236
      ETI Ex. 6 (Hadaway Direct) at 36-38, 45.
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relationship between equity risk premiums and interest rates according to ETI. Dr. Hadaway used
that negative interest rate change coefficient in conjunction with current and forecasted interest rates
to establish the appropriate ROE. 237 Staff witness Cutter agreed that the risk premium analysis needs
to reflect this adjustment. 238

           The results of Dr. Hadaway' s initial equity risk premium studies indicate an ROE range of
10.00 percent to 10.01 percent. ETI states that these results reflect the sharp drop in interest rates
that have occurred for high quality borrowers. The Federal Reserve System's continuing "easy
money" policies have provided renewed liquidity in the credit markets that is reflected in these lower
yields. These models, however, cannot capture the current equity volatility or the increased level of
risk aversion for equity investors. These circumstances indicate that the cost of equity has not
declined to the extent that interest rates on utility debt have dropped. Thus, Dr. Hadaway testified
that the results of the risk premium analysis must be discounted and more emphasis placed on the
                   239
DCF analysis.

           In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but
employing the same methodologies that he used in his previous analysis. 240 His updated risk
premium analysis was an ROE of 10.38 percent using projected triple-B utility interest rates and
9.96 percent using current triple-B utility interest rates. 241

           TIEC contends that Dr. Hadaway' s utility risk premium analysis is flawed for two primary
reasons. First, Dr. Hadaway developed a forward-looking risk premium model that relied on
forecasted interest rates and volatile utility spreads that are uncertain and produce inaccurate results.
As Mr. Gorman testified, it is more reasonable at this time to rely on current observable interest rates
rather than forecasted projections. Over the last several years, forecasted yield projections have

237
      ETI Ex. 6 (Hadaway Direct) at 45-46, Ex. SCH-5; ETI Ex. 52 (Hadaway Rebuttal) at 32.
238
      Staff Ex. 6 (Cutter Direct) at 20.
239
      ETI Ex. 6 (Hadaway Direct) at 10-23, 45; Tr. at 233-235.
240
      ETI Ex. 52 (Hadaway Rebuttal) at 44.
241
      Id. at 45.
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proven to be overstated because, even though interest rates have been projected to increase, those
projections have consistently been proven wrong. 242 Accordingly, Dr. Hadaway' s forecasted utility
bond yield of 5.17 percent is overstated.

          Second, TlEC argues that Dr. Hadaway's risk premium model is flawed because he
improperly inflates his actual risk premium of 3.28 percent with an adjustment of 1.56 percent that
he asserts reflects the inverse relationship between interest rates and utility risk premiums. 243 TlEC
argues that Dr. Hadaway's use of this adjustment is improper and not supported by academic
research. Mr. Gorman testified that "a relative investment risk differential cannot be measured
simply by observing nominal interest rates."244 He noted:

          While academic studies have shown that, in the past, there has been an inverse
          relationship with these variables, researchers have found that the relationship changes
          over time and is influenced by changes in perception of the risk of bond investments
          relative to equity investments, and not simply changes to interest rates. 245

          As described in Mr. Gorman's testimony, correcting Dr. Hadaway's models for the
elimination of this inverse relationship adjustment puts Dr. Hadaway' s risk premium in the range of
8.5 percent to 10 percent, with a midpoint of 9.3 percent. 246

          Staff witness Cutter's "conventional risk premium estimate" estimated the cost of ETI's
equity by comparing the costs of equity authorized for utilities across the United States to the yields
of large-company corporate bonds that are rated Baa by Moody's within the timeframe of 1980
through 2011. This risk premium approach relies on the historical relationship between two indices

242
      TIEC Ex. 2 (Gorman Direct) at 42-43; OPC Ex. !(Szerszen Direct) at 27-28.
243
      TIEC Ex. 2 (Gorman Direct) at 42-43; see also ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5 at 1.
244
      TIEC Ex. 2 (Gorman Direct) at 44.
245
    TIEC Ex. 2 (Gorman Direct) at 44 (citing "The Market Risk Premium: Expectational Estimates Using
Analysts' Forecasts," Robert S. Harris and Felicia C. Marston, Journal ofApplied Finance, Volume 11, No. 1,
2001 and "The Risk Premium Approach to Measuring a Utility's Cost of Equity," Eugene F. Brigham, Dilip
K. Shome, and Steve R. Vinson, Financial Management, Spring 1985).
246
      TIEC Ex. 2 (Gorman Direct) at 45.
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to forecast a value for one of the indices in a period for which it is unknown by using the known
                                                    247
value of the other one during that same period.

          To account for the relationship between the authorized costs of equity and the bond yields
required to quantify ETI's cost of equity, Mr. Cutter subtracted the bond yields from the authorized
costs of equity to determine a risk premium for the riskier equity. He tested the data by performing a
regression analysis, which showed with high confidence that there is a trend in the relationship. It is
an inverse trend, in which the risk premiums increase as bond yields decrease. On average, from
1980 to 2011, risk premiums increased 0.4207 percent for every 1.00 percent that bond yields
              248
decreased.

          The calculation of the adjustment to the risk premium that the regression analysis indicated
was incorporated in Staffs analysis. The results of this risk premium analysis produced a cost of
equity of 9.81 percent. 249

          Mr. Gorman' s risk premium analysis produced an ROE estimate in the range of 9.2 percent to
9 .4 percent, with a midpoint estimate of approximately 9 .3 percent. His risk premium model was
based on two estimates of an equity risk premium. First, he estimated the difference between the
required return on utility common equity investments and U.S. Treasury bonds for the period 1986
through 2011, which produced an equity risk premium of 5.23 percent. The second equity risk
premium estimate was based on the difference between regulatory commission-authorized returns on
common equity and contemporary "A" rated utility bond yields for the period 1986 through 2011,
which produced an equity risk premium of 3.8 percent. Mr. Gorman testified that "[t]he equity risk
premium should reflect the relative market perception of risk in the utility industry today." 250

247
      Staff Ex. 6 (Cutter Direct) at 10, 19.
248
      Staff Ex. 6 (Cutter Direct) at 20.
249
      Id. at 20, Attachment SC-6.
250
      TIEC Ex. 2 Gorman Direct) at 26.
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Accordingly, to gauge investor expectations he examined the yield spread between utility bonds and
Treasury bonds over the last 32 years. 251

           According to TIEC, this analysis showed that the current utility bond yield spreads over
Treasury bond yields are lower than the 32-year average spreads, which is evidence that "the market
considers the utility industry to be a relatively low risk investment and demonstrates that utilities
continue to have strong access to capital."252 Mr. Gorman then added a projected long-term Treasury
bond yield to his estimated equity risk premium over Treasury yields, which produced a common
equity in the range of 8.2 percent to 9.95 percent. Due to unusually large yield spreads between
Treasury bond and "Baa" utility bond yields, Mr. Gorman gave two-thirds weight to his high end risk
premium of 9.95 percent and one-third weight to his low-end risk premium of 8.2 percent, which
produced an equity risk premium of 9 .4 percent. He also added his equity risk premium over utility
bond yields to the current 13-week average yield on "Baa" rated utility bonds for the period ending
March 2, 2012, of 5.05 percent. Adding his equity risk premium of 3.03 percent to 4.62 percent to
the bond yield of 5 .05 percent, produced an ROE in the range of 8.08 percent to 9 .67 percent, which
he then weighted more heavily on the high end estimate to produce a recommendation of
9 .2 percent. 253

           The primary criticism that Dr. Hadaway lodged against Mr. Gorman' s risk premium analysis
was that Mr. Gorman did not adjust his analysis upward to reflect a purported inverse relationship
between equity risk premiums and interest rates. 254 For example, Dr. Hadaway's risk premium
analysis adjusted his risk premium results by 1.56 percent to account for this relationship. 255

           OPC witness Szerszen also performed a risk premium analysis, using Dr. Hadaway' s study of
historical authorized electric company allowed returns on equity and average bond yields. The

251
      Id. at 25-28.
252
      Id. at 27.
253
      TIEC Ex. 2 (Gonnan Direct) at 26-28.
254
      ETI Ex. 52 (Hadaway Rebuttal) at 32.
255
      ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5.
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average risk premium from Dr. Hadaway's 1980-2010 study was 328 basis points.256 Adding this
historical risk premium to current triple B bond yield (4.67 percent) results in a 7.95 percent
risk-premium derived DCF rate, and using Dr. Hadaway' s 5 .17 percent projected bond yield results
in a risk premium derived rate of 8.45 percent. Giving more weight to the 2001-2010 risk premiums
shown in Dr. Hadaway's exhibit results in an average risk premium of 4.21 percent. This yields an
8.88 percent to 9.38 percent risk premium derived cost of equity based on the current 4.67 percent
and projected 5.17 percent bond yields, according to Dr. Szerszen's analysis.2s 7

           4. Comparable Earnings

           Cities witness Parcell also performed a Comparable Earnings analysis. According to
Mr. Parcell, the Comparable Earnings method is derived from the "corresponding risk" standard of
the Bluefield and Hope cases. This method is thus based upon the economic concept of opportunity
cost. The cost of capital is an opportunity cost: the prospective return available to investors from
alternative investments of similar risk. 258

           The Comparable Earnings method is designed to measure the returns expected to be earned
on the original cost book value of similar risk enterprises. Thus, according to Mr. Parcell, this
method provides a direct measure of the fair return, because the Comparable Earnings method
translates into practice the competitive principle upon which regulation is based. 259

           The Comparable Earnings method normally examines the experienced and/or projected
returns on book common equity. The logic for examining returns on book equity follows from the
use of original-cost, rate-base regulation for public utilities, which uses a utility's book common
equity to determine the cost of capital. This cost of capital is, in tum, used as the fair rate of return
which is then applied (multiplied) to the book value of rate base to establish the dollar level of

256
      ETI Ex. No. 6 (Hadaway Direct) at Ex. SCH-5.
257
      OPC Ex. 1 (Szerszen Direct) at 29-30.
258
      Cities Ex. 3 (Parcell Direct) at 28.
259
      Id. at 29.
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capital costs to be recovered by the utility. Mr. Parcell stated that this technique is thus consistent
with the rate base methodology used to set utility rates. 260

            Mr. Parcell conducted the Comparable Earnings methodology by examining realized returns
on equity for several groups of companies and evaluating the investor acceptance of these returns by
reference to the resulting market-to-book ratios. He testified that in this manner it is possible to
assess the degree to which a given level of return equates to the cost of capital.

            Mr. Parcell's Comparable Earnings analysis is based on market data (through the use of
market-to-book ratios) and is thus essentially a market test. As a result, he testified that his analysis
is not subject to the criticisms occasionally made by some who maintain that past earned returns do
not represent the cost of capital. In addition, he stated that his analysis uses prospective returns and
thus is not confined to historical data. 261

            Mr. Parcell' s Comparable Earnings analysis considered the experienced equity returns of the
proxy groups of utilities for the period 1992-2011 (i.e., the last twenty years). His Comparable
Earnings analysis required an examination of a relatively long period of time to determine trends in
earnings over at least a full business cycle. Further, in estimating a fair level of return for a future
period, it is important to examine earnings over a diverse period of time to avoid any undue influence
from unusual conditions that may occur in a single year or shorter period. Therefore, in forming his
judgment of the current cost of equity he focused on two periods: 2002-2011 (the recent business
cycle) and 1992-2001 (the prior business cycle). 262

            Based on the recent earnings and market-to-book ratios, Mr. Parcell' s Comparable Earnings
analysis indicated that the cost of equity for the proxy utilities is no more than 9.5 percent to
10.0 percent (9.75 percent mid-point). Recent returns of 10.0 percent to 12.1 percent have resulted
in market-to-book ratios of 143 and greater. Prospective returns of9.5percentto10.3 percent result

260   Id.
261
      Cities Ex. 3 (Parcell Direct) at 29.
262
      Id. at 30.
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in anticipated market-to-book ratios of over 125. As a result, it is apparent that returns below this
level would result in market-to-book ratios of well above 100. According to Mr. Parcell, an ROE of
9.5 percent to 10.0 percent should thus result in a market-to-book ratio of well over 100 .263

          5. CAPM Analysis

          The Capital Asset Pricing Model (CAPM) is a risk premium approach that estimates the ROE
for a given security as a function of a risk-free return plus a risk premium to compensate investors
for the non-diversifiable, or systematic, risk of that security. The CAPM formula is as follows:

Where Ke equals the required market ROE; f3 equals the Beta of an individual security; r1equals the
risk free rate of return; and rm equals the required return on the market as a whole. In this equation,
(rm - r1) represents the market risk premium. According to the theory underlying the CAPM, because
diversifiable risk can be diversified away, investors should be concerned only with non-diversifiable
risk, which is measured by Beta. In effect, Beta represents the risk of the particular security relative
to the market as a whole.

          Only Staff witness Cutter, Cities witness Parcell, and State Agencies witness Miravete used
the CAPM methodology to estimate ETI's ROE.

          Mr. Cutter used CAPM in the qualitative analysis of ETI' s cost of equity. He did not directly
use the CAPM in the determination of ETI' s cost of equity because it yielded a cost of equity that
was over 200 basis points lower than the lower of the other two estimates, while those other two
estimates were less than half a percent apart from each other. 264 The CAPM provides an additional
indication that a significant drop to the estimated costs of equity that Staff made in prior dockets is

263
      Cities Ex. 3 (Parcell Direct) at 31-32.
264
      Staff Ex. 6 (Cutter Direct) at 21.
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appropriate because the CAPM estimate is lower than either of the two other approaches even when
adjusted for the current low yield on Treasury Bonds. 265

            Mr. Cutter testified that the CAPM is one of the cornerstones of financial theory. 266 In its
simplest sense, the model describes the relationship between the risk of an asset and its expected
return, and assumes that investors will not hold a risky asset unless they are adequately compensated
for the risk. 267

            In this case, without any adjustment to the way it has been used in recent rate cases at the
Commission, the CAPM yielded a cost of equity for ETI of 6.93 percent. Mr. Cutter testified that
aspects of the capital markets today were likely causing the CAPM's cost of equity estimate to be
low. Specifically, the Federal Reserve System is following an aggressive policy designed to keep the
yields of both short-term and long-term Treasury bonds low. This policy influences two of the three
variables used in the CAPM formula to be lower, which, in tum, makes the CAPM's final estimate
of ETI' s cost of equity lower. 268

            To account for the impact of this aggressive Federal Reserve System policy, Mr. Cutter made
two adjustments to his CAPM analysis. First, Mr. Cutter adjusted the risk-free rate variable in the
CAPM because it is most influenced by current Federal Reserve System policy. By changing this
variable to 3.7 percent (which is the average yield from 1926 through 2010 of the risk-free rate's
proxy security, U.S. Treasury Bills), the CAPM's estimate of ETI's cost of equity increased from
6.93 percent to 7.92 percent, or by 99 basis points. 269

            The second adjustment to the CAPM result that Mr. Cutter made to account for the current
aggressive Federal Reserve System policy was to the risk premium, which is also particularly

265   Id.
266   Id.
261   Id.
268
      Staff Ex. 6 (Cutter Direct) at 21-24.
269
      Id. at 24.
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sensitive to Federal Reserve System policy. By using the difference between the averages of the
yield of long-term government bonds and the yield of large company stocks between 1926and2010,
the effect of Federal Reserve System policy on the risk premium was significantly diluted.
Mr. Cutter found that because the CAPM estimate of ETI' s cost of equity was excessively low, even
with adjustments for Federal Reserve System policy, it would be appropriate to further adjust it by
multiplying the unadjusted estimate plus two times the effect of adjusting the risk-free rate, or:
6.93 percent+ (2 * 0.99 percent)= 8.91 percent. 270 It is important to note, however, that Mr. Cutter
used the CAPM analysis only as a qualitative check on its DCF and risk premium analyses, not as an
independent source of analysis.

          Although Cities witness Parcell did perform a CAPM analysis, he does not employ the
CAPM results in arriving at his 9.0 percent to 10.0 percent range of results. 271

          State Agencies witness Miravete used the daily average of the yield of the ten-year Treasury
bond between December 1, 2011, and March 2, 2012, as reported by the Board of Governors of the
Federal Reserve System, as his risk-free return in his CAPM model. He used Value Line's most
recent betas for the regulated utilities included in the proxy group. Dr. Miravete corrected the betas
by substituting an average between their value and LO to recognize that markets trend towards
long-term equilibrium because these regulated utilities were able to attract investors during the most
troubled times, which indicates that the perceived market risk of these utilities is lower than for other
firms. Dr. Miravete's capitalization-weighted average CAPM ROE is 7.64 percent on a 90 days
averaging period, with a range between 7.64 percent (30 days) and 8.28 percent (180 days).
Dr. Miravete characterizes these estimates as low relative to those of the DCF model because of the
low yields of Treasury bonds after the implementation of the quantitative easing monetary policy
over the past two years. 272

270
      Id. at 21, 24-25.
271
      Cities Ex. 3 (Parcell Direct) at 3, 25-28.
272
      State Agencies Ex. 1 (Miravete Direct) at 19-21.
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       6. ALJs' Analysis

       Given the detail, time, and effort that went into the various experts' testimony on this issue,
one might easily conclude that the development of an estimated ROE is a precise science. But, as
acknowledged by virtually all experts on the subject, estimating the cost of equity is not an exact
science but rather a result of informed judgment.

       The first question that must be addressed is the appropriate proxy group. There were
essentially only two competing views on this issue- one presented by Dr. Hadaway and the other by
Mr. Cutter. The ALJs have reviewed the evidence and the arguments of both sides with respect to
the composition of the proxy group. Although Staff's proxy group could, in some respects, be
considered more comparable to ETI than Dr. Hadaway' s larger group, the Al.J s do not believe that
this overcomes the flaws inherent in such a small group. In the end, a group of nine companies,
while comparable, simply does not provide a robust enough sample to create a valid group for
comparison. The Al.J s therefore find that the 23 utility group selected by ETI witness Hadaway is
the appropriate proxy group.

       The next issue is the core issue to be decided: the appropriate ROE for ETI. The experts in
this case testified to the following ROE ranges or estimates, depending on the calculation
methodology employed:

           Witness/Analvsis                   Ranee           Ultimate Recommendation
      Hadaway - DCF                       9.9 10.7                       10.6
      Hadaway - Risk Premium              9.96 10.38
                                                                                             -
      Cutter-DCF                          7.46-10.71                        9.6
      Cutter - Risk Premium               9.81
      Cutter - CAPM                       8.91

      Gorman-DCF                          9.3-9.7                           9.5
      Gorman Risk Premium                 9.2-9.4

      Parcell - DCF                       9.0 9.5                           9.5
      Parcell - Comparable Earnings       9.5-10.0
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               Witness/Analysis                   Ranee        Ultimate Recommendation
         Szerszen - DCF                       8.32 9.32                   9.3
         Szerszen - Risk Premium              9.3

         Miravete - DCF                       9.23-9.34                     9.3
         Miravete CAPM                        7.64- 8.28

Just focusing on the ultimate ROE recommendations, it is clear that there is a fairly tightly grouped
range when considering Staff and the intervenors. This ranges from a low of 9 .3 percent to a high of
9 .6 percent. The range expands when it is considered that Staff witness Cutter did not contest ETI' s
assertion that Staffs DCF recommended ROE would be 10.0 percent if he had used the same proxy
group as the other witnesses. 273 The ALls believe that the criticisms leveled at Dr. Hadaway's ROE
recommendation are generally correct, certainly to the point that the ultimate recommendation is so
high as to be an outlier. The ALJ s conclude that the proper range of acceptable ROEs would be from
9.3 percent to 10.0 percent. This is actually confirmed by ETI's own witness, Mr. Barrileaux, who
testified that, from a cash flow metric standpoint, an ROE of 9.99 percent would provide "a
reasonable outcome that balances debt and equity financing." 274

          The mid-point of the range discussed above is 9.65 percent. There has been a tremendous
amount of testimony about the unsettled economic conditions facing utilities and the effect of those
conditions on the appropriate ROE. The ALJs believe that this is an effect that must be taken into,
account, and that the effect would be to move the ultimate ROE towards the upper limits of the range
determined to be reasonable. In this case, the ALJ s find that the reasonable adjustment would be
15 basis points, moving the reasonable ROE to 9.80 percent. Accordingly, the ALls recommend that
the Commission find that 9.80 percent is the appropriate ROE for ETI.

273
      Tr. at 1795.
274
      ETI Ex. 44 (Barrileaux Rebuttal) at 5, Ex. CEB-R- L
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C.        Cost of Debt

          ETI' s weighted average cost of debt at the end of the test year was 6. 74 percent. 275 No party
has taken issue with that cost of debt. Therefore, the ALl s recommend that the Commission enter an
order finding that the appropriate cost of debt for ETI is 6.74 percent.

D.        Overall Rate of Return

          The overall rate of return is a product of the capital structure, ROE, and cost of debt. Based
on the discussions set forth above, the ALls recommend that the Commission adopt the following
overall rate of return for ETI:

                                                                                    Weighted
           Component                    Cost                   Weif!htin2            Cost
          Debt                          6.74                     50.08%                3.38
          Equity                        9.80                     49.92%                4.89
          Overall                                                                      8.27

  VII.      OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4,
                                     and 16]

A.        Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order
          Issue No.1]

          One of the most hotly contested issues in this case concerned the appropriate size of ETI' s
purchased power capacity costs (PPCCs). In order to understand this issue, it is necessary to
understand some background relative to how ETI obtains and uses power generation capacity.

          1. The Sources of ETI's Purchased Power

          The Entergy System Agreement is a FERC-approved tariff that mandates that the Operating
Companies operate as a single, integrated system. 276 The System Agreement's essential function is
to provide the contractual basis for the planning, construction, and operation of generation and

275
      ETI Ex. 5 (Barrilleaux Direct) at 37.
276
      ETI Ex. 30 (Jaycox Direct) at 5-6; ETI Ex. 39 (Cicio Direct) at 6-10.
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PUC DOCKET NO. 39896

transmission resources in an economic and reliable manner. By jointly planning and operating their
electric systems, the Operating Companies believe they are able to aggregate their loads and jointly
dispatch their resources to serve that load using the lowest cost resources available from all of the
Operating Companies, resulting in lower total costs than the total cost of each Operating Company
planning and operating separately. Another function of the Entergy System Agreement is to provide
a basis for the equalization among the Operating Companies of any imbalances of costs arising from
the construction, ownership, or operation of facilities that are used for the collective benefit of all
Entergy Operating Companies. 277

          To provide reliable service, ETI must have sufficient generation capacity to meet the
maximum demands imposed on its system. Some of this generation capacity (approximately
1,200 MW) is generating plants owned and operated by ETI. 278 The remainder of ETI' s capacity
comes from four types of purchased capacity: (1) capacity purchases from third parties; (2) capacity
purchases from other Entergy affiliates through "legacy affiliate contracts" under MSS-4;
(3) capacity purchases from other Entergy affiliates through "other affiliate contracts" under MSS-4;
and (4) capacity purchases from the Entergy system through reserve equalization payments under
MSS-1. 279 MSS-1 and MSS-4 are schedules included in the Entergy System Agreement which set
out complex mathematical formulas whereby the various Operating Companies can equalize and
share the costs of power capacity among themselves. 280 These four sources of purchased capacity are
inversely related to one another: the more ETI purchases from one source, the less it needs to
purchase from the others. 281

               ~   Capacity Purchases from Third Parties

          Third-party capacity contracts are contracts that the system has allocated in whole or part to
ETI.      ETI has contracted to purchase capacity from a number of third parties, including

277
      ETI Ex. 39 (Cicio Direct) at 6, 8-10, 11-30.
278
      Tr. at 1539-40.
279
      ETI Ex. 34 (Cooper Direct) at 20-21; Tr. at 1901; ETI Initial Brief at 71.
280
      ETI Ex. 39 (Cicio Direct) at PJC-1, pp. 30 and 62.
281
      Tr. at 1946-47.
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ConocoPhillips-SRW, Dow Pipeline, Frontier, Calpine-Carville, and Sam Rayburn Municipal Power
Agency (SRMPA). Since 2009, ETI has been in the process of substantially increasing its reliance
upon third party purchases of capacity. During the Rate Year, it plans to more than double the
amount of capacity it purchases from third parties as compared to the amount it purchased during the
               282
Test Year.

            Since the Test Year, Entergy has been engaged in an effort to increase ETI's long-term power
capacity through dealing with third parties. It has entered into a number of agreements in that regard:

•      In 2009, it entered into a ten-year purchased power agreement with Calpine Energy Services
       (Calpine) to purchase 485 MW of capacity from Calpine's Carville Energy Center (Carville
       Contract). Purchases pursuant to the Carville Contract will commence during the Rate Year, on
       June 1, 2012, and 50 percent of this contract is allocated to ETI. 283

•      During the Period from July 2009 through June 2011, the Company executed an agreement with
       NRG for a 75 MW one-year call option, with a delivery period that began on March 1, 2011, and
       100 percent of this contract is allocated to ETI. 284

•      During the Period from July 2009 through June 2011, the Company executed a three-year
       agreement with Dow Pipeline for 100 MW capacity, with a delivery period that began on April 1,
       2011, and 100 percent of this contract is allocated to ETI. 285

•      During the Period from July 2009 through June 2011, the Company executed a 25-year
       agreement with SRMPA for 225 MW, with a delivery period beginning on December 1, 2011,
       and 100 percent of this contract is allocated to ETI. ETI contends that the SRMPA contract will
       be beneficial because it provides "much-needed long-term base load capacity at an economically
       attractive price."286

282
      ETI Ex. 34 (Cooper Direct) at 23; see also ETI Init. Br. at 75-76.
283
      ETI Ex. 34 (Cooper Direct) at 16, 19.
284
      ETI Ex. 34 (Cooper Direct) at 16, 19.
285
      Id. at 17, 19.
2s6   Id.
                                                                                                       ····---··----

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PUC DOCKET NO. 39896

•      An additional contract, the Frontier contract, was in place during the Test Year, and saw a
       150 MW increase in contract capacity during the Test Year. 287

           ETI argues that its growing reliance on third-party purchases will diversify its energy
portfolio and help the Company meet its reliability needs at a lower cost. 288 The new purchased
power contracts will also reduce ETI's fuel costs and dependence upon aging, higher heat rate
generation units within the Entergy system. 289

               »     Capacity Purchases from Other Entergy Affiliates Through "Legacy" Affiliate
                     Contracts Under MSS-4

           The term "legacy affiliate contracts" refers to those contracts resulting from the December 31,
2007, jurisdictional separation of EGSI into ETI and EGSL, pursuant to which ETI purchases its
allocated share of power from plants such as the River Bend nuclear plant, located in Louisiana and
owned by EGSL as a result of the separation. The legacy affiliate purchases are made under
MSS-4. 290

               »     Capacity Purchases from Other Entergy Affiliates Through "Other" Affiliate
                     Contracts Under MSS-4

           "Other affiliate contracts" refers to all affiliate contracts other than legacy contracts whereby
ETI purchases capacity and associated energy from other Operating Companies. 291 The other
affiliate purchases are also made under MSS-4. 292 Among others, in 2009 ETI entered into a new
affiliate contract with Entergy Arkansas, Inc. (EAI) for wholesale base load resources (the EA WBL
Contract), whereby ETI was allocated 31. 7 percent of 336 MW capacity. 293

287
      Tr. 1937-38.
288
      ETI Ex. 34 (Cooper Direct) at 24.
289
      Tr. at 1112-13, 1940-41.
290
      ETI Ex. 39 (Cicio Direct) at 24-26.
291
      ETI Ex. 34 (Cooper Direct) at 21.
292
      ETI Ex. 39 (Cicio Direct) at 24-26.
293
      Cities Ex. 6 (Nalepa Direct) at 13-14.
                                                                                                     ..~-·-----

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PUC DOCKET NO. 39896

              ~   Capacity Purchases from the Entergy System Through Reserve EqualizaJion
                  Payments Under MSS-1

          Reserve Equalization payments are made under MSS-1. In any given month, some of the
Operating Companies might be "long" on the amount of generating capacity they own (meaning that
they own more capacity than they need) while others might be "short" on capacity (meaning they
own less capacity than they need). In such a month, the long Operating Companies would receive
                                                                                      294
MSS-1 payments from the short Operating Companies for use of their capacity.

          2. ETl's Request Regarding PPCCs

          During the Test Year, ETI had total PPCCs of $245,432,884. 295 In the application, however,
ETI is not seeking to recover its Test Year expenses. Rather, it is asking to recover roughly
$276 million, which represents the Company's anticipated PPCCs in the Rate Year. 296 In other
words, ETI is seeking roughly $31 million more than its actual Test Year expenses. ETI derived this
estimate based largely upon what it believes will the purchased power agreements in place during the
Rate Year. 297

          As the following tables illustrate, ETI projects that, during the Rate Year, the total quantity,
and the relative quantities purchased from each source, will differ substantially from its Test Year
purchases.

                        Test Year vs. Rate Year Power Capacity Quantities
                                         (MW-Months)298
                         Purchase                Test Year        Rate Year
                  Third Party Purchases            5,884            12,834

294
      ETI Ex. 39 (Cicio Direct) at 11-13; Cities Ex. 4 (Goins Direct) at 13.
295
      TIEC Ex. 1 (Pollack Direct) at Ex. JP-1; Tr. at 652-53.
296
    TIEC Ex. 1 (Pollack Direct) at JP-1; ETI Ex. 34 (Cooper Direct) at 20; ETI Ex. 34A (Errata to Cooper
Direct).
297
      TIEC Ex. l (Pollack Direct) at 22.
298
      TIEC Ex. 1 (Pollack Direct) at 22, Table 1 (Errata).
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PUC DOCKET NO. 39896

                         Test Year vs. Rate Year Power Capacity Quantities
                                          (MW-Months)298
                           Purchase               Test Year        Rate Year
                  Affiliate Purchases (both        21,670           21,711
                  Legacy and Other) Under
                  MSS-4
                  Reserve Equalization              8,309            5,262
                  UnderMSS-1
                  Total                            35,863            39,807

                           Test Year vs. Rate Year Power Capacit v Costs2""
                           Purchase                Test Year         Rate Year
                  Third Party Purchases           $32,094,893       $69 ,061,200
                  Affiliate Purchases (both      $189,032,442       $188,430,917
                  Legacy and Other) Under
                  MSS-4
                  Reserve Equalization            $25,461,353       $18,317,367
                  UnderMSS-1
                  Total                         $246,588,688j!JU    $275,809,484

          This indicates ETI will purchase roughly 11 percent more power in the Rate Year than it did
in the Test Year. Moreover, while the purchases pursuant to MSS-4 will remain fairly stable, the
third-party purchases will substantially increase, with a somewhat corresponding decrease for
purchases pursuant to MSS-1. In other word, ETI' s plan is to become "less short" (on capacity)
relative to the other Operating Companies in the Rate Year than it was in the Test Year.

          ETI contends that the shift toward more third party purchases is part of its effort to develop a
more diverse, modern, and efficient portfolio of generation supply resources, both to serve current
customer needs and to serve anticipated load growth. This, in turn, will lower energy costs and result
in savings for customers. 301

299
      Cities Ex. 12.
300
      Cities now agree that the correct amount for the Test Year is $245,432,884. See TIBC Reply Brief at 18.
3
ot ETI Ex. 47 (Cooper Rebuttal) at 7-8.
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PUC DOCKET NO. 39896

           ETI' s initial request in this case was for a Purchased Power Rider (PPR) that would allow the
Company to recover $276 million, but would be subject to future reconciliation based on actual
expenses and revenues, much like a fuel factor. 302 The intervenors point out that the PPR proposal,
while unprecedented, would have at least matched any post-Test Year increases in total purchased
capacity costs with corresponding increases in sales, and would also have allowed for a prudence
review of any post-Test Year purchased power capacity expenses in a future reconciliation
proceeding. 303        The Commission, however, rejected the PPR proposal in its Supplemental
Preliminary Order. 304 In lieu of the PPR proposal, ETI now proposes to simply recover the
$276 million as part of its base rates.

           3. Staff and Intervenors' Opposition to ETl's PPCCs Proposal

           Staff and all of the active! y-engaged intervenors oppose ETI' s proposed adjustment to its Test
Year PPCCs. They make a number of arguments against ETI' s proposal.

                         (a) The PPCCs Requested by ETI Are Not Known and Measurable

           First, they contend that ETI' s Rate Year forecast cannot be considered known or measurable.
Staff points out that the four3° 5 components from which ETI purchases power are interrelated, such
that, "when ETI adds capacity under one element, such as through third party contracts, the other
components, such as ETI's MSS-1 payments, will decrease."306 Staff describes each of the
components comprising ETI' s PPCC Rate Year forecast as being "infected" with numerous
assumptions. 307 For example, ETI necessarily made projections, rather than relying upon actual
payments, when it estimated what it will pay for third-party contracts in the Rate Year. 308 Many of

302
      Tr. at 1954; Cities Ex. 4 (Goins Direct) at 14.
303
      TIEC Init. Br. at 25-26; Tr. at 1954; Cities !nit. Br. at 37; Cities Ex. 6 (Nalepa Direct) at 8.
304
      Supplemental Preliminary Order at 2 (Jan. 9, 2012).
305
  Staff (and some of the intervenors) describe them as three components, by combining affiliate purchases
under legacy contracts and affiliate purchases under other contracts into one component.
306
      Staff Initial Brief at 25 (citing Tr. at 1946).
307
      Staff Initial Brief at 26.
308
      Tr. at 704.
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the third party contracts that will be in effect in the Rate Year do not contain fixed price terms.
Rather, the amounts ETI will pay will fluctuate based upon factors such as required availability and
performance. Nevertheless, ETI simply assumed it would pay the maximum amount possible under
each of its third party contracts, and disregarded any of the contractual factors that might reduce its
Rate Year payments. 309 Thus, the intervenors contend that ETI's cost estimates for third party
purchased power are merely projections, as opposed to known and measurable changes. 310

           Similarly, ETI' s contractual agreements with its affiliate Operating Companies require ETI to
make assumptions about their future costs. The contracts do not definitively fix prices or quantities.
Rather, prices and quantities under the contracts will fluctuate based on the specific operational
conditions actually experienced by the various Operating Companies during the Rate Year. 311 The
ultimate determination of payments made in the Rate Year will be calculated based upon the
complex mathematical formula set out in schedule MSS-4. That formula contains a great number of
variables. ETI had to make assumptions about each one of those variables in order to estimate its
Rate Year costs. 312 The intervenors point to ETI' s new contract with EAi (the EA WBL Contract) as
evidence of the "inherently speculative nature" of ETI' s PPCCs request.              According to the
intervenors:

•      the EA WBL Contract was signed on April 11, 2012 (only days before the hearing in this matter
       commenced); purchases will not commence under the contract until January 1, 2013;

•      pricing under the contract will be determined in 2013 pursuant to the complex formula contained
       inMSS-4;

•      the quantity of capacity ETI ultimately purchases under the contract will be based on a yet-to-be-
       determined allocation percentage between ETI and the other Operating Companies;

•      the contract itself may never go into effect because it is contingent upon ETI receiving all
       necessary "regulatory approvals" before August 1, 2012; and

309
      Tr. at 704-05.
310
      TIEC Initial Brief at 29-30; Staff Initial Brief at 26.
311
      Tr. at 606.
312
      See Staff Initial Brief at 27; Tr. 606.
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PUC DOCKET NO. 39896

•     if it does go into effect, it will still be subject to at least two further revisions before any power is
      received by ETI under the contract. 313

The EA WBL Contract accounts for more than one-third of ETI' s upward adjustment to its Test Year
PPCCs. The intervenors contend that, in order for ETI to arrive at its forecasted PPCCs for the Rate
Year, it had to make myriad assumptions as to the future values of the many variables in the EA
WBL Contract (and the other affiliate contracts). 314 Therefore, the intervenors argue that ETI' s cost
estimates for its contractual agreements with its affiliate Operating Companies are merely
projections, as opposed to known and measurable changes. 315

          ETI' s estimated costs for its MSS-1 payments also require assumptions about the future. In
order to calculate its future reserve equalization responsibilities using the complex formula set out in
MSS-1, ETI had to forecast its own future loads, along with the future loads of all the other
Operating Companies. If those assumptions prove to be wrong, then ETI' s actual MSS-1 costs will
be different than as projected in the application. 316 It is noteworthy, according to the intervenors, that
ETI projected the future load growths of all the Operating Companies when it calculated its projected
Rate Year MSS-1 costs because, elsewhere in ETI' s evidence, the Company has taken the position
that future projected loads should not be considered known and measurable. 317 Staff argues:

          ETI cannot have it both ways. It cannot claim load growth to be speculative in one
          context, and then claim that it can forecast with absolute certainty the respective load
          growths for each EOC on the Entergy System. 318

TIEC points out that ETI' s estimated MSS-1 payments "were still changing on the eve of the
hearing."319 In the following exchange, even ETI witness Phillip May, one of the Company's

313
      ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, and Tr. at 628-9.
314
   Staff Initial Brief at 27-28. Staff makes the further point that, because the EA WBL Contract was executed
only days before the hearing, Staff has been unable to determine whether the contract is even a prudent one.
315
      TIEC Initial Brief at 30-32; Staff Initial Brief at 27-28.
316
      Tr. at 651-52.
317
      Tr. at 1907; see also Staff Initial Brief at 28; TIEC Initial Brief at 27-28.
318
      Staff Initial Brief at 29; see also TIEC Initial Brief at 37.
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primary witnesses regarding its PPCCs, seems to have conceded that the Company's MSS-1
projections are not known and measurable:

           Q:       Do you think that the projection ... of rate year sales that is implicit in the
                    calculation of MSS-1 costs ... is a known and measurable change?
           A:       I think that there is some uncertainty with regard to that projection, yes, sir. 320

In sum, the intervenors contend that ETI' s cost estimates for all components of purchased power in
the Rate Year are merely projections, as opposed to known and measurable changes. 321

                         (b) The PPCCs Requested by ETI Violate the Matching Principle

           Second, the intervenors acknowledge the principle that Test Year expenses may be adjusted
for known and measurable changes. However, they contend that such adjustments can only be made
where the attendant impacts on all aspects of a utility's operations (including revenue, expenses, and
invested capital) can with reasonable certainty be identified, quantified, and matched.322 They assert
that ETI' s proposed adjustment does not satisfy this matching principle. The intervenors complain
that ETI is improperly attempting to "compare apples to oranges" by mixing a forecast of future Rate
Year PPCCs with actual Test Year billing determinants. As explained by Cities witness Nalepa,
"[u]nder the company's approach of mixing estimated rate year costs with test year billing units,
there is a failure to recognize customer growth and increased sales revenue - thus overstating the
revenue requirement."323 The argument, essentially, is that the various new or expanded contracts
that ETI has entered into were executed so that, in whole or in part, ETI would be able to meet future
demand, but that ETI is seeking to recover the costs of those new contracts from its existing
customers. 324

319
      TIEC Initial Brief at 28.
320
      Tr. at 1918-19.
321
      TIEC Initial Brief at 27-28; Staff Initial Brief at 29.
322
      Cities Ex. 6 (Nalepa Direct) at 12, citing P.U.C. SUBST. R. 25.23 l(c)(2)(F).
323
      Cities Ex. 6 (Nalepa Direct) at 8; Cities Ex. 4 (Goins Direct) at 14-15.
324
      Cities Ex. 6 (Nalepa Direct) at 11; see also Cities Initial Brief at 38, Staff's Initial Brief at 30, TIEC Initial
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PUC DOCKET NO. 39896

           The intervenors offer various examples, of which the following is typical, to illustrate why it
was inappropriate for ETI to fail to take load growth into account when it calculated its Rate Year
PPCCs. Assume that, during the Test Year, Utility X had 100 billing units and $500 of PPCCs. Also
assume that, during the Rate Year, Utility X had 200 billing units and $1,000 of PPCCs. If Utility X
were limited to setting its rates based solely on its Test Year numbers, then it would recover
precisely the right amount to cover its PPCCs in both the Test Year (100 billing units x $5 per unit=
$500 of PPCCs) and in the Rate Year(200 billing units x $5 per unit= $1,000 of PPCCs). If, on the
other hand, Utility X were allowed to set its rates based upon it billing units from the Test Year(lOO)
and its PPCCs from the Rate Year ($1,000), then Utility X would unfairly recover twice the amount
needed to cover its actual PPCCs in the Rate Year (200 billing units x $10 per unit= $2,000). 325
Thus, intervenors contend that ETI' s load growth must be taken into account if PPCCs are to be
based on Rate Year projections. 326 They point out that ETI itself expects steady load growth in the
next few years, 327 and experienced "good" growth over the two years preceding the Test Year. 328

           For its part, ETI denies that its increased capacity has been obtained in order to meet load
growth. Rather, it contends that it has added capacity in order to be "less short" in comparison to the
other Operating Companies. 329 Moreover, ETI contends that the load growth adjustments proposed
by intervenors are "uncertain and unnecessary." 330

                       (c) ETl's Proposal Would Preclude Prudence Review

           Third, TIEC contends that ETI' s future Rate Year proposal would set rates based on
projections without any effective Commission review of: (1) what the actual expenditures under

Brief at 35-39.
325
      Cities Ex. 4 (Goins Direct) at 16-17.
326
      Cities Ex. 4 (Goins Direct) at 17; see also TIEC Ex. 23.
327
      Cities Ex. 4 (Goins Direct) at 17; Tr. at 706.
328
      Tr. at 130.
329
      ETI Initial Brief at 68-69.
330
      Id. at 69.
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purchased capacity contracts turn out to be; (2) whether those expenditures turn out to be reasonable;
and (3) whether the future contracts were prudent. 331

          4. The Intervenors' Recommendations Regarding PPCCs

          The intervenors agree that the amount requested by ETI is unreasonable, excessive, and
should be rejected. They do not universally agree, however, about what the proper number for
PPCCs should be. Staff, TIEC, and State Agencies argue that ETI' s PPCCs should be set at the
amount of the Company's Test Year PPCCs: $245.4 million. This position is best summarized by
Staff:

          Staff recommends that the Commission adhere to traditional ratemaking principles
          and set the amount of ETI' s purchased power expenses based on what the Company
          actually experienced during its test year. During its test year, ETI had total purchased
          power capacity expenses of $245.4 million. This amount is not in dispute. This
          amount is known. This amount is measurable. The Commission should utilize this
          amount to set just and reasonable rates for ETI and its ratepayers. 332

           Rather than recommending Test Year PPCCs, Cities offer two alternatives - one
recommended by its witness Dr. Dennis Goins, and another recommended by its witness
Mr. Nalepa. 333       Dr. Goins recommends that ETI be allowed to recover PPCCs of roughly
$242.9 million. 334 This amount is roughly $33 million less than ETI's requested amount and
$3 million less than ETI' s actual Test Year costs. To arrive at this amount, Dr. Goins made several
calculations. First, he adjusted the average perkW cost of ETI' s legacy and other affiliate purchases
using cost data from November 2010 through October 2011, which is slightly more current data than
that relied upon by ETI. 335 Second, as to MSS-4 costs, because the EA WBL contract is set to expire
sooner than the three years he assumed ETI' s new rates will be in effect, Dr. Goins "normalized" the

331
      TIEC Initial Brief at 33-35.
332
      Staff Initial Brief at 29.
333
      Cities Initial Brief at 40.
334
      Cities Ex. 6 (Nalepa Direct) at 17, and Errata No. 3.
335
      Cities Ex. 4 (Goins Direct) at 17-18.
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PUC DOCKET NO. 39896

costs of the EA WBL contract over the three year period. 336 Finally, he adjusted the Rate Year total
PPCCs estimate to reflect the effects of load growth, based upon ETI forecasts. 337

           Mr. Nalepa took a slightly different approach. He recommended that ETI be allowed to
recover PPCCs of $236,838,634, or roughly $39 million less than ETI' s requested amount and
$8 million less than ETI's Test Year costs. 338 To arrive at this amount, Mr. Nalepa first calculated
the per kW cost of ETI's third party Rate Year capacity and applied it to ETI's Test Year-end
capacity. In this way, "the increased cost of the new resources is recognized, but current demand is
better matched to current resources."339 Second, he made the same adjustment as Dr. Goins as to
MSS-4 costs due to the EA WBL contract. 340

           TIEC explains it is reluctant to "descend into the rabbit hole and engage in ratemaking based
on prognostications, estimates, projections, and assumptions about what may happen in the
future." 341 If the Commission were to do so, however, TIEC argues that the final result would be
lower than the Test Year PPCCs, not higher. TIEC' s witness Jeffry Pollock calculated the impact of
projected unit prices based upon ETI' s projections, and he eliminated the expiring EA WBL
Contract. His result, which TIEC is not advocating, would allow ETI to recover PPCCs of $238.8
million, roughly $7 million less than its Test Year costs. 342

           ETI describes the proposals made by TIEC and Cities as "extreme" and contrary to common
sense. 343 For example, Mr. Pollock's calculations indicate that ETI' s MSS-1 costs would increase by
roughly $5 million, while its third-party and affiliate contracts would slightly decrease. ETI argues

336
       Cities Ex. 4 (Goins Direct) at 18; Cities Ex. 6 (Nalepa Direct) at 15-16.
337
       Cities Ex. 4 (Goins Direct) at 18- l 9.
338
       Cities Ex. 6 (Nalepa Direct) at 17.
339
       Cities Ex. 6 (Nalepa Direct) at 12-13.
3
 4-0   Id. at 15-16.
341
       TIEC Initial Brief at 41.
342
       TIEC Ex. 1 (Pollack Direct) at 25-27; TIEC Initial Brief at 41-42.
343
       ETI Initial Brief at 83.
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that this is the opposite of reality. By adding capacity through third party contracts, its reliance upon
the other purchased power components, especially MSS-1, will necessarily decline, not increase. 344
ETI also argues that load growth is inherently uncertain and should not be taken into account. 345

          5. The ALJs' Analysis Regarding PPCCs

          The AU s conclude that ETI failed to meet its burden to prove that the adjustment it seeks to
its Test Year PPCCs is known and measurable. The known and measurable standard is an exception
to the actual data contained in the Test Year. The point of a historical Test Year is to review actual
costs, which include the ups and downs of what actually occurred. As to a forecast of the Rate Year,
by contrast, the evidence demonstrates that the costs attributable to a particular contract to purchase
capacity cannot currently be known because there are so many variables that will play into the
amount ETI ultimately pays. As stated above, ETI' s third party contracts lack fixed prices and the
amounts ETI will pay could fluctuate based upon factors such as required availability and
performance. ETI simply assumed it would pay the maximum amounts under those contracts, and
disregarded the contractual factors that could lower the payment amounts. Yet this assumption runs
counter to ETI' s historical experience with its contracts. 346 Similarly, ETI' s affiliate contracts do not
fix prices or quantities, and the amount ETI ultimately pays will fluctuate based upon operational
conditions experienced by all of the Operating Companies during the Rate Year. Those operational
conditions obviously cannot be known at this time. Both the affiliate contracts under MSS-4 and the
equalization payments under MSS-1 are based upon highly complex mathematical formulae that
utilize numerous variables. Any of the variables could change during the Rate Year, thereby altering
the amounts paid by ETI under affiliate contracts or MSS-1. As a result, the evidence demonstrates
that there could be a substantial difference between ETI' s projected Rate Year costs and what

344
      Id. 83.
345
      Id. 84.
346
      Tr. at 705.
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PUC DOCKET NO. 39896

actually ends up occurring. ETI asks the Commission to trust it that these differences would be
"small,"347 but provides no evidence as to what small means.

          The efforts made by ETI, Cities, and TIEC to forecast Rate Year PPCCs further illustrate the
difficulty of deviating from actual Test Year data in an area that involves so many future
contingencies and unknowns. Those forecasts swung wildly- ETI estimated Rate Year PPCCs that
were $31 million more than the Test Year, while the Cities' and TIEC's estimates came in at $3
million, $8 million, and $7 million less than the Test Year, respectively. Indeed, even Cities' own
witnesses disagreed substantially among themselves as to what the proper amount should be.
Moreover, arguably ETI could not even agree with itself regarding the proper amount because, in its
Initial Brief, it suggested that a reduction of roughly $4.5 million might be warranted to account for
its latest projection of its MSS-1 costs in the Rate Year. 348

          The ALls are similarly convinced that ETI's request violated the matching principle by
mixing its forecast of future Rate Year PPCCs with Test Year billing determinants. It is logically
inconsistent for ETI to have, on the one hand, based its estimate of Rate Year MSS-1 costs on its
projections of the load growths of ETI and all the other Operating Companies and, on the other hand,
argue that load growth cannot be considered known and measurable when calculating its overall
PPCCs. This argument does not withstand scrutiny, especially in light of tJ:ie fact that ETI clearly
believes its load will be larger in the Rate Year than it was in the Test Year and it has, in fact,
contracted for six percent more load in the Rate Year. 349

          Simply put, the intervenors presented substantial evidence that all of the components of ETI' s
purchased power capacity contain significant variability and uncertainty in costs, thereby leading to
the conclusion that estimates of Rate Year PPCCs cannot be considered known and measurable. For
this reason, the ALls recommend that ETI's PPCCs request be rejected. In its place, the ALls
recommend that ETI be allowed to recover its Test Year PPCCs of $245,432,884.

347
      ETIInitial Brief at 81.
348
      ETI Initial Brief at 77 (citing Tr. at 684, 1945).
349
      ETI Ex. 47 (Cooper Rebuttal) at 4; Tr. at 667-68.
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B.         Transmission Equalization (MSS-2) Expense

           The Entergy system transmission grid is a large, integrated transmission network that is
operated for the mutual benefit of all of the Entergy Operating Companies. 350                Service
Schedule MSS-2 is a FERC jurisdictional tariff that equalizes the ownership costs of certain high
voltage transmission facilities among ETI and the other Operating Companies, so that each
Operating Company pays its just and reasonable share of those costs. Accordingly, those costs are
referred to as "transmission equalization" payments. 351 MSS-2 generally applies to equalization of
transmission costs for transmission assets of 230 kV and larger. 352

           In any given month, some of the Operating Companies might be "long" on the amount of
transmission capacity they own (meaning that they own more capacity than they need) while others
might be "short" on capacity (meaning they own less capacity than they need). In such a month, the
long Operating Companies would receive MSS-2 payments from the short Operating Companies for
use of their transmission facilities. 353 Over the course of the Test Year, ETI was short, meaning that
it paid a total of $1,753,797 in MSS-2 payments to various other Operating Companies. 354

           In the application, rather than seeking to recover only the $1.7 million in Test Year MSS-2
costs, ETI is seeking to recover roughly $10.7 million, which represents its anticipated MSS-2
expenses in the Rate Year. 355 The additional $9 million that ETI seeks is based on the Company's
estimates of transmission construction projects that are expected to have been completed by or
during the Rate Year which will result in changes to the relative transmission line ownership ratios
between the Operating Companies. In other words, ETI expects that, by or during the Rate Year, its
ownership share under the MSS-2 will decrease relative to the other Operating Companies (as the

350
      Tr. at 450, 793.
351
      Tr. at 724; ETI Ex. 39 (Cicio Direct) at 15-17 and PJC-1at38.
352
      Tr. at 450-51, 73 l.
353
      Tr. at 731, 735.
354
      Tr. at 723-24, 737; Cities Ex. 28.
355
      Tr. at 452-53, 738, 760.
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PUC DOCKET NO. 39896

transmission capacity owned by the other Operating Companies increases), thereby driving the
amount of ETI's MSS-2 payments upward. 356

            The increase is driven by ETI's prediction that $184.9 million in additional transmission
capacity will be built by other Operating Companies by the end of the Rate Year. ETI identified six
construction projects that are either underway or approved for construction and which, collectively,
will account for roughly $141 million of the predicted $184.9 million in additional transmission
capacity. Of those six projects, one was completed and went into service on December 16, 2011,
after the end of the Test Year. The other five are either under construction or still in the planning
phase and are currently scheduled to go into service on dates ranging from June 29, 2012, to
December 31, 2012. 357 According to ETI, the remaining $43.9 million of the $184.9 million in
additional transmission capacity is derived from "an estimate of the capital investment necessary to
maintain equalizable [i.e. MSS-2 qualifying] transmission investments across the Entergy
Transmission System."358 The estimate is based upon the Operating Company's projected budgets
and historical spending patterns for maintenance of transmission facilities. 359

            Staff, State Agencies, TIEC, and Cities all oppose ETI's effort to recover $10.7 million in
MSS-2 expenses. The parties make a number of arguments. First, they point out that MSS-2 utilizes
a complex mathematical formula to calculate each Operating Company's liability (or credit) under
the equalization process. There are a great number of variables that are used in the formula, such as
the amount of investments made by each Operating Company in transmission facilities, the costs of
capital for each Operating Company, the size of the load demanded by each Operating Company, and
the amount of state and federal taxes paid by each Operating Company. Changes to any of these
variables can change the amount ETI owes (or is due) pursuant to MSS-2. 360 Moreover, these
variables relate not only to ETI, but to all of the Operating Companies. Indeed, Cities calculate that,

356
      Tr. at 775-77.
357
      ETI Ex. 59 (McCulla Rebuttal) at 2 and MFM-R-1; Tr. at 456-58.
358
      ETI Ex. 59 (McCulla Rebuttal) at 3.
359   Id.
360
      ETI Ex. 39 (Cicio Direct) at PJC-1 at 38-43; Tr. at 454-55.
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to perform the MSS-2 calculation, at least 360 "mini-forecasts" must be made, only 60 of which
relate to ETI. 361 As explained by TIEC witness Pollock, any effort to estimate future amounts of
these many variables "is susceptible to a host of uncertainties." 362 The intervenors argue that for ETI
to arrive at its estimate of$10.7 inMSS-2 costs duringthe Rate Year, the Company had to speculate
as to what the many MSS-2 variables would be in the Rate Year. In other words, they contend that
ETI's estimate of its future MSS-2 costs cannot possibly be considered "known and measurable"
and, therefore, is not recoverable. 363 State Agencies and Staff liken ETI's attempt to obtain an
MSS-2 adjustment for not-yet-complete construction projects to an impermissible request to recover
the costs of CWIP without having to meet PURA's burden of proving that recovery is necessary to
protect the utilities financial integrity. 364

           Second, the parties oppose ETI's effort to recover its predicted MSS-2 expense in the Rate
Year point out that the primary driver of the increased costs over the Test Year comes from a number
of transmission projects that have not yet come into service, and are still in the planning or
construction phase. ETI concedes that if the projects do not actually come into service at the
currently estimated times, then the Company's estimates of its MSS-2 costs during the Rate Year
will be inaccurate. 365 Thus, Staff contends that ETI's projections about future MSS-2 costs cannot
be considered known and measurable. 366 Moreover, TIEC and Staff contend that ETI is effectively
seeking higher rates based upon expenses associated with projects that are not yet completed and,
therefore, the projects cannot be considered ''used and useful."367 As explained by TIEC:

361
      Cities Reply Br. at 68-69.
362
      TIEC Ex. 1 (Pollock Direct) at 29.
363
   Staff Initial Brief at 31; State Agencies Initial Brief at 11-13; TIEC Initial Brief at 44-45; Cities Initial Brief
at44.
364
   State Agencies Initial Briefat 12 (citing PURA§ 36.054; P.U.C. SUBST. R. 25.23 l(c)(2)(D)); Staff Reply
Brief at 20.
365
      Tr. at 800-801
366
      Staff Initial Brief at 32.
367
      TIEC Initial Brief at 47; Staff Initial Brief at 19-20.
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          It would be bad public policy for the Commission to rely on speculative construction
          end dates to form the basis of a known and measurable change to test year costs.
          ETI' s own witness Mr. Cicio admitted that in-service dates can be uncertain. . ..
          Similarly, costs can change upward or downward. For this reason, the Commission
          has typically followed the policy that proper ratemaking requires that a utility actually
          build the transmission infrastructure suggested by its projections, and then seek to
          account for that investment on a historical basis in a future rate case. In Docket
          No. 28906, for example, the Commission held that LCRA' s projections of future
          transmission investment did not support a finding that its projected capital needs
          satisfied the known and measurable test. It is similarly unreasonable for ETI to make
          a post-test year adjustment associated with transmission projects that are not serving
          any of its customers and that may or may not impact ETI' s transmission equalization
          expense, depending on when the projects are finally completed. 368

          Third, in addition to the six transmission projects that are under development, another driver
of the increased costs over the Test Year comes from ETI' s estimate that $43 .9 million will be spent
to maintain transmission investments across the Entergy Transmission System. The intervenors
contend that ETI has provided little to no evidentiary support for this estimate. State Agencies and
Cities also point out the unfairness of allowing ETI to begin recovering $10. 7 million per year in its
rates immediately based upon new transmission facilities, even though many of those new facilities
will not come into service (and ETI will therefore not incur higher MSS-2 payments for those
facilities) for many months. 369

          Fourth, Cities points out that Entergy and the various Operating Companies have announced
a plan to sell all of their transmission assets to a third party. That process is currently underway. The
evidence suggests that, if and when that transaction is complete, ETI's MSS-2 expenses will
disappear. 370

          Finally, TIEC argues that there is no need to grant ETI's request for a pro Jonna adjustment
to its test year MSS-2 expenses because the Company can avail itself of a TCRF if its Rate Year

368
      TIEC Initial Brief at 47 (citing Docket No. 28906, Order at 6).
369
      State Agencies Initial Brief at 12; Cities Initial Brief at 45.
 °
37
     Cities Reply Brief at 67-68; Tr. at 113-14; Cities Ex. 4 (Goins Direct) at 20-21. Admittedly, if these
expenses disappear, ETI will still have to bear transmission expenses. However, it is impossible to know, at
this time, what those expenses would be.
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costs deviate substantially from its Test Year costs. Thus, if it turns out that ETI experiences an
increase in its MSS-2 expenses during the Rate Year, the utility has cost recovery mechanisms at its
disposal that could make it whole in a timely manner.

           Staff and State Agencies argue that only $1.7 million (representing ETI's actual Test Year
expenses) should be approved in this proceeding. TIEC witness Pollock recommends approving a
slight upward adjustment to account for the fact that ETI's MSS-2 expenses were substantially
higher in the second six months of the Test Year than they were in the first six months. Mr. Pollock
and TIEC recommend a pro Jonna adjustment equal to twice the amount of MSS-2 payments
                                                                                       371
incurred by ETI in the second six months of the Test Year, or $2. 7 million.

           Cities' witness Goins presented yet another alternative. Dr. Goins proposes to adjust the
projected Rate Year costs for known expenses incurred after the Test Year. He proposed reducing
the adjusted Rate Year MSS-2 expense to a Test Year level by applying a load growth adjustment
using ETI' s own projected load growth as a benchmark indicator of the reasonable anticipated level
of growth. (Cities invoke essentially the same "matching principle" argument regarding load growth
that they raised with respect to PPCCs). The result of Dr. Goins' adjustment would be to would
allow ETI to recover $4,103,850 in MSS-2 expenses. 372

           ETI responds to these arguments on a number of fronts. It contends that the main driver of
changes in MSS-2 expenses is the relative amount of equalizable transmission investment in the
transmission system by ETI and the other Operating Companies, compared to their proportionate
responsibility for that investment, based on each company's responsibility ratio. 373 ETI argues that
the other elements of the formula are relatively stable, and do not vary significantly from year to

371
      TIEC Ex. I (Pollack Direct) at 32-33.
372
      Cities Ex. 4 (Goins Direct) at 20-21.
373
   ETI Ex. 45 (Cicio Rebuttal) at 3-4. Responsibility Ratio is an allocator that reflects the relative contribution
of each Operating Company to the System's coincident peak load - in other words, an Operating Company's
coincident peak load divided by the System peak load, calculated on a rolling twelve-month average. ETI
Ex. 39 (Cicio Direct) at 12.
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year. 374 ETI contends its requested level of MSS-2 expense is based on a known and measurable
change because it is based on the $184.9 million in additional transmission investment for all of the
Operating Companies that ETI knows will occur and can reasonably measure. ETI points out that
"the vast majority" of the planned transmission projects have received full funding approval and
have been constructed or are on schedule to be completed before the end of the Rate Year, while the
remaining amount is reasonably quantified and measured based on the budget and historical spending
for maintenance of equalizable transmission facilities. 375

           ETI also argues that its actual MSS-2 expenses have steadily trended upward since the Test
Year. ETI explains as follows:

           [l]n the last month of the test year (June 2011), ETI's payments began to increase
           significantly, as the balance of relative equalizable investment levels shifted among
           the Operating Companies. ETI' s actual monthly payments have climbed steadily ever
           since, reaching $698,289 in the most recent actual month's bill (February 2012).
           Annualization of this most recent actual data yields an annual MSS-2 amount of
           $8.4 million, almost five times the test year level. In light of this trend in actual
           historical data, the notion of basing the MSS-2 expense in rates on the test year level
           is unreasonable on its face. 376

Thus, ETI contends its requested expense level is "consistent" with actual recent historical levels of
MSS-2 expense. 377

           ETI describes Cities' concern regarding load growth as a "red herring." ETI contends that
load growth is not the cause of changes in MSS-2 costs. Instead, its MSS-2 increases are driven by
the other Operating Companies' transmission investments, "separate and apart from, and unaffected
by," any increase in ETI's load. 378 Moreover, ETI contends that load growth adjustments are not

374
      Tr. at 763 and 780.
375
      ETI Ex. 59 (McCulla Rebuttal) at 2-3; ETI Initial Brief at 88-89.
376
      ETI Initial Brief at 90-91; Tr. at 784.
377
      ETI Initial Brief at 91.
378
      ETI Ex. 45 (Cicio Rebuttal) at 4-5; ETI Initial Brief at 93.
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PUC DOCKET NO. 39896

known and measurable and are not the proper subject of a post-test year adjustment for ordinary
expenses such as MSS-2 costs. 379

          Finally, if the Commission rejects its request for $10.7 million in MSS-2 costs, ETI suggests
annualizing the most recent period of its actual MSS-2 costs, by multiplying its February 2012 MSS-
2 bill times 12, resulting in an amount of $8,379,480.                  ETI contends this would be more
representative of expected Rate Year MSS-2 costs than the amounts proposed by the intervenors. 380

          For largely the same reasons as were discussed relative to PPCCs, the ALls conclude that
ETI failed to meet its burden to prove that its proposed Rate Year MSS-2 costs are known and
measurable. The MSS-2 formula requires assumptions about a great number of variables. Changes
to any of the variables could occur during the Rate Year, thereby altering the amount paid by (or
received by) ETI during the Rate Year. The projects that underlie ETI's Rate Year request are
largely not yet built, and might never be built. Additionally, much like with the PPCCs estimates,
there is a wide gulf between the competing estimates by ETI, Cities, and TIEC of forecast Rate Year
MSS-2 costs, illustrating the problem of deviating from actual Test Year data in an area that involves
so many future contingencies and unknowns.

          The ALls are equally unconvinced by ETI's alternative proposal to multiply its February
2012 MSS-2 bill times 12, resulting in an amount of $8,379,480. ETI offered no evidence to
establish that a single month's costs can serve as a reasonable representation of what ETI's future
Rate Year MSS-2 costs will be. Moreover, February 2012 is outside of the Test Year.

          The intervenors presented substantial evidence to demonstrate that ETI' s estimate of its Rate
Year MSS-2 costs cannot be considered known and measurable. For this reason, the ALls
recommend that ETI's MSS-2 request be rejected. In its place, the ALls recommend that ETI be
allowed to recover its Test Year MSS-2 costs of $1,753,797.

379
      ETI Ex. 57 (May Rebuttal) at 12; ETI Initial Brief at 93.
380
      ETI Ex. 46 (Considine Rebuttal) at 37; ETI Initial Brief at 32.
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PUC DOCKET NO. 39896

C.        Depreciation Expense [Germane to Preliminary Order Issue No. 12]

          ETI currently has an annual depreciation expense of approximately $72.1 million. This
expense is based on the previously approved depreciation rates. 381 ETI now requests depreciation
rates that would result in an annual depreciation expense of approximately $86 million. This
requested amount represents an increase in the annual depreciation expense of approximately
$13.9 million - almost 20 percent - from the current annual depreciation expense. 382               The
depreciation expense ultimately included in retail rates, however, will be derived by applying the
Commission approved rates to the test year end plant balances as of June 30, 2011.

          The other parties have accepted the vast majority of ETI' s recommendations, but take issue
with the Company on a few issues related to generation, transmission, distribution, and general plant
accounts. Staff recommends an annual depreciation expense of approximately $78.2 million, an
increase of approximately $6.1 million from the current annual depreciation expense. 383 Cities
recommend an annual depreciation expense of approximately $67.6 million. 384

          The identical positions of ETI, Staff, and Cities on depreciation issues are set forth in the
following table: 385

  Plant Group               Approved           ETI Proposal        Staff Proposal     Cities Proposal
Hydro                            $7,137                 $245                 $245                  n/a
Production
Regional Trans.                  $685,351              $685,351          $685,351                    n/a
&Market
Operations
General                        $4,175,311             $5,946,949       $5,946,949                    n/a
Amortized Plant

381
      ETI Ex. l3 (Watson Direct) Attachment DAW-1. Appendix Bat 3.
382
      ETI Ex. 13 (Watson Direct) at 7.
383
      Staff Ex. 2 (Mathis Direct) at 8.
384
      Cities Ex. SC (Pous Depreciation Study) at 2.
385
    ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. SC (Pous Depreciation
Study) at 7, 8, and 34.
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PUC DOCKET NO. 39896

        The differing positions of ETI, Staff, and Cities on depreciation issues are set forth in the
following table: 386

  Plant Group             Approved             ETI Proposal          Staff Proposal         Cities Proposal
Steam                       $17,497,781            $18,660,946            $14,709,942                       n/a
Production
Transmission                $13,679,827            $16,493,761            $16,417,727            $13,451,479
Plant
Distribution                $32,110,774            $40,493,392            $38,806,863            $33,186,546
Plant
General Plant                 $3,943,450             $1,604,644             $1,604,644               $973,519
General Plant                         $0             $2,134,924                     $0                     n/a
Reserve
Deficiency
TOTAL                       $72,099 ,631           $86,020,212            $78,171,721                    n/aj/5/

        The competing positions of ETI, Staff, and Cities reflected in the table above are primarily
the result of different: (1) net salvage rates for certain accounts; (2) remaining life parameters for
certain accounts; and (3) treatment of a potential general plant reserve deficiency. Cities witness
Pous also questions the reliability of the data employed by ETI witness Watson in the performance of
his study.

        An analysis of the competing net salvage rates and life parameters for each account is
presented in detail below, organized by plant and account group.

        1. Terminology and Methodology

        Depreciation is a method of allocating the loss of the service value, not restored by current
maintenance, over the useful life of an asset. This loss may be caused by wear and tear, decay,
obsolescence, or changes in demand. 388

386
    ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation
Study) at 7, 8, and 34.
387
    A total value of Cities' adjustments in this format would be out of context and is therefore not provided in
this table.
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PUC DOCKET NO. 39896

          Within the context of a rate case, the purpose of depreciation is to allow a company to
recover the cost of an asset over the asset's useful life. Ideally, the cost of the asset is spread out
evenly across the years the asset is in service, thus recovering the cost of the asset from the
customers who receive the benefit of the asset. 389

          Both ETI and Staff use the remaining-life technique, average life group procedure, and
straight-line method to calculate the depreciation rate. 390 The basic formula for the remaining life
technique is presented below.

                                                  1 - book reserve ratio - net salvage ratio}
          depreciation rate ( %)          =   {                  .        . . ll
                                                          composite remm.nmg z e
                                                                                                * 100

          For example, if an asset has a book reserve ratio of 0.5 (i.e., 50 percent of the asset's value
has already been recovered through prior depreciation expense), a net salvage ratio of zero (i.e., the
asset will cost nothing to retire, or all retiring costs will be recovered through its subsequent sale),
and the composite remaining life is ten years (i.e., the asset is expected to remain in service for
another ten years), then the depreciation rate will be 5 percent (i.e., { [ (1 - 0.5 - 0) I 10 ] *100 }).

          By operation of the remaining-life formula, a greater net salvage value will reduce the
numerator and result in a lower depreciation rate and a lower depreciation expense. Likewise, a
lower net salvage value will increase the numerator and result in a higher depreciation rate and a
higher depreciation expense. Similarly, a longer remaining-life will result in a lower depreciation
rate and lower depreciation expense, and a shorter remaining-life will result in a higher depreciation
rate and a higher depreciation expense.

          Because net salvage and remaining-life values are the two contested variables in the
remaining-life formula, a clear explanation of net salvage and remaining-life will be helpful.

388
      Staff Ex. 2 (Mathis Direct) at 8.
389
      Staff Ex. 1 (Mathis Direct) at 8-9.
390
      ETI Ex. 13 (Watson Direct) at 15; Staff Ex. 2 (Mathis Direct) at 10-11.
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PUC DOCKET NO. 39896

          Net Salvage Value. Net salvage is calculated by taking the amount received for an asset as a
result of its sale, reuse, or reimbursement, and subtracting that amount from the cost associated with
retiring the asset. This figure is then divided by the original cost of the asset to determine the net
salvage ratio. For example, if an asset with an original cost of $200 is resold for $20, but it costs the
owner $10 to ship the asset to the purchaser, then the net salvage value of that asset would be $10
($20 - $10), and the net salvage ratio of that asset would be 5 percent ($10/$200).

          ETI witness Watson and Staff witness Mathis used different methods of calculating a net
salvage rate. 391 Mr. Watson took the average (mean) of recorded net salvage values for groups of
successive years (rolling bands), and then selected the net salvage rate from among these averages. 392
Ms. Mathis also used rolling band averages (means), but then took the median from a representative
group of rolling bands when the historical salvage data would have otherwise produced what
Mr. Watson considers skewed results. 393

          Ms. Mathis' method of calculating net salvage rates follows recent Commission precedent. 394
As Mr. Watson explained at the hearing, it is appropriate to infer acceptance of a methodology by
looking at whether the Commission adopted the conclusions that the methodology produced. 395 In
other words, if the Commission adopts the conclusions, then by inference the Commission has
adopted the methodology used to derive those conclusions. Thus, it is necessary to examine recent
litigated rate cases to ascertain Commission precedent.

          In the most recent fully-litigated rate case, Docket No. 38339, 396 Staff disagreed with
CenterPoint' s depreciation witness, Mr. Watson, concerning the net salvage rates for five

391
      Tr.at415-416.
392
      ETI Ex. 13 (Watson Direct) at 20-21.
393
      Id. at 22-23, 32-33.
394
      Tr. at 1766; Staff Ex. 9 (Docket No. 38339 Final Order) at FoF 126, 128, 130, and 131.
395
      Tr. at 397.
396
    Application of CenterPoint Energy Houston Electric, UC, for Authority to Change Rates, Docket
No. 38339 (June 23, 2011).
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accounts. 397 In its order, the Commission adopted Staffs recommended net salvage rates for four
out of those five accounts for which Staff disagreed with Mr. Watson. 398 Staffs method for
                                                                                                        399
calculating net salvage rates is the same in the present case as it was in the CenterPoint rate case.

            ETI argues that the use of a median, as employed by Ms. Mathis, is not a sufficiently rigorous
or expansive approach to depreciation analysis. According to ETI, depreciation training and texts, as
well as authoritative statistical texts, favor the average, or mean, not the median, as the best indicator
of the central tendency of a data set. ETI argues that this is particularly the case because depreciation
analysis requires careful consideration of trends over time. 400 ETI then offers the following
comments:

            [Ms. Mathis] agreed in response to a hypothetical that the median value of an initial
            period of ten years of +5% net salvage, followed by one year of 0% salvage, followed
            by the most recent period of ten years of -5% salvage, would be 0%. This
            hypothetical plainly illustrates how reliance on the median can overlook data trends.
            In the hypothetical, if the depreciation analyst would otherwise wish to give more
            weight to the most recent historical period as indicative of conditions going forward,
                                                                                      401
            the use of the median would obscure that important trend information.

A close examination of the hypothetical shows that in the case posited by ETI, however, the median
and the mean are identical: both are zero. While the use of the median would produce a result that
ignores the trend that ETI says should be taken into account, the mean produces the same result.
Changing the hypothetical produces no more clarity. If the examination was of a period that had ten
years of positive five percent salvage value, followed by one year of zero percent net salvage value,
followed by the most recent 10-year period, which had negative 10 percent net salvage value, the
median would still be zero but the mean would be negative 2.38 percent. This appears to support the
trending argument advanced by ETI. If the analysis then focuses on a different hypothetical, one

397
      Tr. at 401-402.
398
      See Staff Ex. 9 (Docket No. 38339 Final Order); Tr. at 402.
399
      Tr. at 415-416.
400
      ETI Initial Brief at 105.
401   Id.
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with ten years of positive 10 percent net salvage value followed by one year of zero percent net
salvage value, with the most recent ten-year period having negative five percent net salvage value,
the results are more perplexing. The median is still zero, but the mean, which ETI contends will
recognize the trending, is 2.38. Although this does in some respects recognize the trend to a negative
salvage value, it does not recognize it as well as the median.

       Principles and Procedures of Statistics, by Steel and Torrie, states: "Certain types of data
show a tendency to have a pronounced tail to the right or the left. Such distributions are said to be
skewed, and the arithmetic mean may not be the most informative central value." Where the average
of the incomes of a group of individuals is required, and most of those incomes are low, the mean
income could be considerably larger than the median. In Docket No. 38339, Staff posed the
following example, which the AU s found both informative and persuasive: Suppose a sample of
50 incomes from professional baseball players was taken that happened to include the salary of two
of the most highly compensated players in the league today. As a result, the mean of the salaries
would likely be far greater than the median salary, because the use of the median would be skewed
by the very high salaries. The median would likely provide a more accurate measure of the central
tendency of the salaries. Such circumstances are found where using the median to find the central
tendency prevents outliers in data that "skews" or shows extreme variations rather than showing
more symmetrical variations. The ALls believe this is as accurate today as it was during the Docket
No. 38339 timeframe. They therefore find that the use of the median is the more appropriate
methodology for determining net salvage value.

       Remaining Life. Composite remaining life is the weighted average remaining life of the
property account for a group of all vintages. The average remaining life represents the future years
of service expected for the surviving property.

       There are numerous ways to calculate the remaining life (life parameter) of a group of assets
in a depreciation study. Examples include the interim retirement rate method and the retirement
(actuarial) rate method. The interim retirement rate method uses interim retirement curves to model
(predict) the retirement of individual assets within plant accounts. Alternatively, the retirement
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PUC DOCKET NO. 39896

(actuarial) rate method uses historical mortality data for a group of assets and compares that data to
various known patterns of industrial asset mortality rates (Iowa Curves). If the historical data creates
a pattern of mortality that closely follows one of the Iowa Curves, then that Iowa Curve may be used
to approximate the remaining lives of that given group of assets in the future. Whether the historical
mortality data creates a pattern that closely follows a given Iowa Curve is determined through
plotting both sets of data (the historical mortality data and the Iowa Curve) on a graph and
quantifying the closeness of fit through statistical analysis and visual examination.

          Mr. Watson used multiple methods to calculate the remaining lives of assets, depending on
the asset. Generally, he used the retirement rate (actuarial) method. 402 However, to calculate the
remaining life of production plant accounts, he used the interim retirement rate method. 403 Ms.
Mathis disagreed with the use of the interim retirement rate method because the Commission has
rejected the application of interim retirement rates of production plant, as they are based on future
projection of retirements, for ETI and Central Power and Light Company in Docket Nos. 16705404
and 14965,405 respectively.

          ETI argues that the life span procedure, without the use of interim retirement curves, is
unrealistic in its assumption that all production plant assets are "depreciated (straight-line) for the
same number of periods and retire at the same time (the terminal retirement date)." Use of interim
retirements is an important refinement that adds accuracy to the determination of the depreciation
rates according to ETI. Mr. Watson offered the following explanation:

          Adding interim retirement curves to the procedure reflects the fact that some of the
          assets at a power plant will not survive to the end of the life of the facility and should

402
      ETI Ex. 13 (Watson Direct) at 16.
403
      Staff Ex. 2 (Mathis Direct) at 14.
404
   Application ofEntergy Gulf States, Inc., for Approval of its Transition to Competition to Competition Plan
and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel
Factors, and to Recover a Surcharge for Under-recovered Fuel Costs, Docket No. 16705 (Oct. 14, 1998).
405
    Application of Central Power & Light Company for Authority to Change Rates, Docket No. 14965
(Oct. 16, 1997).
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          be depreciated (straight-line) more quickly and retired earlier than the terminal life of
          the facility. 406

ETI contends that this issue presents a unique situation where all the experts agree with the
theoretical soundness of Mr. Watson's approach, but Mr. Pous and Ms. Mathis recommend its
rejection due to the existence of contrary Commission precedent. The impact of their position is a
$1,558,081 reduction to depreciation expense, based on December 31, 2010, plant balances.
Mr. Pous generally supports the use of interim retirements because "I think it's right,"407 and he uses
the method in other jurisdictions, where it is a prevalent practice. Ms. Mathis "also appears to
recognize the theoretical soundness of utilizing interim retirements."408 Even in Docket No. 16705,
the precedent cited by Mr. Pous and Ms. Mathis, the Staff depreciation witness agreed that the use of
interim retirements was appropriate, though not blessed by the Commission. ETI argues that use of
interim retirements reflects the undisputable fact that "generating units will have retirements of
depreciable property before the end of their lives.''409

          ETI is correct that neither Ms. Mathis nor Mr. Pous provide any reasoning behind the prior
Commission precedent. Moreover, it is also true that the Commission precedent is relatively old at
this point (dating back to the mid-1990s) and apparently has not been revisited in any recent cases.
ETI argues that the Commission has in at least one other case used interim retirements (Docket
No. 15195410), but provides little more than that comment to support the concept. It is true that in
concept, interim retirements are determined in much the same fashion as other elements of
depreciation analysis.        Primarily based on historical accounting data, the analyst identifies
characteristics in the history of the data upon which to base a reasoned assessment of retirements
going forward, which is similar to what occurs in determining asset lives or net salvage. Interim

406
      ETI Ex. 13 (Watson Direct) at Ex. DAW-I, at 7-8.
407
      ETI Ex. 7 I (Watson Rebuttal) at 7 I, citing Pous Deposition at 49, 5 I.
408
      Staff Ex. 2 (Mathis Direct) at I2-l3.
409
      ETI Ex. 13 (Watson Direct) at Ex. DAW-I, p. 8.
410
   Application of Texas Utilities Electric Company for the Reconciliation of Fuel Costs, Docket No. I 5 I 95
(Aug. 26, I 997).
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retirement determinations are supported by their own Iowa Curves, just as is the analysis of plant
lives.

          Although the AU s are persuaded by ETI' s arguments that the use of interim retirements may
be the more theoretically correct methodology to employ, Commission precedent clearly disfavors
the use of interim retirements and the A.Us are reluctant to rule contrary to Commission precedent.
Accordingly, the Al.Js find that the retirement (actuarial) rate method, rather than the interim
retirement method, should be used.

          2. Production Plant

                       (a) Lives

          Mr. Watson primarily used the life span method to calculate remaining lives of the
production plant accounts. 411 The life span method estimates a production plant's life based on
consultation with utility management, financial, and engineering staff.412 However, he used interim
retirement methodology to reduce the remaining lives determined by the life span method. Staff
does not dispute the remaining lives determined by the life span methodology, but does dispute the
use of interim retirements. For the reasons discussed in Section VII.C.l, ETI should not be allowed
to use the interim retirement methodology to adjust downward the remaining lives of its production
plant accounts.

          Cities witness Pous disputed only the remaining life determination for ETI's Sabine Power
Plant Units 4 and 5, ETI's largest and newest gas fired generating units. Mr. Pous recommended a
life span for Sabine Units 4 and 5 of 64 years based on assessment of the units, comparison to the
estimated life span of similar units owned by ETI as well as other gas fired generating units across
the country. ETI proposes a 60-year life for the two units. Mr. Pous noted that a "64-year life span
recommended for Sabine Units 4 and 5 is consistent with the life span proposed by the Company for
its Lewis Creek 1 generating unit. Lewis Creek Unit 1 is an older, smaller, and generally less

411
      ETI Ex. 13 (Watson Direct) at 16.
412
      Staff Ex. 2 (Mathis Direct) at 14.
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efficient generating unit than Sabine Units 4 and 5. Cities contend that there is no basis or logic for
assigning a shorter life span for a more capital-intensive asset that is newer, larger, and generally
more efficient."413

          ETI witness Watson explained that he primarily relied on the determination of Company
personnel to arrive at the 60-year life for the Sabine Units. Although Cities attempted to cast doubt
on Mr. Watson's determinations regarding the life of these units, it is clear that his determinations
are based on conversations with ETI various generation personnel and that those conversations
confirmed that based on evaluation of a variety of considerations, including age, operational role,
level of funding, unit condition, and operational risk, 60 years constitutes a reasonable threshold for
the expected life of Sabine Units 4 and 5. It is also clear that comparisons to Lewis Creek Unit 1 are
not appropriate. Lewis Creek Unit 1 has significant differences, which explain its longer life-span.
Unlike the Sabine Units, ETI is planning to spend in excess of $100 million to refurbish the Lewis
Creek critical equipment over the next three years to sustain operating reliability. ETI is not
performing similar refurbishment activities at Sabine. 414

          The Sabine Units are projected to be "must-run" units. This means that these units are, for
the most part, deployed to operate whenever they are available for service. Mr. Pous compared these
units to EAi's Lake Catherine Units 1 & 2, 415 but ETI contends this is not a reasonable comparison.
EAi's Lake Catherine Units 1 & 2 are not "must-run" units. They experience very infrequent
operation and are not projected to run much in the future. Other things being equal, according to
ETI, this would justify the longer 67-year life span assigned to these Arkansas units, because they
would not be experiencing the wear and tear of daily operation.416

          The explanations offered by ETI for the 60-year life of the Sabine Units 4 and 5 generating
facilities are convincing. It appears that Mr. Watson engaged knowledgeable people within ETI to

413
      Cities Ex. 5C (Pous Depreciation Study) at 9.
414
      ETI Ex. 51 (Garrison Rebuttal) at 3.
415
      Cities Ex. 5 (Pous Direct) at 7-8.
416
      ETI Ex. 51 (Garrison Rebuttal) at 3.
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gather pertinent information and applied that information appropriately. The comparison to Lake
Creek units is not appropriate given the planned refurbishment of those units. Similarly, the
comparison to the Lake Catherine units also fails. A unit that does not carry the "must-run"
designation can easily be expected to perform longer than a unit, such as the Sabine Units, that
carries the "must-run" designation. Accordingly, the ALls find that ETI' s choice of a 60-year life for
the Sabine Units 4 and 5 is reasonable.

                       (b) Net Salvage Value

          In determining the net salvage attributable to production plant, ETI witness Watson started
with the negative 5 percent net salvage factor approved most recently for ETI in PUC Docket
No. 16705. This is a net salvage value that the Commission has adopted in a number of cases for
production plant. 417 Mr. Watson testified that the net salvage calculation must reflect known
changes in the cost of retiring production plant since the net salvage factor was last set. Accordingly,
Mr. Watson's study used the Handy-Whitman labor index to calculate the change in labor costs
applicable to removal activity for the years 1997 to 2010. Consideration of the increases in labor
costs over this 13-year period resulted in an increase in the cost of removal, and a corresponding
increase in the level of negative net salvage, from negative five percent to negative 8.5 percent. 418

          Both Staff witness Mathis and Cities witness Pous disagreed with ETI's proposal for
production plant net salvage. Ms. Mathis proposed that the existing negative 5 percent net salvage
factor be retained. Ms. Mathis stated that Mr. Watson's analysis is flawed for three reasons:

•     First, Mr. Watson did not calculate a gross salvage value for each plant. This is a
      necessary element of the fundamental net salvage rate calculation. 419

•     Second, Mr. Watson unreasonably assumed that all steam production plants would be
      demolished at the end of their estimated remaining lives without any consideration of

417
      Staff Ex. 2 (Mathis Direct) at l 7.
418
      ETI Ex. 13 (Watson Direct) at Ex. DAW-l, at 64.
419
      Staff Ex. 2 (Mathis Direct) at 16-17.
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      reuse of the unit after refurbishment, or mothballing the unit or selling the unit in the
      event of deregulation of the generating function of the utility. 420

•     Third, Mr. Watson did not provide detailed plans for the actual demolition of each of its
      power plants. The Commission has consistently approved negative five percent net
      salvage rates for production plants if detailed plant-specific and reasonable demolition
      cost studies were not filed by the utility. 421

            ETI responds that Staffs recommendation fails to account for the fact that the
negative 5 percent benchmark is stale, having been established in a Commission proceeding 35 years
ago. Since that time, "labor costs have escalated by 267 percent with the rational expectation that
they will continue to increase at least with inflation."422

            Cities witness Pous recommended moving from the current negative five percent net salvage
to a positive 5 percent net salvage; i.e., that it should be determined that the gross salvage from the
power plants will exceed the removal cost. Mr. Pous stated that he bases this claim on the ETI' s
actual experience over the past 45 years as well as current trends within the industry in the last
14 years. According to Mr. Pous, ETI has retired many units since 1965 and demolished or sold the
units and achieved a range of net salvage values from zero percent net salvage to
positive 180 percent. 423 Other utilities in Texas and elsewhere have also experienced positive net
salvage levels. 424 Mr. Pous testified that since 1998 over 1,000 generating units have been sold, and
in all instances resulted in positive net salvage. 425 He also claims that his positive five percent
production net salvage is consistent with the Commission's decision in the most recent SPS case,
Docket No. 32766, where Mr. Watson was hired by SPS as a depreciation witness and the

420
      Id. at 17.
421   Id.
422
      ETI Ex. 71 (Watson Rebuttal) at 17, 19.
423
      Cities Ex. 5 (Pous Direct) at 15.
424
      Cities Ex. 5C (Pous Depreciation Study) at 11; Cities Ex. 5 (Pous Direct) at 15-16.
425
      Cities Ex. 5C (Pous Depreciation Study) at 11.
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Commission ultimately approved a positive five percent net salvage. 426 As ETI notes, however, the
SPS rate case was the result of settlement427 and is of little precedential value.

          ETI argues that Cities witness Pous appears to primarily base this claim on the fact that the
sale of utility plants in circumstances bearing no relationship to depreciation analysis has yielded
gains that Mr. Pous characterizes as "positive net salvage." He uses as examples sales that form a
part of the restructuring of the Texas utility business to introduce retail competition. Ms. Mathis also
concluded, without elaboration, that ETI' s production plant net salvage analysis is flawed because it
does not consider the possibility that the unit could be sold as a consequence of deregulation.
Neither Ms. Mathis nor Mr. Pous, however, pointed to any instance in which the Commission has
adopted such an approach to determining net salvage.

          ETI contends that this argument should be rejected for a number of reasons. It argues that
although there is no precedent supporting Ms. Mathis' and Mr. Pous' approach, there is clear recent
precedent rejecting the inclusion of sales in depreciation analysis. 428 The sales referenced by these
witnesses are unique and unpredictable events, as should be evident from the use of the restructuring
of the utility industry as an example of this type of activity. Indeed, at this time the Texas
Legislature has halted for the foreseeable future any ETI move to competition. For purposes of
depreciation analysis, net salvage is aimed at determining the salvage received at the end of the
plants' useful lives. Mr. Pous' analysis necessarily assumed that, due to the sale, the life of the
plants will be truncated. Yet he made no adjustment to production plant lives to account for the
effect of theoretical sales.429

          ETI also contends that Mr. Pous' other examples of positive net salvage are equally
unavailing. Mr. Pous points to ETI's retirement of Neches Station as an example of positive

426
      Cities Ex. 5 (Pous Direct) at l 7.
427
      See ETI Ex. 71 (Watson Rebuttal) at 6.
428
   See Application ofAEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, FoF l 07,
108, 112 (Mar. 4, 2008) (proceeds from sale of building properly removed from depreciation analysis as
non-recurring item).
429
      ETI Ex. 71 (Watson Rebuttal) at 5-7.
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salvage,430 but fails to mention that: (1) this outcome was uniquely the result of insurance proceeds
received by ETI after a boiler explosion; and (2) the proceeds flowed back to customers via means
other than depreciation rates. 431 ETI contends that Mr. Po us' claim that a contractor paid $1 million
for the right to demolish a power plant, apparently based on unrecorded hearsay conversations, and
without any information from Mr. Pous regarding the facts and circumstances surrounding the
transaction, proves nothing.

          Finally, Mr. Pous stated that Mr. Watson's adjustment to the net salvage rates is flawed
because it does not adequately reflect the increase in scrap metal prices in recent years. ETI responds
that although scrap metal prices have gone up recently, it is unknown what the prices will be in the
future, and these commodity prices have proven to be quite volatile and unpredictable. 432 According
to ETI, it is not reasonable to assume, as does Mr. Pous, that prices will stay indefinitely at what is
their historically highest level. ETI argues that Mr. Pous' method is based on speculation and broad,
conclusory opinions regarding economic trends, as to which he makes no attempt to actually arrive at
a quantifiable analysis that yields his unprecedented positive net salvage recommendation. 433

          Mr. Pous' testimony that net salvage value should be revised to reflect a value of
positive 5 percent is seriously flawed. First, pointing to a settled case as precedent carries no weight.
Second, attempting to draw conclusions from sales that were forced to comply with the regulatory
framework and apply those conclusions to an entity that is not subject to the same regulatory
framework is equally flawed. Finally, Mr. Pous attempted to use ETI's own experience to support
his position ignores the fact that ETI' s experiences were driven by factors that were unique to ETI at
the time and circumstances involved; they do not support the more universal application urged by
Mr. Pous.

43
  ° Cities Ex. 5 (Pous Direct) at 14.
431
      ETI Ex. 46 (Considine Rebuttal) at 49-50.
432
      ETI Ex. 71 (Watson Rebuttal) at 17-18.
433
      ETI Initial Brief at 103.
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PUC DOCKET NO. 39896

          Ms. Mathis' analysis, in some respects, suffers from the same flaws as Mr. Pous'.
Nevertheless, some of her points carry more weight. The AUs believe that Mr. Watson is correct
that labor costs have increased since the negative five percent net salvage value was first established
by the Commission. However, that is not the end of the story. Are there other factors that also have
changed in the corresponding time period? There is no evidence on this point, and that is the crux of
the matter. As Ms. Mathis argues, there is only one way that all the changing values can be
evaluated; through the introduction of plant-specific demolition cost studies. Had studies of that
nature been provided, the parties would have been able to evaluate them and provide a supportable,
fully-vetted recommendation.           The AUs recommend that the Commission find that a
negative 5 percent net salvage value for production plant is appropriate.

                      (c) Depreciation Reserve

          TIEC argues that $1.1 million of ETI's requested $13 million increase in depreciation
expenses is related to ETI' s production plant assets. 434 ETI has a $92,537 ,000 surplus in production
plant assets. A surplus depreciation reserve occurs when the theoretical reserve (the reserve that
would exist if the current proposed rates had been in place in the past) exceeds the per book
depreciation reserve. According to TIEC, this indicates that ETI customers have overpaid the value
of production plant assets. 435 Since ETI has already over-recovered the value of the production plant
assets, there is no valid reason to seek any additional recovery. TIEC contends that ETI has not
shown why it needs to increase production depreciation rates at this time given that the production
depreciation reserve has a considerable surplus. Therefore, it argues, $1.1 million of the proposed
increase should be rejected.

          ETI rejects TIEC' s recommendation because it is clearly contrary to Commission policy and
precedent. According to ETI, the Commission has consistently adopted the remaining life, straight-
line method for determining depreciation rates. 436 This method requires that the remaining life of

434
    ETI Ex. 13A (Watson Workpapers) at Appendix B. This figure is derived by subtracting the expenses
from the existing production plant account from the proposed production plant account.
435
      TIEC Ex. l (Pollock Direct) at 36-37, Ex. JP-5.
436
      See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, PFD at
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PUC DOCKET NO. 39896

the asset be determined, and depreciation rates established to recover the asset's remaining cost in
equal installments over that life. In this way, by the end of the life, the costs will be recovered.
Mr. Pollock's approach ignores these principles, and seeks to look back in time to compare how the
depreciation rates now proposed would have affected the recovery in the past. Those past
depreciation rates, however, were authorized for use by the Commission.                  ETI argues that
depreciation rates are at all times estimates, subject to adjustment using updated studies, and there is
no reason for adoption of Mr. Pollock's alternative. Finally, the Commission expressly rejected
adjustment to the outcome of remaining life depreciation determinations based on differences
between theoretical and book depreciation reserves in CenterPoint Docket No. 38339. 437

          The ALls agree with TIEC that the Commission's decision in Docket No. 38339 is not
four-square on point with this case. That is not sufficient, however, to overcome the arguments
advanced by ETI in favor of its position in the current case. The Commission has consistently used
the remaining life, straight-line methodology for determining depreciation rates, and that
methodology requires that the remaining life of the asset be determined, and depreciation rates
established to recover the asset's remaining cost in equal installments over that life. Mr. Pollock's
proposal ignores that consistently applied methodology. The AU s recommend that the Commission
approve ETI's recommended treatment of the production plant depreciation reserve.

          3. Transmission Plant

                      (a) Lives

          Mr. Watson's study presents ETI's life proposal for transmission Accounts 350.2 to 359, a
                           438
total of eight accounts.         Neither Staff witness Mathis nor Cities witness Pous took issue with any

 127-128 (Mar. 4, 2008); Application of CenterPoint Electric Delivery Company for Authority to Change
Rates; Docket No. 39339, PFD at 86 (Dec. 3, 2010); Application of Oncor Electric Delivery Company, LLC,
for Authority to Change Rates, Docket No. 35717, PFD at 153-154 (June 2, 2009).
437
      ETI Ex. 71 (Watson Rebuttal) at 75-77 (citing CenterPoint Docket No. 38839 PFD).
438
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 30-36.
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                                                                 439
of the recommended lives for transmission plant accounts.              Accordingly, the ALJs recommend that
the Commission adopt ETI's proposed lives for these accounts.

                       (b) Net Salvage Value

          Staff disagrees with Mr. Watson's recommendations for two of the eight transmission
accounts, and Mr. Pous disagrees regarding three of the accounts. The parties' positions on
transmission net salvage values in dispute are set out below:

                                    Transmission Account Net Salva2e
                 Account                    Current        ETI                     Staff         Cities
                                          Net Salvage    Proposal                Proposal       Proposal
                                             Value
352-Structures & Improvements                    -5%              -10%              -5%           -10%
353-Station Equipment                           +5%               -20%             -20%            0%
354-Towers & Fixtures                            -5%              -20%              -5%           -20%
355-Poles and Fixtures                          -25%              -30%             -30%           -15%
356-0verhead Conductors &                       -20%              -30%             -30%           -10%
Devices

                   (i) Account 352-Structures & Improvements

          Mr. Watson's analysis of this account, and for all the accounts in his study, included the
examination of trends and bands for numerous years. For Account 352, he found the five-year and
ten-year moving averages for the years 2008-2010 particularly telling. 440 A moving average is a
rolling average that updates each year to include the additional year as part of the average for the
longer period under study. Mr. Watson testified that his recommendation of negative 10 percent net
salvage is consistent (albeit less negative) with the five-year and ten-year moving averages for 2008,
which range from negative 16.31 percent to negative 16.80 percent. Although the moving averages

439
      Staff Ex. 2A (Mathis Direct) at 21; Cities Ex. 5 (Pous Direct) at 28.
440
      ETI Ex. 71 (Watson Rebuttal) at 56.
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for 2009 and 2010 appear more positive, this was the result of a large, atypical gross salvage in
            441
2009.             Cities propose no change to Mr. Watson's recommendation.

              Staff witness Mathis recommended a net salvage rate of negative five percent for
Account 352. This recommendation is based on analysis of historical salvage data for the period of
1984 through 2010. Specifically, the three-year moving average for the same period produces a net
salvage rate of negative 5.53 percent, which is very close to the currently approved net salvage rate
for this account. Moreover, an examination of the mean and median rolling band averages for
Account 352 shows a range of net salvage rates between positive 0.08 percent and
negative 6.83 percent. 442 Thus, according to Ms. Mathis, the net salvage rate of negative 5 percent is
a reasonable estimate based on the available historical data.

              In response to Mr. Watson's contention that the 2008 moving average is the most important,
Ms. Mathis pointed out that the 2009 five-year and ten-year moving averages feature
positive 16.66 percent and positive 4.45 percent net salvage rates, respectively. Moreover, the 2010
five-year and ten-year moving averages feature positive 25 .13 percent and positive 6. 75 percent net
salvage rates, respectively. 443 Ms. Mathis stated that if it is a sound depreciation methodology to
select a net salvage rate based on recent five-year and ten-year moving averages, then the rate for this
account should be significantly greater than either Ms. Mathis' or Mr. Watson's recommendation. 444

                  Although the moving averages cited by Ms. Mathis for 2009 and 2010 appear to belie the
arguments raised by Ms. Watson, the AlJs are persuaded that those are significantly influenced by
the atypical gross salvage resulting from the 2009 sale of a spare transformer, an asset whose cost is
booked to an entirely different account. If, as claimed by Mr. Watson, the sale was sufficiently

441
   ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65. The atypical gross salvage resulted from the sale of a
spare transformer, an asset whose cost is booked to an entirely different account. ETI Ex. 71 (Watson
Rebuttal) at 57. The atypical amount is shown at Appendix E-2 at 1 of Mr. Watson's depreciation study.
442
      Staff Ex. 2 (Mathis Direct) at 22, Appendix Cat l.
443   Id.
444
   According to Ms. Mathis, if 2009' s moving averages are adopted, the net salvage ratio should be around
positive 4.45 percent or positive 16.66 percent If 2010's moving averages are adopted, the net salvage ratio
should be around positive 6.75 percent or positive 25.13 percent
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atypical, it would influence both 2009 and 2010 moving averages, making them unreliable.
Accordingly, the Alls recommend that the Commission adopt ETI' s negative 10 percent net salvage
value for Account 352.

                   (ii) Account 353~Station Equipment

            Similar to Account 352, a large atypical positive salvage amount in this account makes the
most recent moving average appear more positive than the history would otherwise suggest. 445
Mr. Watson recommended setting net salvage at negative 20 percent, which he contended is a
reasonable middle ground between the values suggested by the five-year and ten-year moving
averages for transaction year 2010 (which show net salvage of negative 14.42 percent and
negative 20 percent, respectively). 446 Ms. Mathis agreed with the Company's proposal on this
account.

            Although Mr. Pous acknowledged that retention of the current Commission-approved
positive five percent net salvage is supported by ETI's experience, he ultimately opted for a
recommendation that the net salvage value be reduced to zero percent. Mr. Pons noted that the
actual per book data for a five-year band and a ten-year band are a positive 117 .04 percent and a
positive 31.95 percent, respectively. 447 Mr. Pous stated that his analysis does not ignore the positive
net salvage recorded by ETI because of the sale of transmission investment, rather he testified that:

            the Company has reported five separate sales during the past 22 years, or about once
            every four years. Such activity cannot be considered an 'unusual circumstance' or an
            outlier, and should be taken into consideration as an event that may continue to occur
            in the future. In a proper evaluation phase of a depreciation study, recognition of
            some level of future sales is appropriate. 448

445
      The atypical amount is shown at Appendix E-2, p. 1 of 10 of Mr. Watson's depreciation study.
446
      ETI Ex. 13 (Watson Direct) at Ex. DAW-I at 65.
447
      Cities Ex. SC (Pous Depreciation Study) at 21, 23.
448   Id.
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Mr. Pous' analysis also reflected that transformers, which contain large quantities of copper and
produce gross salvage when retired, comprise a significant level of investment in this account, but
were underreported in the five-year and ten-year band analyses. 449 Mr. Pous stated that, given the
significant increase in the value of copper, the future proportionate retirement of transformers will
result in future net salvage values being less negative or more positive than the historical data.

           ETI responds that Cities' criticism that the per book data in Mr. Watson's workpapers show a
large positive net salvage value for the five-year and ten-year bands is unfounded. According to ETI,
Mr. Watson's workpapers clearly indicate that adjustments were required and made to the per book
data for unique transactions involving sales and storm activity. As to sales, the workpapers 450 show
that in the 26 years of data for Account 353, there were three occasions with very large sales
proceeds for the sale of substations. As to storm activities, the same workpapers show only one
occasion in 26 years where gross salvage amounts were recorded. ETI contends that these unique
events are properly excluded from net salvage analysis and Mr. Pous' reliance on the per book data
to establish positive net salvage is erroneous. With respect to Mr. Pous' concem's relating to the
price of copper, ETI responds that Mr. Pous' reliance on copper's scrap value is pure speculation,
unsupported by any ETl-specific data regarding the amount of copper at issue, or any consideration
of the offsetting significant and increasing labor costs involved in the removal of large station
transformers.

           As explained by Mr. Watson, it appears to the AlJs that the adjustments made were, indeed,
required because of the unique nature of the events they reflected. The AU s also find that Mr. Pous'
concerns relating to the price of copper are speculative. Coupled with the fact that Staff supports
ETI's proposed net salvage value, the AUs recommend that the Commission approve ETI's
recommended negative 20 percent net salvage value.

449
      Id. at 22.
450
   ETI Ex. 13A (Watson Direct) Workpaper on CD, "Entergy Net Salvage Transmission Distribution
General" Spreadsheet, "Data Adjustments" Tab, Account 353.
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                   (iii) Account 354-Towers and Fixtures

           Although there is limited experience available for this account, the five-year and ten-year
moving averages for transaction year 2010 show a substantial level of negative net salvage
(negative 299 percent and negative 233 percent, respectively). Taking into account the low level of
retirement experience, Mr. Watson stated that he moderated the outcome by recommending moving
                                           451
to negative 20 percent net salvage.              Mr. Pous concurred in this recommendation.

           Ms. Mathis recommended a net salvage rate of negative 5 percent for Account 354. 452 This
recommendation is based on Commission precedent due to the absence of reliable historical salvage
data. 453 Although historical salvage data is available for the period of 1984 through 2010, this
account had a low level of retirement during this period. 454 Because of the limited retirement
activity, Ms. Mathis stated that a reasonable net salvage rate cannot be calculated from the historical
salvage data. 455         For example, annual net salvage rates range from approximately
negative 6,000 percent to approximately positive 31,253,400 percent.456 According to Ms. Mathis,
such divergent numbers are indicative of the low retirement activity within this account.

           The negative five percent net salvage value recommended by Ms. Mathis is the current
Commission-approved number. The AUs find it difficult to draw any conclusions from the paucity
of historical data. Had there been additional historical data, it might have been possible to reach the
conclusion urged by Mr. Watson; however, there was not.                   The ALls recommend that the
Commission adopt the negative five percent net salvage value recommended by Staff.

451
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66.
452
      Staff Ex. 2 (Mathis Direct) at 23.
453
      Id. at 23.
454
      ETI Ex. 13 (Watson Direct) at DAW-1at66.
455
      Staff Ex. 2 (Mathis Direct) at 23.
456
      Id. at Appendix C at 2.
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                  (iv) Account 355-Poles and Fixtures

          The Commission approved net salvage value for this account is a negative 25 percent.457
This account has shown negative salvage since the 1990s, and the most recent ten-year moving
averages show negative 33.84 percent net salvage. Although years 2009-2010 reflect positive
salvage values, Mr. Watson determined that these values were the product of differences in the
timing of the recording of the various transactions associated with the asset retirement, rather than
reflecting an actual positive salvage amount. 458 For example, Mr. Watson's net salvage workpapers
show a significant level of positive salvage only for the years 2009-2010 in Account 355. 459 This is
at odds with the remainder of the net salvage data shown in the workpapers, which is almost
exclusively negative net salvage. 460 Accordingly, Mr. Watson gave less weight to the 2009 and 2010
values, but moderated his recommendation compared to the ten-year moving averages, resulting in a
recommended net salvage of negative 30 percent. Ms. Mathis concurred.

          Cities witness Po us disagreed with Mr. Watson's analysis, claiming: ( 1) per book data from
the five-year and ten-year moving averages show positive net salvage amounts; (2) authoritative
depreciation treatises do not support Mr. Watson's decision to adjust relocation-related transactions
out of the analysis; 461 (3) no portion of relocation-related costs can be treated as removal unless that
treatment is prescribed by contract with the third-party; and (4) after the correction to his analysis,
Mr. Watson changed his methodology to arrive at a negative net salvage recommendation. Mr. Pous
recommended an increase in the net salvage values to a negative 15 percent based on the actual
historical data of ETI. Cities contend that Mr. Pous was conservative in his recommendation given

457
      Cities Ex. 5C (Pous Depreciation Study) at 23.
458
      ETI Ex. 13 (Watson Direct) at Ex. DAW-I, p. 66.
459
    ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, lines 130-131,
columns I S.
460
   ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, at lines 105-129,
columns I - AC. The 2005-2006 data in this workpaper show an obvious example of an accounting
adjustment timing difference, wherein the year 2005 shows a $1,867,532 removal cost (row 126, column G),
while the immediately following year 2006 shows a large negative removal adjustment of ($1,059,096),
(row 127, column G).
461
    Relocations involve the situation where the Company is reimbursed by a third party who desires the
relocation or replacement of the facilities in question.
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the trend in the data. The most recent five-year band of actual data yields a positive two percent net
salvage.462

          The ALI s agree that the debate regarding this account essentially boils down to whether
Mr. Watson's adjustment to remove relocation expense associated with third-party reimbursement
from the analysis is appropriate. Although Mr. Pous claims that Mr. Watson's approach is contrary
to authoritative guidance, ETI contends that he arrives at that conclusion only by disregarding the
guidance in question, as well as Commission precedent. ETI argues that the depreciation text in
question squarely supports Mr. Watson's approach:

          A reimbursed retirement is one for which the company is fully compensated at the
          time of retirement .... Usually reimbursed retirements should not be included in
          analysis of property whose investment is recovered through depreciation accruals. 463

          Mr. Watson explained at hearing that, in his experience, adjustments to remove relocation
expense are standard in depreciation analysis, and to do otherwise would result in a disproportionate
impact on reasonably expected ongoing net salvage, caused by a transaction (the relocation) that
constitutes a very small portion of the overall assets in question. 464

          Mr. Pous stated that all third-party reimbursements for facility relocation performed by the
Company have to be deemed as salvage (thereby inflating the salvage portion of the net between
removal costs and salvage proceeds) unless a contract between ETI and a third-party explicitly says
otherwise. Mr. Watson's approach, however, is squarely supported the Commission's decision in the
recent Oncor case, Docket No. 35717, where it was held that these third-party "reimbursements are
prepayments for new property being installed."465 The Al.Js find that Mr. Pous' argument is not
credible in light of Mr. Watson's treatment of relocations in general. Since Mr. Watson properly
removed such relocation expense from the depreciation analysis altogether, those amounts correctly

462
      Cities Ex. 5C (Pous Depreciation Study) at 22-25.
463
      ETI Ex. 71 (Watson Rebuttal) at 63 (quoting Depreciation Systems, Iowa State Press, 1994, at 16-17).
464
      Tr. at 405.
465
      ETI Ex. 71 (Watson Rebuttal) at 63.
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PUC DOCKET NO. 39896

have no impact on depreciation rates, regardless of how they are allocated between gross salvage
proceeds and the cost of installing new facilities.

          ETI' s evidence and argument support its request. Accordingly, the AUs recommend that the
Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson.

                  (v) 356-0verbead Conductors and Devices

          The Commission approved net salvage value for this account is a negative 20 percent.466
Much as was the case with Account 355, ETI argues that timing differences in reflecting accounting
adjustments made the more recent shorter data bands less representative of reasonably expected
future net salvage. Mr. Watson's study determined that the longer ten-year moving average for
transaction year 2010 showed salvage of negative 33 percent, so Mr. Watson recommended moving
to negative 30 percent net salvage for this account.467 Staff witness Mathis adopted the same
negative net salvage value.

          Cities' witness Pous recommended an increase to the net salvage value to a
negative 10 percent based on a review of the actual historical data. The actual five-year and ten-year
bands yield a positive one percent and a negative 31 percent. Mr. Pous argues that the trend in the
data could justify even a less negative value.

          As with Account 355, the AUs find that ETI's evidence and arguments support its request.
Accordingly, the ALl s recommend that the Commission approve a net salvage of negative 30 percent
as proposed by Mr. Watson.

466
      Cities Ex. SC (Pous Depreciation Study) at 25.
467
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66-67.
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           4. Distribution Plant

                      (a) Lives

           An asset's useful life is used to determine the remaining life over which the cost will be
spread for recovery through depreciation expense.468 The Company's depreciation study addresses
14 distribution accounts included between Accounts 360.2 and 373.2. According to ETI, the life
parameters in Mr. Watson's study reflect standard depreciation analysis procedures, including
comparison to standard Iowa curves and actuarial analysis, along with the exercise of informed
judgment.469 Multiple bands and trends were reviewed and, in general, Mr. Watson's study
explained that the dispersion curve chosen for each account is based on examination of the various
"placement and experience bands"470 and the characteristics of the underlying asset in each account.
The dispersion curve is then chosen that best matches the actual data. 471 Staff disagrees with
Mr. Watson's life parameters for three accounts; Cities with five accounts. The parties' various
recommendations on the accounts in dispute are shown below:

                                   De reciation Plant Lives
       Account          A roved Life    ETIPro osal       Staff Pro osal                   Cities Pro osal
361                    45 s. S2       65                 70                               65 s. R3
364                    44             38                 40                               44
365                    44             39                 40                               42
367                    40             35                 35                               45
368                    39             29                 29                               33
369.1                  36             26                 26                               33

468
      Id. at 16.
469
      Id. at Ex. DAW-I at 37-54.
470
   Placement bands look at assets installed in various years and reveal the types of assets in the account over
time. Experience bands show accounting transactions associated with the assets over time and reveal trends
associated with operational changes and other events.
471
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 37-54.
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                   (i) Account 361 - Structures and Improvements

      Mr. Watson's study depicts the fit between the actual data in the account and the 65 R3 life
                                             472
parameter that he proposed for this account.      Mr. Pous agreed with this recommendation.
Ms. Mathis stated, however, that a life parameter of 70 R3 is a better visual fit for the 1960-2010
experience band. 473

        Considering all the historical mortality data available for this account (the overall experience
band), the selected Iowa Curve produces a conformance index (Cl) of 37.53.474 The CI is a measure
of closeness of fit, and a higher CI value indicates a closer fit between the two sets of data that are
being compared.475

           Mr. Watson recommended a life parameter of 65 years based on comparing various slices
(bands) of this account's mortality data to the 65 R3 Iowa Curve. 476 However, Staff argues that
Mr. Watson's recommended life parameter and Iowa Curve of 65-R3 produces a CI of only 23.61
when measured against the overall (1960-2010) experience band.477

           ETI responds that the flaw in Ms. Mathis' position is that she only looks at one band. As the
average age of the investment is only 19.22 years, it is inadequate to look at only one band that
examines a 50-year period. When shorter bands are also factored in (1970-2010 and 1990-2010), the
Company's proposal shows a significantly higher CI, which is indicative of a better fit to the actual
data.478

           The AL.Ts are persuaded that, in this instance, Ms. Mathis erred by limiting her review to a
single band, especially when that band is significantly longer than the average age of the investment

472
      Id. at Ex. DAW-1at37.
473
      Staff Ex. 2 (Mathis Direct) at 25-26.
474
      Id. at 26, Table-5.
475
      ETI Ex. 71 (Watson Rebuttal) at 24.
476
      ETI Ex. 13 (Watson Direct) at 18, Figure 1.
477
      Staff Ex. 2 (Mathis Direct) at 26, Table-5.
478
      ETI Ex. 7 I' (Watson Rebuttal) at 24.
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PUC DOCKET NO. 39896

at issue. In this case, looking at multiple, shorter bands will give a clearer picture of the average life
of the investment at issue. Therefore, the AU s recommend the Commission approve the 65 R3 life
parameter Mr. Watson proposes for this account.

                   (ii) Account 364-Poles, Towers, and Fixtures

                                                                                     479
          Mr. Watson's study results in his proposing a life parameter of 38 Rl.5.         He stated thatthe
current plant in service reflects a life (13.97 years on average) that is substantially shorter than his
recommendation, and all the bands examined reflect a shorter life than the currently approved
44 years. Mr. Watson testified that his recommendation balances these facts with the additional fact
that ETI is currently using Penta and CCA-treated poles (as opposed to creosote treated poles), for
which a longer life is expected.

           Ms. Mathis (40 Rl) and Mr. Pous (44 Ll) both proposed different life parameters than
Mr. Watson. Ms. Mathis stated that her proposed life parameter is a better visual and mathematical
fit for the single experience band (1959-2010) she considered. 480 Mr. Watson responded to this
argument, stating that the mathematical computer fitting emphasized by Ms. Mathis is too limited an
approach, because there is too little information provided at the tail of the curve to rely on computer
fitting in this instance. Mr. Watson indicated that his proposed life parameter shows a better fit over
the full range of placement and experience bands applicable to this account. 481

           Mr. Pous recommended that the expected service life remain at 44 years based on actuarial
analysis and advances made by the industry and ETI in treating and preserving poles. 482 Mr. Pous
also noted that "absent identifiable and supportable specific problems, the industry is not
experiencing shorter lives for poles and neither should ETI." 483 He stated that selection of different
types of poles and different treatments by other utilities have their engineers expecting lives between

479
      ETI Ex. 13 (Watson Direct) at Ex. DAW-I at 41.
480
      Staff Ex. 2 (Mathis Direct) at 28-29.
481
      ETI Ex. 71 (Watson Rebuttal) at 29-31.
482
      Cities Ex. SC (Pous Depreciation Study) at 35-36.
483
      Id. at 37.
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PUC DOCKET NO. 39896

                     484
50 and 70 years.           According to Mr. Pous, it is simply not realistic to believe or assume that ETI
would operate now or in the future in a manner that its poles would only last two-thirds the life
                                            485
expectance being achieved by others.              Mr. Watson responded that the increased life span urged by
Mr. Pous based on his general discussion of varieties of poles with longer lives is not verifiable, not
consistent with the Company-specific data or the specific experience of its distribution personnel,
and is plainly exaggerated. 486

            The AU s reviewed the evidence and arguments of the parties with respect to this issue and
were most persuaded by the Cis that resulted from the recommendations of Staff and ETI.
Considering all the historical mortality data available for ~his account (the overall experience band),
Staff's selected Iowa Curve produces a CI of 41..44, while ETI's produces a CI of only 20.66 when
measured against the overall (1958 - 2010) experience band.487 The AUs recommend that the
Commission adopt Staff's proposal of 40 Rl.

                    (iii) Account 365 - Overhead Conductors and Devices

                                                                          488
            The Commission approved average service life is 44 years.           All parties propose a change to
this life parameter. Mr. Watson proposed a life parameter of 39 R0.5, Ms. Mathis proposes a life
parameter of 40 R0.5, and Mr. Pous proposed a life parameter of 42 S.-5.

            Mr. Watson noted that his analysis took into account the fact that the currently authorized life
is longer than the history would support, and that the young average age of the current plant in
service (12.15) points toward placing more weight on recent bands for life selection. He also noted
that ETI' s movement toward re-conductoring lines supports the conclusion that lives in this account
will be shorter.

484   Id.
485
      Id. at 36.
486
      ETI Ex. 71 (Watson Rebuttal) at 28-29.
487
      Staff Ex. 2 (Mathis Direct) at 29, Table-6.
488
      Cities Ex. SC (Pous Depreciation Study) at 38.
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          Ms. Mathis indicated that her recommendation is based on comparing the account's historical
mortality data for the period of 1958 through 2010 to the 40 R0.5 Iowa Curve.489 Considering all the
historical mortality data available for this account (the overall experience band), the selected Iowa
Curve produces a CI of 29.63.490 Mr. Watson countered that Ms. Mathis used the wrong curve to
represent the Company's proposal in her calculations. He stated that when her analysis is corrected
to make the proper comparison, ETI's proposal has a higher CI (and thus a better fit) across all
experience bands save one. 491

          Mr. Pous testified that his life parameter best matches the actuarial analysis taking into
account the unusually high level of retirement activity recorded in the first 0.5 year of age.       As
Mr. Pous noted, "the highest retirement ratio for this investment in the first 23 years occurred at age
0.5 years, for brand new assets. While such events can and have occurred associated with utility
plant, it is not the type of event that is reasonably expected to repeat itself in future periods as
different equipment it purchases if it was an equipment problem, or different installation processes
are employed if the early retirement were due to installation issues."492 Mr. Pous criticized
Mr. Watson's recommendation on several grounds: (1) it is not consistent with expected lives
reported by ETI personnel; (2) it did not account for anomalies and/or unusual activity in the
retirement data; (3) the major re-conductoring activity shown in the account should not be expected
to continue; and (4) the life-curve combination chosen by Mr. Watson is not long enough to match
                      493
the actual data.

          Mr. Watson took issue with Mr. Pous. He stated that Mr. Pous simply misread the data
Mr. Watson argued that Exhibit DAW-R-1 to his rebuttal testimony shows that retirements are
decreasing. 494 Mr. Watson believes that his proposed life parameter is a better fit to the actual data.

489
      Staff Ex. 2 (Mathis Direct) at 30.
490
      Id. at 31, Table-7.
491
      ETI Ex. 71 (Watson Rebuttal) at 36.
492
      Cities Ex. 5C (Pous Depreciation Study) at 38-39.
493
      Id. at 38-41.
494
      ETI Ex.71 (Watson Rebuttal) at 32-33.
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PUC DOCKET NO. 39896

The very small amount of plant that may not last until the tail of the curve used by Mr. Watson does
not alter this conclusion.495 Finally, ETI argues that Mr. Pous provides no persuasive basis for
second guessing the opinion of Company personnel regarding re-conductoring.

          The AI.Js are persuaded by ETI's evidence and argument. It does appear that Ms. Mathis
used the wrong curve in her calculations. If corrected, Mr. Watson's proposal renders the higher CI.
Mr. Pous' arguments fair no better. To the Al.Js' eye, Mr. Pous did misread the data, and the
conclusions drawn by Mr. Pous are simply inaccurate. The ALl s recommend that the Commission
adopt ETI's proposed life parameter of 39 R0.5.

                   (iv) Account 367 - Underground Conductors and Devices

          The Commission approved average service life is 40 years. 496 Mr. Watson's life parameter
for this account (35 Rl.5) is based on h.is review of the various placement and experience bands, as
well as the characteristics and longevity of the conductors in place in the ETI system and the
retirement patterns that are unique to underground conductor performance and the locations where it
is buried. 497 Ms. Mathis agreed with Mr. Watson on this account. Cities propose a significantly
longer life (45 S-0.5). Mr. Pous stated that Mr. Watson's and Ms. Mathis' recommendations do not
account for the increased durability of newer types of conductor, and that the actuarial analysis
should focus on more recent data that he believes is more consistent with the newer conductors. 498

          Mr. Watson testified that Mr. Pous' recommendation should be rejected for a variety of
reasons. The Southern California Edison-based opinions regarding longer life for the conductor,
relied on by Mr. Pous, relate to plant installed less than ten years ago. Therefore, based on his own
theory, much of the investment in question in this account is still the older, shorter-lived variety, and
his recommendations are premature. Moreover, Mr. Watson's plotting of the dispersion curves show

495
      Id. at 32, 33-35.
496
      Cities Ex. 5C (Pous Depreciation Study) at 41.
497
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 45.
498
      Cities Ex. 5C (Pous Depreciation Study) at 41-44.
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PUC DOCKET NO. 39896

that his is a better fit than that of Mr. Pous. fu this instance, Mr. Pous' analysis, relying only on the
shortest band, failed to pick up the older investment that constitutes almost 80 percent of the
surviving investment.499

           It appears that Mr. Pous, in relying on the shortest band, did fail to take into account
investment that comprises almost 80 percent of the surviving investment in this account. That is a
significant flaw in his analysis. Similarly, his reliance on the Southern California Edison-based
opinions relate to newer plant, which again calls his analysis into question in the present
circumstances. The Al.J s recommend that the Commission approve ETI' s recommended service life
of 35 Rl.5.

                   (v) Account 368 - Line Transformers

           The Commission approved anticipated service life is 39 years. 500 Mr. Watson proposed a
service life of 29 Ll ,501 with which Ms. Mathis agreed. Mr. Watson stated that this is consistent with
the data showing decreasing lives for these assets, the expected lives per Company personnel, and the
fact that transformers are junked or sold rather than repaired. 502

           Mr. Pous recommended that the expected service life be decreased to 33 years, representing a
15 percent reduction in the anticipated service life. Mr. Pous stated that his analysis is based on
actuarial analyses and the Company's addition of approximately $80 million of pad mounted
transformers since the last case, when the Commission approved a 39-year anticipated average
service life. According to Mr. Pous, ETI personnel have stated that pole mounted transformers have
a life of between 25 and 35 years. However, pad mounted transformers are expected to last up to
40 years by the same Company personnel. Given the sizable investment since the last case in the pad
mounted transformers with a longer expected service life, a decrease in the anticipated service life of

499
      ETI Ex. 71 (Watson Rebuttal) at 40.
500
      Cities Ex. SC (Pous Depreciation Study) at 44.
501
      ETI Ex. 13 (Watson Direct) at Ex DAW-I at 50.
502
      Id. at 47.
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greater than 15 percent is not warranted, according to Mr. Pous. Moreover, Mr. Pous stated his
analysis uncovered abnormally high retirement ratios in the 21.5 to 22.5 year age brackets indicative
of one-time events such as the ice storm or changes in accounting systems. As such, Mr. Pous
performed his curve fitting analysis recognizing the unusually high retirement activity between years
21.5 and 22.5 rather than emphasizing such unusual activity as Mr. Watson did for his proposal to
reduce service life by 26 percent. 503

            Mr. Watson recommended a decline in average service life from a 39-year anticipated service
life to a 29-year anticipated service life citing the high occurrence of lightning in the ETI service
area. 504 However, Mr. Pous noted that the effects of lightning in ETI' s service area would have been
present in ETI's last base rate case when a 39-year anticipated service life was approved by the
Commission. Both Mr. Watson and Mr. Pous recognized that the pad mounted transformers are not
subject to the same forces of retirement like weather, lightning, and animal disturbances. 505
However, Mr. Watson did not realistically factor ETI's relative increased investment in pad mounted
transformers into his analysis. Moreover, when performing his curve fitting analysis, Mr. Watson
neither analyzed nor adjusted for the abnormal unusual retirement ratios between years 21.5 and
22.5. 506 Instead, Mr. Watson attempted to select a life analysis that anticipates a high level of
retirement within that time period in the future. sm Cities argue that, by failing to recognize the
sizable new investment in pad mounted transformers and failing to consider the unusual retirement
ratios, Mr. Watson proposed an average service life that is lower than the bottom end of the range of
life estimates of Company personnel for pad mounted transformers. Moreover, Mr. Watson's
proposal does not even reach the midpoint of life estimates expected by Company personnel for pole
mounted transformers.

503
      Cities Ex. 5C (Pous Depreciation Study) at 45.
504
      ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.
505   Id.
506
      Cities Ex. 5C (Pous Depreciation Study) at 47.
507
      ETIEx.13 (WatsonDirect)atExDAW-1 at50-51.
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          The arguments and evidence advanced by Cities witness Pous are persuasive to the ALl s.
Mr. Watson's contention regarding the occurrences of lightening in the ETI service area was equally
applicable at the time the existing approved rate was set, and is, therefore, of little value in this
proceeding. Further, Mr. Watson's failure to analyze the abnormal retirement ratios between years
21.5 and 22.5 also argues against his analysis. The ALls recommend that the Commission adopt
Mr. Pous' proposed life of 33 L0.5.

                  (vi) Account 369.1-0verhead Services

          The Commission previously approved anticipated service life for this account is 36 years.508
Mr. Watson's analysis of this account shows that overhead assets have retired earlier and have been
replaced more frequently than is consistent with the existing 36 S4 life. The average age of current
investment is 10.12 years. Consistent with this data and his review of various curves and placement
and experience bands, he recommended shortening the life to 26 L4. Ms. Mathis agrees with this
proposal. 509

          Mr. Pous recommended that the expected service life be shortened to 33 years based on the
lack of Company historical data and based on comparative utility experience including recent studies
by Mr. Watson, where he proposed significantly longer average service lives. Mr. Pous testified that
an evaluation of the actual data casts serious doubt about the reliability of the data for depreciation
purposes. ETI does not have any records of services in this subaccount surviving past 1978.
Mr. Pous stated that his recommended 33-year life expectancy for this sub-account is still far shorter
than industry expectations, but is consistent with the depreciation study recently conducted for EGSL
where the depreciation expert hired by EGSL recommended a 33-year life. 510

          ETI argues that Mr. Pous apparently made no attempt to perform any curve fitting regarding
this account, as none appears in his study; in the absence of performing this essential analysis, he

508
      Cities Ex. SC (Pous Depreciation Study) at 48.
509
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1at49.
510
      Cities Ex. SC (Pous Depreciation Study) at 48-49.
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settles for again casting doubt on the reliability of Company accounting data. ETI contends that, in
reality, Mr. Pous appears to present no recommendation for this account based on evaluation of any
of the accounting data that actually depicts the past and current characteristics of the assets. 511

          ETI argues that its recommended life is clearly supported by the Company-specific data,
graphically depicted in Mr. Watson's rebuttal testimony, while Mr. Pous' suggested life parameter is
not even close, and is based on unsupported speculation. 512

          Although the evidence on this issue is sparse, the ALls ultimately are persuaded that ETI's
(and Staffs) position is more reasonable. Accordingly, the AUs recommend the Commission adopt
ETI' s proposed 26 L4 life span.

                         (b) Net Salvage Value

          Staff disagrees with Mr. Watson's recommendations for five of the distribution accounts, and
Mr. Pous disagrees regarding two of the accounts. The parties' positions on distribution net salvage
values in dispute are set out immediately below:

                                    Distribution Plant Net Salva2e
       Account            Approved Rate     ETI Proposal      Staff Proposal          Cities Proposal
 361                                 -5%                -10%                  -5%                 -10%
 362                                +15%                -20%                 -10%                   0%
 365                                +10%                 -7%                  -7%                   0%
 368                                  0%                  0%                  -5%                   0%
 369.1                              -10%                 -5%                 -10%                  -5%
 369.2                              -10%                 -5%                 -10%                  -5%

                      (i) Account 361 - Structures and Improvements

          The existing net salvage value for this account is negative five percent, which is the value
proposed by Staff. Mr. Watson and Mr. Pous, on the other hand, proposed a salvage value of
negative 10 percent.

511
      Id. at 48-50.
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          Mr. Watson's recommendation is based on the most recent five-year and ten-year net salvage
ratios, which are negative 9.70 percent and negative 36.70 percent, respectively. Ms. Mathis'
recommendation is based on analysis of historical salvage data for the period of 1984 through 2010.
Specifically, the two-year moving average median for the same period produces a net salvage rate of
negative 5.87 percent, which is very close to the currently approved net salvage rate for this
account. 513 Moreover, the one-year, three-year, four-year, five-year, six-year, and seven-year moving
average      medians      of    negative 6.95 percent,   negative 5.11 percent,   negative 3.64 percent,
negative 1.90 percent, negative 4.57 percent, and negative 7.24 percent, respectively, support this
recommendation.          Additionally, this account contains a few significant outliers, such as
negative 655.91 percent in 2002 and negative 322.55 percent in 2005. 514 Ms. Mathis' use of the
median average eliminates the skewing effect of these outlying values.

          As discussed in Section VII.C.l, the use of the median is the most appropriate methodology.
For this reason, the AUs recommend the Commission approve Staffs proposed negative 5 percent
net salvage value.

                   (ii) Account 362 - Station Equipment

          The existing net salvage value of this account is positive 15 percent. Mr. Watson proposed
that it be changed to negative 20 percent, Staff proposes it be changed to negative 10 percent, and
Cities propose it be changed to zero.

          Mr. Watson's study shows that the most recent five-year and ten-year net salvage ratios are
negative 22.10 percent and negative 43.55 percent, respectively.           He recommended negative
20 percent net salvage based on the Company's experience. 515

512
      ETI Ex. 71 (Watson Rebuttal) at 46-48.
513
      Staff Ex. 2 (Mathis Direct) at 27.
514
      Id. at Appendix C at 4.
515
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1at68.
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          Ms. Mathis' recommendation is based on analysis of historical salvage data for the period of
1984 through 2010. Specifically, the recommendation is supported by the two-year moving average
median for the same period of negative 12.23 percent.516 Moreover, the one-year, three-year,
five-year, six-year, seven-year, and eight-year moving average medians of negative 11.07 percent,
negative 14.16 percent, negative 7.62 percent, negative 8.19 percent, negative 11.75 percent, and
negative 14.15 percent, respectively, support her recommendation. 517

           Mr. Pous' recommendation is based on what he characterizes as the Company's actual,
unadjusted, experience; recognition of the type of investment in the account; recognition of
significant value of scrap copper; investigation of retirement mix compared to investment mix over
the past ten years; and recognition of industry values. 518 According to Mr. Pous, given the
significant increase in the value of copper, the retirement of a transformer could be expected to
significantly influence the net salvage value for this account.

           Mr. Pous' recommendation is the outlier among the three before the ALls, and the ALls are
not convinced that the reasons put forth by Mr. Pous in support of his position are sufficient to carry
the day. The real argument here is between ETI and Staff, which centers on the use of the median
(Staff) and the mean (ETI). As discussed in Section VII.C.l, the use of the median is the most
appropriate methodology. For this reason, the ALls recommend the Commission approve Staff's
proposed negative 10 percent net salvage value.

                   (iii) Account 365 - Overhead Conductors and Devices

           The current net salvage value for this account is positive 10 percent. 519 ETI and Staff
recommend changing it to negative seven percent, and Cities recommend changing it to zero.

516
      Staff Ex. 2 (Mathis Direct) at 27.
511
      Id. at Appendix C at 4-5.
518
      Cities Ex. SC (Pous Depreciation Study) at 26.
519
      Id. at 28.
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          Mr. Pous recommended a reduction in the current net salvage values to zero based on review
of the actual historical data and the relative mix of the investment recorded in this account. Mr. Pous
noted that $40 million of investment recorded in this account is associated with clearing rights of
way, which will not likely be retired or incur cost of removal or gross salvage. Another $40 million
is associated with investment in copper conductors, which has escalated in demand in recent years
and should result in positive net salvage. 520

          Mr. Watson corrected his analysis and recognized that timing differences between the
recording of accounting adjustments related to net salvage (i.e., salvage and removal costs for a
particular transaction were not recorded at the same time) made one of the recent years less
representative of reasonably expected ongoing net salvage levels. He focused, therefore, on longer
period averages and recommends negative seven percent net salvage consistent with the most recent
ten-year ratios. 521 Mr. Watson explained that his adjustments removed relocation activity altogether
from this account because it is not characteristic of the vast majority of retirements and because, if
the adjustment is not made, it will shorten and skew the life analysis. Further, Mr. Watson stated
that Mr. Pous' claims regarding the impact of copper prices ignore those prices' future volatility and
are not supported by any analysis or quantification specific to these accounts. Mr. Watson indicated
that his recommendations are based on the most clear and reliable source - Company-specific
accounting data - not "selective comparisons of industry norms," as alleged by Mr. Pous. 522

          The AUs find Mr. Watson's explanations of the rationale behind his analysis to be both
credible and convincing. Accordingly, the AUs recommend the Commission adopt ETI's requested
negative 7 percent net salvage value.

520
      Id. at 28-29.
521
      ET1Ex.13(WatsonDirect)atEx.DAW-l at69.
522
      ETI Ex. 71 (Watson Rebuttal) at 68-69.
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                  (iv) Account 368 - Line Transformers

          The existing net salvage value for this account is zero, which both Mr. Watson and Mr. Pous
recommended be retained. Ms. Mathis, on the other hand, argued that the net salvage value should
be changed to negative five percent.

          The argument here is whether the median or the mean best represents the appropriate net
salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in
Section VIl.C.1, the use of the median is the most appropriate methodology. For this reason, the
Al.J s recommend the Commission approve Staff's proposed negative five percent net salvage value.

                  (v) Account 369.1-0verhead Services

          The existing net salvage value for this account is negative 10 percent, which Staff
recommends be retained. Mr. Watson and Mr. Pous argue in favor of a change to negative 5 percent
net salvage value.

          The argument here is whether the median or the mean best represents the appropriate net
salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in
Section VIl.C.l, the use of the median is the most appropriate methodology. For this reason, the
Al.J s recommend the Commission approve Staffs proposed negative 10 percent net salvage value.

                  (vi) Account 369.2- Underground Services

          ETI began specifically charging salvage and removal cost to this account just in the last two
years, producing a five-year net salvage ratio of negative 15. 75 percent. Mr. Watson recommended
moving from the current negative 10 percent to negative five percent net salvage. 523 Mr. Pous

523
      ETI Ex. 13 (Watson Direct) at Ex. DA W-1 at 70.
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agreed. Because of the limited available data, Ms. Mathis recommended retaining the existing
negative 10 percent net salvage. 524

          The AUs agree with Staff that because of the limited retirement activity, a reasonable net
salvage rate cannot be calculated from the historical salvage data.           Accordingly, the AUs
recommend the Commission adopt the negative 10 percent net salvage value proposed by Staff.

          S. General Plant

          General plant includes some accounts that are subject to depreciation, and some that are
subject to amortization. ETI proposes to adopt "Vintage Group Amortization," consistent with
FERC Rule AR-15 for Accounts 391-397.1 and Account 398. This approach, approved by both the
FERC and the Commission (Docket No. 38339), does not affect the annual level of expense, but
provides for timely retirement of assets and simplifies accounting for general property. 525
Ms. Mathis concurred in the Company's proposal to adopt Vintage Group Amortization and with its
recommendations for lives, amortization periods, and net salvage. 526

          The increase in expense for general plant proposed by ETI is due to the need to reduce the
deficit in the general plant reserve caused by inadequate account level rates in the past. 527 This is a
matter of debate among the parties, as discussed in more detail below.

                       (a) Account 390 - Structures and Improvements (Life Parameter)

          Based on his analysis of the data in comparison to various potential dispersion curves,
Mr. Watson recommended an increase in the life of this account to 45 R2. 528 Ms. Mathis agreed with
this life. Mr. Pous proposed a significantly longer life (54 S0.5) and claimed that Mr. Watson did

524
      Staff Ex. 2 (Mathis Direct) at 34.
525
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1at2-3.
526
      Staff Ex. 2 (Mathis Direct) at 35-37.
527
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.
528
      Id. at Ex. DAW-1 at 56.
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PUC DOCKET NO. 39896

not adequately investigate the data and investments in this account. Mr. Pous concluded that
"superstructures and roadways" are a significant element in the account which can be expected to
have a long life. 529

          ETI contends that Mr. Pous' analysis is incorrect. First, as confirmed by his workpapers,
Mr. Watson conducted an analysis of five bands, not a single band as alleged by Mr. Pous.
Furthermore, Mr. Pous' argument regarding long lives, based on the idea that the investment dates
back to 1927, is contrary to the actual data showing a minute amount of old investment (0.02 percent
of the account) dating back only to 1939. The average age of investment in the account, however, is
only 15.87 years. Mr. Watson explained that the actual data shows no investment has achieved a life
of 85 years, as alleged by Cities. 530

          The AI.Js believe that the actuarial analysis and curve fitting shown in Mr. Watson's direct
and rebuttal testimony demonstrate a more reasonable approach, as recognized by Staff witness
Mathis.      Therefore, the AI.Js recommend the Commission adopt the 45 R2 life parameter
recommended by ETI.

                        (b) Account 390-Structures and Improvements (Net Salvage Value)

          Account 390 is a depreciable account for structures and improvements. Though the current
authorized net salvage is zero, Mr. Watson recommended a negative five percent net salvage value,
and Staff agrees with this recommendation. Mr. Pous recommended a positive 15 percent net
salvage value.

          Mr. Watson based his recommendation on the most recent five-year and ten-year ratios,
which are negative 1.51 percent and negative 34.27 percent. 531 Mr. Pous disagreed, arguing that:
(1) Mr. Watson's data adjustments present an incorrect picture of the salvage history; and

529
      Cities Ex. SC (Pous Depreciation Study) at 51.
530
      ETI Ex. 71 (Watson Rebuttal) at 49.
531
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 73.
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(2) Mr. Watson failed to account for the difference in net salvage values between the retirements of
leaseholds, versus Company-owned facilities, which should not produce negative salvage. 532

          According to ETI, Mr. Po us' argument that retirement and sales of buildings will result in
positive net salvage is not backed up by the Company-specific data for this account. Such data
shows that negative net salvage has occurred in every period of the most recent ten-year moving
average.       Averages of six years or longer range from negative 4.56 percent to negative
34.27 percent. 533 ETI also argues that Mr. Pous' attempt to use sales of facilities as an element of
depreciation analysis is contrary to Commission precedent regarding building sales 'and that his
opinion is contrary to the facts that such sales are unique circumstances that do not reasonably
represent the ongoing year-to-year retirement activity that should form the basis of depreciation
analysis.

          The ALls find that Mr. Pous' arguments are not supported by the facts and that Mr. Watson's
explanations are the more credible. Accordingly, the ALls recommend the Commission adopt ETI's
proposed negative five percent net salvage value for this account.

                       (c) General Plant Reserve Deficiency

          A $21.3 million deficit has developed over time in the reserve for the accounts that ETI
proposes should be converted to General Plant Amortization. This deficit, or under-recovery, has
occurred because assets have been retired more quickly than can be addressed by the existing
amortization rate. ETI, therefore, proposes a $2.1 million annual expense level to recover the deficit
over ten years. 534 Ms. Mathis recommended that the amortization of the reserve deficiency be
rejected and that the deficit be recovered through application of the remaining life method to the
individual accounts where the deficit occurred. 535

532
      Cities Ex. 5C (Pous Depreciation Study) at 3 L
533
      ETI Ex. 71 (Watson Rebuttal) at 73-74.
534
      ETI Ex. 13 (Watson Direct) at Ex. DAW-2 at 2, App. A-2 at 1-2.
535
      Staff Ex. 2 (Mathis Direct) at 38.
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          ETI argues that although Ms. Mathis' recommendation could theoretically allow recovery,
her calculation of the amortization for the accounts that created the deficit is erroneous and
insufficient to carry out her proposed concept for recovery.                 During her cross examination,
Ms. Mathis agreed that she had intended to take the elements of the remaining life calculation
                                                                     536
method exclusively from Mr. Watson's depreciation study.                   ETI contends that she failed to pull
the correct values from Mr. Watson's study and her numbers did not match the corresponding entries
from Mr. Watson's study. 537 For example, Ms. Mathis affirmed that her remaining life calculations
were intended to allow recovery of the remaining investment in general plant account 391.2. The
                                                                                                       538
remaining investment she provided for was $10.9 million of an original cost of $21.7 million.                The
actual remaining investment in the account, however, as shown in the data she purported to rely on,
was a credit balance of negative $4.4 million, meaning that not only the original cost, but
$4.4 million additional investment remained unrecovered. 539 Ms. Mathis had no explanation for the
difference. In fact, it appears that she erroneously substituted the theoretical reserve for the account
in Mr. Watson's study ($10.789 million) as the actual book reserve, resulting in an erroneous
                                                     540
calculation of the amount yet to be recovered.             Mr. Watson's rebuttal points out the errors in the
calculation and provides an exhibit to properly reflect the remaining life approach that Ms. Mathis
intended. 541

          However, Mr. Watson's rebuttal also explained the reasons that the Company's approach is
better. By using a ten-year amortization period for the deficit, ETI lowers the annual amount of the
expense in rates to $2.1 million. Once Ms. Mathis' calculation is corrected, because the remaining
lives through which the asset value is recovered are so short, 'her remaining life approach increases
the annual expense of amortization to $5.8 million. Given the significant level of expense involved,
ETI personnel had asked Mr. Watson to moderate the remaining life approach in this instance by

536
      Tr. at 1752-1753.
537
      Tr. at 1746-1759.
538
      Tr. at 1754; Staff Ex. 2 (Mathis Direct) at Ex. JLM-2 at 4.
539
      Tr. at 1755.
540
      Tr. at 1759-1761.
541
      ETI Ex. 71 (Watson Rebuttal) at 84, Ex. DAW-R-5.
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PUC DOCKET NO. 39896

using a ten-year amortization period that was consistent with the approach used by another affiliate
within the Entergy system. Moreover, although Ms. Mathis purports to rely on the Commission's
decision in Docket No. 38339 in support of her proposal, that case includes no discussion of
rejecting the proposal on general plant that Mr. Watson makes here. 542

          The AUs have reviewed the evidence cited by both parties and the testimony offered in
support of their respective positions. It is clear to the AUs that Ms. Mathis inadvertently did exactly
what ETI alleges - she got numbers confused and, in so doing, confused her analysis. The AUs find
that ETI' s proposed $2.1 million annual expense level to recover the deficit over ten years be
approved by the Commission.

                       (d) Amortization Period for Account 391.2-Computer Equipment

          Mr. Pons challenged the amortization period for this account, contending, contrary to Staff
and Mr. Watson, that the Company's proposal to amortize general plant using ..Vintage Group
Amortization" is not consistent with FERC pronouncement AR-15. ETI argues that Mr. Pous'
critique is wrong because the five-year life of which Mr. Pons complains is based on standard life
analysis.      The life has nothing to do with AR-15, which does not determine such matters.
Mr. Watson's study clearly explains that he based the life parameter on standard actuarial analysis. 543

          According to ETI, Mr. Pons' own recommendation points out the fallacy of his arguments
about AR-15. He recommended a one-year increase in the amortization, which does not match the
previous period of depreciation for this account, or the previous depreciation rate, despite that being
the supposed flaw in Mr. Watson's approach. 544 Mr. Watson explained that the use of AR-15 does
not involve any independent tinkering with the life of the asset account because the AR-15 process

542
      Id. at 80-81.
543
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1at58.
544
      Cities Ex. 5 (Pous Direct) at 36.
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PUC DOCKET NO. 39896

"provides for the amortization of general plant over the same life as recommended," based on
                                                                  545
standard life analysis, which Mr. Watson's study recognized.

          The ALls are persuaded by ETI's arguments on this point. FERC pronouncement AR-15
requires amortization over the same life as recommended based on standard life analysis.
Mr. Watson's study employed standard life analysis to ascertain the recommended five-year life.
The ALls therefore recommend the Commission adopt the five-year life proposed by ETI.

           6. Fully Accrued Depreciation

           Mr. Pous claimed that the Company has failed to conform its Commission-authorized
depreciation rates when it stops accruing depreciation on accounts and sub-accounts that are fully
accrued. He testified that the Company must continue to depreciate such accounts, despite the fact
that this policy would mandate that the Company intentionally create negative depreciation amounts
that do not relate to the existence of any depreciable asset still in existence. Mr. Pous testified that
neither standard depreciation definitions nor GAAP or National Association of Regulatory Utility
Commissioners (NARUC) depreciation guidance support the Company's action. 546 The impact of
Mr. Pous' recommendation is to impute an additional $6,447,731 depreciation amount to reduce rate
base and amortize that credit over four years, with an associated revenue requirement reduction of
                   547
$1,611,933.

           ETI argues that Mr. Pous pointed to no instance in which his theory has been adopted by the
Commission, or any other regulatory body. Other regulators within the Entergy system have rejected
his position. 548 The RRC, which sets gas utility rates under essentially the same regulatory
framework as PURA, has rejected Mr. Pous' position on three separate occasions. 549 ETI contends
that Mr. Pous' suggestion violates GAAP, which requires that once an asset's service value (original

545
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2.
546
      Cities Ex. 5 (Pous Direct) at 39-45.
547
      Id. at 45.
548
      ETI Ex. 46 (Considine Rebuttal) at 45-46.
549
      ETI Ex. 71 (Watson Rebuttal) at 81, n. 61; ETI Ex. 46 (Considine Rebuttal) at Ex. MPC-R-11.
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PUC DOCKET NO. 39896

cost less net salvage) has been fully amortized through the application of the most recently approved
depreciation rates, there is no further service value to be recognized. This has been ETI' s practice as
long as ETI regulatory accounting witness Considine has been aware. Furthermore, ETI suspends
depreciation only so long as the account is fully amortized. Once additional activity hits the account,
depreciation will begin again under the Company's automated systems. 550

          ETI also argues that Mr. Pous' retroactive approach is unreasonably selective. He would
reach back into recoveries under existing rates to reclaim revenues associated with the depreciation
expense that relates to the fully accrued accounts. According to ETI, Mr. Pous takes no notice of the
depreciation taken on new assets that are not included in rate base or recovered through depreciation
expense under existing rates. ETI witness Considine notes that Mr. Pous has essentially formulated a
one-sided exact recovery mechanism for depreciation expense that is completely unique in the annals
of base rates. 551

          According to ETI, Mr. Pous also ignores that the remaining life depreciation method already
addresses any over- or under-accrual of depreciation expense. As depreciation rates and the
remaining life are adjusted over time, any over (under) recovery will be carried forward and the net
(if any) of the original investment less any accumulated reserve will begin to be recovered under the

new and future rate structures. This is the basic concept of remaining life depreciation rates. Thus,
                                                                        552
ETI contends that no further actions or adjustments are appropriate.

          The AUs find that Mr. Pous' recommendation has previously been rejected, by other
regulatory bodies. There is nothing in the arguments advanced by Cities that changes that fact.
Accordingly, the AUs recommend the Commission reject Cities' proposal.

550
      ETI Ex. 46 (Considine Rebuttal) at 44-45, 47.
551
      Id. at 43, 45.
552
      ETI Ex. 71 (Watson Rebuttal) at 78.
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           7. Other Depreciation Issues - Accumulated Provision for Depreciation

           ETI proposes to amortize the $21 million general plant deficiency over ten years. Both the
Cities and Staff agree with and use the accumulated depreciation reserve amounts per account from
Mr. Watson's study. 553 TIEC witness Pollock, in arguing against amortization of the amortized
general plant reserve deficiency, testified that this reserve deficiency should instead be simply
reallocated to other depreciable general plant accounts that have depreciation surplus. 554

           Mr. Pollock discussed transferring the depreciation reserve between the amortizable and
depreciable general plant accounts. He failed to show, however, how the reserve reallocation would
be computed and provided no workpapers to substantiate his analysis. ETI argues that without a
verifiable basis for the computations, his recommendations to recompute general plant depreciation
accruals should be rejected.

           ETI also argues that Mr. Pollock's testimony shows that he has reallocated the amortizable
general plant deficiency from the amortized general plant accounts to the depreciable general plant
accounts. The depreciable plant accounts have shorter remaining lives than the ten-year amortization
of the deficiency proposed by ETI. 555 ETI contends that common sense dictates that transferring
dollars from an account with a relatively longer remaining life to one with a shorter life will yield a
higher annual depreciation or amortization expense, yet Mr. Pollock somehow takes this step and
still arrives at a lower level of expense.

           According to ETI, Mr. Pollock's methodology has the effect of "amortizing the difference
between the book and theoretical reserve over a time period that is significantly shorter than the
average remaining life of the assets within this function." 556 ETI asserts that such an adjustment to

553
      Id. at 77.
554
      TIEC Ex. 1 (Pollock Direct) at 38-39.
555
      ETI Ex. 13 (Watson Rebuttal) at Ex. DAW-l, App. A-1at4.
556
      ETI Ex. 71 (Watson Rebuttal) at 75.
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PUC DOCKET NO. 39896

depreciation and amortization expense was rejected by the Commission in the CenterPoint rate case,
and it should be rejected here. 557

          TIEC argues that it does not propose any amortization of any accounts. Rather, TIEC states
that it is proposing a more efficient method for ETI to cure its deficits. Because ETI retired
equipment prior to the end of the assumed life of those assets, there is approximately a $21,300,000
deficiency in general plant accounts. ETI seeks to amortize the deficiency over ten years so that the
book reserve will "catch-up" with the theoretical depreciation reserve for the deficient reserve. TIEC
contends that its position is that the catch-up adjustment is not necessary. 558

          The ALJs have reviewed the evidence and arguments advanced by the parties and find that
those of ETI are more persuasive. Accordingly, the ALJs recommend the Commission reject TIEC' s
recommendation.

D.        Labor Costs

          1. Payroll and Related Adjustments

          A number of parties suggest various adjustments to ETI' s proposed payroll and related costs.
In the application, ETI' s Test Year payroll costs were adjusted downward by $957 ,695 to reflect a
decrease in the employee headcount levels at ETI during the Test Year. At the same time, payroll
costs were increased in the amount of $1, 105,871 to account for employee pay raises. The net result
was that ETI's Test Year payroll expense was adjusted upward by $148,176. Similar calculations
were made for ESI employees, resulting in a net upward adjustment for ESI payroll expenses of
$852,493. Thus, ETI requested an upward adjustment of $1,000,669 ($148,176 plus $852,493) for
ETI and ESI payroll expenses. 559

557
      Id. at 75-76.
558
      TIEC Ex. 1 (Pollock Direct) at 37.
559
      ETI Ex. 8 (Considine Direct) at 24-25; 3 at Sched. A-3 and WP/P AJ22.
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PUC DOCKET NO. 39896

           Cities oppose one part of these proposed adjustments. As noted above, ETI is proposing an
upward adjustment to account for pay raises given to ETI and ESI employees. One set of those raises
was given to employees in early August 2011, one month after the end of the Test Year. Another set
of raises was given to employees in April 2012, roughly nine months after the end of the Test Year.
Cities witness Garrett testified that it is acceptable to make an adjustment for the raises made in
August 2011 because they occurred shortly after the end of the Test Year. However, he stated that it
is unreasonable to include an adjustment for the raises given in April 2012. He believes that any
increase in costs due to the April 2012 pay raises might be offset by changes in productivity and the
overall workforce that may occur during the same time period, such as the replacement of higher-
paid workers who retire with new, lower paid employees. 560 Thus, Cities propose an adjustment that
would reverse ETI's proposed increase for the April 2012 pay raises thereby reducing payroll
expense by $1,185,811. 561 No other party makes a similar challenge to the April 2012 pay raise.

           With regard to the adjustments proposed by ETI, Staff witness Givens accepted the
adjustments for headcount changes and the pay raises, but recommended a further downward
adjustment of $778,034 to account for a further decrease in ETI employee headcount levels from 678
at Test Year-end to 660 as of February 2012. She also recommended an upward adjustment of
$158,589 to account for an increase in ESI employee headcount levels from 3,055 to 3,089 as of
December 2011. 562 Ms. Givens also recommended that, in addition to adjusting payroll expense
levels, the more recent headcount numbers should be used to adjust the level of payroll tax expenses,
benefits expenses, and savings plan expenses. 563 As an alternative to its primary line of attack
(discussed above), Cities agree with the adjustments recommended by Staff.

           ETI also agrees, in concept, with the adjustments recommended by Staff, but contends that
Ms. Givens made some errors in her calculations. First, according to ETI, Ms. Givens used
erroneous headcounts for the end of the Test Year for ETI and ESL According to the Company,

56
  ° Cities Ex. 2 (Garrett Direct) at 13-15.
561
      Id. at 19.
562
      Staff Ex. I (Givens Direct) at 10-12.
563
      Id. at 13-15.
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ETI's headcount at Test Year-end was 675 and ESI's was 3,054. Ms. Givens wrongly used
headcounts of 678 and 3,055, respectively, which caused a double counting of three ETI employees
and one ESI employee. 564 Second, Ms. Givens made an error in the calculation of benefits costs
associated with the updated ESI headcount. Ms. Givens inadvertently used the ETI percentage in the
calculation rather than the ESI percentage shown on her exhibit. 565 Third, Ms. Givens' adjustment
for savings plan expense was not necessary and is thus inappropriate. According to ETI witness
Considine, savings plan expense is already included in benefits expense levels so it would be double
counting to adjust for both benefits expense and savings plan expense. 566 Fourth, Ms. Givens'
full-time equivalent calculations need to be corrected. She included an incorrect assumption
regarding part time employee salaries. Ms. Givens assumed that a part time employee's average
salary is 50 percent of the full time average salary. In his rebuttal testimony, Mr. Considine provided
the correct calculation of full time equivalents, thereby making it unnecessary to rely upon an
assumed average. 567 According to Mr. Considine, the combined impacts of these errors is that
Ms. Givens' ETI headcount adjustment overstated her O&M payroll reduction by $224,217, and her
                                                                                          568
ESI headcount adjustment understated her O&M payroll increase by $37,531.                       No party
challenged these corrected numbers.

            The Al.J s are unpersuaded by Cities' attempt to exclude the April 2012 pay raises. There can
be no real dispute about the fact that the pay raises are known and measurable. Moreover, there is an
obvious logical inconsistency in the Cities' position - on the one hand they oppose consideration of
certain pay raises because they fall outside the Test Year, and on the other hand they support
consideration of headcount reductions even though they also fall well outside the Test Year.

            The ALls are also persuaded that, conceptually, the adjustments suggested by Staff are
reasonable and appropriate. Indeed, all parties agree on this point. Moreover, no party challenged

564
      ETI Ex. 46 (Considine Rebuttal) at 32-33.
565
      Id. at 33.
566   Id.
567
      Id. at 34.
568
      Id. at MPC-R-5, and MPC-R-6.
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the corrections to Staff's adjustments that were suggested by ETI, and the AU s can find no basis for
challenging those corrections. Thus, the AU s recommend that the Commission: ( 1) accept the
payroll adjustments proposed in the ETI application~ and (2) accept the further payroll adjustments
proposed by Staff, corrected by ETI.

          2. Incentive Compensation

          One of the hotly contested issues concerns the extent to which ETI should be allowed to
recover, through its rates, the incentive compensation it pays to its employees. All parties agree that
Commission precedent generally identifies two types of incentive compensation, only one of which
is recoverable. Specifically, pursuant to Commission precedent, incentive compensation that is tied
to operational goals is recoverable, while incentive compensation that is tied to financial goals is
not. 569 In its application, however, ETI requests that it be allowed to recover its Test Year costs of
all of its incentive compensation costs, regardless of whether those costs are tied to operational goals
or to financial goals.

                       (a) Financially Based Incentive Compensation Should Not Be Recoverable

          ETI acknowledges that costs of incentive compensation tied to financial goals have typically
been disallowed by the Commission. However, ETI asks for the Commission to reconsider its
precedents on this issue. 570 ETI argues that the Commission precedent is not, and should not be, a
hard and fast rule. ETI contends that the reason why cost recovery has been denied for incentive
compensation in prior rates cases is that, in those prior cases, there was "a lack of evidence showing
sufficient customer benefits."571 ETI asserts that, in this case, it has assembled evidence not
previously considered by the Commission that shows the benefits to customers of using financial

569
    See, e.g.,TIBC Initial Brief at 51-52; see also AEP Application of AEP Texas Central Company for
Authority to Change Rates, See Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application
of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170
(Aug. 15, 2005).
570
      Tr. at 1726.
571
      ETI Initial Brief at 129.
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measures in incentive compensation programs.               For example, ETI argues that incentive
compensation that encourages the financial health of a company also benefits customers because:

           (1)     if a company maintains a financially healthy position, it will tend to have a
                   lower cost of capital that will in tum benefit customers through lower rates;
           (2)     a financially healthy company will be more prepared for emergency events
                   such as storms (which is particularly important in the Gulf Coast areas served
                   by ETI, which are subject to experiencing hurricanes); and
           (3)     with financial health, the costs of doing business with suppliers (of both
                   goods and services, including labor) will remain lower because, for example,
                   if a company was not in a financially stable condition, suppliers would tend
                   to demand higher prices or more onerous credit terms, resulting in higher
                   costs that would lead to higher rates than would otherwise occur.

           ETI witness Kevin Gardner, Vice President of Human Resources for ESI, testified that
customers receive benefits from those portions of the incentive compensation plans that are tied to
financial goals and measures. He explained that incentive compensation based on financial metrics
is a reasonable, necessary, and common component of compensation for companies like ETI. He
also opined that such incentives are a market necessity that ETI must include in its compensation
package so that it can hire and retain talented employees. He contended that customers benefit from
the incentives because they attract and keep qualified people. 572 Mr. Gardner further testified that
disallowing financially-based incentives would only encourage utilities to eliminate them, thus
weakening the alignment of employees' financial interests with the interest of the ratepayers in
having an efficiently run and financially healthy utility. He opined that having only operational
incentives could encourage utilities to overspend in some areas resulting in an incomplete,
unbalanced incentive program that would be atypical when compared with American industry in
general. 573

           A second ETI witness, Dr. Jay Hartzell, also testified in favor of the concept of allowing ETI
to recover its costs associated with its financially-based incentive compensation. He is a professor of

572
      ETI Ex. 36 (Gardner Direct) at 31.
573
      Id. at 32.
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finance in the business school at the University of Texas at Austin. Dr. Hartzell acknowledged the
historical distinction that has been made by the Commission between compensation tied to financial
measures and compensation tied to operational measures. However, he argues that this distinction is
based upon a "false dichotomy" and that the more appropriate focus should be on whether customers
benefit from the incentive in question, regardless of whether it is a financial or operational
incentive. 574 Dr. Hartzell summarized his key opinion as follows:

           In my opm1on, a well-designed compensation plan that includes incentive
           compensation tied to cost controls, profitability, and stock prices would tend to
           provide greater benefits to customers than an otherwise similar compensation plan
           that did not include any such incentive compensation. 575

           Dr. Hartzell argues that compensation linked to stock prices (provided it is part of a
reasonable, well-designed compensation plan) has four advantages for customers, :

•     helps ensure that managers will consider the financial health of the company when they make
      decisions, and it is in customers' interests for the company be fmancially healthy;
•     provides an incentive for managers and employees to ensure that the company operates
      efficiently, resulting in lower rates than would otherwise occur;
•     provides a monitoring mechanism for managerial decision-making and the overall quality of
      management; and
•     results in lower customer costs because capital markets will tend to reward efficient long-term
      investments or capital expenditures. 576

Dr. Hartzell cited a number of studies which support the theory that the benefits of incentive
compensation linked to stock price and profitability measures extend to customers of the company,
such as by lowering the company's cost of capital, increasing the company's ability to respond to

574
      ETI Ex. 15 (Hartzell Direct) at 3-4, 6, and 9-10.
575
      Id. at 7.
576
      Id. at 13-14.
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external shocks, improving customer satisfaction, and increasing oversight on managerial
decisions. 577

          Conversely, Dr. Hartzell opined that if the use of incentive compensation linked to
profitability and stock prices is discouraged, via Commission policy disallowing recovery of the
costs of such compensation, then utility customers would be adversely affected. For example, if
employees did not receive any incentive compensation, salaries would have to be higher to attract
and retain the same quality of talent. Dr. Hartzell also testified that a compensation plan solely
consisting of salary and incentives based on operational performance could likely lead to "horizon
problems," meaning that, absent incentives to focus on the long run health of the company, managers
might maximize their immediate compensation at the expense of longer-run benefits that the
customer could have enjoyed. 578

          All of the other parties oppose ETI' s efforts to recover the costs of its incentive compensation
tied to financial goals. The parties uniformly agree that the Commission has a well-established and
straightforward policy regarding the recoverability of incentive compensation through rates:
incentive compensation that is tied to operational goals is recoverable; incentive compensation tied
to financial goals is not. 579 They contend that ETI' s position in this case flies directly in the face of
that policy. TIEC points out that ETI has offered no legal authority, such as a statute or rule, which
would justify its desire to have the Commission reverse its policy and allow the recovery of incentive
compensation tied to financial goals. State Agencies similarly argue that ETI failed to establish a
reason why the Commission should deviate from its long-standing policy. The parties also support
the reasoning behind the Commission's policy: that financially-based incentives are of more
immediate benefit to shareholders, not ratepayers, and therefore are not necessary and reasonable for
the provision of service.

577
      ETI Ex. 15 (Hartzell Direct) at 15-21.
578
      Id. at 22-25.
579
    TIEC Reply Brief at 35; State Agencies Initial Brief at 14; OPC Reply Brief at 12; Staff Initial Brief at 56;
Cities Initial Brief at 67; see also, Application ofAEP Texas Central Company for Authority to Change Rates,
Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application ofAEP Texas Central Company
for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005).
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PUC DOCKET NO. 39896

          State Agencies point out that, in support of his theory that financially-based incentives
provide benefits to ratepayers, Dr. Hartzell relied upon studies of utilities in competitive markets.
Thus, State Agencies contend, the studies are of little to no benefit in evaluating the effects of
financially-based incentives upon ETI customers because ETI is a monopoly that is not subject to
competitive pressures. Moreover, State Agencies examine at length the underlying studies relied
upon by Dr. Hartzell and assert, essentially, that the studies do not fully support the findings that
Dr. Hartzell ascribes to them.

          Staff refutes ETI's contention that the only reason why cost recovery has historically been
denied for financially-based incentive compensation is that there has been a lack of evidence
showing customer benefits. For example, Staff points out that, in one of the prior dockets cited by
ETI, the Commission disallowed recovery for financially-based incentive costs after stating,
"Incentive compensation based on financial measures or goals is of more immediate benefit to
shareholders." 580 This suggests that the question is not, as ETI contends, whether the incentives
provide any benefit to ratepayers. Rather, the question is whether the incentives are primarily
intended to provide benefits to shareholders.

          Mark Garrett, an attorney and certified public accountant who works as a consultant in the
area of public utility regulation, testified on behalf of the Cities in opposition to cost recovery for
financially-based incentive compensation. He stated there are a number of reasons why it makes
sense to exclude financially based incentive costs from rates: (1) there is no certainty from year to
year what the level of incentive payments will be (because incentive payments are conditioned upon
future events and triggers that might not occur), thereby making it difficult to set rates and recover a
level of expense; (2) many of the types of factors that increase earnings per share-such as an
unusually hot summer or customer growth-are outside the control of employees and have no value
to customers; and (3) earnings-based incentives can discourage energy conservation. 581 Mr. Garrett

580
   Staff Reply Brief at 44, quoting Application of Oncor Electric Delivery Company for Authority to Change
Rates, Docket No. 35717, Order on Rehearing at FoF 92 (Nov. 30, 2009).
581
      Cities Ex. 2 (Garrett Direct) at 29-30
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PUC DOCKET NO. 39896

also discussed the results of a survey of 24 other states, which revealed that 17 states closely follow
Texas' approach, and none allow full recovery of incentive compensation. 582

          Mr. Garrett testified that ETI will not be placed at a competitive disadvantage in its ability to
obtain and retain qualified employees if its financially-based incentives are disallowed. He stated
that the Company's total payroll costs for 2011 were 10 percent above the market price, and that
most of the above-market payroll costs derived from the incentive program. 583

          The AI.Js conclude that ETI should not be entitled to recover its financially based incentive
compensation costs. Based upon prior Commission precedents, the AI.Js conclude that the issue is
not, as ETI contends, whether such incentives might provide any benefits to customers. The proper
question to be asked is whether they provide benefits most immediately or predominantly to
shareholders. Without a doubt, the primary purpose of financially based incentives, such as
incentives tied to earnings per share or stock price, is to benefit shareholders, not ratepayers. Even
construing Dr. Harzell's testimony in the most generous light, any benefits that might accrue to
ratepayers would be merely tangential to that primary purpose.

          Moreover, even if the AI.Js were to completely accept as true the opinions offered by
Dr. Hartzell, it would be of limited benefit to ETI because his opinions were almost completely
theoretical. The premise of his testimony was that "a well-designed compensation plan" that
includes incentive compensation tied to financial goals would "tend to provide greater benefits to
customers" than a plan that did not include such compensation. 584 He stressed that the customer
benefits of incentive compensation tied to financial goals can only exist if such compensation is part
of a larger, reasonable, and well-designed overall compensation plan. 585 However, he did not
meaningfully apply this abstract theory to ETI's compensation plan. For example, Dr. Harzell did
not offer an evaluation of ETI' s compensation plan and conclude that it is "well designed," nor did

582
      Id. at 32-38.
583
      Id. at 45-46.
584
      ETI Ex. 15 (Hartzell Direct) at 7 (emphasis added).
585
      See, e.g., ETI Ex. 15 (Hartzell Direct) at 13.
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PUC DOCKET NO. 39896

he testify that ETI' s incentives tied to financial goals actually provide benefits to its customers. He
admitted that he did not study the details of ETI' s incentive plans, nor did he do any type of analysis
to see if the costs of ETI's incentive programs outweighed their benefits. 586 He did not know the
amounts of incentive compensation that was paid by ETI. 587 One of his major premises was that
financially-based incentives can benefit customers by lowering their costs, but he did not know how
ETI customer's costs compared with customer costs in the other Entergy operating companies. 588
Another of his major premises was that financially-based incentives can benefit customers by
ensuring the financial health of the Company, but he made no attempt to determine whether ETI was,
in fact, a financially healthy company. 589 By confining his testimony to the abstract, it is impossible
to know whether Dr. Hartzell believes that ETI's incentive compensation tied to financial goals
achieves the customer benefits that he believes such compensation can theoretically achieve. It is
true that Mr. Gardner described some of the specifics of ETI' s incentive plans. However, because
Dr. Hartzell did not explain the metrics of what he would consider "a well-designed compensation
plan," it is impossible to know if ETI's plan meets those metrics.

          Simply put, the ALls conclude that ETI has failed to establish a sufficient justification for
overturning the well-established Commission policy that financially based incentive compensation is
not recoverable.

                      (b) The Adjustment for Financially-Based Incentive Compensation Costs

          Having concluded that ETI is not entitled to recover the costs of its financially based
incentive programs, it is necessary to determine the amount of those costs so that they may be
removed from consideration in this rate case. The parties disagree on the correct amount. Staff

586
      Tr. at 484.
587
      Tr. at 478.
588
      Tr. at 480.
589
      Tr. at481-82.
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PUC DOCKET NO. 39896

                                                                                      590
argues that $5 .3 million of ETI' s incentive compensation is financially based.            TIEC contends the
                                     591                                        592
correct number is $6.2 million.            Cities contend it is $8.4 million.

          Broadly speaking, ETI has two categories of incentive compensation programs - annual
programs and long-term programs. ETI witness Gardner testified that 100 percent of ETI' s
long-term programs are financially based, whereas an average, representing a far lower percentage,
of the Company's annual programs are financially based. 593 Staff witness Givens applied those
percentages to determine her estimate of the amount spent by ETI in the Test Year on financially
based incentives. As to the Company's long-term programs, she recommended removing the entire
costs of those programs (i.e. 100 percent) from the cost of service. As to the Company's annual
programs, she recommended removing average percentage of the costs of those programs.
Ms. Givens then applied the FICA tax rate to the total amount she identified as financially based
costs to account for direct taxes that ETI would have paid as a result of those costs. By her estimate,
the FICA taxes associated with ETI's financially based incentives paid in the Test Year totaled
$429,096. In total, Ms. Givens recommended removing $5,609,093 (representing ETI' s financially
based incen,tives paid in the Test Year, plus FICA taxes associated with those payments) fromETI's
requested O&M expenses. However, based upon subsequent additional information supplied by
ETI594 relative to the actual payroll taxes paid by the Company for its financially based incentive
compensation, Staff has agreed to lower its estimate of FICA taxes from $429,096 to $143,801.
Thus, Staff now recommends removing $5,323,798 (representing ETI's financially based incentives
paid in the Test Year, plus FICA taxes associated with those payments) from ETI' s requested O&M
expenses. 595

590
    Staff Initial Briefat 56. (As discussed more below, Staff's original estimate was roughly $5.6 million. The
estimate was reduced, however, in response to supplemental payroll tax information supplied to Staff by ETI.)
591
      TIEC Initial Brief at 53-54.
592
      Cities Initial Brief at 70.
593
      ETI Ex. 36 (Gardner Direct) at 30.
594
      ETI Ex. 46 (Considine Rebuttal).
595
      Staff Ex. I (Givens Direct) at 15-22; Staff Initial Brief at 56-63.
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          Like Ms. Givens for Staff, TIEC witness Pollock relied on the numbers and percentages
concerning ETI's incentive programs that were provided by Mr. Gardner. However, Mr. Pollock
calculated those numbers and percentages in a slightly different manner, leading to a different
recommended reduction amount. Just as Ms. Givens did, as to the Company's long-term programs,
he recommended removing the entire costs of those programs from the cost of service. ETI witness
Gardner testified that actual percentages of each annual program were quite different than the
average percentages for all programs used by Ms. Givens. 596 Thus, as to the Company's annual
programs, while Ms. Givens applied the average percentage reduction to all of the annual programs,
Mr. Pollock applied the actual percentage reductions applicable to each of the annual programs.
Based on Mr. Pollock's calculations, TIEC recommends removing $6,196,037 (representing ETI's
financially based incentives paid in the Test Year) fromETI's requested O&M expenses. 597 TIEC
appears not to have taken into account any payroll taxes associated with ETI' s financially based
incentives.

          Cities witness Garrett took a substantially different approach when he calculated his estimate
of ETI's financially based incentive costs. He agreed with Ms. Givens and Mr. Pollock that
100 percent of the Company's long-term program costs should be removed from the cost of service.
As to the annual programs, however, Mr. Garrett defined what qualifies as "financially based" much
more broadly than ETI, Staff, and TIEC. ETI witness Gardner testified that, when the Company's
five annual programs were averaged together, specific percentages of those programs were
financially based, aimed at "cost control," and aimed at "cost control, operational, safety."598
Mr. Garrett added together the percentages representing the financially-based costs, the cost-control
costs, and roughly one-third of the cost-control, operational safety costs to arrive at the figure he
identified as the amount of ETI' s costs for its annual programs that is "related to financial
performance measures." 599 Cities contend this approach is supported by the decision in a prior

596
      ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
597
      TIEC Ex. l (Pollock Direct) at 41-45 and JP-7; TIEC Initial Brief at 51-54.
598
      ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
599
      Cities Ex. 2 (Garrett Direct) at 39-40, 46-50, MG2.10.
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PUC DOCKET NO. 39896

docket. 600      Based on Mr. Garrett's calculations, Cities recommend removing $8,397,232
(representing ETI's incentives "related to financial performance measures" paid in the Test Year)
from ETI' s requested O&M expenses.601 Mr. Garrett also agreed with Ms. Givens that an additional
reduction should be made to account for the FICA taxes that ETI would have paid as a result of those
costs. 602

          The Al.Js reject Cities' attempt to broadly expand the definition of what qualifies as a
financially based incentive to include items such as cost control measures.                 Cities' primary
justification for doing so is that the Commission has done so previously in the AEP Texas case. As
pointed out by ETI, however, the Commission did so in that case merely because AEP Texas lumped
its cost control measures in with its financially based incentive costs. The evidence in this case
demonstrates that ratepayers benefit when a utility incentivizes its employee to control costs. Even
TIEC witness Pollock testified that "incentives that encourage employees to minimize costs are
probably more or less in the best interest of ratepayers."603                 ETI further provided evidence
establishing that cost control incentives that result in lower costs for the Company likewise result in
lower rates for customers. 604

          As to the approaches advocated by TIEC and Staff, the AU s conclude that TIEC' s approach
more accurately captures the true cost of ETI' s financially based incentive programs. Rather than
averaging across all of ETI's annual programs (as was done by Staff), TIEC used the percentage
applicable to the single annual program that included a component of financially based costs. Thus,
theALls recommend removing $6,196,037 (representing ETI's financially based incentives paid in
the Test Year) from ETI's requested O&M expenses. Additionally, the Al.Js agree with Staff and

600
   Cities Initial Brief at 68, Application of AEP Texas Central Company for Authority to Change Rages,
Docket No. 28840, Final Order (August 15, 2005).
601
      Cities Ex. 1 (Garrett Direct) at 51-52 and MG2. l O; Cities Initial Brief at 70.
602
      Cities Ex. 1 (Garrett Direct) at 53.
603
      Tr. at 1528.
604
      ETI Ex. 50 (Gardner Rebuttal) at 6-7, ETI Initial Brief at 137-38.
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PUC DOCKET NO. 39896

Cities that an additional reduction should be made to account for the FICA taxes that ETI would
have paid as a result of those costs. That amount is not specifically known at this time.

            3. Compensation and Benefits Levels

            In the application, ETI included, as part of its labor costs, $54,965,005 in base payroll paid by
ETI and ESI in the Test Year. It also included $20,428,817 in costs associated with various benefits
(such as medical/dental, and life insurance) that ETI and ESI provided to their employees. 605 Cities
contend that the amounts for base pay and the benefits package should be reduced by $989,370 and
$2,860,034, respectively, because the amounts paid were above the market price.606 No other party
challenges the reasonableness of the base payroll and benefits package.

            As to base payroll, Cities contends that the amount paid by ETI and ESI was 1.8 percent
above the prevailing market price (above market). 607 Cities witness Garrett acknowledges that ETI
and ESI are free to pay their employees at above market wages, but he contends that ratepayers
should only be asked to pay the market rate for wages, which he contends constitute the only
"necessary'' costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 1.8 percent
downward adjustment to base payroll expense (or $989,370) "to bring the company's base payroll
down to a market-based level."608

            As to the Company's benefits package, Cities points out that the amount paid by ETI and ESI
was 14 percent above market when compared to a peer group of Fortune 500 companies. 609 Cities
witness Garrett again contends that ratepayers should only be asked to pay the market rate for
benefits, which he contends constitute the only "necessary" costs of providing utility service. Thus,

605
      Cities Ex. 2 (Garrett Direct) at 25, MG2.8, and MG2.9.
606   Id.
607
      Id. at 25 and MG2.8.
608
      Id. at 26-27 and MG2.8.
609
      Id. at 58 and MG2.9; ETI Ex. 36 (Gardner Direct) at 41-42.
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PUC DOCKET NO. 39896

Mr. Garrett and Cities recommend a 14 percent downward adjustment to benefits expenses (or
$2,860,034).610

           ETI concedes that its Test Year base pay was 1.8 percent "above the market median," but
argues that this is not the same thing as being "above market." As ETI witness Gardner explained,
"being 'at market' means being within a reasonable range, such as +/-10 percent, of the market
median; therefore, the Company's base pay levels are at market."611 According to Mr. Gardner,
some compensation consultants use an even broader range, such as a+/- 15 percent range, for
determining whether compensation levels are at market. 612 Mr. Gardner testified that, because no
two jobs are likely to be identical, attempting to benchmark jobs to a "market price" is an inexact
science, involving inherent imprecision. Thus, Mr. Gardner testified that, when using a benchmark
analysis to compare companies' levels of compensation, it is advisable to view the market level of
compensation as a range (e.g.,+/- 10 percent of a mid-point) rather than a precise, single point. 613

           ETI also disputes Cities' contention that the Test Year costs of the Company's benefits
package were 14 percent "above market." Mr. Gardner acknowledged that the costs were 14 percent
higher than those of Fortune 500 companies, but he pointed out the costs were only 1 percent above
the market median of a peer group of utility companies. 614 ETI contends that the comparison against
the peer group of utility companies provides a more appropriate comparison for ETI than Fortune
500 companies. ETI also points out that, even if equal weight were given to the comparisons against
the Fortune 500 companies and the peer utilities group, the value of the Company's benefit plans
would average within a +/- 10 percent range and, therefore, be at market. Thus, ETI argues that its
benefit plan levels are within a reasonable range, and no disallowance should be required. 615

610
      Cities Ex. 2 (Garrett Direct) at 58-59 and MG2.9.
611
      ETI Ex. 50 (Gardner Rebuttal) at 11.
612
      ETI Ex. 36 (Gardner Direct) at 23, and ETI Ex. 50 (Gardner Rebuttal) at 11 n. l.
613
      ETI Ex. 50 (Gardner Rebuttal) at 11-12.
614
      ETI Ex. 36 (Gardner Direct) at 42.
615
      ETI Ex. 50 (Gardner Rebuttal) at 13-14; ETI Initial Brief at 139-142.
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PUC DOCKET NO. 39896

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

          4. Non-Qualified Executive Retirement Benefits

          ETI provides three types of supplemental executive retirement plans: the Pension
Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan. 616
In the application, ETI included, as part of its labor costs, $2, 114,931 in costs associated with its
executive retirement plans.          The expenses represent non-qualifying retirement plan expenses
designed to provide retirement benefits to key managerial employees and executives who are invited
to participate in the plans. They are generally available only to employees and executives earning
more than $245,000 per year. 617

          On behalf of the Staff, Ms. Givens recommended a complete disallowance of the costs for
these programs, on the grounds that they are offered to only select, highly compensated employees
and are excessive. Ms. Givens offered the opinion that the expenses were not reasonable and
necessary forthe provision of electric utility service and were not in the public interest.618 On behalf
of Cities, Mr. Garrett agreed with Ms. Givens' recommendation, arguing that it is fair to have
ratepayers pay for benefits included in regular pension plans, but that shareholders ought to pay for
any additional benefits included in supplemental plans, "since these costs are not necessary for the
provision of utility service, but are instead discretionary costs of the shareholders."619 Mr. Garrett
also testified that costs associated with supplemental executive retirement plans are typically

616
      ETI Ex. 50 (Gardner Rebuttal) at 14.
617
      Staff Ex. l (Givens Direct) at 22-23; Cities Ex. 2 (Garrett Direct) at 54.
618
      Staff Ex. l (Givens Direct) at 23; Staff Initial Brief at 64.
619
      Cities Ex. 2 (Garrett Direct) at 55; Cities Initial Brief at 71-72.
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PUC DOCKET NO. 39896

excluded by utility commissions in Oklahoma, Oregon, Idaho, Arizona, and Nevada.620 On behalf of
OPC, Dr. Szerszen also recommended a complete disallowance of the portion of these costs
allocated from ESI to ETI.621 She stated that ETI has not shown that ratepayers benefit from the
expenses, the costs are not necessary to provide utility service, and that the ESI allocation method is
               622
unjustified.

           ETI disagrees with all of these criticisms and maintains that the costs of the plans should be
recoverable. ETI witness Gardner testified that the supplemental executive retirement plans are
needed for attracting, retaining, and motivating highly competent and qualified leaders.              He
explained that the Pension Equalization Plan provides supplemental retirement benefits to account
for the fact that Internal Revenue Code regulations limit the level of retirement benefits that qualify
for tax treatment favorable to ETI and Entergy. The existence of this supplemental benefit program
allows the Company to pay retirement benefits to highly-compensated employees that are
proportionate to the compensation they receive while active in their employment. The Supplemental
Retirement Plan and the System Executive Retirement Plan provide supplemental benefits beyond
the amounts restricted in the qualified plan to some participants to attract, retain, and motivate
employees.623 According to Mr. Gardner, these types of retirement benefits are widely provided by
companies within the utility business sector. 624 Accordingly, ETI argues that it needs to offer them
in order to be competitive in the employment market with peer companies, and thereby to retain and
adequately compensate these employees in terms of future retirement benefits.

           The ALl s conclude that the supplemental executive retirement plans are not reasonable and
necessary for the provision of electric utility service and are not in the public interest. They are
non-qualifying retirement plan available only to employees and executives earning more than

62
  ° Cities Ex. 2 (Garrett Direct) at 56-57.
621
   OPC Ex. 1 (Szerzen Direct) at 68. Dr. Szerzen quantifies the costs of the plans as $1,391,861 (a much
lower estimate than those of Ms. Givens and Mr. Garrett).
622
      Id. at 68-69.
623
      ETI Ex. 50 (Gardner Rebuttal) at 15-16.
624
      Id. at 16.
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PUC DOCKET NO. 39896

$245,000 per year, and they constitute benefits over and above the Company's standard retirement
benefits package. Because these costs are not necessary for the provision of utility service, but are
instead discretionary costs, they should be paid by the shareholders. Accordingly, the AUs
recommend an adjustment to remove $2, 114,931, representing the full costs associated with ETI' s
non-qualified executive retirement benefits.

           5. Employee Relocation Costs

           In the application, ETI included, as part of its labor costs, $436,723 in employee relocation
         625
costs.         ETI contends that, in order to be competitive in the employment market, it must provide
relocation assistance to certain of its employees. ETI witness Gardner testified that ETI' s relocation
policies and costs are reasonable and consistent with general industry practice. He also testified that
the Company's average relocation costs are in line with the relocation costs for the companies
surveyed by the Employee Relocation Council. 626

           Staff recommends an adjustment to remove the entire $436,723 of ETI's relocation
expenses. 627 No other party challenged the legitimacy of relocation expenses. Staff points out that
ETI pays 110 percent of the market median for total annual compensation. 628 Staff contends that the
fact that ETI pays more than the average market wage demonstrates that employees should be
sufficiently enticed to join and move around within its organization without the need for ETI to pay
relocation expenses to attract employees. Therefore, Staff argues that the relocation expenses do not
meet the reasonable and necessary standard required for inclusion in cost of service, nor are the
expenses in the public interest. 629 Staff also points out that similar types of payments were removed

625
      Staff Ex. 1 (Givens Direct) at 25.
626
      ETI Ex. 36 (Gardner Direct) at 45-46.
627
      Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.
628
      Staff Ex. 1 (Givens Direct) at 24 (citing ETI Ex. 36 (Gardner Direct) at 26).
629
      Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.
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from cost of service in recent proceedings, such as in Docket No. 28906, where payments for moving
expenses or signing bonuses were removed from cost of service. 630

           ETI responds by pointing out that Staff does not challenge the reasonableness of the amount
spent on relocations by ETI. It also contends that most of its peers offer moving assistance. Thus, it
would be competitively disadvantaged if it did not offer it as well. ETI reiterates that its relocation
costs are reasonable and necessary and should be authorized. 631

           The AU s conclude that ETI has the better argument. There is no allegation that ETI was too
lavish in its relocation expenditures. The only complaint offered by Staff is that ETI' s overall
compensation costs are 110 percent of the market median. It does not necessarily follow that the
relocation program is unnecessary. ETI provided substantial evidence that, without a relocation
program, it would be at a competitive disadvantage with its peers. Accordingly, the AI.Js reject
Staffs request to disallow the Company's relocation expenses.

           6. Executive Perquisites

           In the application, ETI included, as part of its labor costs, $40,620 in costs associated with its
executive perquisites. Those perquisites consist of financial counseling and tax gross-ups for system
officers and executives. Specifically, the financial counseling program promotes maximizing
investment growth opportunities for eligible officers and executives, and allows reimbursement for
certain expenses incurred for personal financial counseling services. 632 Staff recommends an
adjustment to remove the full cost of the executive perquisites ($40,620), reasoning that the costs are
not reasonable and necessary for the provision of electric utility service. 633 ETI does not oppose that

630
  Stafflnitial Brief at 64; Staff Ex. 1 (Givens Direct) at 24, citing Application ofLCRA Transmission Services
Corporation to Change Rates, Docket No. 28906, Final Order (Apr. 5, 2005).
631
      ETI Initial Brief at 143.
632
      Staff Ex. 1 (Givens Direct) at 23.
633
      Staff Initial Brief at 65; Staff Ex. 1 (Givens Direct) at 23.
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PUC DOCKET NO. 39896

adjustment.634 The AU s agree that the adjustment is warranted. Therefore, the AUs recommend an
adjustment to remove $40,620, representing the full cost of ETI' s executive perquisite costs.

E.        Interest on Customer Deposits

          Staff witness Givens adjusted ETI's requested interest expense of $68,985 by removing
$(25,938) from FERC account 431. 635 This decrease is a result of applying the interest rate of
                                                                          636
0.12 percent for calendar year 2012 on deposits held by utilities.              Using the active customer
deposits amount of $35,872,476 and the 2012 interest rate, Ms. Givens calculated a recommended
interest expense of $43,047 ($35,872,476 multiplied by .12 percent).637

          This change, which reflects Commission-approved interest rates for 2012 as set in December
2011, complies with Project No. 39008 and ETI agreed with this amount. Accordingly, the ALls
recommend that the Commission approve this amount.

F.        Property (Ad Valorem) Tax Expense

          During the Test Year, ETI's property tax expense equaled $23,708,829.638 Patricia Galbraith,
ETI' s Tax Officer, testified that a proforma adjustment should be made to this level of expense for a
known and measurable change that reflects the level of property tax expense ETI will experience in
the Rate Year. Specifically, her proposed adjustment would increase the Test Year level of expense
by $2,592,420 to $26,301,249. 639 As Ms. Galbraith testified, ETI's property tax expense for the
calendar year 2012 will be paid in January of 2013 and be based on 2011 calendar year-end values
for both net operating income and net plant amounts. 640 Her proposed adjustment is based on an

634
      ETI Initial Brief at 144.
635
      Staff Ex. l (Givens Direct) at 24.
636
      Setting Interest Rates for Calendar Year 2012, Project No. 39008, Order (Dec. 8, 2011).
637
      Staff Ex. l (Givens Direct) at 24-25.
638
      ETI Ex. 26 (Galbraith Direct) at 5; ETI Ex. 3 at Sched. G-9.
639
      ETI Ex. 26 (Galbraith Direct) at 5 and PAG-1; ETI Ex. 3 at Sched. G-9.
640
      Tr. at 1235.
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PUC DOCKET NO. 39896

expected ad valorem rate increase of 1 percent and expected increases in both net plant values and
                                                          641
ETI net operating income that will equal 9.81 percent.

          TIEC, Cities, and Staff oppose the property tax adjustment proposed by ETI. TIEC argues
that ETI' s proposed adjustment should be rejected entirely, on the grounds that it is not a known and
measurable change from ETI' s Test Year property tax costs. Ms. Galbraith admitted that she does
not know, with certainty, what the relevant property tax rate will be in 2012, nor has ETI received
any tax bills advising that tax rates will rise. 642 Thus, TIEC witness Pollock testified that ETI' s
proposed adjustment is not known and measurable and recommended that the Commission reject the
adjustment and include only the Test Year level of expense in cost of service.643 TIEC further points
out that the Commission has twice rejected requests to include projected property tax expense in
rates. 644 For example, in Docket No. 28813, Cap Rock prepared an independent analysis indicating
that property taxes were expected to increase to $2,700,000 per year from its test year tax level of
approximately $900,000 per year. The analysis used an estimated tax assessment of $110,000 with
an estimated tax rate of $2.47 per $100 of value. The ALls in that case concluded that the property
tax increases were estimates at the time of the hearing, and thus they were not known and measurable
and should not be allowed. 645 Subsequently, the Commission adopted the ALls' finding. 646 The
Commission rejected a similar request from ETI's predecessor Gulf States Utilities (GSU). 647 In
consolidated Docket No. 8702, the Commission rejected GSU's request for projected 1989 property

641
      ETI Ex. 26 (Galbraith Direct) at PAG-1.
642
      Tr. at 1221, 1238.
643
      TIEC Ex. 1 (Pollock Direct) at 40-41.
644
   In re Cap Rock Corp., Petition ofPUC (Staff) to Inquire into the Reasonableness ofthe Rates and Services
of Cap Rock Energy Corporation, Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005) ("Cap
Rock failed to prove any increase in property taxes above those in the test year-$899,597-was known and
measurable."); Application of Gulf States Utilities Company for Authority to Change Rates, Application of
Sam Rayburn G&T Electric Coop., Inc. for Sale Transfer or Merger, Appeal of GulfStates Utilities Company
from Rate Proceedings of Various Municipalities, Docket Nos. 8702, 8922, 8939, 8940, 8946, 8233, 8944,
8945, 8947, 8948 and 8949, Order at FoF 111(May2, 1991) ("The 1988 calendar year level of actual property
taxes paid should be used in determining rate year taxes because it is a known and measurable change.").
645
      Docket No. 28813, PFD at 99 (Mar. 17, 2005).
646
      Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005).
647
      Docket No. 8702, Order at FoF 111 (May 2, 1991).
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PUC DOCKET NO. 39896

taxes and instead only allowed the actual calendar year property tax expenses. 648 In both cases the
Commission found that projected tax expense is not a known and measurable change. 649
Accordingly, TIEC contends that ETI' s request for a forecasted tax expense increase should be
rejected. 650

            Staff concedes that some level of increase is warranted but argues that the increase should be
smaller than ETI is asking for. Rather than an increase of $2,592,420, Staff contends that ETI' s Test
Year property tax expenses should be adjusted upward by only $1,214,688. 651 Staff witness Givens
arrived at this increase by applying the effective tax rate forthe calendar year2011 to the Staffs Test
Year end plant in service recommendation. She testified that both of these inputs to her calculation
are known and measurable and thus may be used to determine the increase. 652

            Cities also concede that some level of increase is warranted, but argue that the increase
should be smaller than ETI is asking for, and smaller than Staff proposes. Cities contend that ETI' s
Test Year property tax expenses should be adjusted upward by only 1,134,442. 653 Cities witness
Garrett offered the opinion that ETI' s proposed adjustment was based on estimates that were
unreasonably high when compared to the actual tax valuation increases experienced since 2008. Mr.
Garrett arrived at his projected increase in tax expense by applying the average annual valuation
increase experienced over the period of 2009-11 to net plant value for 2011. Cities argue that both of
these inputs to the calculation are known and measurable and thus may be used to determine the
increase. 654

648
      Docket No. 8702, Order at 52.
649
  Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005); Docket No. 8702, Order at 52, FoF 111
(May 2, 1991).
650
      TIEC Initial Brief at 54-56.
651
      Staff Ex. 1 (Givens Direct) at 25.
652
      Id. at 25-26.
653
      Cities Ex. 2 (Garrett Direct) at 61.
654   Id.
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PUC DOCKET NO. 39896

          ETI responds to its opponents by pointing out that the Commission has, in the past,
recognized that the adjustment proposed by Staff, which was obtained by applying a historical
effective tax rate to the level of test year end plant in service, is known, measurable, and
appropriate. 655 ETI also notes that, although it had not done so at the time Ms. Galbraith filed her
testimony, ETI has since filed its 2011 year end FERC Form 1 data and now knows both the final net
income amounts and net plant values for year end 2011 that will be used to determine the Company's
2012 tax expense (that will be paid in January of 2013 ). 656 ETI contends that those known values are
substantially larger than the estimates used by Ms. Galbraith when she calculated the proposed
adjustment, such that the known increases in 2011 net operating income and net plant amounts over
2010 are so large that, even without the 1 percent increase in tax rate assumed in the property tax
adjustment, Rate Year property tax expenses will be larger than the $26,301,249 amount requested
by the Company. 657

          The issue with regard to property taxes is whether a level of increase is known and
measurable. The ALls conclude that the approach taken by Staff does the best job of generating a
known and measurable value for ETI' s property tax burden in the Rate Year. As explained above,
Staffs approach is supported by prior Commission precedent. Moreover, unlike the approaches
advocated by ETI and Cities, Staffs approach requires no guesswork about future tax rates.
Accordingly, the AUs recommend that ETI's property tax burden should be adjusted upward by
applying the effective tax rate for the calendar year 2011 to the final, adopted Test Year-end plant in
service value for ETI.

655
   ETI Initial Brief at 145; see also, Application of AEP Texas Central Company for Authority to Change
Rates, Docket No. 28840, Final Order at FOF 189-191 (Aug. 15, 2005); Petition of General Counsel to
Inquire Into the Reasonableness of the Rates and Services of Central Telephone Company of Texas, Docket
No. 9981, 19 Tex. P.U.C. Bull. 936, 1080-82, 1217 (Sept. 8, 1993);Application of Central Power and Light
Company for Rate Changes and Inquiry Into the Company's Prudence with Respect to South Texas Project
Unit 2, Docket No. 9561, 17 Tex. P.U.C. BULL. 157, 231-232 (Dec. 19, 1990).
656
      Tr. at 1236-37.
657
      ETI Initial Brief at 146-47.
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PUC DOCKET NO. 39896

G.         Advertising, Dues, and Contributions

           In the application, ETI included, as part of its operating expenses, $2,046,214 in costs
associated with advertising, dues, and contributions.658 Staff recommended an adjustment to remove
$12,800, representing contributions to organizations primarily focused on influencing legislative
activities. Staff reasons that these costs are not reasonable and necessary for the provision of electric
utility service. 659 ETI makes no response to the suggested adjustment. 660 The ALls agree that the
adjustment is warranted. Therefore, the ALls recommend an adjustment to remove $12,800 from
ETI' s costs of advertising, dues and contributions.

H.         Other Revenue-Related Adjustments

           Several items within the Company's revenue requirement are interrelated. This means that
changes to one area or item will impact one or more additional items, such as the Texas state gross
receipts tax, the PUC Assessment tax, and Uncollectible Expenses. 661 From the discussions in
briefs, it does not appear that there are any substantive differences among the parties regarding these
amounts, which will ultimately be determined during number running.

I.         Federal Income Tax

           As explained by ETI witness Rory Roberts, the Company calculated its income tax expense
in the cost of service by taking into account only the revenues and expenses included in the cost of
           662
service.         To the extent the Commission makes changes to the revenues and expenses that are
ultimately included in the cost of service, the income tax expense amount included in the cost of

658
      ETI Ex. 3, Sched. G-4.
659
      Staff Initial Brief at 66; Staff Ex. 1 (Givens Direct) at 26.
660
      ETI Initial Brief at 147.
661
      Staff Ex. 1 (Givens Direct) at 28-29.
662
      ETI Ex. 21 (Roberts Direct) at IO; Ex. 3 Sched. G-7.
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PUC DOCKET NO. 39896

service will change accordingly. This represents a proper matching of income tax effects to the
expenses and revenues that produced those tax effects.663

          Mr. Roberts contended that the Commission's past practice of reducing tax expense for a
consolidated tax adjustment based on some measure of the tax "savings" the utility realized by
joining in a consolidated group federal income tax return was inappropriate. He testified that it is
improper to reduce tax expense for deductions or losses that are not also included in the cost of
service. In the case of the Commission's consolidated tax adjustment, tax expense is reduced to the
extent that utility income is used to offset non-utility affiliate losses, even though those losses are not
                                                                                   664
included in cost of service or borne in any manner by the utility's customers.

          Despite his disagreement with the approach, Mr. Roberts performed a calculation of the
adjustment using the interest credit methodology adopted by the Commission. He concluded that,
instead of positive taxable income, ETI had net tax losses over the 15-year calculation period and
thus provided no taxable income that could be used to offset affiliate losses. 665 In fact, over the
15-year period, ETI's tax losses were offset by taxable income produced by other affiliates. Thus,
ETI contends that, were the Commission to be consistent in applying its interest credit methodology,
it should increase ETI tax expense included in cost of service due to the fact that its affiliates'
taxable income had to be used to offset ETI's tax losses. Nevertheless, in its application, ETI
rejected the interest credit methodology and has not requested that ETI' s tax expense be increased as
a result of the consolidated tax adjustment calculation. No other party to the proceeding challenged
the Company's position on federal income tax expense in testimony or at the hearing. The ALls find
no reason to do so either.

663
      ETI Ex. 21 (Roberts Direct) at 10.
664
      Id. at 10-1 L
665
      Id. at 10, and RLR-5.
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J.        River Bend Decommissioning Expense

          ETI has an ownership interest in River Bend. In the application, ETI requested that
$2,019 ,000 be included in its cost of service to account for the Company's annual decommissioning
expenses associated with River Bend. 666 This is the same amount that was requested and approved
on December 13, 2010, in Docket No. 37744. 667 The amount of $2,019,000 was derived from an
ETI decommissioning study that was completed in 2009. In this case, ETI chose not to propose any
change to its 2009 estimate. ETicontends that this decision is supported by an August 9, 2011, letter
from the Nuclear Regulatory Commission. 668

          Cities argue that the decommissioning expense should be reduced to $1,126,000. 669 Cities
point out that the larger amount sought by ETI was merely the amount agreed to by the parties, as
opposed to being substantively considered and approved by the Commission in Docket No. 37744.670
In the current case, ETI was asked through discovery to provide an updated estimate of the annual
decommissioning expense responsibility for Texas retail customers calculated using the most current
Texas jurisdictional decommissioning fund balance.            ETI responded that the current annual
decommissioning revenue requirement is $1,126,000. 671

          Under P.U.C. SUBST. R. 25.231(b)(l)(F)(i), the annual cost of decommissioning for
ratemaking purposes must "be determined in each rate case based on . . . the most current
information reasonably available regarding the cost of decommissioning, the balance of funds in the
decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the
decommissioning trust, and other relevant factors." The cost determined must then be expressly
included in the cost of service established by the Commission's order.

666
      ETI Ex. 3 Scheds. M-1 and M-2; ETI Ex. 8 (Considine Direct) at 57-58.
667
      ETI Ex. 8 (Considine Direct) at 58.
668
      Id. at 58 and MPC-2.
669
      Cities Ex. 2 (Garrett Direct) at 64-65.
670
  Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Final Order at
FoF 32 (Dec. 13, 2010); Cities Initial Brief at 73.
671
      Tr. at 348-49.
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PUC DOCKET NO. 39896

            The parties agree that $1,126,000 is the best estimate of the current annual revenue
requirement to meet ETI' s estimated decommissioning cost. However, ETI relies on P.U.C. SUBST.
R. 25.23l(b)(l)(F)(iv) and Staff witness Cutter's testimony to contend that it need not adjust the
current amount being charged.672 Pursuant to subpart (iv), ETI is required to periodically study its
decommissioning costs, and such a study must be done "at least every five years." Because its last
study was done in 2009, ETI contends that it need not do a new study now, but may simply rely of
the outcome of its last study, which showed that its annual revenue requirement is $2,019,000. 673

            Cities agree that ETI is not required to conduct a new decommissioning study at this time.
However, the most current information reasonably available clearly shows that the annual amount
required to meet the total cost determined in the Company's last decommissioning study has
decreased. Cities argue that to ignore the most current information available disposal would
unreasonably shift future costs to current customers and would be a violation of P.U.C.        SUBST.

R. 25 .231 (b)( 1)(F)(i). The AUs agree. ETI' s annual decommissioning revenue requirement should
reflect the most current calculation of $1, 126,000. Therefore, an adjustment of $893,000 to the pro
form.a cost of service is needed to reflect the difference between the requested level for
decommissioning costs of $2,019,000 and recommended level of $1,126,000.

K.          Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5]

            In prior dockets, the Commission authorized ETI to recover $3,650,000 annually for storm
damage expenses and to maintain a reasonable and necessary storm damage reserve account of
$15,572,000. 674       ETI requests to increase the authorized storm damage reserve account to
$17,595,000 (an increase of $2,023,000) and to increase the annual accrual to $8,760,000 (an
increase of $5,110,000). ETI's proposed annual accrual is composed of two elements: (1) an annual
accrual of $4,890,000 to provide for average annual expected losses from all storms that do not

672
      ETI Ex. 46 (Considine Rebuttal) at 38-39.
673   Id.
674
      Staff Ex. 4 (Roelse Direct) at 8.
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PUC DOCKET NO. 39896

exceed $100 million; and (2) a 20-year annual accrual of $3,870,000 to bring the reserve up from its
current deficit of $59,799,744 to ETI's target reserve of $17,595,000.

           No party disputes that ETI's proposal to self-insure for catastrophic property loss is
appropriate under PURA§ 36.064 and P.U.C. SUBST. R. 25.23l(b)(l)(G). However, Cities, OPC,
and Staff oppose the amount of ETI' s proposed annual accrual, and Cities and OPC also oppose
ETI' s proposed target reserve. The parties' recommendations are:

                                          Annual Accrual      Target Reserve
                            Current        $3,650,000          $15,572,000
                            ETI           $8,760,000           $17,595,000
                            Cities        $6,150,339           $15,572,000
                            OPC-1         $2,335,047           $15,572,000
                            OPC-2         $3,650,000           $15,572,000
                            Staff         $8,270,000           $17,595,000

           The first component of ETI' s requested annual accrual is $4,890,000 for expected annual
losses. ETI explains that this is the amount of annual losses projected to be incurred by ETI from all
storm damage, except those over $100 million (the minimum amount likely to be securitized),675
adjusted to reflect current conditions and current cost levels. 676 This recommended accrual was
calculated by ETI witness Gregory Wilson using a Monte Carlo simulation of ETI's loss history. 677
A statistical distribution was estimated from ETI' s trended loss experience, and the model indicated
an average annual loss of $4,890,000. Mr. Wilson excluded losses from Hurricanes Rita, Gustav,
and Ike from the model because those losses were securitized and not recovered through the
insurance reserve. 678 ETI adds that results from the model simulation were also adjusted by
removing any simulated year in which the total storm loss exceeded $100 million, which would
likely be securitized.

675
      ETI Ex. 19 (McNeal Direct) at 32.
676
      ETI Ex. 14 (Wilson Direct) at 5.
677
      Id. at Ex. GSW-3.
678
      Id. at 9.
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           The second component of the proposed annual accrual is $3,870,000 per year for 20 years to
restore the reserve from the current deficit of $59,799,744 up to the $17,595,000 requested target
level. In ETI's opinion, a 20-year period balances the interests of future and past ratepayers. It
added that Mr. Wilson's calculations were prepared in accordance with generally accepted actuarial
procedures, with certain adjustments to reflect the nature of ratemaking for public utilities. 679

           ETI also requests a target reserve of $17 ,595,000. It argues that this would be an actuarially
sound provision to cover self-insured losses. ETI noted that the target reserve was also developed by
Mr. Wilson through the Monte Carlo simulation based upon the ETI's loss history. 680

           Cities recommend maintaining the current target reserve of $15,572,000 and adopting an
annual storm damage accrual of $6,150,399. Cities' proposed annual accrual is comprised of two
parts: (1) keeping the current accrual of $3,650,000 for projected annual storm expense; and
(2) adding $2,500,399 annually to bring ETI's reserve deficit amount, as adjusted by Cities, up to a
target reserve of $15,572,000. Cities' witness Jacob Pous testified that the current target reserve of
$15,572,000 should be maintained given ETI' s plan to divest itself of the transmission system, which
would reduce storm damage expenses. 681 For the same reason, Mr. Pous also stated that the
Commission should maintain the current annual accrual amount that was approved most recently in
Docket No. 37744.682

           According to Cities, ETI witness Wilson acknowledged that his calculations assumed that the
current transmission system would be owned by ETI, and if the transmission system were sold, his
analysis would need to be adjusted. 683 Cities also note that Mr. Wilson included ETI's 1997 ice
storm expenses within the historical storm data used for his calculations. 684 As discussed in

679
      ETI Ex. 14 (Wilson Direct) at 11-12.
680
      Id. at 9.
681
      Cities Ex. 5 (Pous Direct) at 65-66.
682
      Id. at 66; see also Docket No. 37744, Final Order at FoF 31 (Dec. 13, 2010).
683
      Tr. at 1247.
684
      Tr. at 1244-1246.
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Section V .F., Cities challenge these expenses. If the Commission determines that those costs should
be excluded, Mr. Wilson agreed that it would be inappropriate to include them in his analysis. 685 In
addition, Cities stated, Mr. Wilson's Monte Carlo model analysis has been rejected in several cases
by the Commission, as noted by Staff witness Chris Roelse. 686 Cities noted that Mr. Wilson limited
the storm reserve expense in his model to $100 million, as anything over that amount might be
securitized. 687 But, Cities contend, Mr. Wilson did not consider that the storm loss history provided
to him by ETI included only storm damage expenses and not capital costs, which are also included
when determining the amount capable of being securitized. Thus, in Cities opinion, Mr. Wilson's
cap of $100 million was overstated, and for all these reasons Cities argues that Mr. Wilson's analysis
should not be considered reliable.

          Finally, Cities note that ETI requested that the annual storm reserve accrual "would be made .
. . only until it reaches the recommended target level, at which point contributions to the reserve
would reduce to the lower of annual expected losses or actual losses."688 In Cities view, this request
should be rejected and the accrual should only be modified through a future rate case.

          OPC also recommends adjustments to the storm damage reserve and the annual accrual. As
discussed in Section V.F., OPC argues that ETI failed to prove that its storm damage expenses
booked since 1996 were reasonable and prudently incurred. Consequently, OPC recommends
disallowing all of those charges. Removing those charges would leave ETI with a positive storm
reserve balance of $41,871,059, which exceeds the currently approved storm reserve balance of
$15,572,000 by $26,299,059. OPC witness Benedict proposed that this surplus be refunded to rate
payers at a rate of $1,314,953 per year for 20 years. He also recommended that current annual storm
damage accrual of $3,650,000 be maintained, less his proposed customer refund of $1,134,953 per
year, leaving a net annual storm damage accrual of $2,335,047 per year. Mr. Benedict acknowledged
that some storm damage expenses incurred by ETI since 1996 likely were reasonable and necessary.

685
      Tr. at 1246-1247.
686
      Staff Ex. 4 (Roelse Direct) at 12.
687
      ETI Ex. 14 (Wilson Direct) at 9.
688
      ETI Initial Brief at 151.
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PUC DOCKET NO. 39896

Therefore, as an alternative proposal, Mr. Benedict suggested that ETI's current storm balance
reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or deficit) and
that the currently approved total annual accrual of $3,650,000 be maintained. In addition, OPC
argues that Mr. Wilson's Monte Carlo model analysis was flawed because it included expenses that
ETI did not establish were reasonable and prudently incurred.689

          Staff witness Chris Roelse agreed that ETI's proposed target reserve of $17,595,000 is
reasonable. However, he recommended an annual accrual of $8,270,000, which is $490,000 less
than ETI' s request. Mr. Roelse pointed out that ETI' s witness calculated the proposed annual accrual
based on a Monte Carlo simulation, which projects a loss experience over a longer time than the
period captured in the available loss history. However, Mr. Roelse stated, the Commission has not
approved the use of these models in prior dockets; instead, it has relied on averaging known
insurance losses over a period of time to compute the annual accrual. Using historical loss data,
Mr. Roelse calculated an annual expected storm loss of approximately $4,400,000. When this
amount is added to the proposed annual accrual of $3,870,000 to restore the reserve balance from its
current deficit, it produces a total annual accrual of $8,270,000, which Staff recommends.690

          In response, ETI agreed that if portions of the underlying costs upon which the Monte Carlo
analysis was performed are removed from the reserve, then the outcome of Mr. Wilson's analysis
would be different. However, ETI stressed that questions about the underlying expenses are not an
attack on the Monte Carlo analysis itself. Rather, Mr. Wilson provided an analysis based upon
information supplied by ETI, and he did not claim to support the expenses themselves. But ETI
disagreed with the challenges to the underlying costs, as discussed in Section V.F. 691

          Most of Cities' and OPC's objections to ETI's requested storm damage annual accrual and
target reserve relate to their objections to the underlying expenses, as discussed in Section V .F. For
the reasons stated in that section, the AUs denied those objections, and they do not support rejecting

689
      OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 14-20; OPC Reply Brief at 13-15.
690
      Staff Ex. 4 (Roelse Direct) at 10-15; Staff Initial Brief at 13-14.
691
      ETI Reply Brief at 81.
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PUC DOCKET NO. 39896

ETI' s request for the annual accrual or target reserve. Likewise, the AUs find that Cities' concerns
about ETI selling its transmission system are too uncertain to justify altering the storm damage
reserve at this time.

        Cities also raised a question about whether Mr. Wilson properly calculated the cap he used to
exclude from his analysis storms that would likely result in securitized costs. Staff pointed out that
the Commission has not approved the use of the Monte Carlo simulation model in prior dockets.
Rather, the Commission has traditionally used known insurance losses over a period of time. The
AUs note that neither PURA nor the Commission's rules either require or prohibit the use of
actuarial models, such as the Monte Carlo simulation. The prior dockets cited by Staff did not adopt
the recommendations developed by actuarial models, but the Commission also did not expressly
reject the models in those cases. Likewise, however, ETI has not cited any Commission decisions
that expressly adopted or used such models.

        Staff witness Chris Roelse explained that the Commission has traditionally averaged known
insurance losses over a period of time to compute the annual accrual. He made such a calculation
that produced an annual accrual for storm damage loss of $4,400,000. When added to the proposed
annual accrual of $3 ,870,000 to restore the reserve balance from its current deficit, the total annual
accrual equals $8,270,000. No party challenged that calculation. Because a question remains as to
whether Mr. Wilson properly calculated his cap to exclude storm damage expenses that would likely
be securitized, the AUs find it is more reasonable to adopt the annual accrual proposed by Staff.
Therefore, the AU s recommend that the Commission approve a total annual accrual of $8,270,000,
comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses,
plus an annual accrual of $3 ,870,000 for 20 years to restore the reserve from its current deficit. The
AU s also recommend approval of ETI' s proposed target reserve of $17 ,595,000. Finally, the AU s
recommend that the Commission require ETI to continue recording its annual accrual until modified
by an order in a future rate case, as requested by Cities. Otherwise, ETI could continue to receive
rates based on the total accrual amount, but not record the receipts in the storm damage reserve. The
AUs find that such circumstances would not result in just and reasonable rates.
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PUC DOCKET NO. 398%

L.        Spindletop Gas Storage Facility

          Cities challenged ETI' s use of the Spindletop Facility, arguing that the costs of operating it
outweigh the benefits gained from it. In Section V.H., the AI.Js rejected Cities' contention that a
substantial portion ofETI's annual costs to operate the Spindletop Facility should be removed from
ETI' s rate base. For the same reason he challenged the Spindletop Facility costs associated with rate
base, Cities witness Nalepa also challenges a portion of ETI' s costs derived from the Spindletop
Facility that are associated with operating expenses. Specifically, Mr. Nalepa and Cities argue that
$2,090,116 (consisting of $309,751 in depreciation expense and $1,780,365 associated with the
Spindletop Facility) ought to be removed from ETI' s operating expenses. 692 For the same reason that
they rejected Cities' Spindletop Facility arguments relevant to rate base, the AI.J s also reject Cities'
Spindletop Facility arguments relevant to operating expenses.

 VIII.      AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3]

          PURA requires that more stringent standards be applied to affiliate expenses than are applied
to other utility company expenses. Section 36.058 begins by stating "except as provided by
Subsection (b),"the PUC may not allow as capital cost or as expense a payment to an affiliate for the
cost of a service, property, right, or other item or interest expense. Subsection 36.058(b) provides
that the Commission may allow an affiliate payment "only to the extent" that the PUC finds the
payment is reasonable and necessary for each item or class of item as determined by the
Commission.

          The seminal case interpreting PURA' s affiliate transaction standard under Section 36.058 is
Railroad Commission v. Rio Grande Valley Gas Company. 693 In that case, the court recognized that
PURA' s affiliate transaction statute created a presumption that a payment to an affiliate is
unreasonable. The court explained:

692
      Cities Ex. 6 (Nalepa Direct) at 19; Cities Initial Brief at 76.
693
      683 S.W.2d 783 (Tex. App.-Austin 1985, no writ).
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PUC DOCKET NO. 39896

         Rio's entire approach has been that the Commission is required to allow the residual
         affiliate charges unless they are shown to be imprudent, unreasonable, or out of line.
         Although this may be true with respect to arms length transactions, it is not true with
         respect to affiliates about which the Legislature has its suspicion and which to any
         reasonable mind are clearly tainted with the possibility of self-dealing.

         The court went on to state that the burden was upon Rio to show that its affiliate charges
were just and reasonable. The court interpreted the PURA affiliate transaction statute and explained
four major areas in which Rio had failed to meet its burden of proof:

•     Plaintiff had the burden of showing that the prices it was charged by its affiliate were no higher
      than the prices charged by the supplying affiliate to its other affiliates ....

•     Plaintiff had the burden of showing that expenses which may not be allowed for rate making
      purposes for any reason ... were not included in the "allocated expenses." ...

•     Plaintiff had the burden of proving that each item of allocated expense was reasonable and
      necessary....

•     Plaintiff had the burden of proving that the allocated amounts reasonably approximated the
      actual cost .of services to it. ...

          fu 2000, the Third Court of Appeals once again spoke on the issue of affiliate transactions in
the utility setting.    fu Central Power and Light Company/Cities of Alice v. Public Utility
Commission, the court cited to Rio Grande Valley Gas Company and stated:

         Because of the possibility for self-dealing between affiliated companies, however,
         expenses paid to an affiliated entity are presumptively not included in the rate base.
         A utility can overcome this presumption against affiliate expenses only if it
         demonstrates that its payments are 'reasonable and necessary for each item or class of
                                                    694
         items as determined by the commission. '

PURA Section 36.058 places a greater burden of proof on the utility to prove the reasonableness and
necessity of its affiliate transactions because of the nature of the relationship between the utility and
its affiliates. These transactions are not considered to be arms-length, and there is a potential for

694
      36 S.W.3d 547 at 564 (Tex. App.-Austin 2000, pet. denied) (citations omitted).
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PUC DOCKET NO. 39896

self-dealing. The transactions must be disallowed for regulatory purposes, unless the utility presents
sufficient evidence that it has met each of the affiliate transaction statutory requirements. If the
regulatory tests for affiliate transactions are not properly enforced, the regulated utility may become a
vehicle for cross-subsidization by ratepayers of other regulated or unregulated affiliates.

          OPC witness Szerszen was the only witness to challenge ETI's affiliate transactions, 695
recommending a total affiliate disallowance (after erratas) of $8,945 ,221. 696 Dr. Szerszen reviewed a
select subset of ETI' s affiliate expenses using the PURA affiliate transaction standards. She
reviewed the Company's affiliate transactions on a project by project basis, noting that such a review
was more efficient and easier to understand. 697            Dr. Szerszen testified that a review by the
Company's 25 classes of service presents a far too macro view of affiliate transactions that does not
allow an adequate review of ETI' s affiliate transactions according to PURA mandates and takes the
focus away from the important issues. 698

          OPC notes that PURA Subsection 36.058(f) requires that if the Commission finds an affiliate
expense for the test period to be unreasonable, then the Commission is to make a determination of
what level of the expense is reasonable. By analyzing ETI' s affiliate transactions on a project basis,
OPC contends that it has facilitated the Commission's ability to make such a determination for each
of ETI' s classes of service; instead of an "up or down" decision on the macro level of expense for the
class, the Commission can disallow the portion not shown to be reasonable and approve the
remainder as reasonable.

695
     Cities witness Mark Garrett recommended disallowance of certain short-term incentive compensation
affiliate costs, but those disallowances are largely also recommended by Dr. Szerszen. See ETI Ex. 69
(Tumminello Rebuttal) at 17. ETI contends that the duplicated disallowances by Dr. Szerszen and Mr. Garrett
would result in double counting $217 ,520 of the requested affiliate charges and requests that if the AUs rule in
OPC' sand Cities' favor regarding these short-term incentive compensation costs, that disallowance should be
reduced by $217,520. ETI Initial Brief at 157, n. 898.
696
      Tr. at 1607.
697
      OPC Exhibit No. 1 (Szerszen Direct) at 42-43.
698
      OPC Exhibit No. 1 (Szerszen Direct) at 42-43; Tr., at 1671-72.
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PUC DOCKET NO. 39896

          ETI disagrees with OPC's contentions and argues that Dr. Szerszen's approach to addressing
the Company's affiliate case is inappropriate for a number of reasons and should be rejected.

•     First, her approach is directly contrary to the Commission's Guiding Principles included as part
      of the Commission's Transmission and Distribution Cost of Service Rate Filing Package that
      was issued on April 2, 2003. 699 Item 2 of the Guiding Principles clearly states that a class of
      service approach is required for purposes of complying with the provisions of Section 36.058 of
      PURA. 700 Dr. Szerszen ignores the class of service approach required by Section 36.058 of
      PURA as detailed in the Guiding Principles, and instead states OPC' s case on a project code-by-
      project code basis.

•     Second, Dr. Szerszen's approach is directly contrary to the Commission's directives in Docket
      No. 16705. In that docket, the Commission disallowed a substantial amount of affiliate expense
      because Entergy Gulf States, Inc. had done then what Dr. Szerszen proposes here - based the
      affiliate analysis solely on project codes, rather than affiliate classes of service. Because the
      Commission found that a scope statement/project code-based affiliate analysis is "impossible,"
      the Company, in its subsequent base rate cases, including its filing in this docket, changed to a
      class-based presentation, as directed by the Commission.

•     Third, by refusing to consider a class-based analysis, Dr. Szerszen has ignored the Company's
      testimony, presented by 19 affiliate witnesses, which explains in detail why the Company's
      affiliate-incurred costs meet the Section 36.058 of PURA and Rio Grande standards. 701
      According to ETI, the Company's affiliate class witnesses, who are knowledgeable about the
      activities that are encompassed in each of their classes, have each shown why the services
      provided through those classes are necessary. They have each also addressed numerous
      Commission-recommended metrics to measure the reasonableness of costs, including cost trends,
      staffing trends, the budgeting process, and, if applicable, benchmarking and outsourcing
      comparisons. 702 Their testimony and exhibits, according to ETI, show numerous different
      "views" of the costs in their classes, including the project codes that comprise their classes. Each
      affiliate witness also addressed the "not higher than" and "reasonably approximates cost"
      standards applicable to affiliate costs. ETI contends that the evidence provided by its witnesses
      meets the requirements of these Guiding Principles and supports the Company's burden of proof
      for the recovery of affiliate costs. ETI also contends that Dr. Szerszen ignores this overwhelming

699
      See ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1.
700
    Dr. Szerszen conceded that the Guiding Principles require that a utility's affiliate case be presented in a
sufficient number of class or other logical groupings. Tr. at 1632.
701
    Dr. Szerszen claimed that, instead of considering the narrative class testimony, she instead "looked at more
of the detail," presumably meaning the exhibits. Tr. at 1629.
702
   ETI Ex. 69 (Tumminello Rebuttal) at Ex. SB T -R-1. Dr. Szerszen conceded that the Company's testimony
included proof items such as benchmarking data, outsourcing, staffing trends, and cost trends. Tr. at 1631.
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PUC DOCKET NO. 39896

      evidence and the careful attention paid to presenting it in an organized manner. In addition, she
      presents no evidence in accordance with the Guiding Principles that supports her proposed
      disallowances.

•     Fourth, the Company's case is much less cumbersome and less complex than the approach
      suggested by OPC, which would require a showing on the necessity, reasonableness, "not higher
      than," and "reasonably approximates cost" standards for each of almost 1,300 project codes
      subject to this docket. Even if the Company were to do that, Dr. Szerszen's "cherry picking"
      approach among the project codes ignores any savings in other project codes that would
      comprise a class of affiliate costs, thereby resulting in an overall reasonable level of costs within
      the class even assuming that any of her complaints about individual project codes had merit.

•     Fifth, ETI contends that Dr. Szerszen fails to mention Section 36.058(f) of PURA, which
      requires that the Commission determine the reasonable level of "an affiliate expense" if it first
      finds that the expense presented is unreasonable. But rather than offering an alternative
      "reasonable" level of an expense"", she either categorically disallows all costs in that project; or,
      in some instances, substitutes an arbitrary sharing or allocation of costs between ETI and its
      regulated affiliates, or ETI and its non-regulated affiliates. In doing so, Dr. Szerszen does not
      make any evidence-based attempt to ground her alternative allocation (and associated
      disallowance of ETI affiliate costs) on any objective basis reflecting cost causation principles.
      ETI contends that the effect of her approach is to presume that the Company needs zero dollars in
      its cost of service to perform a variety of essential utility support activities.

•     Sixth, Dr. Szerszen' s positions in the 2009 Oncor rate case,703 which she agrees are similar to her
      positions in this ETI base rate case, 704 were rejected by the two SOAH AU s and the Commission
      in that docket. ''Many of the allegations and arguments made by Dr. Szerszen in this case are
      very similar, if not identical, to the points she asserted in the Oncor case.

          The AU s agree that the Commission's Guiding Principles set forth the minimum that a
utility must present to establish a prima facie case, and it is clear that ETI met that burden. That,
however, is not the end of the question. Permitting a utility to escape further scrutiny of its affiliate
transactions by resting on its prima facie presentation imposes too many limits and, as suggested by
OPC, presents too macro a view to be a legitimate review for rate case purposes.

703
   Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 35717
(PFD issued on Jun. 2, 2009; Order on Rehearing issued on Nov. 30, 2009) (Oncor).
704
      Tr. at 1656.
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PUC DOCKET NO. 39896

          OPC performed essentially a sample review of ETI' s affiliate transactions. The review was
not exceptionally large, and (as evidenced by ETI' s concurrence in the removal of some of the costs)
it represented an additional layer of review to ensure that improper costs would not inadvertently be
charged to ratepayers. That, of course, is not the sole focus of OPC' s review, but it is important for
purposes of determining whether the review itself is appropriate. If intervenors and Staff were
limited to the macro level of review urged by ETI, such matters would never be revealed and there
would exist a possibility that ratepayers would be charged for matters not their responsibility. The
ALJs do not characterize OPC's review as "cherry picking." It is more a reasonable sample for
examination that gives ETI a reasonable opportunity to explain the reasons for the charges to
ratepayers. Accordingly, the ALJs find that the Commission's Guiding Principles do not limit the
review performed by OPC, and the review performed by OPC is not contrary to the Commission's
holdings in Docket No. 16705.

A.        Large Industrial & Commercial Sales Reallocation

          OPC contends that ETI incurs considerable amounts of sales and marketing expenses that are
exclusively for the benefit of the larger commercial and industrial customers. However, most of
ESI' s sales, marketing, and customer service expenses are allocated to residential and small business
customers. 705 The vast majority of the sales, marketing and customer service expenses are allocated
to the operating companies based on customer counts, the majority of these expenses are
consequently allocated to residential and small business customers. In the test year, residential and
small general service customers made up 94.8 percent of the ETI total customer count. ETI' s
General Service, Large General Service, and Large Industrial Power Service, and Lighting classes
combined comprise only 5.2 percent of ETI' s customers. For the test year, OPC argues that ETI is
requesting the recovery of $2.086 million of sales, marketing, billing and load research expenses that
benefitted only the large customer service classes. OPC contends that it is inappropriate for
residential and small customers to pay for these expenses, when cost causation is so readily
identifiable, particularly since a disproportionately small portion of larger customer sales and

705
      OPC Ex. l (Szerszen Direct) at 45.
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PUC DOCKET NO. 39896

marketing expenses is allocated to ETI's largest customers. 706 The total recommended reallocated
large customer expense is $2,086,145.

          ETI and TIEC oppose OPC' s recommendation, arguing that it is "cherry-picking" and that the
evidence does not demonstrate that the $2.086 million of affiliate expense should be directly
assigned to the large commercial and industrial classes. 707

          With respect to the first argument, ETI and TIEC contend that Dr. Szerszen developed her
adjustment by examining a limited sample of affiliate project code summaries and making the call,
based on project code descriptions, that certain affiliate costs for marketing, sales and customer
service expense should be directly assigned to large commercial and industrial customers. 708 Both
TIEC and ETI contend that the bias and results-oriented nature of her recommendation became
apparent when Dr. Szerszen admitted on cross examination that she made no effort to examine
whether certain affiliate costs should be directly assigned to residential and small customers.709 Both
ETI and TIEC contend that it is inappropriate to take a "limited sample of costs" and directly assign
them to a particular class.

          According to TIEC, Dr. Szerszen admitted that it could have been appropriate to make an
adjustment for direct assignment of costs to small commercial and residential customers based on
principles of cost causation. 710 However, she made no effort to do that herself, nor did she ask ETI
to conduct such an analysis. 711 The parties argue that the evidence shows that Dr. Szerszen's
recommendation rests on an incomplete analysis of ETI's affiliate costs and her recommendation
should be rejected because direct assignment of costs is only appropriate if there has been a thorough

106
      OPC Ex. 1 (Szerszen Direct) at 45.
707
      ETI Ex. 55 (LeBlanc Rebuttal) at 5; TIEC Ex. 3 (Pollock Cross Rebuttal) at 36.
708
      Tr. at 1609.
709
      Tr. at 1609-10.
710
      Tr. at 1685.
rn Tr. at 1613-1624.
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PUC DOCKET NO. 39896

and complete cost study analysis to determine what costs are or are not appropriate for direct
assignment to all of the classes.

           TIEC further argues that the evidence did not demonstrate that the $2.086 million of affiliate
expense that Dr. Szerszen proposes for direct assignment to large commercial and industrial
customers is solely attributable to costs caused by those customers. Mr. Pollock testified that the
project codes Dr. Szerszen selected include load research expenses that benefit residential and small
commercial customers. 712 TIEC pointed out that ETI witness Stokes testified that the billing
methods used for the affiliate expenses for customer service operations and retail operations were
fair and reasonable.713 According to TIEC, Dr. Szerszen's proposal should be rejected because her
assertion that these expenses exclusively benefit large commercial and industrial customers is
incorrect.

           The AU shave reviewed the arguments of the parties and find that Dr. Szerszen' s analysis is
far from complete. It appears to be result-oriented, ignoring critical aspects (such as failing to make
an adjustment for direct assignment of costs to small commercial and residential customers based on
principles of cost causation). The AUs believe that Dr. Szerszen's analysis with respect to this issue
should not be adopted.

B.         Administration Costs

           Dr. Szerszen recommended disallowance of $94,709 (25 percent) of the charges in
Project F3PCFACALL, contending that ESI failed to directly charge any of the costs in this project
code to ETI. She claimed that the billing method applied to this project code by ESI (that is, Billing
Method "SQFALLC"), which is based on square footage, is not appropriate for these types of
         714
costs.

712
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 35.
713
      ETI Ex. 66 (Stokes Rebuttal) at 3.
714
      OPC Ex. l (Szerszen Direct) at 80-82.
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          ETI witness Plauche explained that the costs captured in this project code are primarily for
the oversight of administrative functions, such as facilities, real estate, and security.715 This project
code applies to the administration of these types of functions. These services benefit all companies
that receive facility services and are not attributable to any one specific Entergy affiliate. Therefore,
it is appropriate to bill these costs to all companies based on their pro rata share of square footage
occupied. 716

          The AUs concur that this is the appropriate method to employ and, therefore, recommend
that the Commission approve the inclusion of these costs as requested by ETI.

C.        Customer Service Operations Class

          Dr. Szerszen recommended disallowances in seven project codes covered primarily by ETI' s
Customer Service Operations Class: (1) F3PCR29324 (Revenue Assurance - Adm.) for a
disallowance of $70,849; (2) F3PCR53095 (Headquarter's Credit & Collect) for a disallowance of
$110,338; (3) F3PCR73380 (Credit Systems) for a disallowance of $73,562; (4) F3PCR73458
(Credit Call Outsourcing) for a dis allowance of $197; (5) F3PCR73381 (Customer Svc Cntr Credit
Desk) for a disallowance of $43,378; (6) F3PCR73390 (Customer Svs Ctl - Entergy Bus) for a
dis allowance of $60, 926; and (7) F3 PCR73403 (Customer Issue Resolution - ES) for a dis allowance
of $1,869. 717

          1. Projects F3PCR29324 (Revenue Assurance· Adm.), F3PCR53095 (Headquarter's
             Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call
             Outsourcing)

          For the costs captured by these project codes, Dr. Szerszen recommended that the costs be
reallocated based on the Company's 10 percent "bad debt" expense percentage.

715
      ETI Ex. 20 (Plauche Direct) at 15-26.
716
      ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-2 at 10.
717
      OPC Ex. l (Szerszen Direct) at 76-78.
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PUC DOCKET NO. 39896

          ETI witness Stokes responded that the costs captured by these project codes are for
management and supervision of credit, collection, and revenue assurance activities for all of the
Operating Companies. These functions ensure the most efficient processes are used in managing
write-offs for all the Operating Companies and have contributed to Entergy' s first quartile ranking in
benchmarking of credit and collection operations. These managerial and supervisory costs, which
include bankruptcy administration, surety administration, arrears management, collection agency
administration, skip tracing, and final bill collections, remain consistent whether ETI's bad debt
percentage is 10 percent, 30 percent, or any other percent and are appropriately allocated using the
CUSTEGOP billing method, which is based on the number of electric and gas customers for each
Operating Company. 718

          ETI has provided credible evidence that it has chosen the correct billing methodology.
Therefore, the Al.Js recommend the Commission approve inclusion of these costs as requested by
ETI.

          2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer
             Svs Ctl • Entergy Bus), and F3PCR73403 (Customer Issue Resolution - ES)

          Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing
method. Given ESI's demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this
project using a 10.8 percent customer call allocator, which is on the low end of the
10.70 percent-11.04 percent Test-Year CUSTCALL allocators. 719

          ETI witness Stokes believes that Dr. Szerszen' s proposed reallocation is arbitrary and fails to
consider the cost causation associated with the actual project code at issue. These costs are not
driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL
allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick

718
      ETI Ex. 66 (Stokes Rebuttal) at 15-16.
719
    OPC Exhibit No. l (Szerszen Direct) at 77 and 118; OPC Exhibit No. 27 (ETI's Ex. SBT-15,
Attachment 6) at 2; Tr., at 838-839.
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PUC DOCKET NO. 39896

Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of
calls by customers to the Company.

         The ALls are persuaded that the allocation methodology chosen by ETI is the superior
method and that the CUSTCALL allocator would not be appropriate given the cost causation
associated with the project. Accordingly, the ALls recommend the Commission approve the costs
proposed by ETI.

D.       Distribution Operations Class

         Dr. Szerszen addressed three project codes that are within the Distribution Operations Class:
(1) F5PCDW0200 (Lineman's Rodeo Expenses) for adisallowanceof $7; (2) F3PCTJGUSE(Joint
Use With Third Party E) for a disallowance of $6,405; and (3) F3PCTJTUSE (Joint Use With 3rd
Parties -A) for a disallowance of $36,293. 720

         1. Project F5PCDW0200 (Lineman's Rodeo Expenses)

         Dr. Szerszen claimed that the expenses captured by this project should be disallowed because
ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.

         ETI witness Tumminello responds, stating that this minimal amount is related to a safety
competition known as the "Lineman's Rodeo," it is not a corporate "image" expense. The cost,
according to Ms. Tumminello, is driven by Entergy employee safety in the Distribution business
units. 721

         The AI.Js agree that the Lineman's Rodeo competition is not a corporate image expense,
rather it is designed to promote employee safety. The AI.Js recommend the Commission approve
inclusion of the costs captured by this project as requested by ETI.

720
      OPC Ex. 1 (Szerszen Direct) at 66, 75.
721
      ETI Ex. 41 (Tumminello Direct) at Ex. SBT-E at 1234.
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PUC DOCKET NO. 39896

          2. Projects F3PCTJGUSE (Joint Use With Third Party- E) and F3PCTJTUSE (Joint
             Use With Third Parties - A)

          Dr. Szerszen recommends exclusion of these two projects, which she claims represent the
difference between the costs incurred for ETI for pole rental costs and the revenues received from
pole space rentals.

          With respect to this proposed disallowance, ETI witness McCulla states that Dr. Szerszen has
confused the rental of space on transmission poles and the rental of space on distribution poles. She
has essentially performed a cost-benefit analysis that erroneously compares the cost of providing
rental space on distribution poles with the income received solely from rental of space on
transmission poles. Mr. McCulla explained that data for the distribution poles show that the more
than $2.5 million in revenues from distribution pole rentals far exceeds the $67, 174 in costs billed to
ETI under these two project codes and, therefore, Dr. Szerszen's misassumption that the revenues
were less than the costs incurred is unfounded. 722

          The AU s find that Dr. Szerszen erred. Making the correct comparison, as demonstrated by
Mr. McCula, shows there is no basis for the disallowance claimed by Dr. Szerszen. The ALls,
therefore, recommend the Commission deny the requested disallowance.

E.        Energy and Fuel Management Class

          Dr. Szerszen addresses seven project codes that are within the Energy and Fuel Management
Class: (1) F3PCCSPSYS (System Planning And Strategic) for a disallowance of                   $29,304;
(2) F3PCWE0140 (EMO Regulatory Affairs) for adisallowance of $114,468; (3) F3PPSPE002 (SPO
2009 Renewable RFP Expense) for a disallowance of $3,014; (4) F3PPSPE003 (SPO Summer 2009
RFP Expense) for a disallowance of $56,672; (5) F3PPSPE004 (SPO Summer09RFP
IM&Propslsubmt) for a disallowance of $42,018; (6) F3PPWET300 (SPO 2008 Western Region

722
      ETI Ex. 59 (McCulla Rebuttal) at 8-12.
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RFP-Te) for a disallowance of $645; and (7) F3PPWET303 (SP02008WinterWestnRegionRFP-IM)
for a disallowance of $4,200. 723

           1. Project F3PCWE0140 (EMO Regulatory Affairs)

           Dr. Szerszen testified that Texas ratepayers do not receive benefits as a result of the costs
captured by this project code and should therefore not be charged those costs. 724

           ETI witness Cicio explained that Dr. Szerszen misinterpreted an RFI response to conclude
that Texas ratepayers did not receive benefits from the activities whose costs were booked through
this project code. That project code is not intended to capture costs for docketed or large System
Planning and Operations projects. Mr. Cicio states that it is not possible to assign a specific project
code for every discrete activity performed by each employee, nor would it be appropriate to attempt
to do so. Regardless of the number of activities specifically identified through project codes, there
will remain the need to have generic project codes that capture time spent on more general,
undocketed matters and activities that are no less beneficial to ratepayers. 725

           The AU s agree that Texas ratepayers receive benefits as a result of the costs charged to this
account. Accordingly, the AUs recommend the Commission approve inclusion of the costs as
requested by ETI.

           2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO
              Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM &
              Propslsubmt), and F3PPWET303 (SP02008 Winter Westn RegionRFP-IM)

           Dr. Szerszen testified that the costs captured by these projects should be disregarded because
they were incurred during the 2008-2009 period, which is outside of the Test Year, and are
nonrecurring. 726

723
      OPC Ex. l (Szerszen Direct) at 55, 60, and 65-66.
724
      Id. at 55.
725
      ETI Ex. 45 (Cicio Rebuttal) at 8-9.
726
      OPC Ex. I (Szerszen Direct) at 65.
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          ETI witness Cicio explained that although these projects were initiated prior to the Test Year,
the costs that the Company seeks to recover through these project codes were expenses incurred
during the Test Year, including development activities, request for proposal issuance, bidders
conferences, written and posted questions and answers from market participants and other interested
parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions
and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports,
and regulatory approvals, if necessary. These routinely encompass a multi-year time frame, and the
costs required to perform those activities, although associated with a project that may have been
initiated several years previously, are properly incurred over the life span of the project. He also
states that they are recurring because they reflect the kinds and levels of charges that would be
expected to be incurred on an ongoing basis in association with requests for proposals managed by
ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these
types of solicitations since 2002. 727

          The AlJs find that the costs captured by these projects were incurred during the Test Year
and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly, the
AU s recommend that the Commission approve their inclusion as requested by ETI.

          3. Project F3PCCSPSYS (System Planning and Strategic)

          Dr. Szerszen recommended total disallowance of the costs captured by this project code
because they are allocated based on the total assets of the Entergy affiliates. 728 Dr. Szerszen' s
conclusion appears to be that no such corporate-level costs should be allocated to ETI because there
are other project codes that allocate corporate planning and analysis-type costs only to the regulated
utilities, such as ETI; thus, any corporate-level costs that are allocated to all subsidiaries, whether
regulated or non-regulated, should not be charged to ETI.

727
      ETI Ex. 45 (Cicio Rebuttal) at 13-14.
728
      OPC Ex. 1 (Szerszen Direct) at 60-61.
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            ETI witness Tumminello testified that Dr. Szerszen's theory neither considers the Entergy
organization as a family of companies and ETI' s place in that family, nor the fact that these services
are not only relevant to ETI as part of the Entergy family, but are reasonable, necessary and meet the
Commission's affiliate cost recovery standard. ESI's corporate oversight services are provided to
both individual companies and groups of companies within the Entergy 'corporate structure. As a
member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and
forecasting activities provided by ESI. 729

            The ALls find that ETI (and, therefore, its ratepayers) does receive benefits as a member of
the Entergy family of companies and that it is appropriate for it to receive charges for those services.
Therefore, the AUs recommend the Commission approve the inclusion of costs as requested by ETI.

F.          Environmental Service Class

            Dr. Szerszen recommended disallowance of $301,879 in six project codes primarily within
ETI's Environmental Services Class: (1) F3PCCE0129 (Corporate Sustainability Strat) for a
disallowance of $6,781; (2) F3PCCE0193 (Corp Environmental Special Pro) for a disallowance of
$1,203; (3) F3PCCEIE01 (Corp Environmental Initiatives) for a disallowance of $2,413;
(4) F3PCCEll01 (Corp Environmental Initiatives) for a disallowance of $2,413; (5) F3PCCEP001
(Corporate Environmental Policy) for a disallowance of $269,248; and (6) F5PPBCNAVF (Avian
Flu Contingency Planning) for a disallowance of $47. 730

            Dr. Szerszen' s reasoning for this disallowance was that these six project codes, which all deal
with corporate environmental policy, initiatives, strategy, and consulting services, were allocated
based on Billing Method CAPAOPCO, which is based on the fossil plant capacity of the regulated
utility operating companies, even though "non-regulated entities clearly benefit from the corporate
level expenses."731 Dr. Szerszen recommended a $47 disallowance for Project F5PPCCNAVF

729
      ETI Ex. 69 (Tumminello Rebuttal) at l 0-11.
730
      OPC Ex. 1 (Szerszen Direct) at 62-63.
131   Id.
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PUC DOCKET NO. 39896

(Avian Flu Contingency Planning), asserting that this charge is a "corporate imaging expense that
should not be borne by Texas ratepayers."732

           According to ETI, Dr. Szerszen has a fundamental misunderstanding of how the affiliate
billing system works and, as a result, she incorrectly assumed that ESI charges are not being properly
allocated. ETI argues that the non-regulated Entergy affiliates do receive the proper and appropriate
allocation of costs. The two service companies for non-regulated affiliates also provide services to
their non-regulated affiliates directly. There simply is no subsidization or improper allocation. 733

           Dr. Szerszen noted that Entergy' s website indicates that nuclear-related environmental issues
are being pursued. 734 She argued that this shows that the non-regulated affiliates are under-allocated
environmental-related costs. Ms. Stokes explained that the project codes at issue "deal with services
provided to the operating companies .... and just looking at the website there are other things ...
that are not covered or paid for by Texas ratepayers in these project codes that are in this
                   735
testimony."              Therefore, according to Ms. Stokes, these project codes are not allocated in such a
way that under-recovers costs from the non-regulated affiliates; they pay their own way.

           Finally, the Project Summary for the Avian Flu Contingency Planning project shows that
these costs involve developing and communicating Avian Flu business continuity plans and then
maintaining, checking, and adjusting those plans once established. 736 These are not "corporate
imaging expenses" as characterized by Dr. Szerszen.

732
      Id. at 66.
733
     See, e.g., ETI Ex. 41 (Tumminello Direct) at 10-15. Moreover, while ESI bills the regulated utility
affiliates such as ETI at cost, it bills the non-regulated affiliates at cost plus a 5 percent mark-up pursuant to a
June 1999 Securities and Exchange Commission order. ETI Ex. 41 (Tumminello Direct) at 15. This 5 percent
mark-up is then flowed back to entities that receive service from ESL Therefore, the regulated affiliates are,
by federal order, receiving essentially a rebate from the non-regulated affiliates.
734
      OPC Ex. 1 (Szerszen Direct) at 62.
735
      Tr. at 884.
736
      ETI Ex. 41 (Tumminello Direct) at SBT-E at 1342-43.
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          The AU s agree that ETI' s evidence demonstrates the recoverability of the costs captured by
these project codes. Therefore, the ALJs recommend the Commission approve their recovery.

G.        Federal PRG Affairs Class

          Dr. Szerszen recommended disallowances for three project codes primarily in the Federal
PRG Affairs Class: (1) F5PPSPE044 (PMO Support Initiative-System) for a disallowance of $344;
(2) F3PPUTLDER (Utility Derivatives Compliance) for a disallowance of $20,447; and
(3) F3PCSYSRAF (System Regulatory Affairs-Federal) for a disallowance of $352,084.737

          1. Project FSPPSPE044 (PMO Support Initiative-System)

          Dr. Szerszen recommended disallowance of $344.29 from Project F5PPSPE044 (PMO
Support Initiative System). ETI responds, however, that a review of the Project Summary for that
project code in Ex. SBT-E reveals that ETI already removed those costs before even filing its direct
case. Therefore, according to ETI, Dr. Szerszen is recommending disallowance of a cost that is not
in this case.738

          The AU s agree that examination of the exhibit referenced by ETI appears to reveal that the
costs challenged by Dr. Szerszen have been removed from this case through a pro Jonna adjustment.
Accordingly, the ALJs recommend the Commission reject OPC's challenge.

          2. Project F3PPUTLDER (Utility Derivatives Compliance)

          Dr. Szerszen recommended disallowance of $20,447 of derivatives expenses because ETI did
not use derivative instruments and therefore should not be charged these costs and because
ratepayers do not benefit from derivatives. 739

737
      OPC Ex. 1 (Szerszen Direct) at 46-47, 66-67.
738
      ETI Initial Brief at 174-175.
739
   ETI stated that it assumes that Dr. Szerszen must be referring to Project Code F3PPUTLDER (Utility
Derivatives Compliance) because her recommended disallowance is the same total ETI adjusted amount shown
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PUC DOCKET NO. 39896

          ETI witness Tumminello responded that Project F3PPUTLDER was charged by a group
developing compliance mechanisms to protect Entergy' s regulated utility interests in observance of
the Dodd-Frank Act. Although ETI does not currently use any derivative activities, understanding
the impacts of that Act is necessary to ensure current and future compliance through Entergy. The
definitions under the legislation have not been finalized, and there remain issues that ETI must be
aware of to fully comply. These costs, therefore, are necessary and reasonable charges that should
not be disallowed. 740

           The explanation offered by ETI for the inclusion of these charges appears reasonable to the
AU s. Even though ETI does not now use derivatives, it is possible that it will in the future and it is
important that it be aware of the regulatory framework associated with such actions to avoid
problems. The AU s therefore recommend the Commission approve inclusion of these costs as
requested by ETL

           3. Project F3PCSYSRAF (System Regulatory Affairs-Federal)

           In the regulatory affairs category, ETI requests the recovery of various legal,
testimony-related, communications, and filing costs associated with both Texas-specific regulatory
activities, FERC-related regulatory activities, and non-Texas specific regulatory activities. OPC
witness Szerszen did not recommend a disallowance of the $1,442,223 in adjusted Test Year
expenses for regulatory affairs that ETI has shown to be specific to the Texas jurisdiction. 141 Rather,
Dr. Szerszen recommended that all regulatory affairs expenses not specific to Texas be
disallowed.7 4 2 These expenses total $759,868.743

on the Project Summary for that project code. See SBT-E at 1113. The ALJ s make the same assumption as it
appears reasonable.
740
      ETI Ex. 69 (Tuminello Rebuttal) at Ex. SBT-R-2 at 3.
741
      See OPC Ex. 3 (Szerszen Workpapers) at 368-371.
742
      OPC Ex. 1 (Szerszen Direct) at 46-47.
743
      Id. at 46.
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PUC DOCKET NO. 39896

          Project F3PCSYSRAS (System Regulatory Affairs - State) was incurred for administrative
activities for senior management, project work associated with system-wide regulatory matters,
system-wide regulatory strategies and emerging regulatory issues, and it relates to multiple regulated
jurisdictions. 744 Project No. F3PCSYSRAF (System Regulatory Affairs - Federal) was incurred for
regulatory oversight and coordination of FERC matters. 745 OPC contends that ETI provided no
evidence that Texas ratepayers receive any tangible benefits from "system" regulatory affairs costs in
proportion to the costs being allocated to Texas.

          Project F3PCSYSRAS costs are allocated to the subsidiaries based on electric customer
counts, and OPC states that it is questionable whether Entergy's positions on "emerging" state or
national regulatory issues or "system-wide regulatory strategies" are conveying any benefits to its
electric customers beyond those already captured in the Texas-specific regulatory affairs project
codes.7 46 In fact, according to OPC, the Company's shareholders are the primary beneficiaries of
these system-wide regulatory strategies.747 The federal regulatory affairs costs captured under
Project F3PCSYSRAF are allocated to the regulated subsidiaries based on each company's load
responsibility ratio; this ratio assumes that every FERC docket and/or FERC issue is related to ETI' s
peak demand. According to OPC, this is not reality, nor is it consistent with FERC's primary
responsibility to ensure that electric wholesale buyers and sellers are provided open access
transmission across utility systems.

          ETI witness May offered the following as rebuttal of Dr. Szerszen's contentions regarding
these two project codes:

          The affiliate charges to Project Codes F3PCSYSRAS and F3PCSYSRAF are directly
          associated with the issues and matters within the federal jurisdiction of the Federal
          Energy Regulatory Commission ("FERC") including but not limited to the Open
          Access Transmission Tariff ("OATT") as well as any other federal statutes, rules and

744
      OPC Ex. 3 (Szerszen Workpapers) at 365.
745
      OPC Ex. l (Szerszen Direct) at 46-47; OPC Ex. 3 (Szerszen Workpapers) at 367.
746
      OPC Ex. 3 (Szerszen Workpapers) at 368-371.
747
      OPC Ex. 1 (Szerszen Direct) at 47.
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PUC DOCKET NO. 39896

          regulations. These are the result of issues and matters raised concerning the OATT,
          operations of the transmission system, requests for transmission service and
          interpretation of applicable provisions under the jurisdiction of FERC. They are
          costs incurred on an Entergy System-wide basis that cannot be directly assigned to
          any one Operating Company, such as ETI.748

He then went on to state that the affiliate Test Year issues and costs related to these project codes are
                                                                                                   749
reflective of typical issues and costs that the Company experiences on an ongoing basis.                 With
respect to the benefits derived by Texas ratepayers as a result of activities conducted under these
project codes, Mr. May stated that:

          the benefit to ETI involves a multitude of issues that are directly related to the
          jurisdiction of the FERC, including but not limited to any revisions to Service
          Schedules under the System Agreement that applies to all operating companies
          including ETI, power purchase agreements for cost-based, short-term power sales,
          and compliance with FERC by each Operating Company to the market-based rate
          tariff and cost-based rate tariff. The Entergy Operating Companies' market-based
          rate tariff and cost-based rate tariff are joint tariffs containing terms and conditions of
          service. 750

Mr. May also explained why the billing methods applied to these two project codes are appropriate.
The cost drivers for Project F3PCSYSRAF are labor, employee expenses, consultant expenses, and
other general operating expenses incurred for the benefit of the Entergy Operating Companies and
their regulated customers. Therefore, a billing method based on load responsibility "LOADOPCO"
  is appropriate for this type of project code. Project F3PCSYSRAS captures costs associated with
general regulatory support work that is applicable across all of the jurisdictions. The primary
activities associated in this project code include but are not limited to: special project work
associated with system-wide regulatory matters, analysis of emerging state or national regulatory and
accounting issues affecting the Entergy System, and internal process improvement work. What
drives the cost of this project code is the average number of both electric and gas customers served-

748
      ETI Ex. 57 (May Rebuttal) at 25.
749
      ETI Ex. 57 (May Rebuttal) at 25.
750
      ETI Ex. 57 (May Rebuttal) at 27-28; see also, Tr. at 370-371.
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PUC DOCKET NO. 39896

CUSTEGOP because all such customers benefit from these services provided by ESI to ETI.751 In
short, according to ETI, the activities undertaken under both of these project codes benefit Texas
ratepayers, and they are properly allocated to the regulated operating companies using the billing
methods employed.

          The AU s believe that resolution of this question is a close call. Although ETI provided an
adequate explanation of the reasons underlying the allocation of costs to Texas ratepayers and the
appropriateness of the allocation methodologies used, the one troubling aspect, as noted by OPC,
was that Mr. May's testimony regarding Projects F3PCSYSRAF and FP3PCSYSRAS contradicted
the fact that ESI has a specific project dedicated to open access transmission issues entitled "FERC-
Open Access Transmission" (Project F3PCE01601). 752 As OPC notes, if Mr. May was correct that
OATT issues have been included in Projects F3PCSYSRAF and FP3PCSYSRAS the project pages
should arguably be more specific about the purpose of the expenditure. Nevertheless, the AU s find
ETI' s testimony credible and recommend that the costs of Projects F3PCSYSRAF and
FP3PCSYSRAS not be disregarded.

H.        Financial Services Class

          Dr. Szerszen recommended disallowances in nine project codes that are primarily captured
within ETI's Financial Services Class of affiliate costs: (1) F3PCF05700 (Corporate Planning &
Analysis) for a disallowance of $4,254; (2) F3PCF21600 (Corp Rptg Analysis & Policy) for a
disallowance of $320,157; (3) F3PCFF1000 (Financial Forecasting) for a disallowance of $96,734;
(4) F3PPADSENT (Analytic/Decision Support-Entergy) for a disallowance of $93,544;
(5) F3PPSPSENT         (Strategic   Planning Svcs-Entergy) for         a disallowance of $45,265;
(6) F3PCR73345 (Quick Payment Center, Adm) for a disallowance of $14,484; (7) F3PCF20990

751
      ETI Ex. 57 (May Rebuttal) at 28-29.
752
      OPC Ex. l l; also found in OPC Exhibit No. 3 (Szerszen Workpapers )at 363-364.
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PUC DOCKET NO. 39896

(Operations Exec VP & CFO) for a disallowance of $146,267; (8) F3PCFF1001 (OCE Support) for
a disallowance of $1,923; and (9) F3PCF23936 (Manage Cash) for a disallowance of $15,677.753

          1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg
             Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT
             (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-
             Entergy)

          Dr. Szerszen proposed to disallow all costs related to these five project codes, which she
collectively describes as addressing Corporate Planning, Reporting, and Forecasting issues because
she contends that an assets-based allocator should not be used to allocate these costs and, regardless
of the allocator used, these types of services do not benefit Texas ratepayers because ESI has, in
other instances, directly billed corporate-level services to ETI.

          ETI witness Tumminello responded, stating that Dr. Szerszen failed to consider the Entergy
organization as a family of companies and ETI's place in that family. The services provided under
these project codes are not only relevant to ETI as part of the Entergy family, but are reasonable and
necessary. ESI' s corporate oversight services are provided to both individual companies and groups
of companies within the Entergy Companies' corporate structure. As a member of the corporate
group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities
provided by ESL Ms. Tumminello contested that the use of an asset-based allocator is appropriate
because this is an example of the stewardship of the company-wide assets and such an allocator is,
therefore, appropriate. 754 The AU s agree.

          The AUs find that ETI's proposed allocator is appropriate and that the costs benefit Texas
ratepayers. Accordingly, the AUs recommend the Commission approve the costs proposed by ETI.

753
      OPC Ex. I (Szerszen Direct) at 56, 60-62, and 74, and Schedules CAS-9, CAS-10, and CAS-15.
754
      ETI Ex. 69 (Tumminello Rebuttal) at 10-11.
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PUC DOCKET NO. 39896

         2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE
            Support)

         Dr. Szerszen recommended disallowance of all costs captured by these project codes because,
in her opinion: (1) there are "no perceivable benefits to ETI's ratepayers"; (2) they should be paid
for by the parent entity (presumably meaning Entergy's shareholders); and (3) an asset.s-based
allocator is not appropriate. 755

         As to Dr. Szerszen' s assertion that Texas ratepayers do not benefit from the costs captured by
these project codes, ETI witness Domino, President of Entergy, provided anecdotal evidence that that
Entergy was vital to ETI' s restoration efforts on two fronts. First, the parent provided cash to ETI for
its hurricane restoration efforts; second, ETI was not required to pay dividends to the parent while it
was strapped for funds due to hurricane restoration efforts. 756 With respect to the argument that an
asset-based allocator is not appropriate, Ms. Tumminello testified that the functions covered by this
project code relate to the oversight of all system operations and the stewardship of corporate assets
and that because ETI is part of a corporate group, the allocated charges associated with these services
are relevant to ETI as part of that group. Furthermore, ETI argues, the asset-based allocator is
appropriate because it reflects the cause of the costs incurred, in that services provided relate to the
stewardship of all the corporation's assets. 757

         Dr. Szerszen took too narrow a view and, without justification, argued that these costs
provide no benefit to Texas ratepayers. There are innumerable benefits provided by the corporate
structure adopted; those mentioned by Mr. Domino are just a few. Ms. Tumminello's testimony
explained why an asset-based allocator is appropriate. Accordingly, the AUs recommend the
Commission approve the inclusion of these costs as requested by ETI.

755
      OPC Ex. 1 (Szerszen Direct) at 56-57.
756
      Tr. at 141.
757
      ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
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PUC DOCKET NO. 39896

          3. Project F3PCR73345 (Quick Payment Center, Adm)

          Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing
method. Given ESI's demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this
project using a 10.8 percent customer call allocator, which is on the low end of the
10.70 percent-11.04 percent Test-Year CUSTCALL allocators. 758 As a result of Dr. Szerszen's
reallocation, $14,484 associated with this project should, according to Dr. Szerszen, be
disallowed.759

          ETI witness Stokes responded, stating that Dr. Szerszen's proposed reallocation is arbitrary
and fails to consider the cost causation associated with the actual project code at issue. These costs
are not driven by a specific proportion of calls from each Operating Company (that is, by the
CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing
the Quick Payment Center vendors in each of the Entergy Operating Companies, regardless of the
number of calls by customers to the Company. 760

          The AI.Js are persuaded that the allocation methodology chosen by ETI is the superior
method and that the CUSTCALL allocator would not be appropriate given the cost causation
associated with the project. Accordingly, the AI.Js recommend the Commission approve the costs
proposed by ETI.

          4. Project F3PCF23936 (Manage Cash)

          Dr. Szerszen recommended disallowance of $15,677 from Project F3PCF23936 (Manage
Cash), arguing that this project: (1) is duplicative of ETl-specific financing and cash management

758
      OPC Exhibit No. 27 (ETI' s Ex. SBT-15, Attachment 6) at 2; Tr. at 838-839.
759
      OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118.
760
      ETI Ex. 66 (Stokes Rebuttal) at 11.
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PUC DOCKET NO. 39896

activates; (2) the allocator is wrong; and (3) Entergy, not ETI ratepayers, should pay for this
activity. 761

          ETI witness McNeal testified that the services are not duplicative of the cash management
services performed by the Cash Management department in the Treasury Class. The services
provided under Project F3PCF23936 are associated with daily cash management responsibilities,
such as loading bank balances, setting daily cash position for all the Entergy Companies, transmitting
wire/ACH files to Entergy Company banks for vendor payments, and maintaining proper cash
controls over these cash functions. These services are necessary for the daily operation of all the
Entergy Companies, including ETI, and are thus not directly associated with any one specific legal
entity. The costs are driven by the time spent on the daily cash management activities, which is
directly related to the number of bank accounts that the Entergy Companies have open. Since the
services provided under this project code cannot be identified to a particular Entergy Company, the
billing method based on the number of open bank accounts is the best allocation. Billing method
BNKACCTA does that and, according to Mr. McNeal, is therefore appropriate for allocating costs
for this project code. 762

          The evidence demonstrates that the activities captured by this project code are not directly
associated with any one specific entity; rather, they benefit all the entities under the Entergy
umbrella. It also appears that a billing method based on the number of open bank accounts is the
appropriate allocation methodology. Accordingly, the ALls recommend the Commission approve
inclusion of costs as requested by ETI.

I.        Human Resources Class

          Dr. Szerszen recommended dis allowances for three project codes that are primarily within the
Human Resources Class of affiliate costs: (1) F3PCHRCCSM (HR Competitive Compensation) for
a disallowance of $20,146; (2) FSPCZUBENQ (Non-Qualified Post-Retirement) for a disallowance

761
      OPC Ex. l (Szerszen Direct) at 74 and Schedule CAS-15.
762
      ETI Ex. 61 (McNeal Rebuttal) at 4, 6; Tr. at 546-547.
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PUC DOCKET NO. 39896

of $115,078; and (3) F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl) for a disallowance of
$241,073. 763

          1. Project F3PCHRCCSM (HR Competitive Compensation)

          Dr. Szerszen testified that an asset-based allocator is not appropriate for a project, such as
Project F3PCHRCCSM, that captures overall executive management-related costs.764

          ETI contends that the functions covered by this project code relate to the oversight of all
system operations and the stewardship of corporate assets and that because ETI is part of a corporate
group, the allocated charges associated with these services are relevant to ETI as part of that group of
companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the
cause of the costs incurred, in that services provided relate to the stewardship of all the corporation's
assets. 765

          A corporation cannot function without executives, who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class
costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a
logical allocator - the assets the executives are charged with overseeing. The AU s recommend that
OPC' s challenge be rejected.

          2. Projects FSPCZUBENQ (Non-Qualified Post-Retirement) and FSPPZNQBDU
             (Non-Qual Pension/Benf-Dom Utl)

          With respect to Projects F5PCZUBENQ and F5PPZNQBDU, Dr. Szerszen testified that:
(1) there is no evidence that Texas ratepayers benefit from the pension-related benefits in these

763
      OPC Ex. I (Szerszen Direct) at 56, 68.
764
      OPC Ex. I (Szerszen Direct) at 56.
765
      ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-1 l.
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codes; and (2) the LBRBILAL allocator (Labor Billings to All) is not appropriate because the
benefits are unrelated to ESI labor costs. 766

          Initially, ETI agrees that $112,531 of the costs in total for both of these project codes should
be excluded because that amount is attributable to nuclear and non-regulated employees.767

          With respect to the remaining costs, ETI disagrees. The AUs, however, have already
resolved this issue in their discussions related to Section VII.D.4, above, where they concluded that
that the supplemental executive retirement plans are not reasonable and necessary for the provision
of electric utility service and are not in the public interest. Accordingly, the Al.Js recommend the
Commission accept OPC' s proposed disallowance of $356, 151 (which includes the $112,531 agreed
to by ETI).

J.        Information Technology Class

          Dr. Szerszen recommended disallowances in two project codes that are primarily within
ETI's Information Technology Class: (1) F3PPFXERSP (Evaluated Receipts Settlement) for a
disallowance of $10,279; and (2) F3PCFX3555 (BOD/Executive Support) for a disallowance of
$3,148. 768

          1. F3PPFXERSP (Evaluated Receipts Settlement)

          Dr. Szerszen testified that Project F3PPFXERSP is not moving forward due to tax and freight
implications and, as such, the cost is not recurring. 769 Ms. Tumminello testified in response that the
"Evaluated Receipt Settlement" program was originally being capitalized in a capital project. But
when it was decided that the program would be cancelled, the capital project was closed and the
charges to the project were expensed. Although the costs for this particular project do not recur

766
      OPC Ex. l (Szerszen Direct) at 68.
767
      ETIInitial Brief at 179.
768
      OPC Ex. l (Szerszen Direct) at 56, 71.
769
      OPC Ex. 1 (Szerszen Direct) at 71.
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every year, they are part of normal utility operations, and this type of project does recur as
necessary.770

          Although the AU s understand the concept of normally recurring cost types, they do not
believe that the costs captured by this project code fall within that category. Those costs related to a
project that was cancelled and sufficient explanation of how similar projects in the future might
occur was not provided. Accordingly, the ALls recommend the Commission reject inclusion, as
proposed by OPC.

          2. Project F3PCFX3555 (BOD/Executive Support)

          Dr. Szerszen argued that Project F3PCFX3555 is an executive-related project that does not
provide perceivable benefits to ETI ratepayers, the Entergy shareholders should bear this cost, and an
assets-based allocator is not appropriate. 771

          ETI argues that the functions covered by this project code relate to the oversight of all system
operations and the stewardship of corporate assets and that because ETI is part of a corporate group,
the allocated charges associated with these services are relevant to ETI as part of that group of
companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the
cause of the costs incurred, in that services provided relate to the stewardship of all the corporation's
assets. 772

          A corporation cannot function without executives who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her arguments. The utility and executive management class
costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a
logical allocator- the assets the executives are charged with overseeing. The AU s recommend that
OPC's challenge be rejected.

770
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4.
771
      OPC Ex. 1 (Szerszen Direct) at 56.
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K.        Internal and External Communications Class

          Dr. Szerszen recommended disallowances in four project codes that are primarily within
ETI' s Internal and External Communications Class: ( 1) F3PCR40118 (Utility Communications for a
$6 disallowance; (2) FSPCZPDEPT (Supervision and Support- Public) for a $138 disallowance;
(3) FSPPICCOOO (Integrated Customer Communications) for a $199 disallowance; and
(4) FSPPICCEMP (ICC - Employee Education Initiative) for a $3 disallowance.773

          ETI witness Tumminello responded to Dr. Szerszen's claim that the costs captured by these
project codes are corporate image costs by stating that the costs are for advertising activities that are
of a good will or institutional nature, which is primarily designed to improve the image of the utility
or the industry, including advertisement which inform the public concerning matters affecting the
Company's operations, such as, the costs of providing service, the Company's efforts to improve the
quality of service, the Company's efforts to improve and protect the environment. According to
FERC, such costs are properly includable inFERCAccount 930.1 and are recoverable. According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs. 774

          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did little better, but it did provide the testimony of
Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and
are, therefore, recoverable. In the end, the AUs must go with the weight of the evidence, which is in
ETI's favor. The AUs recommend the Commission reject OPC's contention that costs covered by
these project codes are not recoverable.

772
      ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
773
      OPC Ex. l (Szerszen Direct) at 66.
714
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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L.      Legal Services Class

        Dr. Szerszen recommended disallowances in 13 project codes that are primarily within the
Legal Services Class: (1) F3PPCASHCT (Contractual Altemative/Cashpo) for a disallowance of
$2,553; (2) F3PCF99180 (CORP. COMPLIANCE TRACKING SYS) for a disallowance of $9;
(3) F3PPINVDOJ (DOJ Anti Trust Investigation) for a disallowance of $1,039,664; 775
(4) F3PCE01601 (Ferc - Open Access Transmission) for a disallowance of $84,183;
(5) F3PCERAKTL (RAKTL Patent Matter) for a disallowance of $75; (6) F3PPEASTIN
(Willard Eastin et al) for a disallowance of $19,714; (7) F3PPTCGS11 (TX Docket Competitive
Generation) for a disallowance of $310,746; (8) F5PCE13759 (Jenkins Class Action Suit) for a
disallowance of $205,l 07; (9) F5PCZLDEPT (Supervision & Support- Legal) for a disallowance of
$225,794; (10) F3PCCDVDAT (CorporateDevelopmentDataRoom)foradisallowanceof $6,147;
(11) F3PCSYSAGR (SystemAgreement-200l)for a disallowanceof$880,841; (12) F3PPWET302
(SPO 2008 Winter Western Region) for a disallowance of $13,919; and (13) F3PPWET308 (SPO
Calpine PPA/Project Houston) for a disallowance of $435,963.

        1. Project F3PPCASHCT (Contractual Altemative/Cashpo)

        With respect to Project F3PPCASHCT ($2,553 disallowance), ETI agrees that these costs are
non-recurring and should be disallowed. Accordingly, the AUs recommend the Commission
exclude those costs.

        2. Project FSPCZLDEPT (Supervision & Support - Legal)

        As to Project F5PCZLDEPT ($225,794), OPC, through its Second Errata, removed that
proposed disallowance, and it is no longer contested by Dr. Szerszen. Accordingly, the AUs
recommend the Commission approve inclusion of those costs.

775
    Dr. Szerszen also proposed disallowance of $765 in charges for related Project Code F3PPTDHY 19 (Dept.
of Justice Investigation), which is actually primarily attributable to the Transmission Operations Class, rather
than the Legal Services Class. Because the issues are intertwined, that project will be discussed here, rather
than in the Transmission Operations Class.
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          3. Project F3PCF99180 (Corp. Compliance Tracking Sys)

          F3PCF99180 (Corp. Compliance Tracking Sys) is one of the project codes that Dr. Szerszen
claimed should be disallowed because ETI is a monopoly and Texas ratepayers should not have to
pay for corporate image costs. 776

          ETI witness Tumminello testified that these costs are for advertising activities that are of a
good will or institutional nature, which is primarily designed to improve the image of the utility or
the industry, including advertisement which inform the public concerning matters affecting the
Company's operations, such as, the costs of providing service, the Company's efforts to improve the
quality of service, the Company's efforts to improve and protect the environment. According to
FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs. 777

          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did little better, but it did provide the testimony of
Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and
are, therefore, recoverable. The weight of the evidence is in ETI' s favor. The ALls recommend the
Commission reject OPC' s contention that costs covered by these project codes are not recoverable.

          4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of
             Justice Investigation)

          Entergy is currently under investigation by the Department of Justice (DOJ) for certain
business practices of the Operating Companies, including the procurement of generating assets and
power, dispatch of generation within the Entergy system, and transmission capacity expansion. This
is a civil investigation under Section 2 of the Sherman Act and Section 7 of the Clayton Act. The

776
      OPC Ex. I (Szerszen Direct) at 66.
777
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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investigation has been ongoing since 2010, and Entergy does not know when the investigation will
conclude. 778

          Dr. Szerszen testified that there are two reasons why ratepayers should not pay for the DOJ
expenses. First, ETI does not have the ability to make its own power procurement, generation
dispatch, or transmission capacity decisions. These decisions are made by ESI and Entergy' s
corporate management, which has traditionally planned and managed the electric operating
companies' generation and transmission functions on a system-wide basis. Second, ETI is not
responsible for the development and administration of the system agreement, and should not be held
responsible for these antitrust investigation expenses. Furthermore, according to Dr. Szerszen, if the
DOJ finds that Entergy has acted illegally, it is even more inappropriate to charge ETI ratepayers for
corporate-level illegal actions. These expenses should be borne by Entergy's corporate parent and/or
the corporation's shareholders, and not the ratepayers. 779

           ETI contends that Dr. Szerszen fundamentally misunderstands the nature of the System
Agreement and the benefits that ETI derives from that agreement. All of the Entergy Operating
Companies voluntarily entered into the System Agreement so that the Entergy system can be planned
and operated on a total system basis, in order to maximize economic benefit and reliability of
service. All of the Operating Companies benefit from integrated planning and operations in this
manner. This does not mean that ETI has no decision-making role in these activities. ETI notes that
under Section 5.01 of the System Agreement, the agreement is administered through an Operating
Committee, which includes an ETI representative, as well as representatives of the other Operating
Companies and Entergy. ETI' s representative is one of the voting members of the Committee, and
all decisions of the Operating Committee must be approved by a majority vote. As a voting member
of the Operating Committee, ETI is responsible for administering the System Agreement and does
participate in decision-making on generation and transmission matters. 780

778
      OPC Ex. 1 (Szerszen Direct) at 51-52.
779
      Id. at 52.
780
      ETI Ex. 65 (Sloan Rebuttal) at 8.
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PUC DOCKET NO. 39896

            ETI acknowledges that ESI is tasked with providing services and making decisions related to
generation dispatch, power procurement, and transmission operations on behalf of the Entergy
Operating Companies and at the direction of the Operating Committee, but these activities are for the
benefit of the Operating Companies and their ratepayers. ETI receives the benefits of these services
and integrated planning and operations under the System Agreement and, according to ETI, should
also be responsible for its portion of costs related to those services and operations. 781

            As to Dr. Szerszen' s contention that the costs should be disallowed because DOJ might find
that Entergy acted illegally, ETI notes that the DOJ is not an adjudicatory body or regulatory agency
and, thus, it does not make "findings of fact." If DOJ believes the civil antitrust laws have been
violated, it can file a complaint in federal district court. To date, no complaint has been filed. ETI
points out that ESI routinely incurs legal costs in responding to regulatory audits and investigations
on behalf of ETI and the other Operating Companies in the same manner in which other operating
costs are incurred. ESI is authorized to retain legal counsel on behalf of, and for the benefit of, ETI
and the other Entergy Operating Companies. ESI is authorized to allocate the respective costs to the
Operating Companies under a service agreement with the Entergy Operating Companies designated
as Rate Schedule FERC No. 435. This service agreement is on file with, and was approved by,
FERC under FER C Docket No. ER07-38-000. 782 Thus, according to ETI, it is appropriate that ETI is
allocated its share of the costs of legal services related to the DOJ investigation. 783

            The DOJ antitrust investigation is a massive undertaking. Unfortunately, it is a part of the
ordinary course of modem business life. OPC's arguments that ESI is solely responsible for
decision-making under the System Agreement miss the mark, as pointed out by ETI. It is clear that
ETI and the other Operating Companies play an active role in the decision-making. As to OPC's
arguments about what would happen if Entergy were found to have violated the antitrust laws, those
arguments are little more than speculation. As ETI noted, the DOJ is not an adjudicatory body and
its investigation can only result in the filing of a complaint in Federal court (if the DOJ believes that

1s1   Id.
782
      Entergy Serv. Inc., 117 FERC 1 6 l ,288 (2006 ).
783
      ETI Ex. 65 (Sloan Rebuttal) at 8-9.
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PUC DOCKET NO. 39896

such an action is justified). Until that time, it is imperative for the company to fully respond to the
DOJ investigation. The Al.Js find that ETI has met its burden of proving that Texas ratepayers
should be charged the costs of the DOJ investigation allocated to them by ETI.

          S. Project F3PCE01601 (Ferc - Open Access Transmission)

          Project F3PCEO 1601 costs are incurred to manage costs associated with regulatory oversight
and coordination of the Entergy System Open Access Transmission Service before FERC. OPC
contends that not only are most of the FERC dockets accruing costs under Project F3PPEO 1601 no
longer open as of December 31, 2011, 784 most of the closed dockets have absolutely nothing to do
with Texas operations.785 Furthermore, according to OPC, ETI witness Sloan agreed that only three
of the dockets shown in OPC Exhibit No. 12 were open at the end of the test year, and one of the
open dockets involves a transmission service agreement involving the Missouri Joint Municipal
Electric Utility Commission and various cities in Missouri and Arkansas.786

          ETI responds that the activities in this project relate to oversight and coordination of the
OATT proceedings before the FERC. Costs billed to this project code are related to ESI's
representation of the Operating Companies, including ETI, before the FERC on OATT issues.
Revenues derived from provision of service under the OATT are credited to all of the Operating
Companies on a load responsibility ratio basis. ETI' s retail share of these revenues was $168,366
during the test period, demonstrating the benefits derived by Texas ratepayers as a result of the
activities undertaken through this project code. 787

          Activities relating to a company's OATT are not one-time activities; they will continue from
year to year. OPC's contention that because most of the dockets listed as having taken place during
the Test Year were completed by the end of the Test Year they should be disregarded is not

784
      OPC Ex. 12 (OPC RPI No. 7-3); OPC Ex. 3 (Szerszen Workpapers) at 363.
785
      OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. l (Szerszen Direct) at 54.
786
      Tr. at 280.
787
      ETI Ex. 65 (Sloan Rebuttal) at 10.
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PUC DOCKET NO. 39896

well-founded. It is clear that the activities covered by this project code not only benefit ETI' s Texas
ratepayers, but will continue (albeit under new docket numbers) into future years. The AUs
recommend that costs under this project code be allowed.

          6. Project F3PCERAKTL (RAKTL Patent Matter)

          The costs under this project code involve the RAKTL patent, which relates to call center
operations. RAKTL is a patent infringement claim lodged against several Entergy companies. The
alleged patents are for voice prompting technology used in call centers. 788

          Dr. Szerszen testified that it is not appropriate to charge ETI for the costs associated with this
litigation because ETI did not purchase the call center telephone equipment at issue, and therefore
should not be required to pay any legal costs associated with patent infringement investigation or
settlement costs. ESI is totally responsible for system-wide technology purchases and operations,
and, according to Dr. Szerszen, it is not reasonable to require the operating companies to pay legal
costs associated with ESI technology acquisition or technology application errors.789

          ETI contends that ESI incurred the legal expenses on this patent matter on behalf of the
Entergy Operating Companies, whose residential and small commercial customers call into the call
centers to obtain customer service for issues related to connection and disconnection of electric
service, billing issues, and other customer transactions. The call centers provide an interface
between ETI customers and the Entergy Operating Companies and, as such, are valuable in providing
quality service to customers. Consequently, according to ETI, costs related to the call centers,
including the costs of defending lawsuits involving technologies used at those call centers, is a
reasonable and necessary expense that is appropriately allocated to ETI.790

          OPC tends to ignore the purpose and benefits of a centralized service company such as ESL
If ETI were to fund stand-alone call centers, it is likely that the costs to Texas ratepayers would be

788
      Id. at 4; OPC Ex. 1 (Szerszen Direct) at 49-50.
789
      OPC Ex. I (Szerszen Direct) at 50.
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PUC DOCKET NO. 39896

higher than those proposed by ETI in this case. Part of the costs that ESI incurs is the cost of patent
claims. Those are legitimate costs that should be borne by all who receive service from ESI.
Accordingly, the ALls recommend the Commission reject OPC's challenge.

          7. Project F3PPEASTIN (Willard Eastin et al.)

          This project code, which contains costs in the amount of $19,714, collects costs related to an
age discrimination law suit filed by Willard Eastin, et al. against Entergy. The defendants to the
lawsuit were Entergy, ESI, Entergy Louisiana, fuc. (ELL), and Entergy New Orleans, fuc. (ENOI).
The plaintiffs to the lawsuit were employees of ESI, ELL, and ENOI.791

          OPC witness Szerszen testified that ETI should not be required to pay any of the costs of this
litigation. Although ESI provides services to the Operating Companies, this does not imply that the
Operating Companies should be charged costs associated with the service company's employment
                                                            792
practice problems or errors according to Dr. Szerszen.

          ETI argues that costs are driven by ESI having the need for legal services to defend itself. As
shown on the Project Code Summary for this project, since all ESI functions are in service to the
various affiliates and arise as a consequence of providing such services, it is appropriate to relate
these legal costs to the total ESI billings to the affiliates. 793

          ETI has provided little in the way of explanation regarding these costs or the litigation that
generated them. What is troubling to the AUs is that the only named defendants are Entergy, ESI,
ELL, and ENOI; ETI is not included among the named defendants. If this were simply a cost of
doing business for ESI, as claimed by ETI, why were ELL and ENOI named? No explanation was
offered. It appears to the ALls that although this litigation is related to ESI's operations, it is more

790
      ETI Ex. 65 (Sloan Rebuttal) at 4.
791
      ETI Ex. 65 (Sloan Rebuttal) at 2; OPC Ex. 1 (Szerszen Direct) at 49-50.
792
      OPC Ex. 1 (Szerszen Direct) at 50.
793
      ETI Ex. 65 (Sloan Rebuttal) at 2.
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immediately related to ELL and ENOI. The AUs do not believe that ETI's Texas ratepayers should
be charged for these costs; therefore the AUs recommend that $19,714 not be included.

          8. Project F3PPTCGS11 {TX Docket Competitive Generation)

          The costs billed through this project code all pertain to ETI' s CGS matter currently pending
before the Commission in Docket No. 38951. 794

          OPC witness Szerszen testified that because no decision has been made yet as to the
disposition of the expenses associated with the CGS tariff, ETI should not be expensing the costs
associated with that docket.         Dr. Szerszen disallowed $310,746 in Test-Year expenses, and
recommended that ETI be allowed to defer the expenses until the Commission determines the
appropriate regulatory treatment. 795

          ETI argues that these costs were incurred during the Test Year in a pending Commission
docket, and ETI continues to incur costs related to this matter. As such, according to ETI, these costs
are appropriately included in ETI' s cost of service and should neither be disallowed nor deferred.7 96

          OPC's arguments with respect to these costs are not well-founded. It appears to be likening
these regulatory costs to rate case expense, which would be subject to Commission review and
approval in the proceeding to which they relate. But that is not the nature of these expenses. They
are simply regulatory expenses incurred in the course of ongoing regulatory proceedings. They are
ordinary and necessary expenses, the reasonableness of which OPC did not challenge. Accordingly,
the AU s find that it is appropriate for ETI to charge these expenses to its Texas ratepayers.

794
      Id. at 5; OPC Ex. 1 (Szerszen Direct) at 50.
795
      OPC Ex. l (Szerszen Direct) at 50.
796
      ETI Ex. 65 (Sloan Rebuttal) at 5.
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            9. Project FSPCE13759 (Jenkins Class Action Suit)

            The project code relates to a class action lawsuit filed in Texas District Court in 2003 on
behalf of all Texas retail customers served by ETI's predecessor-in-interest, EGSI (Jenkins Class
Action). The Jenkins Class Action plaintiffs allege that they have been damaged due to manipulation
of the dispatch and pricing of the Entergy system's generating units and electricity purchases. As a
result of this alleged manipulation, they contend that ETI's Texas retail customers were charged
more than they should have been for purchased power.797 Dr. Szerszen asserted there are three
reasons why these legal expenses should not be borne by ETI:

•     ESI charges 100 percent of the legal expenses to ETI, even though ETI is only one of several
      defendants;

•     ETI claims that it is defending practices relating to system operations, but fails              to
      acknowledge that Entergy' s system operations are comprised of many generation                 and
      transmission components other than those of ETI; and

•     ETI does not have any authority to administer the System Agreement, that           being a function
      solely within the purview of ESI.798

Dr. Szerszen testified that "[i]t would be more appropriate for the Entergy parent to be charged for
these lawsuit expenses, particularly since ETI cannot make unilateral power purchases and power
sales decisions."799

            ETI responds that the plaintiffs in this lawsuit are challenging the reasonableness of ETI' s
Commission-set rates and that the Commission has filed an amicus brief in support of ETI' s position
in the case. ETI further argues that retail ratepayers are benefitting from ETI' s pursuit of the
litigation because ETI is defending practices that are in place to ensure the lowest reasonable cost
consistent with system reliability. Finally, ETI states that the costs are reasonable and necessary

797
      OPC Ex. 1 (Szerszen Direct) at 49; ETI Ex. 65 (Sloan Rebuttal) at 2-3.
798
      OPC Ex. l (Szerszen Direct) at 49.
799   Id.
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expenses because the plaintiffs purport to represent only ETI's ratepayers and seek to recover
damages inconsistent with ETI' s filed rates approved by the Commission. 800

          The ALls understand Dr. Szerszen's concerns that there are multiple defendants involved in
this litigation, there are many aspects to Entergy' s system operations, and ETI does not have power
to unilaterally make decisions under the System Agreement. The crucial point, however, is that these
are Texas ratepayers pursuing a challenge to ETI's Texas rates. The matter centers around Texas,
and the costs of the litigation should be borne by Texas ratepayers.

          10. Project F3PCSYSAGR (System Agreement-2001)

          OPC witness Szerszen disallowed $880,841 in legal expenses regarding the 2001 complaint
filed by the Louisiana Public Service Commission and the City of New Orleans seeking revisions to
the Entergy System Agreement. 801 OPC states that it generally agrees with ETI witness Sloan that
the complaint challenges the equalization of costs between all Entergy Operating Company
jurisdictions. 802 However, OPC does not agree that the inquiry "will" affect all Entergy jurisdictions.
Texas has benefitted from the complaint primarily through the past receipt of equalization payments
pursuant to FERC's decision in this complaint matter. However, Entergy's SEC FormlO-K shows
that for 2012 and 2013, ETI will receive no equalization payments, and further shows that ETI
received no rough production cost equalization payments in 2010. 803 Thus, according to OPC, the
legal expenses sought to be recovered under Project F3PCSYSAGR are non-recurring for ETI and
therefore not representative of future costs and should be removed from ETI' s cost of service. 804

          ETI established that this litigation involved the System Agreement, which governs the
equalization of costs between all of the Entergy Operating Company jurisdictions, it provides
benefits to ETI's Texas ratepayers as well as those of the other Entergy Operating Companies.

800
      ETI Ex. 65 (Sloan Rebuttal) at 3.
801
      OPC Ex. 1 (Szerszen Direct) at 53.
802
      ETI Ex. 65 (Sloan Rebuttal) at 9.
803
      ETI Ex. 98 (Entergy's SEC Fonn 10-K) at 79-80.
804
      OPC Ex. 1 (Szerszen Direct) at 52-53.
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OPC' s argument that ETI did not receive equalization payments in 2010 and is non-recurring for ETI
does not overcome the benefits received by ETI's Texas ratepayers. The ALls recommend that
OPC's disallowance be denied.

          11. Project F3PCCDVDAT (Corporate Development Data Room)

          ETI requests the recovery of $6, 147 in ESI allocated costs for the corporate development data
room. The stated purpose of the data room is for due diligence reviews associated with Entergy
merger, acquisition, or diversification activities. The expenses associated with the corporate
development data room are for the gathering, collating, indexing, manning, and storage of data
during the due diligence reviews. 805 OPC contends that the costs incurred for the corporation's
analysis of merger, acquisition, and diversification opportunities should not be charged to ETI's
ratepayers.     Entergy has not acquired any utilities or utility operations that might produce
system-wide benefits to utility customers. 806 The $6, 147 of expenses for the corporate development
room are not reasonable and necessary expenses that ratepayers should shoulder and therefore,
according to OPC, recovery of these expenses should be disallowed.

          ETI responds that these costs are driven by each company's need for corporate services and
the costs, therefore, are appropriately allocated based on the level of service provided by ESI, which
is a reasonable proxy of each company's need for corporate services. 807 Further, just because
Entergy has not acquired any utility or utility operations in the recent past does not mean that these
are not reasonable and necessary costs. Entergy points out that as Dr. Szerszen noted in her
description of this project, it is not only for the acquisition of other operating units, but also used to
analyze diversification activities, which is a legitimate and reasonable undertaking by an integrated
utility and its parent company.

805
      OPC Ex. 3 (Szerszen Workpapers) at 394.
806
      OPC Ex. 1 (Szerszen Direct) at 45-46.
807
      ETI Ex. 69 (Tumminello Rebuttal) Ex. SBT-R-2 at 1.
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          The AU s believe that there are legitimate costs that may not on their face appear to be
properly allocable to entities such as ETI, but on closer examination they merit such an allocation.
These fall into that class. As Ms. Tumminello testified, the Corporate Development Data Room
includes costs not only related to mergers and acquisitions, but also diversification activities that
could benefit ETI ratepayers. Accordingly, they are properly allocated to ETI ratepayers.

          12. Project F3PPWET302 (SPO 2008 Winter Western Region)

          Dr. Szerszen argued that Project F3PPWET302 costs should be disregarded because they
were incurred during the 2008-2009 period, which is outside of the Test Year, and they are
nonrecurring. 808

          ETI witness Cicio explained that although this project was initiated prior to the Test Year, the
costs that the Company seeks to recover through this project code were expenses incurred during the
Test Year. These costs included development activities, requests for proposal issuance, bidders'
conferences, written and posted questions and answers from market participants and other interested
parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions
and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports,
and regulatory approvals, if necessary. He stated that these types of costs routinely encompass a
multi-year time frame, and the costs required to perform those activities, although associated with a
project that may have been initiated several years previously, are properly incurred over the life span
of the project. He also stated that they are recurring because they reflect the kinds and levels of
charges that would be expected to be incurred on an ongoing basis in association with request for
proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has
been involved in these types of solicitations since 2002. 809

          The AU s find that the costs captured by Project F3PPWET302 were incurred during the Test
Year and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly,
the AUs recommend the Commission approve their inclusion as requested by ETI.

808
      OPC Ex. 1 (Szerzen Direct) at 65.
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          13. Project F3PPWET308 (SPO Calpine PPA/Project Houston)

          With respect to Project F3PPWET308, which deals with the Calpine-Carville purchased
power agreement, Dr. Szerszen testified that the costs were either non-recurring, or rate case
expenses, or expenses that should have been charged to Louisiana ratepayers. 810

          ETI witness Cicio explained that these are recurring costs because they reflect the kinds and
levels of charges that the Company expects to incur on an ongoing basis in association with RFPs
managed by ESI on behalf of the Entergy Operating Companies; they were not incurred as part of
some rate case preparation and, therefore, are not a rate case expense that is otherwise sought for
recovery by ETI; and the costs in the matter are costs that were billed only to Texas and should not
have been billed to Louisiana because there is a separate project code that captures the Louisiana
costs that are billed to Louisiana. 811

          The AU s find that these costs, like those captured by Project F3PPWET302, are recurring in
that they represent the kinds and levels of costs routinely incurred on a year-in and year-out basis.
Further, the AU s find that the costs should not have been charged to Louisiana and that there existed
a separate project code to capture costs attributable to Louisiana. Accordingly, the AU s recommend
the Commission approve the inclusion of these costs as requested by ETI.

M.        Other Expenses Class

          Dr. Szerszen recommended disallowances in 11 project codes that are primarily within the
Other Expenses Class of affiliate costs: (1) F3PCSPETEI (Entergy-Tulane Energy Institute) for a
disallowance of $14,288; (2) F3PCC08500 (Executive VP, Operations) for a disallowance of $4, 117;
(3) F3PPBFMESI (ESI Function Migration Relocation) for a disallowance of $4,187;
(4) F3PPBFRESI (ESI Business Function Relocation) for a disallowance of $11,444;
(5) F3PPDRPESI (ESI Disaster Recovery Plan Charge) for a disallowance of $761;

809
      ETI Ex. 45 (Cicio Rebuttal) at 13-14.
810
      OPC Ex. I (Szerszen Direct) at 65-66.
811
      ETI Ex. 45 (Cicio Rebuttal) at 14-17.
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(6) F5PPBFMREL (Business Function Migration Employee) for a disallowance of $33,624;
(7) F5PPBFRREL (Business Function Relocation) for a disallowance of $15,624; (8) F5PPBFRSEV
(Business Function Relocation Severance) for a disallowance of $3,066; (9) F5PPDRPREL (Disaster
Recovery Plan Relocation) for a disallowance of $31,006; (10) F5PPETXRFI (2009 Texas Ike
Recovery Filing) for a disallowance of $441; and ( 11) F5PPKATRPT (Storm Cost Processing &
Review) for a disallowance of $929. 812

          1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT
             (Storm Cost Processing & Review)

          ETI agrees with Dr. Szerszen that the $14,288 amount she proposed to disallow for Project
F3PCSPETEI (Entergy-Tulane Energy Institute) can be treated as a donation, and so should be
removed from ETI' s cost of service. ETI also agrees with Dr. Szerszen to remove the $929 billed to
ETI under Project F5PPKATRPT (Storm Cost Processing & Review).                  The charges for the
remaining nine project codes, however, are contested.

          2. Project F3PCC08500 (Executive VP, Operations)

          As to Project F3PCC08500 (Executive VP Operations), Dr. Szerszen testified that an
asset-based allocator is not appropriate for these types of executive management costs, and there is
"no perceivable benefit" to ETI ratepayers for these types of allocated costs. 813

          Ms. Tumminello disagreed, stating that asset-based allocation methods are selected for
projects where the costs are driven by the oversight and stewardship of corporate assets of the
Entergy Companies including, but not limited to, services provided by financial management and
certain finance functions, among others. Each Entergy affiliate with assets on Entergy' s consolidated
balance sheet will be billed their proportionate share of the costs. The use of the Total Assets

812
      OPC Ex. 1 (Szerszen Direct) at 56, 67, and 72.
813
      Id. at 56-57.
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allocation method is, in fact, an appropriate method to allocate corporate-level corporate governance
type services. 814

          The A.Us find credible ETI's assertion that the costs captured by this project code are for
oversight and stewardship of the corporate assets of Entergy and, therefore, an asset-based allocator
is appropriate. Accordingly, the A.Us recommend the Commission reject OPC's challenge to the
inclusion of these costs.

          3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI
             Business Function Relocation), F3PPDRPESI (ESI Disaster Recovery Plan Charge),
             FSPPBFMREL (Business Function Migration Employee), FSPPBFRREL (Business
             Function Relocation), FSPPBFRSEV (Business Function Relocation Severance),
             FSPPDRPREL (Disaster Recovery Plan Relocation), and FSPPETXRFI (2009 Texas
             Ike Recovery Filing)

          The remaining eight of the project codes attributable to the Other Expenses Class all deal
with system restoration and business continuity resulting from Hurricane Katrina, with one applying
to Hurricane Ike. Dr. Szerszen testified that these costs should be disallowed because they should
not be considered to be system restoration costs or, if they are, citing to PURA§ 36.405, ETI should
have requested recovery of these costs in its first base rate following Hurricane Katrina (Docket
No. 34800). She also testified that ETI has not shown that Texas ratepayers benefited from these
costs. 815

          Ms. Tumminello testified that because of the magnitude of Hurricane Katrina, these expenses
were necessary so that activities in connection with the restoration of service and infrastructure
associated with electric power outages affecting customers could continue. These expenses relate to
critical functions needed to support storm restoration, such as business function relocation, and
provided a direct benefit to ratepayers. Ms. Tumminello stated that the costs in seven of these
project codes (F3PPBFMESI, F3PPBFRESI, F3PPDRPESI, F5PPBFMREL, F5PPBFRREL,
F5PPBFRSEV, and F5PPDRPREL) are being amortized over five years. Though these particular

814
      ETI Ex. 69 (Tumminello Rebuttal) at 9-10.
815
      OPC Ex. I (Szertrszen Direct) at 72, Schedule CAS-14.
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costs do not recur every year, they are a part of ETI' s normal utility operations given the service area
served by ETI, and do recur as necessary. 816

          As to Dr. Szerszen's legal conclusion that ETI is no longer authorized to recover Hurricane
Katrina costs, ETI argues that PURA § 36.405 does not restrict or even apply to ETI' s recovery of
such costs. That section deals with securitization of system restoration costs, but ETI did not seek to
securitize any Hurricane Katrina costs. Even so, argues ETI, if that section did apply, it does not
restrict system restoration cost recovery solely to Docket No. 34800; that is, the "next base rate
proceeding" following the hurricane. Instead, the final clause in PURA§ 36.405(a) states in full that
the Company is entitled to recover such costs "in its next base rate proceeding or through any other
proceeding authorized by Subchapter C or D." The same point applies to the Hurricane Ike costs;
while ETI did securitize the Hurricane Ike costs that it had incurred up to the date subject to that
securitization, it continued to incur costs in this test year for that storm restoration (in this case, $441
billed to the Ike-related project code). The costs in these projects were incurred during the test year
for this docket and could not have been recovered in an earlier docket. Moreover, ETI' s filing in this
docket was filed in accordance with PURA Subchapter C as a rate change proposed by a utility. As
such, ETI contends that it is entitled to recover these costs. 817

          To the AU s, the most important part of the argument is that ETI did not seek to avail itself of
PURA § 36.405 with respect to Hurricane Katrina costs. It is difficult to understand how that
section, which deals with securitization of hurricane costs, could block recovery when ETI did not
seek to securitize those costs. Similarly, with respect to Hurricane Ike costs, the $441 challenged by
Dr. Szerszen was not incurred until the Test Year and could not have been securitized.
Ms. Tumminello provided testimony that the costs were reasonable and necessary, representing a
part of ETI' s normal utility operations. Accordingly, the AU s recommend the Commission approve
inclusion of the costs.

816
      ETI Ex. 69 (Tumminello Rebuttal) atl6.
817
      ETI Initial Brief at 188-189.
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N.        Regulatory Services Class

          Dr. Szerszen challenged one project code that is primarily within the Regulatory Services
Class of affiliate costs: Project F3PPE9981S (Integrated Energy Management for ESI) for a
disallowance of $171,032.

          Dr. Szerszen testified that these costs were incurred for the implementation, coordination,
and promotion of demand side and supply side management and energy efficiency programs. But,
she stated, these costs should instead have been recovered through ETI' s Energy Efficiency Cost
Recovery Factor (EECRF) Rider and, as such, it is inappropriate to recover these costs through
affiliate billings in base rates. 818

          ETI witness May testified that recovery of these costs through base rates rather than through
the EECRF Rider is appropriate because these activities are not subject to an active ETI energy
efficiency program. These activities are more in the nature of general research and development
activities that help drive the Company's strategy on these topics, such as the timing of implementing
related programs. In the meantime, until these activities result in an actual program proposal, these
are legitimate known and measurable costs that the Company has incurred and should then be
recovered from retail customers. 819 At the hearing, Mr. May further explained that the costs in this
project code are labor costs that are "not really consistent" with the energy efficiency rule, but
instead involve "primarily costs of investigating" potential future activities (such as smart meters and
electric vehicle chargers) that are generally not consistent with the energy efficiency rider. 820 ETI
witness Considine also addresses this issue from a regulatory accounting perspective. He testified:
"Because these are not costs that must be, or are currently being recovered through the EECRF, they
are not double recovered and should be included in the Company's cost of service." 821 According to

818
      OPC Ex. 1 (Szerszen Direct) at 69-70.
819
      ETI Ex. 57 (May Rebuttal) at 30-31.
820
      Tr. at 1929-1930 and 1934-1935.
821
      ETI Ex. 46 (Considine Rebuttal) at 36.
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ETI, the costs in this project code, therefore, are not costs that should or can be recovered through
ETI's EECRF Rider.

          This is a close call. The Commission's Energy Efficiency Rule places limits on the amount
of research and development costs a utility may recover, 822 which supports the argument that the
costs should be included in the EECRF.            Further, it appears to the ALls that research and
development costs, by their very nature, do not relate to an active program, which negates many of
the arguments advanced by ETI witnesses May and Considine. In the end, the ALl s believe that
these costs should be included in the EECRF. Accordingly, the AUs recommend the Commission
disallow costs in the amount of $171,032 relating to Project F3PPE9981S.

0.        Retail Operations Class

          Dr. Szerszen challenged three project codes that are primarily within ETI' s Retail Operations
Class of affiliate costs: (1) F5PPICCIMG (ICC - "Image" Message) for a disallowance of $3,912;
(2) F3PPR56640 (Wholesale - EGS-TX) for a disallowance of $229,938; and (3) F3PPR56920
(Wholesale - All Jurisdictions) for a disallowance of $333.

          1. Project F5PPICCIMG (ICC-"Image" Message)

          Project Code F5PPICCIMG (ICC-"lmage" Message) is one of the project codes that
Dr. Szerszen testified should be disallowed because ETI is a monopoly and Texas ratepayers should
not have to pay for corporate image costs. 823

          Ms. Tumminello testified that the costs are for advertising activities that are of a good will or
institutional nature, which is primarily designed to improve the image of the utility or the industry,
including advertisement which inform the public concerning matters affecting the Company's
operations, such as, the costs of providing service, the Company's efforts to improve the quality of
service, the Company's efforts to improve and protect the environment. According to FERC, such

822
      P.U.C. SUBST. R. 25.181(i).
823
      OPC Ex. 1 (Szerszen Direct) at 66.
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costs are properly includable in FERC Account 930.1 and are recoverable.                  According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs. 824

          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did provide the testimony of Ms. Tumminello, which
confirms that the costs are properly includable in FERC Account 930.1 and are, therefore,
recoverable. In the end, the weight of the evidence is in ETI's favor. The AUs recommend the
Commission reject OPC' s contention that costs covered by these project codes are not recoverable.

          2. Projects F3PPR56640 (Wholesale • EGS-TX) and F3PPR56920 (Wholesale • All
             Jurisdictions)

          As to Projects F3PPR56640 and F3PPR56920, Dr. Szerszen stated that these costs are
associated with assisting ETI' s wholesale customers in evaluating alternative energy supply and
demand options and that ETI' s retail customers should not be charged for expenses associated with
ETI' s wholesale customers. 825

          ETI witness Stokes noted that ETI has allocated costs to its single large wholesale customer
through its jurisdictional allocation in this rate case and, therefore, to disallow the costs in these two
project codes would essentially result in a double disallowance of those costs. She also explained
that the costs were properly allocable to ETI (keeping in mind that ETI then allocated costs to this
customer) as reasonable and necessary due to the need to have staff on hand to handle contract
negotiations and the like with this large wholesale customer. 826

          The AU s are persuaded by ETI' s argument that disallowing the costs associated with
Projects F3PPR56640 and F3PPR56920, which are already allocated to ETI' s single large wholesale

824
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
825
      OPC Ex. 1 (Szerszen Direct) at 73.
826
      ETI Ex. 66 (Stokes Rebuttal) at 6-9.
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customer through its jurisdictional allocation, would constitute a double disallowance. Accordingly,
the Alls recommend the Commission reject OPC's challenge to these costs.

P.        Supply Chain Class

          Dr. Szerszen challenged two project codes that are primarily within the Supply Chain Class:
(1) F3PPH54075 (Business Development-TX) for adisallowance of$1,888; and (2) F5PCZSDEPT
(Supervision & Support - Supply) for a disallowance of $146. Dr. Szerszen claimed. the costs
associated with these project codes should be disallowed because ETI is a monopoly and Texas
ratepayers should not have to pay for corporate image costs. 827

          Ms. Tumminello testified that the costs are for advertising activities that are of a good will or
institutional nature, which is primarily designed to improve the image of the utility or the industry,
including advertisement which inform the public concerning matters affecting the Company's
operations, such as, the costs of providing service, the Company's efforts to improve the quality of
service, the Company's efforts to improve and protect the environment, etc. According to FERC,
such costs are properly includable in FERC Account 930.1 and are recoverable. According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs. 828

          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly. ETI did
provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in
FERC Account 930.1 and are, therefore, recoverable. The AUs go with the weight of the evidence,
which is in ETI's favor. The Al.Js recommend the Commission reject OPC's contention that costs
covered by these project codes are not recoverable.

827
      OPC Ex. 1 (Szerszen Direct) at 66.
828
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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Q.        Transmission and Distribution Support Class

          Dr. Szerszen challenged three project codes that are included within the Company's
Transmission and Distribution Support Class of affiliate costs: (1) F3PCT53130 (Operations
Manager, Claims Management) for a disallowance of $42,287.50; (2) F3PCTDAMAG (Damage
Claims Of Entergy Property) for a disallowance of $5,555; and (3) F3PCTPUBLC (Public Claims)
for a disallowance of $3,968. Dr. Szerszen's rationale for disallowing 50 percent of the costs in each
of these codes is the same. She believes that ETI' s property damage and workers compensation
claims should be direct billed instead of allocated through a customer count-based allocator;
managerial and supervisory costs should be allocated to the jurisdictions based on the jurisdictional
direct charges; and the Company has not met its burden of proof as to these charges. 829

          Ms. Tumminello addressed Project F3PCT53130, stating that workers' compensation claims
are tracked by jurisdiction as Dr. Szerszen suggested, and are the basis for billing method
COMCLAIM. Project F3PCTWCOMP is used to capture the costs of workers' compensation
claims, and bills to both regulated and non-regulated affiliates. Project F3PCT53130 captures costs
that are primarily for the oversight of the Entergy Companies' Claims Management organization as it
relates to property damage and liability. These services benefit only the companies that serve retail
electric and gas customers. Since only the regulated utility operating companies (and not the non-
regulated companies) serve retail customers, it is appropriate to bill these costs to the regulated
companies based on their pro-rata share of total customers. 830

          Projects F3PCTDAMAG and F3PCTPUBLC are addressed by ETI witness Corkran. With
respect to Project F3PCTDAMAG, Mr. Corkran stated that the costs associated with this project are
associated with the Public Claims employees in the Claims Management Organization. Those
employees pursue the recovery of claims allowed by law when the public inflicts damage to
Company property. The costs of this service are allocated among all of Entergy's Operating
Companies through billing method CUSTEGOP, which allocates costs based on the number of

829
      OPC Exhibit No. l (Szerszen Direct) at 79-80.
830
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 10.
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customers in each Operating Company. Dr. Szerszen claimed that the affiliate costs associated with
pursuing those claims should be directly charged to each Entergy Operating Company based on the
extent to which each claim pertains to the Operating Company instead of generally allocating the
costs to all utility customers. Mr. Corkran testified that the allocation methodology is appropriate
because the Public Claims employees provide knowledgeable, centralized, and consistent pursuit of
damage claims. The actual monies recovered for damage to ETI' s property are returned to ETI
ratepayers as credits against the cost of repairing those damaged facilities, i.e., the recoveries are not
allocated pursuant to CUSTEGOP. Only the Public Claims employees' time and overheads are
allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time
spent by Public Claims employees in pursuing the recovery of claims is driven by the number of gas
and electric customers in each Operating Company. 831

            With respect to Project F3PCTPUBLC, Mr. Corkran stated that the costs associated with this
project are related to Public and Auto Liability employees in the Claims Management Organization.
These employees pursue the resolution and settlement of damage claims made against the Operating
Companies in a timely and fair manner through denials, negotiations, and payments. Such claims
include allegations of damaged appliances due to voltage fluctuation, food loss due to power outages,
and damage caused by Company vehicles (e.g., mailboxes, fence posts, and automobiles). This is an
important process that ensures that only warranted and justifiable claims are paid. The CUSTEGOP
billing method is appropriate because the Public and Auto Liability employees provide
knowledgeable, centralized, and consistent resolution of damage claims. The actual payments
associated with ETI public damage claims are charged to ETI through the use of other project codes.
Only the Public and Auto Liability employees' time and overheads are allocated pursuant to
CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public and Auto
Liability employees in processing claims is driven by the number of gas and electric customers in
each Operating Company. 832

831
      ETI Ex. 48 (Corkran Rebuttal) at 13-15.
832   Id.
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            The explanations that ETI provides for the charges captured by these project codes and the
method of allocation employed makes sense to the AUs. In a large organization, it is necessary to
have a group of people to process claims efficiently so that economies of scale can be realized; that is
what ETI is doing with these project codes. These costs benefit all companies within the Entergy
umbrella (or within the regulated entities portion as noted), so the allocation methodology employed
is appropriate. The ALls recommend the Commission reject OPC's challenge to the recovery of
these costs.

R.          Tax Services Class

            Dr. Szerszen proposed a 25 percent ($221,007) disallowance of costs billed to ETI from a
single project code in this Tax Services Class: Project Code F3PCF10445 (Entergy Consolidated Tax
Services). The costs in this project were incurred in the preparation, research, and other costs
associated with Entergy's consolidated tax return. Dr. Szerszen testified that an assets-based
allocator is not appropriate for these costs and that the costs in the project should instead be directly
billed to each affiliate based on the time spent on preparing that affiliate' s income and expense
data. 833

            Company witness Galbraith, who sponsors ETI' s Tax Services Class, stated that Dr. Szerszen
apparently believes that all costs associated with the preparation of Entergy' s consolidated tax return
are captured by this project code and are allocated, when they should be direct-billed. Most of the
costs associated with preparation of Entergy' s consolidated tax return, according to Ms. Galbraith,
are assigned to other project codes and are direct billed. Ms. Galbraith then explained that:
(1) 56 percent of the time that Tax Services spent on the Entergy consolidated tax return were direct
billed through other project codes to the affiliates; (2) the project code also captures costs for tax
research (both federal and state and local), monthly closing activities not specific to one legal entity,
tax training that is not jurisdiction specific, compliance with file retention policy, and administration
staff time; and (3) why the assets-based allocator is the best method for allocating these departmental

833
      OPC Ex. I (Szerszen Direct) at 63.
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costs. According to Ms. Galbraith, the costs captured by this code are not susceptible to direct
billing. 834

          The AlJs find that Dr. Szerszen did fail to consider that most of the costs of preparing
Entergy's tax return are direct billed and that the costs covered by this project code are not
susceptible to such a billing, which is why they are allocated. The AlJs, therefore, recommend the
Commission reject OPC' s challenge to ETI' s allocation of these costs.

S.        Transmission Operations Class

          Dr. Szerszen challenged three project codes that are primarily within the Transmission
Operations Class: (1) F3PPTDHY19 (Dept. of Justice Investigations) for a disallowance of $765;
(2) F3PPTREORG (Transmission Re-Organization) for a disallowance of $3,661; and
(3) F3PPF30211 (ESI Transmission Bldg (Reclassification)) for a disallowance of $229,991. 835

          Dr. Szerszen addressed Project F3PPTREORG (Transmission-Reorganization) and testified
that costs covered by this project were incurred in 2009 and 2010 and, therefore, are not recurring. 836
Ms. Tumminello responds that, while these particular costs do not recur every year, they are
representative of normal recurring utility operations and do recur as necessary and, as such, they
should not be disallowed. 837

          Dr. Szerszen testified that Project F3PPF30211 (ESI Transmission Bldg.) captures interest
costs after the ESI transmission building was placed in service. She contends that the costs are
reclassified pre-Test Year payments and post-Test Year interest costs that are not known and
measureable. 838 Ms. Tumminello testified that Dr. Szerszen has misconstrued accounting entries.

834
      ETI Ex. 26 (Galbraith Direct) at 10-12.
835
    Project F3PPTDHY 19 (Dept. of Justice Investigations) was discussed in Section VIII.L. (Legal Services
Class) and will not be repeated here
836
      OPC Ex. l (Szerszen Direct) at 54, Schedule CAS-8.
837
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 1.
838
      OPC Ex. 1 (Szerszen Direct) at 71.
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She explains that these charges capture 12 months of interest payments and the annual bond fee
incurred only during the Test Year. 839

          The AUs find that the costs associated with Project F3PPTREORG are representative of
costs that recur every year and should not be disallowed. It appears to the AU s that Dr. Szerszen did
misconstrue accounting entries in preparing her analysis of Project F3PPF3021 land that the charges
in that project capture fees paid during the Test Year. Accordingly, the ALls recommend that OPC's
proposed disallowance be denied.

T.        Treasury Operations Class

          Dr. Szerszen challenged three project codes that are primarily within the Treasury Operations
Class: (1) F5PCZZI07P (Directors & Officers (EIM)) for a disallowance of $14,483;
(2) F3PCF25300 (Daily Cash Mgt Activities) for a disallowance of $7,286; and (3) F3PCF26022
(Financing & Short Term Funding) for a disallowance of $96,700.

          With respect to Project F5PCZZ107P (Directors & Officers (EIM)), Dr. Szerszen testified
that the directors and officers liability insurance subject to this project code is primarily aimed at
benefiting shareholders, rather than ratepayers and, because ETI does not manage ESI' s operations, it
should not be responsible for indemnifying against shareholder lawsuits. 840

          ETI witness McNeal stated that ESI provides essential administrative and operational
services to ETI on a daily basis. To do this, it must employ (and retain) qualified officers and
directors. These individuals must be assured that they can make reasoned decisions without fear of
personal liability and the manner to provide them this assurance is to purchase director's and
officer's liability insurance. Because ETI benefits from the services provided by the officers and

839
      ETI Ex. 69 (Tumminello Rebuttal) at 15. See also Ex. SBT-R-5.
840
      OPC Ex. 1 (Szerszen Direct) at 59.
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directors, ETI argues, it is appropriate to allocate a portion of the cost of the director's and officer's
liability insurance to ETI. 841

          Dr. Szerszen addressed Projects F3PCF25300 (Daily Cash Mgt Activities) and F3PCF26022
(Financing & Short Term Funding), contending that these projects are duplicative of ETI-specific
financing and cash management activities; that these costs should be borne by Entergy shareholders;
and that the bank accounts-based and level of service-based allocators applicable to this projects are
not appropriate. 842

          ETI responds that Project F3PCF25300 captures costs for activities performed by the Cash
Management Department for work associated with maintaining bank relationships, bank fee analysis,
administrative of bank systems and controls, and all other banking and cash management activities
that are general in nature. These are not specific to any one company, but are applicable to all of the
companies within the umbrella of the Entergy corporate family. There are Company-specific
activities that are charged directly to ETI under different project codes, and this constitutes the
majority of financing and cash management activities during the Test Year.                            For
Project F3PCF25300, the costs are driven by cash management products and services delivered to all
the Entergy companies. Because the number of transactions executed on behalf of each Entergy
company is directly related to the number of bank accounts by company irrespective of account size,
billing method BNKACCTA, which allocates costs based on the number of open bank accounts is,
according to ETI, the appropriate method to allocate the costs of these services. 843

          With respect to Project F3PCF26022, ETI explains that the project code captures costs for
managing Entergy companies' liability portfolios comprised of Entergy company securities, bank
lines, and project financings. The work is performed for the benefit of all companies under the
Entergy corporate umbrella, not just ETI and is not duplicative of services performed for ETI. When
work is performed by ESI personnel that relates specifically to ETI, then ETI is charged directly

841
      ETI Ex. 61 (McNeal Rebuttal) at 7-8.
842
      OPC Ex. l (Szerszen Direct) at 74-75, Ex. CAS-15.
843
      ETI Ex. 61 (McNeal Rebuttal) at 3-6; Tr. at 546.
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under a different project code. The services include analyzing and supporting general capital
structure policy, developing and analyzing general financial policies, investigating and evaluating
financing options generally that might prove beneficial for any or all Entergy companies, including
ETI, and facilitating ongoing administration related to all Entergy Operating Company financings.
Accordingly, ETI argues that it is appropriate to allocate a share of those costs to ETI. The costs of
this project are driven by the level of service needed to complete the project or activity. Allocator
LVSVCAL allocates costs based upon the overall service level ofESI. This allocation is appropriate
because ESI is providing the service and no one Operating Company alone benefits from the services
provided under this project code. 844

         OPC appears to have taken too narrow a view with respect to these project codes. First, it
appears that where services are performed solely for ETI, they are charged to ETI through specific
project codes. The project codes that OPC challenges are for company-wide services that are
partially allocated to ETI. It is logical to assume that a certain level of services can be performed
more efficiently at a company-wide level and that Texas ratepayers will benefit by paying only the
allocated portion of those costs, as is done in these cases. The allocators chosen by ETI appear to
reasonably reflect the cost-causation. Therefore, the AUs recommend that OPC's challenge be
rejected.

U.       Utility and Executive Management Class

         OPC challenges five project codes that are primarily within the Utility & Executive
Management Class: (1) F3PPCCSO 10 (Climate Consulting Services) for a disallowance of $19,821;
(2) F3PCCPM001 (Corporate Performance Management) for a disallowance of $173,867;
(3) F3PCC31255 (Operations-Office of the CEO) foradisallowanceof$372,919; (4) F3PPCA0001
(Chief Administrative Officer) for a disallowance of $177,156; and (5) F3PPC00001 (Chief
Operating Officer) for a disallowance of $74,485.

844
      ETI Ex. 61 (McNeal Rebuttal) at 2-3; Tr. at 547-548.
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          As to the first, Project F3PPCCS010 (Climate Counseling Services), Dr. Szerszen testified
that these costs are incurred for the development of company-wide environmental policies,
procedures, and programs; that expenses are improperly allocated to the subsidiaries based on each
company's fossil operating capacity; and, as a result, the non-regulated affiliates are not allocated any
environmental initiative expenses. She therefore recommended that 50 percent of this project's costs
be disallowed. 845

          ETI witness Stokes addressed Dr. Szerszen' s challenge to this project. Ms. Stokes explained
that although nuclear-related environmental projects are being pursued, they are not being pursued
using the project code referenced by Dr. Szerszen in her challenge. The costs for non-regulated
affiliates are charged to projects not included in ETI' s affiliate costs in this case. Non-regulated
affiliates use project codes specific to their businesses to maintain a separation of costs between
regulated and non-regulated Entergy subsidiaries. 846

          For the remaining four project codes in this class, Dr. Szerszen stated that executive
management is primarily concerned with overall corporate functions rather than issues for any one
specific subsidiary, and there is no relationship between an assets-based allocator and executive
management. 847

          ETI responds to these arguments by stating that the functions covered by these project codes
relate to the oversight of all system operations and the stewardship of corporate assets and that
because ETI is part of a corporate group, the allocated charges associated with these services are
relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based
allocator is appropriate because it reflects the cause of the costs incurred, in that, services provided
relate to the stewardship of all the corporation's assets. 848

845
      OPC Ex. 1 (Szerszen Direct) at 62.
846
      ETI Ex. 66 (Stokes Rebuttal) at 5.
847
      OPC Ex. l (Szerszen Direct) at 56, 60.
848
      ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
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            A corporation cannot function without executives, who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class
costs that she challenges are reasonable and necessary costs that are allocated to ETI based on a
logical allocator - the assets the executives manage. The ALT s recommend that OPC' s challenge be
rejected.

      IX.    JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order
                                    Issue No. 13]

            Jurisdictional cost allocation involves the proper method for allocating production costs
between ETI' s Texas retail customers and its wholesale customers, which are subject to FERC
jurisdiction. During the Test Year, ETI provided electric service to retail customers and to three
wholesale customers-including ETEC-under service agreements and rates approved by FERC.
ETEC is a partial requirements customer, and it will be ETI's only wholesale customer during the
Rate Year. ETI estimated its cost of serving wholesale customers in a jurisdictional separation study
that split ETI' s cost of service between retail and the wholesale jurisdictions. 849

            To calculate the wholesale cost allocation factor, ETI proposed the use of 150 MW for the
wholesale load. This results in a retail production demand allocation factor of 95.3838 percent. The
150-MW load represents the contractual minimum amount of capacity for which ETEC is obligated
to pay under its partial requirements agreement. No party contests this aspect of ETI' s proposed
allocation of costs between retail and wholesale customers. 850

            However, Cities contest the type of allocation methodology used to assign demand-related
(fixed) production costs to each jurisdiction. In this proceeding, ETI used the A&E 4CP allocation
method. Although this is the same methodology ETI used in this proceeding's class cost-of-service

849
      Cities Ex. 4 (Goins Direct) at 4.
850
    ETI Ex. 7 (May Direct) at 23-24. Ms. Talkington used the 150 MW number sponsored by Mr. May, and
the associated energy use, to calculate the jurisdictional allocation factor. ETI Ex. 22 (Talkington Direct)
at 11-12.
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PUC DOCKET NO. 39896

study (to assign demand-related production costs to each retail customer class), ETI used a different
methodology - 12 Coincident Peak (12CP) - in its last rate case to assign costs between
jurisdictions. 851

A.        A&E4CP

          Kroger witness Kevin C. Higgins explained the A&E 4CP method:

          [T]he Average and Excess Demand method uses an average demand or total energy
          allocator to allocate that portion of the utility's generating capacity that would be
          needed if all customers used energy at a constant 100 percent load factor. The cost of
          capacity above average demand is then allocated in proportion to each class's excess
          demand, where excess demand is measured as the difference between each class's
          individual peak demand and its average demand. In this manner, the incremental
          amount of production plant that is required to meet loads that are above average
          demand is assigned to the users who create the need for the additional capacity....
          the A&E/4CP variant . . . uses 4 CP to measure excess demand, whereas the
          conventional version uses class non-coincident peak ....852

          ETI witness Myra L. Talkington also explained that the A&E 4CP method, noting that ETI' s
coincident peak demand is measured for the months of June through September. Ms. Talkington
recommends the A&E 4CP allocation because it "reasonably reflects the mix of the Company's
customers and their respective electrical load characteristics and the relative cost incurred to serve
such loads." 853 She also believes this allocation methodology provides a reasonable balance between
the contribution to the system peak and energy requirements. 854

          As noted above, ETI's use of A&E 4CP is a change from the 12CP methodology it used
when it operated within two states. Ms. Talkington testified that 12CP was appropriate in the past
because System Agreement costs were allocated between Entergy Operating Companies using 12CP.
The Texas retail portion of the production costs were then allocated between the retail classes using

851
      Cities Ex. 4 (Goins Direct) at 10.
852
      Kroger Ex. 2 (Higgins Cross Rebuttal) at 3 (footnotes deleted).
853
      ETI Ex. 23 (Talkington Direct) at 6; OPC Ex. 6 (Benedict Direct) at 17.
854
      ETI Ex. 23 (Talkington Direct) at 6.
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PUC DOCKET NO. 39896

the A&E 4CP methodology (as ETI is doing in this case). However, according to Ms. Talkington,
now that ETI operates in only one state, no jurisdictional allocation among states is necessary;
therefore, only one allocation methodology, i.e., A&E 4CP, should be used to allocate production
costs between the retail classes and the wholesale jurisdiction. Ms. Talkington testified that the A&E
4CP methodology factors in year-round demand through the average and excess function and also
                                                                        855
matches the allocator used to allocate costs within the retail class.

          Cities opposes the use of A&E 4CP and suggest a 12CP methodology is preferable.
Commission Staff does not oppose ETI' s use of A&E 4CP. No other party takes a position on this
issue.

B.        12CP

          Thel2CP methodology allocates production capacity costs in proportion to each class's
demands that occur on the date and time of ETI's system peak in each of the 12 months. 856 Cities
believe it is more appropriate for ETI to allocate fixed production costs between the wholesale
customers and Texas retail customers using 12CP. Cities witness Dennis W. Goins testified that the
12CP approach is consistent with the cost-of-service approach FERC typically uses to allocate
demand-related production costs reflected in wholesale rate schedules, and it is consistent with the
assignment of MSS-1 costs (as well as MSS-2 transmission costs) to ETI under the Entergy System
Agreement. Dr. Goins reviewed ETI' s Rate Year purchased power capacity costs month by month.
He determined that ETI' s heavy reliance on capacity purchases to serve retail and wholesale load,
and the relative stability of those projected monthly purchased power capacity costs, suggest that the
12CP method should properly split ETI' s demand-related production costs between the Texas retail
and wholesale jurisdictions.857

855
      ETI Ex. 67 (Talkington Rebuttal) at 6-7.
856
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 26.
857
      Cities Ex. 4 (Goins Direct) at 10-12.
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PUC DOCKET NO. 39896

          Dr. Goins calculated Test Year 12CP allocation factors for the Texas retail and wholesale
jurisdictions, and provided them to Cities witness Karl Nalepa for inclusion in his jurisdictional
separation study. He determined the following: 858

                         Jurisdiction          A&E4CP           12CP
                      Texas Retail              95.3838%         94.6208%
                      Wholesale                  4.6162%          5.7923%
                      Total                         100%              100%

          In making this calculation, Dr. Goins used a loss-adjusted 150 MW (ETEC's monthly
billing MW) as a proxy for the 12 monthly CPs. In his view, the 150 MW is indicative of ETI' s
capacity obligations to ETEC, and it reflects known and measurable changes compared to test-year
wholesale CPs (which would include CPs for wholesale customers that ETI no longer serves). 859

          Cities point out that ETI previously allocated production costs to the wholesale jurisdiction
on a 12CP basis. ETI first requested that the Commission change the 12CP method in Docket
No. 37744. 860 According to Cities, ETI's request to change the 12CP methodology in Docket
No. 37744 is significant because ETI's wholesale load consisted of Brazos Electric Cooperative, Inc.
(Brazos) and ETEC. The Brazos contract assigned Brazos' share of ETI' s production costs based
upon a 12CP allocator. Thus, contends Cities, all costs that would have been over-allocated to retail
customers would have been pocketed by ETI (if the 12CP allocator had changed). Cities argue that
ETI's request to deviate from its approved 12CP allocator will result in retail customers subsidizing
production costs.        Dr. Goins calculated that the 12CP allocation factor for ETI's wholesale
jurisdiction is approximately 5 .3 8 percent versus 4.62 percent under the A&E 4CP method. 861 Cities
conclude that retail customers will subsidize the difference between the two allocators, which is

858
      Cities Ex. 4 (Goins Direct) at 12.
859
      Cities Ex. 4 (Goins Direct) at 10-12.
860
     The parties in that docket stipulated the majority of issues in the case, including issues relating to
jurisdictional allocation.
861
      Cities Ex. 4 (Goins Direct) at l 1-12.
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PUC DOCKET NO. 39896

0.76 percent. Because the allocation is applied to all production costs, including purchased power
capacity costs, the 0.76 percent difference is significant, contend Cities.

           According to ETI, Cities' arguments are based on a non-existent situation-the provision of
service to Brazos-and should be rejected. The AUs acknowledge that ETI is no longer serving
Brazos. Dr. Goins noted such in his testimony. Rather, the basis for his recommendation was:
(1) the 12CP approach is consistent with FERC's wholesale rate allocation; (2) the 12CP method is
used to derive each Entergy Operating Company's load responsibility ratio and share of monthly
MSS-1 and MSS-2 charges; and (3) ETI' s purchased power capacity costs do not vary significantly
month to month. Although Ms. Talkington understood that the A&E 4CP methodology is the same
one used to allocate production costs between classes, TIEC witness Pollock noted that it is often not
appropriate to use the same allocation method for both jurisdictional and class allocations. He noted
that, in jurisdictional separation, allocations are between retail and wholesale entities, with wholesale
subject to FERC regulation. 862 ETI did not fully explain why A&E 4CP is the best methodology for
allocation production costs between the retail and wholesale jurisdictions.             Dr. Goins' and
Mr. Pollock's testimonies were ultimately more persuasive on this issue. Accordingly, the AUs
recommend the use of 12CP to allocate capacity-related production costs between the retail and
wholesale jurisdictions.

      X.   CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary
                                Order Issue No. 1]

           ETI witness Talkington testified regarding the allocation methods for each of the major
function/classification cost categories used in the Company's retail class cost-of-service study.
Ms. Talkington also sponsors ETI's proposed rate design. Contested issues are set out below.

862
   TIEC Ex. 3 (Pollock Cross Rebuttal) at 29. The ALJs acknowledge that Mr. Pollock does not contest ETI's
use of the A&E 4CP jurisdictional allocation methodology-rather, his testimony was explaining why 12CP is
not appropriate as an allocator among the different customer classes.
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PUC DOCKET NO. 39896

A.        Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19]

          The Legislature has established a goal for the installation of an additional 5,000 MW of
generating capacity from renewable energy technology. It also set out annual goals for electric
utilities to meet on a cumulative basis in order to encourage the development of renewable energy
generation in Texas: A utility may meet its annual goals by installing generation, by purchasing
capacity based on renewable energy technology, or by purchasing sufficient renewable energy credits
(RECs). 863

          1. ETl's Proposed Cost Recovery

          Staff witness William B. Abbott explained that the Company currently recovers its REC costs
through base rates. Each credit represents one megawatt-hour (MWh) of renewable energy that
meets certain criteria set forth in P.U.C. SUBST. R. 25.l 73(e), and these credits can be traded among
participants in the Texas market. ETI proposes to remove these costs from base rates and implement
a REC Rider to recover its projected REC costs. After the initial rider is established, the REC Rider
would be reset annually to recover projected REC costs for the upcoming year, adjusted by any past
over- or under-recovery and any revenue-related expenses. 864 With the introduction of the REC
Rider, ETI would withdraw its current Renewable Portfolio Standard Calculation Opt-Out Credit
Rider, which provides a credit to offset the base rate REC costs for certain customers who are
exempt from paying REC costs. These customers would instead be exempt from charges under the
proposed REC Rider. 865

          ETI suggests that a rider is necessary because the level of REC costs incurred from year to
year is not known, and the cots are unknowable and very volatile. ETI witness Heather G. LeBlanc

863
      PURA §39.904(a) and (b).
864
      See ETI Ex. 31 (LeBlanc Direct) at 26.
865
      Staff Ex. 7 (Abbott Direct) at 11-12.
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PUC DOCKET NO. 39896

testified that certain customers can opt out, and a rider is the most efficient manner to administer
such opt out. 866

          Initially, ETI based its rates for the proposed rider on the Company's Test Year renewable
energy credit costs, which were incurred on a Texas retail basis for the 12 months ending June 30,
2011. ETI requested $623,303 and, after applying the revenue-related expense factor of 1.01307,
proposed a revenue requirement of $631,450. 867 In rebuttal testimony, Ms. LeBlanc stated that the
Company's proposal should be updated to reflect the most current data available. She stated that
"events" since the Company's initial filing in November 2011 caused costs for the Company to
increase. 868 She calculated an updated amount of $1,145,043, which, when the revenue-related
expense factor is applied, results in an updated revenue requirement of $1,160,008. 869 She believes
that the updated amounts further support the Company's position that REC costs are volatile.

          2. Opposition to ETl's Proposal

          Cities, OPC, State Agencies, and Commission Staff oppose ETI' s proposed REC Rider.

          State Agencies argue that ETI's proposed REC Rider should be rejected because it deviates
from the Commission's ratemaking policies and is inconsistent with PURA State Agencies witness
Kit Pevoto testified that the proposed rider is not appropriate because: (1) the rider is piecemeal
ratemaking, which deviates from the Commission's traditional ratemaking policies and is
inconsistent with PURA; (2) the reconciliation (true-up) process in the proposed tariff is not
specifically provided for by PURA or PUC rule, or required to implement the REC process; (3) the
redetermination of rates in the proposed annual filings would be based on projected or estimated
costs, rather than historical test year costs; which is not in compliance with PURA or the
Commission's rules; and (4) ETI has not justified the need to have a rate recovery for REC costs

866
      ETI Ex. 31 (LeBlanc Direct) at 25.
867
      Id. at 24. This amount is then divided by all non-transmission level kWh sales.
868
      ETI Ex. 55 (LeBlanc Rebuttal) at l 0-11.
869
      Id. at 11. This amount is then divided by all non-transmission level kWh sales.
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PUC DOCKET NO. 39896

outside of the traditional PURA base rate recovery. Ms. Pevoto explained that the traditional test
year cost of service ratemaking process, including regulatory lag, helps to match costs and revenues
and to provide incentives that balance the utility's and its customers' interests. The proposed REC
rider deviates from the traditional PURA rate-setting because it allows the Company to reset its rates
automatically each year without going through a comprehensive rate proceeding. In her view, the
rider would eliminate the regulatory lag incentive for ETI to prudently manage these costs because
the rider allows for annual cost recovery adjustments. Ms. Pevoto observed that various provisions
in PURA authorize riders for collection of other expenses, but no such provision exists for recovery
of REC expenses, even though the Legislature mandated that utilities be responsible for a certain
level of REC MWs. And she noted that if ETI's REC expenses increase due to increases in total
                                                                                                  870
REC MW requirements, ETI can request to include those increased costs in a future rate case.

          In reference to Ms. LeBlanc's rebuttal testimony that "events" caused ETI's REC costs to
increase, State Agencies contend that ETI may have paid more for RECs during the Test Year
because it contacted suppliers only after the REC requirement was mandated. ETI acknowledged
that RECs were in the $1.10 to $1.25 range at the beginning of the year and then appreciated to over
$2.00 and peaked out at $2.55 in the first quarter of 2012. Moreover, one of the largest REC
suppliers unexpectedly withdrew its offers in March of 2011, which also led to price increases.
March 31 is the end of the compliance period, and the deadline may increase the volume of
purchases, which can add to price increases. 871 State Agencies note that ETI did not participate in
the competitive REC market until February 2012 and bought its RECs near the peak price. State
Agencies contend that only Test Year costs of $623,303 should be included in base rates.

          Cities witness Karl Nalepa also opposed the REC Rider. He testified that the Commission
should not permit ETI to single out REC costs from base rates because it presented no evidence that
these costs should be treated differently than they are now. He added that RECs are not related to
fuel so much as they are related to retail sales and plant output. In his opinion, the Test Year amount

870
      State Agencies Ex. 2 (Pevoto Direct) at 6, 8-1 l.
871
      State Agencies Ex. 12, RFI.
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PUC DOCKET NO. 39896

for REC of $633,985 should be included in base rates. 872 Cities witness James Z. Brazell also
testified that ETI currently recovers a large portion of its revenues through non-fuel piecemeal riders.
While he believes some riders are necessary and appropriate, ETI' s general movement of cost
recovery from base rates to riders (as evidenced in this proceeding) is inconsistent with PURA and
the prohibition against piecemeal ratemaking. 873

          OPC also opposed ETI' s proposed REC Rider on the basis that it constitutes piecemeal
ratemaking. OPC witness Nathan A. Benedict noted that in Project No. 35628, the Commission
rejected alternative mechanisms for the recovery of REC costs but reserved the right to consider the
issue at a later date. 874 He stressed that, when rejecting alternative recovery mechanisms for REC
costs, the Commission recognized that REC costs are variable, that the purchase of RECs is
mandated by law, and that certain customers can opt out of the Renewable Portfolio Standard
program. Thus, in Mr. Benedict's view, the Commission has already rejected the arguments
advanced by ETI here. He added that ETI did not indicate a negative and substantial impact as a
result of transmission customers opting out of the Renewable Portfolio Standard program, and ETI
appears to be currently administering the program effectively without REC Rider. In short,
Mr. Benedict concluded that costs related to renewable energy credits should be recovered through
base rates, and ETI's current opt-out rider should continue as the vehicle for ETI to handle
transmission-level opt-outs. 875

          Commission Staff also opposes ETI' s request, stating that it amounts to unauthorized
piecemeal ratemaking that should be disallowed. In Staffs view, the existing opt-out rider should be
maintained but updated to reflect the test year data used to set the ETI' s base rates. Because ETI' s

872
   Cities Ex. 6 (Nalepa Direct) at 30-32. Mr. Nalepa' s figure of $633,985 differs from tliat the figure of
$623,303 found in ETI's testimony at ETI Ex. 31 (LeBlanc Direct) at 24 and State Ex. 9.
873
      Cities Ex. l (Brazell Direct) at 14-16.
874
    OPC Ex. 6 (Benedict Direct) at Ex. NAB-8, Project No. 35628, Rulemaking Relating to Industrial
Customer Opt-Out of Renewable Portfolio Standard, Order at 6 (December 4, 2008).
875
    OPC Ex. 6 (Benedict Direct) at 37-41. ETI currently has a Renewable Portfolio Standard Calculation
Opt-Out Credit Rider to credit REC costs collected in base rates from transmission level customers who have
opted out of the program.
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proposed rider would include a true-up provision that would guarantee recovery of all of its REC
costs, Staff witness Abbott testified that it would violate PURA § 36.051, which provides the utility
a reasonable opportunity to earn a reasonable return on invested capital but does not guarantee full
recovery of all costs. Mr. Abbott acknowledged that the Legislature has authorized the recovery of
certain specific costs outside of base rates, but no such authorization exists for the recovery of REC
costs. 876

          In addition, Mr. Abbott criticized the proposed REC rider because in the future it would
allow prospective recovery of estimated REC costs. He believed that such an arrangement would
eliminate any regulatory lag and thus eliminate any incentive for ETI to minimize the costs of
purchasing the required RECs. 877 Mr. Abbott also pointed out that the proposed rider contains a
single rate for all customer classes and includes a "revenue related expense factor," which increases
the overall rider revenue requirement to, in part, account for projected uncollectable bills. 878 This
would shift the costs of uncollectable bills from customer classes with greater bad debt onto
customer classes with lower bad debt. Further, Mr. Abbott stated, the proposed true-up portion of
the REC Rider would eliminate the need for a bad debt factor, as any actual under-collected amounts
would carry forward and could be recovered in future filings. Also, the single rate could result in
cost-shifting between customer classes, as over- or under- recoveries resulting from billing
determinant forecast error would vary by customer class. Finally, Mr. Abbott stated, the ETI's
proposed billing determinants are based on a historical year. But if load grows over the long term,

876
   Staff Ex. 7 (Abbott Direct) at 12-13. Mr. Abbott cites to PURA§§ 36.203 (Fuel Cost Recovery), 36.205
(Purchased Power Cost Recovery), 36.209 (Transmission Cost Recovery), 36.210 (Distribution Cost
Recovery), 39.107(h) (Advanced Meter Deployment Surcharge), 39.461 (Hurricane Reconstruction Costs),
39.905(b)(l) (Energy Efficiency Cost Recovery).
877
    While the price of RECs at any point in time are set by the market, presumably a purchaser has some ability
to seek relatively better terms-such as making an effort to accurately forecast the number of credits required
and perhaps purchasing or contracting to purchase available credits beforehand if prices are favorable, seeking
volume discounts, banking excess credits when prices are favorable, etc.
878
      Schedule Q-8.8 at 45.4.
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PUC DOCKET NO. 39896

this will lead to persistent over-recovery of the REC Rider revenue requirements, as Rate Year
billing determinants will tend to exceed the historical billing determinants systematically. 879

          Based on these concerns, Mr. Abbott recommended that the Commission deny ETI' s request
for a REC Rider, and that the ETI's Test Year REC costs of $623,303 be included in base rates.
Additionally, he recommended that the Renewable Portfolio Standard Calculation Opt-Out Credit
Rider should be maintained; however, the credit rates should be updated to reflect the Test Year data
used to set ETI' s base rates. In the alternative, if the Commission approves the REC Rider requested
by ETI, Mr. Abbott recommended the following changes from the Company's request:

                   The REC Rider should be set every year to collect the previous year's actual REC
                   costs (instead of projected REC costs), plus any over- or under- recovery from prior
                   periods.

                   The previous year's actual REC costs should be allocated to each customer class
                   based upon each class's actual energy usage over the time period for which the RECs
                   were acquired.

                   Any over- or under- recovery balances should be tracked by each customer class, and
                   thus a separate REC Rider rate should be calculated for each customer class based on
                   that class's allocated REC costs adjusted by that class's over- or under- recovery
                   balance.

                   The REC Rider rates should be calculated using billing determinants based upon
                   ETI's best forecast of each customer class's energy usage over the rider's Rate
                   Year.880

          3. ETl's Response

          ETI contends that adoption of the rider does not result in piecemeal ratemaking because these
are the types of costs that the Company cannot control. Ms. LeBlanc believes that there is a greater

879
      Staff Ex. 7 (Abbott Direct) at 13-14.
880
      Staff Ex. 7 (Abbott Direct) at 14-15.
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risk of over-recovery of REC costs through base rates than there would be under the proposed
rider. 881

          As to the issue that the Company would be disincentivized to purchase RECs at an
appropriate time, ETI claims that the proposed rider has a true-up mechanism that would allow for
review. ETI disputes State Agencies' claims that ETI could have purchased RECs at a lower level at
other points in the year, stating there is no evidence that the Company could have bought RECs at a
lower level at other points in the year.

          Finally, ETI takes issue with the parties' argument that there is no statutory recovery for REC
costs outside of base rates. ETI argues that there is no statutory authority requiring the Company to
refund costs to opt-out industrial customers. According to ETI, no explicit statutory authority is
necessary, and the parties have failed to establish that any harm would result from implementation of
the rider.

          4. ALJs' Analysis

          The AU s are persuaded by the testimonies of Staff and intervenor witnesses Pevoto, Nalepa,
Abbot, Benedict, and Brazell that ETI's proposed REC rider should be rejected. The testimony
supports a finding that adoption of the rider results in piecemeal ratemaking. ETI' s argument that
costs are volatile and, therefore, should be isolated and recovered in a manner similar to an annual
fuel factor filing was not supported by sufficient evidence. Additionally, the AUs agree that the
proposed rider eliminates any incentive for ETI to minimize the costs of purchasing the required
RECs. ETI proffered unconvincing argument and insufficient evidence that standard cost recovery
was insufficient for ETI to recover its total REC costs and a reasonable return.

             The AU s further find that the Test Year expense of $623 ,303 should be used for setting rates
in this case. 882 ETI failed to proffer sufficient evidence and argument to support any increase to its

881
      ETI Ex. 55 (LeBlanc Rebuttal) at 11.
882
   This is the amount referenced in Ms. LeBlanc' s testimony at ETI Ex. 31 at 24 and confirmed in State
Agencies Ex. 9.
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initial request through rebuttal testimony. As recommended by Staff witness Abbott, the Renewable
Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the
credit rates to reflect the Test Year data used to set ETI' s base rates.

B.        Class Cost Allocation [Germane to Preliminary Order Issue No. 14]

          A cost-of-service study is an analysis used to determine the responsibility for a utility's costs
for each customer class. Thus, it determines whether the revenues a class generates cover that class's
cost-of-service. A class cost-of-service study separates the utility's total costs into portions incurred
on behalf of the various customer groups. Most of a utility's costs are incurred to jointly serve many
customers.      For purposes of rate design and revenue allocation, customers are grouped into
homogeneous classes according to their usage patterns and service characteristics.

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

          1. Municipal Franchise Fees

          Municipal Franchise Fees (MFF) are charges for a utility's use of municipal rights-of-way.
The charges are levied by municipalities based on the amount of electricity sold within the municipal
boundaries. They are also referred to as street rental taxes. The MFF charged to ETI are based on
ordinances passed by the cities in which ETI makes retail sales. Different cities have enacted
different levels of MFF on in-city kWh sales, ranging from 0.0956¢ to as much as 0.2644¢ per
kWh. 883 For the portion of fees ETI collects through base rates, ETI proposes to allocate among
customer classes based on customer class revenues relative to total revenues. 884 Once MFF costs are

883
   TIEC Ex. 1 (Pollock Direct) at 52 and Ex. JP-9. Nineteen cities also charge MFF through separate
"Incremental Franchise Fee Recovery" Riders. These incremental MFF are not included in ETI's proposed
revenue requirements in this case. TIEC Ex. 1 (Pollock Direct) at 53.
884
      Schedule P-13 atlO, lines 32-33; the allocation factor "RSRRTOA-Total" is rate schedule revenue.
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allocated to the rate classes, ETI proposes to collect the costs from all customers regardless of their
geographic location. 885

          ETI proposes the same allocation and collection of MFF in this case as was approved by the
Commission in Docket No. 16705, ETI's last litigated rate case. 886 The positions of the parties, as
set out in testimony and briefs, are listed below:

Party/Precedent          l\ilFF Allocation Between            Collection of l\ilFF Expenses From:
                         Customer Classes By:
ETI                      Total revenues                       All customers
Cities                   Total revenues                       All customers
OPC                      kWh sales in city                    All customers
Staff                    kWh sales in city                    All customers
TIEC                     Franchise fee payments in city       Only from municipal customers
Docket No. 16705         Total revenues                       All customers

                      (a) MFF Allocation Between Customer Classes

          Cities and ETI recommend adoption of ETI' s proposal to allocate to customer classes based
on total rate schedule revenues, which the Commission approved in Docket No. 16705. ETI notes
that it is following Commission precedent, and it opposes the use of different allocation factors for
these FERC accounts: Account 408.152, Franchise Tax State; Account 408.154 Franchise Tax
Local; and Account 408.163, Street Rental.

          OPC witness Benedict testified that MFF should be allocated on the basis of in-city kWh
sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale
occurred. Staff witness Abbot concurs. Stated differently, Messrs. Benedict and Abbot suggest

885
      OPC Ex. 8 (Benedict Cross Rebuttal) at 9.
886
   Application of Entergy Gulf States, Inc.for Approval ofIts Transition to Competition Plan and the Tariffs
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to
Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, Second Order on Rehearing at 98
(FoF 224)(0ct. 13, 1998).
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allocating MFF relative to each class's inside-city kWh sales with the same MFF per unit cost (i.e.,
0.1965¢ per kWh) for all customer classes. 887 Mr. Benedict noted that this allocation method is
based on Commission precedent, as indicated in the recent CenterPoint rate case, Docket No. 38339:

          CenterPoint' s allocation of municipal franchise fees to the customer classes based
          upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers
          within the customer class is reasonable and consistent with Commission precedent. 888

Mr. Benedict also noted that allocating on the basis of in-city kWh sales is consistent with PURA
§ 33.008(b). 889

          Commission Staff supports Mr. Benedict's analysis. Staff points out that PURA§ 33 .008(b ),
which authorizes the collection of municipal franchise fees, states that "[t]he compensation a
municipality may collect from each electric utility ... shall be equal to the charge per kilowatt hour .
. . times the number of kilowatt hours delivered within the municipalities boundaries. " 890 According
to Staff, PURA § 33.008(b) plainly links the amount of municipal franchise fees to each class's
in-city kWh sales. Moreover, the Commission has an established policy of allocating municipal
franchise fees based on in-city kWh sales. 891 According to Staff, the Commission should reaffirm

887
   See OPC Ex. 7 (Benedict Cross Rebuttal) at 4-5; Staff Ex. 7 (Abbott Direct) at 22; TIEC Ex. 3 (Pollock
Cross Rebuttal) at 34.
888
    OPC Ex. 6 (Benedict Direct) at Ex. NAB-1, Application of CenterPoint Electric Delivery Company, UC,
for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 34, (FoF 179) (June 23, 2011).
889
      OPC Ex. 7 (Benedict Cross Rebuttal) at 5.
890
      PURA§ 33.008(b)(emphasis added).
891
   Application of TXU Electric Company for Approval of Unbundled Cost ofService Rate Pursuant to PURA
§ 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350, Order at FoF 156
(Oct. 4, 2001 ). The Commission reached an identical conclusion in Application ofReliant Energy HL&P for
Approval of Unbundled Cost of Service Rate Pursuant to PURA 39.201 and Public Utility Commission
Substantive Rule 25.344, Docket No. 22355, Order at FoF 222A (Oct. 4, 2001). More recently, Application of
CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on
Rehearing at FoF 179 (June 23, 2011) (stating that "CenterPoint's allocation of municipal franchise fees to the
customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers
within the customer class is reasonable and consistent with Commission precedent.").
Staff notes in their initial brief that the Commission has further indicated that this allocation should be
conducted without any adjustment for differences in the rates charged by individual municipalities within a
utility's service territory. Application ofAEP Texas Central Company for Authority to Change Rates, Docket
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this precedent in this case by allocating ETI' s MFF to each customer class on the basis of in-city
kWh sales.

          TIEC witness Pollock disagrees with OPC's and Staffs proposed allocation method,
although Mr. Pollock stated their proposal was better than ETI' s proposed allocation. He believes
OPC' s and Staff's proposal fails to recognize the different MFF rates charged by cities. Because
cities that have a preponderance of industrial sales generally charge lower MFF rates, this proposal
would require LIPS customers to pay 0.1965¢ per kWh, which is more than the weighted average
MFF cost to the LIPS class of 0.1612¢ per kWh. Thus, Mr. Pollock argues that this would require
LIPS customers to subsidize other customer classes and would not be consistent with cost causation.
Mr. Pollock thought his proposal to allocate MFF by city by class resulted in each customer class
paying only the MFF expenses actually incurred. 892

          The AUs find OPC's and Staffs proposed allocation methodology best comports with
PURA§ 33.008 and Commission precedent. As noted by Mr. Benedict, PURA was amended after
the Commission's decision in Docket No. 16705, which allocated MFF on the basis of rate schedule
revenue. PURA§ 33.008 expressly calls for a kWh basis for allocation and this is confirmed in the
cases litigated since Docket No. 16705, which were cited by Commission Staff. Accordingly, the
AU recommend that MFF be allocated on the basis of in-city kWh sales, without an adjustment for
the MFF rate in the municipality in which a given kWh sale occurred.

                      (b) MFF Collection

          All parties except TIEC recommend that the Commission approve ETI' s proposed allocation
of franchise fee rentals to all customers. Cities witness Mr. Brazell testified that franchise fees are in
the nature of a rental, not a tax, and like all rental charges ETI incurs, the expense should be spread
among all customers. He stated that MFF charges have always been collected from all customers,

No. 33309, Order on Rehearing at FoF 150 (Mar. 4, 2008) (stating in connection with a proposed municipal
franchise fee expense rider that "[h]aving different rates in each municipality in TCC's service territory is
contrary to the Commission's desire for uniform, simple rates").
892
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 8, 33-35.
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whether or not they take service within the corporate limits, except for the limited incremental
franchise fees specifically addressed by PURA § 39.456. Mr. Brazell explained that electrical
facilities within ETI's system are physically interconnected and electrically synchronized. The
facilities located within a city's boundaries are not isolated physically or electrically from the
facilities outside the city limits. Rather, they are tied to one another and function as a single
integrated system, and ETI' s facilities inside each city benefit all customers in ETI' s service area,
whether or not those customers are within the city. Therefore, Mr. Brazell recommended that the
Commission approve ETI's request to recover MFF in base rates from all customers. 893

          Mr. Benedict holds the same opinion. He stated that the Commission's policy to collect MFF
from all customers within a customer class is also consistent with the concept that MFF are system
costs that are rightly paid by all customers taking service from the system. He explained that MFF
are paid by a utility to municipalities for use of the municipalities' rights-of-way. Because these
rights-of-way are necessary to operate an integrated electric delivery system from which all
customers benefit, regardless of geographic location, Mr. Benedict stated that MFF should be
collected uniformly from all customers within a given rate class. He stressed that the Commission
agreed with this reasoning in Docket No. 16705, where the Commission concluded:

          Current cost of services studies are not based on geographical differences. Classes
          are not divided based on geography, and industrial sites are not self-sufficient islands.
          The use of city streets and property enables [EGSI] to have an integrated utility
          system from which all ratepayers benefit. 894

          Mr. Pollock objected to the proposals by Mr. Brazell and Mr. Abbott. He stated that
Mr. Brazell' s recommendation to adopt ETI' s proposed MFF allocation should be rejected because
there is no evidence that outside city customers benefit from ETI' s use of city streets and rights-of-
way or that the benefits are evenly distributed between inside and outside city customers. Further,
according to Mr. Pollock, the standard used in class cost-of-service studies is cost causation, not

893
      Cities Ex. 1 (Brazell Direct) at 28-32.
894
    OPC Ex. 6 (Benedict Direct) at Ex. NAB-2, Docket No. 16705, Second Order on Rehearing at 98,
(FoF 224).
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benefits, and he believes allocating MFF based on outside city usage is contrary to cost causation
principles. 895

          The AU s recommend adoption of ETI' s proposal to collect costs from all customers taking
service from the system. The AUs find persuasive the fact that MFF is compensation for the use of
municipalities rights-of-way, which is used to operate an integrated electric delivery system from
which all customers benefit.

          2. Miscellaneous Gross Receipts Taxes

          Miscellaneous gross receipts taxes (MGRT) are state taxes imposed on each utility
company's taxable gross receipts derived from sales in an incorporated city or town having a
population of more than 1,000. Like MFF, these taxes are levied only on sales within the cities. ETI
proposes to allocate MGRT to all retail customer classes based on customer class revenues relative to
total revenues. 896

          TIEC objects to ETI's allocation of MGRT based on class revenues for the same reasons
stated for ETI' s allocation of MFF. It argues that these costs should be allocated and charged to
customers within the municipalities to which the MGRT applied.

          The allocation of MGRT is similar to the allocation ofMFF and should be similarly applied.
For the reasons set out above and to ensure consistent treatment, the AU s do not recommend the
direct method of allocation suggested by TIEC. Rather, these costs should be allocated to the rate
classes according to ETI' s cost of service study.

895
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 7, 32-33.
896
      ETI Ex. 3, Schedule P-13 at 10, line 34.
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          3. Capacity-Related Production Costs

                     (a) Allocation Methodology

          ETI proposes to allocate capacity-related production and transmission costs to the retail
classes on the basis of A&E 4CP. As noted by TIEC and Commission Staff, this allocation
methodology is consistent with the method ETI used in Docket No. 16705, its last contested rate
proceeding:

          Finding of Fact No. 221. The continued use of the A&E 4CP allocator is the most
          reasonable methodology for allocating production and transmission plant among
          classes. The A&E 4CP allocator sufficiently recognizes customer demand and
          energy requirements and assigns cost responsibility to peak and off-peak users. It
          best recognizes the contribution of both peak demand and the pattern of capacity use
          through the year.

          Finding of Fact No. 222. The A&E 4CP method is also preferable because it is
          devoid of any double counting problem. 897

          ETI witness Ms. Talkington explained that the A&E 4CP allocation is appropriate because it
is a method that reasonably reflects the mix of the Company's customers, their respective electrical
load characteristics, and the relative costs incurred to serve such loads. She testified that the
A&E 4CP method provides a reasonable balance between the two primary costing concerns:
contribution to the system peak and energy requirements. While the contribution made to the system
peak is inherently recognized with the use of the average four coincident peaks, energy is also
recognized by reflecting the average demands. 898

          OPC witness Benedict proposed the use of the average and single coincident peak (A&P)
method to allocated production (and transmission costs, which are discussed in the section below)

897
      Docket No. 16705, Second Order on Rehearing at 97, FoF 221 and 222 (Oct. 14, 1998).
898
    ETI Ex. 22 (Talkington Direct) at 5. As noted previously, A&E 4CP is developed by adding each rate
class's average demand for the test year (the "average" component representing the rate class's average energy
consumption), weighted by the ETI system load factor, to each rate class's amount of average coincident peak
demand for the months of June through September in excess of its average demand, weighted by one minus the
ETI system load factor.
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among retail classes. As noted in the discussion concerning jurisdictional allocation, A&E 4CP is a
variant of the A&E allocator. Mr. Benedict believes that A&E 4CP fails to properly assign cost
responsibility to both peak and off-peak usage. 899 Instead, he found that the A&E 4CP allocator
results in the same factors reached by the 4CP method, which means that A&E 4CP assigns cost
responsibility only to peak demand and not to off-peak demand. He believes that the A&P
methodology is the proper plant allocator because it takes into account both peak usage and off-peak
usage patterns. 900

            Mr. Benedict's methodology and recommendation was disputed by Kroger witness Higgins.
He indicated that the A&E method does not converge to a CP result. Rather, the A&E method
addresses a fundamentally important question in production cost allocation-once capacity needed to
serve the average demand on the system is accounted for, how does the regulator fairly assign the
responsibility for the additional or excess capacity that is needed to meet the various capacity
requirements (placed on the system by each customer class). Mr. Higgins concluded that the A&E
method makes an objective and reasonable allocation. However, he did not advocate changing ETI' s
use of A&E 4CP. 901

            Mr. Higgins explained that:

            [T]he Average and Excess demand method begins by allocating a portion of costs on
            the basis of average demand-or energy. The remaining (or "excess") capacity needs
            of the system are then allocated to classes based on peak usage--class NCP in the
            case of the "standard" approach, 4 CP in the case of the A&E/4CP method. In
            contrast, the A&P method proposed by Mr. Benedict, which is classified by the
            NARUC Manual as a "Judgmental Energy Weighting" approach, incorporates a
            subjective determination that includes the full value of average demand both in the
            "average" component of the A&P calculation as well as in the peak component of
            that calculation. 902

899
   Mr. Benedict performed a mathematical proof that he believed demonstrated that the A&E 4CP allocator is
nearly identical to the 4CP allocator. OPC Ex. 6 (Benedict Direct) at 21-22.
900   Id.
901
      Kroger Ex. 2 (Higgins Cross Rebuttal) at 4-5.
902
      Id. at 6 (emphasis in originial).
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          TIEC witness Pollock also disputed Mr. Benedict's proposed methodology, stating that A&P
does not reflect cost causation and is not reasonable for ETI. He believes that Mr. Benedict's
support of the A&P method is based on an oversimplification of the planning process. He also noted
that A&E is recognized in the NARUC Electric Utility Cost Allocation Manual and has been
repeatedly used by the Commission. 903

          The following calculations performed by Messrs. Benedict and Higgins demonstrate the
different results stemming from the allocation methodologies: 904

                                    ETI                 OPC                Kroger
                                 Pro12.osed         Recommended           Standard        Alternative
        Rate Class              A&E/4CP(%)            A&P(%)                A&E              12CP
 Residential                         47.4494              40.1181            48.4013            43.4768
 Small General Service                 2.0990              2.0595              2.7209            2.0169
 General Service                     18.0259              19.4933             18.5183           18.6122
 Large General Service                 7.0794              8.3822              6.6558            7.4339
 Lg. Indust. Power Serv.             20.4401              25.5485            20.2122            22.9417
 Total Lighting                        0.2900              0.2768              0.4042            0.1394
 Total Texas Retail                     95.3838             95.8784           96.9127            94.6208
 Total Wholesale and                     4.6162              4.1216            3.0873             5.3792
 Wheeling
 Total Company                        100.0000             100.0000          100.0000           100.0000

          The AUs recommend the use of A&E 4CP to allocate capacity-related production costs, as
proposed by ETI. The weight of the evidence as well as Commission precedent does not support the
methodology proposed by Mr. Benedict. A&E 4CP was approved for the Company in Docket
No. 16705, and the extensive testimonies (which included calculations and graphs) of
Messrs. Higgins and Pollock indicate that, not only is the methodology frequently adopted by the
Commission, it is also a standard and reasonable methodology. As noted by ETI, it reasonably
reflects the mix of the Company's customers and their respective load characteristics and the relative

903
   TIEC Ex. 3 (Pollock Cross Rebuttal) at 12-14, citing the NARUC Electric Utility Cost Allocation Manual,
January 1992.
904
      OPC Ex. 6 (Benedict Direct) at 25; Kroger Ex. 2 (Higgins Cross Rebuttal) at 5.
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costs incurred to serve such loads. It recognizes the contribution of both peak demand and the
pattern of capacity use throughout the year. 905 It also recognizes that ETI, like all Texas utilities, is a
summer peaking utility. The AU s recommend that ETI' s allocation of capacity production costs be
adopted.

                      (b) Reserve Equalization Payments

          A subset of the Company's requested capacity-related production costs relate to reserve
equalization payments made by the Company pursuant to the Entergy System Agreement (Service
Schedule MSS-1 ). The System Agreement, which is approved by the FERC, prescribes a method by
which each Entergy Operating Company's share of Entergy system reserves are calculated. ETI, as
one of the Operating Companies, is responsible to provide the system with its allocated share of
system reserves. Some Entergy Operating Companies own less than their share of system reserves
and are considered "short" with respect to generation capability. Companies that own more than
their share are considered "long" companies. Short companies make payments to long companies
pursuant to the terms of the System Agreement. Because ETI is a short company, it makes reserve
                                                                      906
equalization payments which are included in the cost of service.

          ETI allocates MSS-1 payments using A&E 4CP. Mr. Benedict argues that this allocation
method is not consistent with the way costs are incurred, as ETI does not make MSS-1 payments on
the basis of A&E 4CP. According to Mr. Benedict, ETI incurs costs by being short with respect to
system reserves-the payment is simply the number of MW by which it is short, multiplied by a
$/MW rate as determined by a contract formula. The degree to which ETI is short is determined by
comparing its generation capability to its allocated share of system reserves. Total system reserves
are allocated to the other Operating Companies on the basis of the Responsibility Ratio. Thus, as

905
      See Docket No. 16705, Second Order on Rehearing at FoF 221 (Sept. 4, 1998).
906
      OPC Exhibit No. 6 (Benedict Direct) at 29-30.
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determined by the Responsibility Ratio, ETI's share of system reserves relative to its generating
capability is what causes ETI to make MSS-1 Reserve Equalization payments. 907

            Mr. Benedict concluded that, because Reserve Equalization payments are incurred on the
basis of ETI' s Responsibility Ratio, which is a rolling 12CP allocator, the payments should be
allocated to ETI' s rate classes on a similar basis. As a result, he recommended that Reserve
Equalization payments be allocated on the basis of 12CP.908

            According to OPC, Mr. Benedict's proposal for allocating MSS-1 payments has been
criticized because 12CP measures class demands at ETI's peak monthly demands whereas the
Responsibility Ratio is measured at the Entergy system's peak monthly demands. OPC agrees that
12CP uses peak hours that may differ from those used to compute the Responsibility Ratio, but
contends that the Company fails to mention that the A&E 4CP method it uses to allocate MSS-1
payments is also subject to the same critique. When choosing between the 12CP allocator and the
A&E 4CP allocator for the purpose of allocating reserve equalization payments, OPC believes 12CP
is more desirable. ETI' s contributions to the Entergy system's peaks in all 12 months, not just the
four summer months, determine ETI' s share of Entergy system reserves. ETI' s share of system
reserves, relative to its generation capability, is what causes reserve equalization payments to the
other Entergy Operating Companies. Moving to a 12CP allocation for MSS-1 payments aligns cost
allocation more closely with cost causation.

            TIEC witness Pollock explained that the Entergy System Agreement is regulated by the
FERC, which does not control the rate design policy applicable to Texas retail customers under
Commission jurisdiction. He views the System Agreement as an accounting mechanism to equalize
the benefits and costs associated with interconnected operation and joint planning. In his opinion, it
is not relevant to determining which production capacity allocation method best reflects cost
causation for Texas retail customer. According to Mr. Pollock, the MSS-1 payments are no different
in concept from the costs associated with ETI' s high-voltage transmission lines, which are allocated

901   Id.
908
      Id. at 31.
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on an A&E 4CP basis. He further indicated that the 12CP method ignores the reality the ETI is a
predominantly summer peaking utility. 909

          The ALls do not find sufficient support to allocate the reserve equalization payments
differently than other capacity-related production costs. For the same reasons noted in the section
above, the AlJ s find the weight of the evidence supports allocation using A&E 4CP. While 12CP is
a reasonable methodology for jurisdictional separation between retail and wholesale entities, the
evidence does not support this methodology for allocation of reserve equalization payments.

          4. Transmission Costs

          As noted above, ETI also allocates transmission costs using the A&E 4CP methodology.
Again, TIEC and Staff cite to the Commission's decision in Docket No. 16705, which adopted the
A&E 4CP approach for both production and transmission costs. OPC witness Benedict, however,
proposes allocating transmission plant using A&E methodology that he proposed for the allocation
                        910
of production plant.

          TIEC argues that methodologies similar to Mr. Benedict's proposal have been repeatedly
rejected by the Commission, and the A&E 4CP methodology has been repeatedly approved. TIEC
suggests that Mr. Benedict offers no rationale for a different result for transmission costs. According
to TIEC, the rationale that he offers for using the A&P method for production costs-the potential
trade-off between capital costs and fuel costs-is entirely absent with respect to transmission plant.
Mr. Benedict does not even assert that such trade-offs exist. Rather, the only basis he offers for
using the average and peak methodology is his assertion that the A&E 4CP allocator "mathematically
reduces to a 4CP allocator."911 TIEC points out that the Commission, by rule, has adopted the 4CP
method for the allocation of transmission plant within ERCOT. 912

909
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 27-29.
910
      OPC Ex. 6 (Benedict Direct) at 26-28.
911
      TIEC Initial Brief at 68, citing OPC Ex. 6 (Benedict Direct) at 27.
912
       P.U.C. SUBST. R. 25.192 specifically provides that transmission costs are allocated based on the
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          ETI witness Talkington indicated the same reasons and rationale for using the A&E 4CP
methodology to allocate transmission costs as she noted for capacity-related production costs. 913

          Kroger witness Higgins also disputed the use of A&E 4CP for allocation of transmission
costs for the same reasons noted above concerning production cost allocation. Moreover, he
compared the different allocation factors-specifically, ETl's proposed A&E 4CP, the A&E, and
Mr. Benedict's recommended A&P. His calculations indicated that A&E 4CP and the A&E produce
                                                                                     914
similar results, while A&P radically departs from ETI's proposed allocations.

          The AUs do not find sufficient or persuasive evidence to change ETI's proposed
methodology for allocation of transmission costs. A&E 4CP is a well-accepted method for
allocating such costs, which the Commission has repeatedly adopted. The AUs recommend the use
of the A&E 4CP to allocate ETI' s transmission costs.

C.        Revenue Allocation

          Wal-Mart, Kroger, TIEC, and Commission Staff advocate that the rates be set on the basis of
the utility's costs of service. These parties recommends the adoption of ETis proposed base rate
revenue allocation, recovering from each class 100 percent of it respective Test-Year base rate costs
per the revenue requirement ultimately adopted.

          TIEC witness Pollock testified that revenue allocation is the process of determining how any
base revenue change approved by the Commission should be spread to each customer class served by
the utility. ETI proposed an overall increase in non-fuel revenues of 17 .53 percent, but the increase
is not spread proportionally to all the classes.915 Rather, ETI proposed class revenue requirements

"coincident peak demand for the months of June, July, August, and September (4CP) .... "
913
      ETI Ex. 67 (Talkington Rebuttal) at 8-9.
914
      Kroger Ex. 2 (Higgins Cross Rebuttal) at 5-6.
915
      ETI's revenue requirement does not include the costs associated with its requested REC Rider.
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that are closely aligned with the Company's proposed cost of service. Set out below is the impact of
ETI's proposed base rate increase for each class: 916

                       Class                                  Change in Base Revenues
                       Residential                                 25.10%
                       Small General Service                       1.82%
                       General Service                             5.54%
                       Large General Service                       19.06%
                       Large Industrial Power Service              11.17%
                       Lighting Service                            29 .36%
                       System Average                              17.53%

          The contested issue concerns whether rates should be set at cost, and any approved change in
base rate revenues should reflect the actual cost of providing service, or whether any rate increase
should be phased in for certain classes (notably Residential and Lighting classes) to reduce the
impact (rate shock)

          1. Argument for Moving Rates to Cost

          ETI and the parties in support of ETI' s class revenue allocation contend it is appropriate to
set rates at each class' cost of service as ETI has proposed in order to avoid continuing inappropriate
and inequitable cost shifting between customer classes. TIEC witness Mr. Pollock testified that
cost-based rates send the proper price signals to customers. He noted other reasons for using cost-of-
service principles: equity, engineering efficiency (cost-minimization), stability, and conservation. If
rates are not based on cost, then some customers subsidize part of the cost of providing service to
other customers. Moreover, he suggested that by providing balanced price signals, cost-based rates

916
      See Kroger Ex. 1 (Higgins Direct) at 5-6; see also Cities Ex. 6 (Nalepa Dire.ct) at 34.
                                                                                               --------

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encourage conservation and may prevent waste or inefficient use. If rates are not based on a class
                                                                    917
cost-of-service study, then consumption choices can be distorted.

          Mr. Pollock developed a class revenue allocation based on his proposed jurisdictional and
class cost-of-service studies. If these recommendations are adopted, his class revenue allocation
produced the following results:

        Rate Class             Present Non-Fuel          Proposed Base
                                   Revenues             Revenue Increases       Percent Increase
          Service
Residential                            $379,382,000            $80,390,000                    21.2%
Small General                           $26,430,000               $283,000                     1.1%
General                                $159,768,000             $9,797,000                     6.1%
Large General                           $49,380,000             $8,714,000                    17.6%
Large Indus. Power                     $104,308,000             $9,862,000                     9.5%
Lighting                                $10,813,000             $2,143,000                    19.8%
Total                                  $730,080,000           $111,189,000                    15.2%

          As discussed below, Mr. Pollock also recommended lower rates for Schedules SMS and
AFC, which would reduce ETI' s revenues by about $2 million. To offset this loss, he testified that
revenues would need to be increased for other classes to achieve the total increase requested by ETI.
These changes would produce the following results: 918

  Rate Class Service           Present Non-Fuel          Proposed Base          Percent Increase
                                   Revenues             Revenue Increases
Residential                            $379,382,000            $81,500,000                    21.5%
Small General                           $26,430,000               $340,000                     1.3%
General                                $159,768,000            $10,205,000                     6.4%
Large General                           $49,380,000             $8,860,000                    17.9%
Large Indus. Power                     $104,308,000            $10,153,000                     9.7%

917
      TIEC Ex. l (Pollock Direct) at 63-65.
918
      Id. at 63-67 and Exs. JP-12 and JP-13.
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  Rate Class Service           Present Non-Fuel          Proposed Base             Percent Increase
                                   Revenues             Revenue Increases
Lighting                               $10,813,000                $2,160,000                     20.0%
Total                                 $730,080,000             $113,218,000                      15.5%
SMSIAFC Impacts                        $13,816,000              ($2,029,000)                     -14.7%
Total Sales                           $743,896,000               111,189,000                      14.9%

           If the Commission disallows other elements of ETI' s rate request, Mr. Pollock testified that
class revenue allocation should be reduced in accordance with how such disallowed costs were
allocated to each rate class. 919

           Mr. Pollock's tables provide examples of the impact on each class of customers when the
Commission makes final decisions concerning the Company's proposed rate design and the final
revenue requirement.

           Staff witness Abbott testified that the Commission ordinarily sets rates for each customer
class to recover the costs incurred by the utility to serve that class. In this case, ETI' s proposed
revenues for all customer classes result in base revenues that are close to the cost of service allocated
costs. No single customer class' proposed revenue requirement differs from ETI' s calculated cost to
serve that class by more than 3 percent. Staff acknowledges that certain classes face proportionally
larger rate increases to bring them closer to unity, where revenue recovery is based on actual cost of
service. However, Staff agrees with Mr. Pollock that setting each customer class at their cost of
service avoids inflating rates for some customer classes and subsidizing the usage of others. Staff
believes that recovering from each class its respective base rate cost is equitable and provides
appropriate pricing signals to facilitate the most efficient use of resources in the provision and
consumption of electricity. Staff also argues that the Commission has approved such class cost of
service allocation in recent rate cases. 920

919
      Id. at 67.
920
   Staff cites Application of CenterPoint Electric Delivery Company, UC for Authority to Change Rates,
Docket No. 28339, Order at FoF 175 (May 12, 2011) and Docket No. 16705, Second Order on Rehearing at
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          Wal-Mart and Kroger concur with Staff and TIEC.

          2. Argument for Gradualism

          Cities witness Karl Nalepa pointed out that, under ETI' s proposed rates, the Residential and
Lighting customer classes receive the highest rate increases while the Small General Service, General
Service, and Large Industrial Power Service classes receive below system average rate increases of
1.62 percent, 4.81 percent, and 10.77 percent, respectively. However, he examined Test Year
customer quantities, energy and loads by customer class for each of ETI' s last three cases, and he
concluded that residential and lighting customers are not imposing an undue cost burden on the
system. Instead, other classes are growing at a faster rate, causing system costs to increase.
Moreover, Mr. Nalepa testified that a number of events are occurring with the Entergy system that
will have significant impact on costs, including: Entergy' s efforts to join MISO; plans by EAi and
EMI to leave the Entergy System Agreement; and the possible divestiture of the transmission system
by all Entergy Operating Companies. Given these uncertainties, Mr. Nalepa proposed that any rate
increase or decrease be spread proportionately across the system classes. Then, once Entergy and
ETI address the proposed system cost changes, a reasonable class cost allocation study can be
presented. 921

          State Agencies do not take a position on overall class revenue allocation but request that
ETI' s proposed rate increase for the Lighting class be moderated. ETI proposes to set base rate
revenues for the Lighting class based on the class cost allocation study, without any adjustment,
which would result in a 20.38 percent increase to the Lighting class, when the entire ETI system
would receive a 15.32 percent increase. Thus, under ETI's proposal, this class would receive a
percentage increase about 1.33 times the system average. Ms. Pevoto contended that that this
increase would be excessive and would create significant rate shock to the class. Because the

FoF 245 (Sept. 4, 1998). TIEC witness Pollock also testified that Commission precedent supports allocation of
costs based on the cost of service study. He also cited to the CenterPoint case and to Application ofAEP Texas
Central for Authority to Change Rates, Docket No. 28840, Order at 50 (Aug. 15, 2005). TIEC Ex. l (Pollock
Direct) at 65.
921
      Cities Ex. 6 (Nalepa Direct) at 34-37.
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services of the Lighting class provides benefits all customers on the system, Ms .. Pevoto believes it
would be reasonable to mitigate the rate shock so that lighting customers can afford to continue their
lighting service. Otherwise, she suggested, some lighting customers may reduce lighting services or
refrain from ordering additional lights. This, in tum, would adversely affect the benefits that lighting
service provides to the public. 922

          Ms. Pevoto also pointed out that in 2009, the Commission adopted a rate moderation
proposal for a similar rate class served by another utility. In that case, the Commission recognized
that the Lighting class was unique in the combination of the public good it performs and in its
demand characteristics. 923 To mitigate the rate shock on the lighting customers in the present case,
Ms. Pevoto recommended a cap on any base rate increase that would be equal to the smaller of:
(1) the lighting class percentage rate increase resulting from the PUC-approved cost of service
allocation study, or (2) the allowed system percentage rate increase. If the percentage rate increase is
smaller than the allowed system percentage rate increase, then no mitigation adjustment would be
necessary. However, if the PUC-approved cost of service allocation results in a percentage base rate
increase for the lighting class that is greater than the allowed system percentage increase, then she
urged that a mitigation reduction should occur. She also proposed that any mitigation reduction for
the lighting class should be spread to other remaining classes, based on each class' cost of service. 924

          ETI argues that the State Agencies are proposing the continuation of a significant subsidy by
other classes. The Company notes that its allocation of costs to the Lighting class is based on the
revenue requirement developed for that class. ETI acknowledges that its proposed increase for the
Lighting class is 20.38 percent greater than the system average increase, but it is less than the
Residential class's proposed increase of21.64 percent. ETI witness Ms. Talkington testified that the

922
      State Agencies Ex. 2 (Pevoto Direct) at 12-13.
923
   Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order
on Rehearing at 32 (Nov. 30, 2009).
924
      State Agencies Ex. 2 (Pevoto Direct) at 15-16.
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Company does not support any subsidies between rate classes. She testified that previous rate cases
with subsidies for the Lighting class have pushed the class farther away from cost. 925

          OPC argues that cost of service should not be the sole factor in setting rates and that
gradualism should be used in appropriate circumstances. OPC witness Benedict disagreed with
Mr. Pollock's (and Staff's) citation to the CenterPoint andAEPTCC rate cases to reject the concept
of gradualism because both CenterPoint and TCC are unbundled transmission and distribution
(T&D) utilities whose charges had a small impact on retail customers' total bill. He noted that the
number runs for TCC and CenterPoint showed retail revenue increases of only 0.14 percent and
1.30 percent, respectively, with some classes receiving rate decreases. 926 Mr. Benedict cited the
following language by the Commission in its Order for the TCC case:

          The Commission declines to adopt gradualism in this case. This proceeding develops
          the T&D rates, as opposed to the broader rates developed for a fully integrated utility.
          As the T&D rates are only a subset of the total rates paid by customers, changes to
          the T&D rates would not have as large an impact as they would if the broader rates
          for a customer class were changed by the same percentage.... 927

In Mr. Benedict's opinion, gradualism should be employed when setting rates for ETI because ETI is
an integrated utility and has proposed a large rate increase. 928

          Mr. Benedict also emphasized the imprecise nature of a cost of service study. He noted that
ETI's cost of service study had 47 allocation factors and, even at the summary level, 22 expense
categories and 24 rate base categories. 929 Thus, he stated, there are a host of decisions made by the
cost of service analyst which, in combination with the various account entries, yield a class' reported
cost of service. Mr. Benedict also pointed to disagreement among qualified experts on the "correct"

925
      ETI Ex. 67 (Talkington Rebuttal) at 18-19.
926
   OPC Ex. 8 (Benedict Cross Rebuttal) 11-12; Ex. NAB-4, Docket No. 28840, TCC Number Run (July 21,
2005); and Ex. NAB-5, Docket No. 38339, Revised Number Running Schedules (Feb. 18, 2011).
927
      Id. citing Docket No. 28840, Order at 23 (Aug. 15, 2005).
928
      OPC Ex. 8 (Benedict Cross Rebuttal) at 9-14.
929
    Allocation factors are provided in Schedule P-7 .1; Expenses are summarized in Schedule P-7.4; Rate Base
is summarized in Schedule P-7.5.
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allocation for certain classes of costs. 930 In addition to these allocation questions, Mr. Benedict
stated that any disallowances made to ETI's requested costs will have asymmetric effects on class
cost of service depending on how the costs were allocated. Thus, while the cost of service study is
                                                                                                        931
an important element of ratemaking, Mr. Benedict stressed that it is not the only consideration.

          Due to the wide variation of rate increases obtained from ETI' s cost of service study,
Mr. Benedict thought that rate moderation (gradualism) would be appropriate. However, he added,
until decisions are made regarding the cost disallowances and allocation modifications proposed by
the parties, it is unclear which rate classes should be granted rate moderation and the degree to which
rate moderation is needed. Mr. Benedict said that the system average rate increase should be used as
a benchmark for rate moderation, but not assigned uniformly to all classes as Mr. Nalepa proposed or
to just one class as Ms. Pevoto suggested. Instead, he believed it would be reasonable to establish a
floor and a ceiling for the increases in revenue from each class, such that a class' individual
percentage increase in revenue requirement is within a defined range of the system's average revenue
increase. Therefore, Mr. Benedict recommended that any rate increase for a particular class be
restricted to a range of 0.75 to 1.25 times the system's average increase. This would result in rate
increases up to 25 percent lower or 25 percent higher than the average rate increase for the system as
a whole. Based on a system average increase of 17.53 percent, individual class increases would
range from 13.15 percent to 21.91 percent under Mr. Benedict's proposal. 932

          3. ALJs' Recommendation

          The parties presented persuasive argument on both sides of the issue. Clearly, in any rate
case, movement toward unity-setting rates to cost-is appropriate when such movement does not
result in rate shock to a particular class or classes. If rate shock is likely, Commission precedent

930
    He noted, for example, that his direct testimony and Mr. Nalepa' s direct testimony proposed a different
allocation methodology for production-related capacity costs, transmission costs, and certain System
Agreement costs. Mr. Pollock proposed a different allocation method for municipal franchise fees and local
gross receipts taxes. Mr. Abbott recommended different allocation methods for municipal franchise fees and
other franchise taxes.
931
      OPC Ex. 8 (Benedict Cross Rebuttal) at 14-17.
932
      OPC Ex. 8 (Benedict Cross Rebuttal) at 17-19.
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supports the use of gradualism. These policies apply to both a fully integrated utility, as well as a
T&D. The salient issue is whether the utility's proposed increase is so out of proportion or harsh to a
particular class that some form of gradualism should be applied. In this rate case, the preponderance
of the evidence does not support the use of gradualism, even for the Lighting class. While that class
may receive an increase almost 1.33 times the system average increase, Commission precedent
indicated an appropriate ceiling of 1.5 or even 1.75 times the system average is appropriate. 933 As to
applying OPC's proposed floor and ceiling approach, this method was introduced in cross-rebuttal
with no calculations depicting the impact on each class. The A1J s do not recommend its adoption
because it fails to offer significant movement towards class responsibility for cost of service. The
A1J s do not recommend Mr. Nalepa' s suggestion to impose any revenue change on an equal percent
basis because it offers no movement towards unity. Accordingly, the A1J s concur with the parties
supporting ETI that revenue allocation in this case should be based on each class's cost of service
and consistent with the AU s' recommendations in the PFD that impact revenue allocation.

D.        Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20]

          Staff explained that the Commission has traditionally established class costs of service based
on the principle of cost causation.         Staff believes the Commission has consistently required
substantial justification for departing from this principle when setting rates that result in
cross-subsidization between customer classes. With respect to intra-class cost causation and rate
design, Staff maintains that the considerations are somewhat different. Rather, the Commission has
traditionally given more weight to policy considerations other than cost causation in determining
intra-class rate design issues because the danger of permanent subsidies within a particular class is
relatively low. 934 For instance, Staff witness Abbott testified that customer usage within a class may
vary throughout the year. He noted that a low-load-factor customer might become a high-load-factor

933
      See Docket No. 28840, Order at 23 (rejecting ALJs' proposed ceiling of 1.75 times the system average).
934
    Staff cites to Mr. Abbott's cross-examination at Tr. at 1818 ("Q: And is there a distinction between factors
that you would consider such as costs or other factors when you're discussing class allocation as opposed to
rate design issues? A: I would say there are different considerations and weights to considerations and the
analysis of allocating costs to classes versus the analysis of allocating costs to rates within a class.").
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customer, resulting in a different mix of charges throughout the year. 935 While an individual
customer's usage characteristics might frequently change and thereby lessen the impact of cost
shifting within a class, Mr. Abbott testified that such customers were unlikely to shift to a different
customer class. 936 While subsidies in the customer class allocation context might be permanent, this
was not necessarily the case for intra-class rates. Moreover, these shifting usage characteristics make
it more difficult to identify cost drivers within a rate class. Staff suggests that consideration be given
to policies such as customer impact and energy efficiency.

            The ALls agree with Stafrs analysis. Mr. Abbott recommended that the Commission apply
gradualism-limiting the magnitude of rate changes-to help stabilize customer expectations and
reduce risk. 937 ETI witness Talkington also advised caution in response to suggested changes to
ETI's proposed rate design, noting that the ultimate impact on a customer's bill is important. 938
However, the ALJ s' rate design recommendations are based on the evidence and argument for each
customer class or rate schedule. Thus, the ALJ s' recommendation on the specific rates or charges for
the industrial customers will impact all other customer classes but that impact is not known at this
time.

            1. Lighting and Traffic Signal Schedules

            Cities witness Dennis W. Goins explained ETI's Lighting and Traffic Signal Schedules.
ETI' s principal rate schedule for street lighting customers is Schedule SHL (Street and Highway
Lighting Service), while Schedule TSS (Traffic Signal Services) is the principal rate schedule for
ETI' s traffic lighting customers that own and maintain their lighting facilities. For Schedule SHL,
the rate includes four categories of service (Rate Groups A, C, D, and E). Rate Group A includes
ETI' s standard fixture and lamps mounted on existing standard wood poles that ETI installs and
maintains. If a customer wants nonstandard lighting facilities (those not provided in Rate Group A),

935
      Tr. at 1818.
936   Id.
937
      Staff Ex. 7 (Abbott Direct) at 25-26.
938
      ETI Ex. 67 (Talkington Rebuttal) at 16.
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the customer is assigned to Rate Group C and required to prepay ETI for the incremental cost of the
nonstandard facilities. Lighting facilities that are customer-owned and customer-maintained are
assigned to Rate Group D, while incidental lighting services (for example, underpass lighting) are
assigned to Rate Group E. Customers in Rate Groups A and C pay a fixed monthly charge per
lighting fixture, while customers in Rate Groups D and E pay a fixed (and identical) energy charge
per kWh.           Each customer's monthly bill also includes charges for ETI's fixed fuel factor
(Schedule FF) and applicable riders applied to monthly kWh per fixture. Under Schedule TSS,
traffic signal customers are subject to a minimum monthly charge ($3.20 proposed) per point of
delivery, plus a fixed kWh rate and all applicable rider charges. 939

           Cities request that the Commission require ETI to institute a discounted lighting rate for
Light Emitting Diode (LED) installations. Mr. Goins testified that the basic structure and pricing
provisions of the SHL and TSS rates were designed for lighting fixtures that use older, less
energy-efficient bulb technology, and ETI did not conduct any analyses to estimate the cost
differential of serving street lighting and traffic signal customers that use energy-efficient LED
fixtures. In fact, Dr. Goins noted that the basic structure and pricing provisions of the SHL and TSS
rates have been place for years. 940

           In Dr. Goins' opinion, adoption of LED lighting rates would help reduce energy consumption
in Texas because such rates help offset the high front-end cost of LED lights and encourage
municipalities to adopt energy-efficient LED options. In 2010, the Commission approved a street
and traffic signal rate for El Paso Electric Company that included separate charges for LED traffic
signals. 941 In that case, the fixed monthly rate for LED signals was generally less than one-third the
comparable rate for incandescent signals.

939
      Cities Ex. 4 (Goins Direct) at 22-23.
940
      Id. at 23.
941
   Application of El Paso Electric Company to Change Rates, to Reconcile Fuel Costs, to Establish Formula-
Based Fuel Factors, and to Establish an Energy Efficiency Cost Recovery Factor, Docket No. 37690 (July 30,
2010).
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            Dr. Goins recommended that the Commission require ETI to modify monthly fixed charges
in Schedule SHL (Rate Groups A and C) and the monthly minimum charge in Schedule TSS to
reflect a 25 percent discount for LED installations. Under his proposal, the discounted Rate Group A
fixed charges (if applicable) in Schedule SHL would be applied according to the estimated monthly
kWh consumption of the installed LED fixture. In addition, he recommended reducing by 25 percent
the Schedule SHL kWh charges applicable to LED customers assigned to Rate Groups D and E to
reflect the lower cost of operating and maintaining LED fixtures. And he added that, in the future,
ETI should be required to provide detailed information regarding differences in the cost of serving
LED and non-LED lighting customers. 942

            Dr. Goins also requested that the Commission require ETI to eliminate the service condition
applicable to Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a
functioning light with a lower-wattage bulb. He stated that this fee actively discourages customers
from adopting more energy-efficient lighting technologies (for example, LED devices), and was not
supported in ETI's filing.          In Dr. Goins' view, this barrier to conservation and efficiency
improvements should be eliminated. 943

            Staff disagrees with Cities' request that ETI institute a discounted lighting rate for LED
installations. Mr. Abbott testified that Cities did not provide empirical cost data to support this
request. Without data on which to base an LED installation discount, he recommended that the
Commission not require ETI to provide such a discount at this time. However, because of the
growing use of LED installations and the potential cost savings to be realized from these
installations, Mr. Abbott did recommend that the Commission require ETI to perform a cost study to
determine appropriate cost-based rates for LED installations. This cost study could be used to
develop LED lighting rates, which Mr. Abbott recommended ETI be required to submit as part of its
next base-rate case. 944

942
      Cities Ex. 4 (Goins Direct) 22-26.
943   Id.
944
      Staff Ex. 7 (Abbott Direct) at 28.
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          ETI is willing to perform a study to determine the feasibility of implementing LED lighting
rates as part of its next base rate case filing. ETI witness Talkington explained that the Company
does not currently offer ETI-owned LED lights but may do so in the future. She stated that if a
customer wishes to use LED technology, it can install LE fixtures and receive service under
Schedule SHL, Rate Groups D and E, or the existing Schedule TSS. 945

          Ms. Talkington took issue with Dr. Goins' proposed 25 percent decrease in Schedule SHL
(Rate Groups A and C) and Schedule TSS for an LED option because the 25 percent rate reduction
was not calculated. Thus, ETI prefers that it propose rates after a cost study. Ms. Talkington also
disagreed with Dr. Goins' proposal for a 25 percent decrease in the energy-only options under
Schedule SHL, Rate Groups D and E or Schedule TSS for customer-owned lights. She believes that
a customer will have the benefit of more efficient LED lights by the reduction in energy
consumed. 946

          The AUs find persuasive Dr. Goins' testimony that: (1) the cost of street and traffic lighting
services can be significant for many cities and towns; (2) government agencies face increasing
pressure to control budgets and energy-efficient lighting is a good option; (3) LED fixtures use
significantly less energy than incandescent and most other light options, last longer, and may require
less maintenance; and (4) LED lighting rates would encourage municipalities to adopt
energy-efficient LED options and help offset the high front-end cost of LED lights. 947 However, the
AUs concur with ETI and Staff that ETI should be directed to perform a LED lighting cost study
before extensive changes are made to its lighting rates. The AU s further recommend that ETI
conduct this study before filing its next rate case and provide the results of any completed study to
Cities and interested parties as soon as practicable but no later than the filing of its next rate case, as
requested by Cities. Further, the AUs recommend that the study include detailed information
regarding differences in the cost of serving LED and non-LED lighting customers, if ETI has LED
lighting customers taking service at the time it conducts its study. Finally, the AUs note that ETI

945
      ETI Ex. 67 (Talkington Rebuttal) at 17.
946
      Id. at 17-18.
947
      Cities Ex. 4 (Goins Direct) at 24-25.
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PUC DOCKET NO. 39896

did not dispute Dr. Goins' suggestion to eliminate the service condition for Rate Groups A and C in
Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage
bulb. As noted by Dr. Goins, this fee discourages customers from adopting more energy-efficient
lighting (such as LED devises). The Al.Js concur and recommend that ETI modify the applicable
tariffs to eliminate this fee for any replacement of a functioning light with a lower-wattage bulb.

          2. Demand Ratchet

          Staff witness Abbott testified that a demand ratchet is a provision in a utility's tariff that
allows it to bill a customer based upon on the greater of either demand by that customer in the
current month, or some fixed percentage of the customer's demand occurring during previous
months. The Commission approved a settlement in Docket No. 37744, ETI's last base rate case, in
which, among other things, ETI agreed to eliminate all life-of-contract demand ratchets from its
tariffs for new customers with the implementation of rates. ETI further agreed that, in its next rate
case, it would eliminate the life-of-contract ratchet for existing customers. 948 The Docket No. 37744
stipulation stated:

          Life-of-Contract Demand Ratchet. The Signatories agree that the life-of-contract
          demand ratchet provision in Rate Schedules Large fudustrial Power Service [LIPS],
          Large fudustrial Power Service-Time of Day [LIPS-TOD], General Service [GS],
          General Service-Time of Day [GS-TOD], Large General Service [LGS ], and Large
          General Service-Time of Day [LGS-TOD] shall be excluded from the rate schedules
          in ETI's next rate case. The Signatories further stipulate that the foregoing rate
          schedules will be revised so that the life-of-contract demand ratchet provision shall
          not be applicable to new customers and, for existing customers, shall not exceed the
          level in effect on August 15, 2010. 949

          ETI then filed compliance tariffs in Docket No. 37744, which implemented the first part of
the settlement by excluding new customers from its proposed life-of-contract demand ratchet. The

948
   Staff Ex. 7 (Abbott Direct) at 16; Application of Entergy Texas, Inc., for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744, Order at FOF 26(t) (Dec. 13, 20 I 0). The ratchet is applicable to the
General Service (GS), General Service - Time of Day (GS-TOD), Large General Service (LGS), Large
General Service - Time of Day (LGS-TOD), Large Industrial Power Service (LIPS), and Large Industrial
Power Service - Time of Day (LIPS-TOD).
949
      TIEC Ex. 27 (Docket No. 37744 Stipulation and Settlement Agreement) at 6.
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following is the relevant sections from that compliance tariff, which is applicable to Large Industrial
Power Service (LIPS) customers (all customers taking service under this tariff are required to enter
into a service agreement contract with ETI):

          VI.    DETERMINATION OF BILLING LOAD
                 The kW of Billing Load will be the greatest of the following:
          (A)    The Customer's maximum measured 30-minute demand during any
                 30-minute interval of the current billing month, subject to§§ III, IV and V
                 above; or
          (B)    75% of Contract Power as defined in § VII; or
          (C)    (1) For existing accounts with contracts for service for loads existing
                 prior to August 15, 2010 - 60% of the Highest Contract Power
                 established prior to August 15, 2010 as defined in § VII, (2) For new
                 accounts with contracts for service for loads not existing prior to
                 August 15, 2010 - Does Not Apply; or
          (D)    2,500 kW.

          VII.   DETERMINATION OF CONTRACT POWER
                 Unless Company gives Customer written notice to the contrary, Contract
                 Power will be as defined below:

                 Highest Contract Power - the greater of (i) the highest Billing Load
                 established under the currently effective contract, or (ii) the kW
                 specified in the currently effective contract.

                 Contract Power- the highest load established under § VI (A) above during the
                 12 months ending with the current month. For the initial 12 months of
                 Customer's service under the current! y effective contract, the Contract Power
                 shall be the kW specified in the currently effective contract unless exceeded
                 in any month during the initial 12-month period. 950

          In this case, ETI changed the tariff provisions for all customers:

          VI.    DETERMINATION OF BILLING LOAD
                 The kW of Billing Load will be the greatest of the following:
          (A)    The Customer's maximum measured 30-rninute demand during any
                 30-minute interval of the current billing month, subject to§§ III, IV and V
                 above; or
          (B)    75% of Contract Power as defined in§ VII; or

950
      TIEC Ex. 29 (Tariff Approved in Docket No. 37744)(emphasis added).
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PUC DOCKET NO. 39896

          (C)     2,500 kW; or
          (D)     60% of the kW specified in the currently effective contract.

          VII.    DETERMINATION OF CONTRACT POWER
                  Unless Company gives Customer written notice to the contrary, Contract
                  Power will be as defined below:

                  Contract Power shall be the highest load established under§ VI(A) above
                  during the 12 months ending with the current month. For the initial 12
                  month& of Customer's service under the currently effective contract, Contract
                  Power shall be the kW specified in the currently effective contract unless
                  exceeded in any month during the initial 12-month period. 951

          The contested issue concerns ETI' s new language. ETI maintains the new language is not a
life-of-contract ratchet. Commission Staff, TIEC, and DOE disagree. Stated simply, Department of
Energy (DOE) witness Dwight D. Etheridge testified that the introduction of the term "kW specified
in the currently effective contract" transforms what was a 12-month ratchet into a life-of-contract
ratchet. 952

          At the outset, the AUs note that some of ETI's proposed tariffs do comply with the
stipulation in the prior case. ETI eliminated the life-of-contract provisions for the GS and GS-ToD
customer classes. However, ETI' s new language for the remaining ratchet classes, according to Staff
witness Mr. Abbott, has the effect of maintaining a slightly different type oflife-of-contract demand
ratchet. 953 The discussion in this section applies to the LIPS class but the same argument follows for
LGS and GS classes.

          The parties contesting ETI' s demand ratchet language argue that: ( 1) ETI' s compliance tariff
in Docket No. 37744 was consistent with the parties' agreement; (2) ETI' s proposal imposes a life-
of-contract demand ratchet; (3) the service agreement and tariff are linked; and (4) the new demand
ratchet is not equitable or cost-based. These arguments are set out below.

951
    ETI 67 (Talkington Direct) at Ex. MLT-R-4 at 15 (emphasis added). ETI changed the relevant language in
its tariff in its rebuttal testimony. Thus, the testimony of Messrs. Etheridge and Abbott can be slightly
confusing because these witnesses address the tariff initially proposed by ETI.
952
      DOE Ex. l (Etheridge Direct) at 11.
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PUC DOCKET NO. 39896

               >     The agreed tariff from Docket No. 37744 was consistent with the parties'
                     agreement and shows how UPS billing load should be calculated.

          Staff, TIEC, and DOE agree that when ETI filed the compliance tariff in Docket No. 37744,
the only demand ratchet that remained in the LIPS tariff for ETI' s new customers was a 12-month
demand ratchet. ETI removed the life-of-contract ratchet that set a perpetual obligation for a
customer to pay for power based on its highest contract power or a percentage of its contract power.
Staff, DOE, and TIEC argue that ETI' s action in removing those provisions was consistent with the
agreement and is evidence of what ETI should have done in this case. They contend that ETI witness
Ms. Talkington agreed that the settlement eliminated both the highest load established under the
currently effective contract and the amount specified in the contract.954              in other words, the
compliance tariff tracked the agreement.

          ETI does not directly respond to this argument: Ms. Talkington did not address this in her
rebuttal testimony. However, ETI states that the AI.Js should "not be distracted by ETI's initial error
of unintentionally removing the contracted capacity provision as to new customers in its compliance
tariffs in Docket No. 37744."955 Apparently, ETI believes that the tariffs it filed in compliance with
the Docket No. 37744 agreement were in error.

               >     ETI proposes a demand ratchet in this case that is based on the contracted quantity
                     stated in the tariff-required service agreement.

          All parties agree that what ETI proposes in this docket is different from the Docket
No. 37744 tariff, as evidenced by Ms. Talkington:

          Q:         So last time, when the company and the parties implemented the elimination
                     of the life-of-contract ratchet, it eliminated the 60 percent ratchet applicable
                     to both actual demand during the contract period or the contract - the amount
                     specified in the contract.
          A.         Yes, the way it's put in the schedule, yes.

953
      Staff Ex. 7 (Abbott Direct) at 16-19.
954
      Tr. at 1432.
955
      ETI Reply Brief at 9 l.
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PUC DOCKET NO. 39896

          Q:         And that's different than what you proposed in this case?
          A:         It is.
          Q:         And do you apply a different meaning to the agreement of what the life of
                     contract ratchet meant than was applied in the tariff?
          A:         Yes. What we have in this case is that the life-of-contract power relates to
                     the highest load established under the currently effective contract ... 956

          According to ETI, its proposed language does not impose life-of-contract ratchet, as defined
by Mr. Pollock in Docket No. 37744 or by Messrs. Etheridge and Abbot in this case.

      Witness                                                  Definition
      Pollock                 "A life-of-contract ratchet is based on the highest demand ever imposed
                              by a customer during the term of the contract." He further explained that
                              ETI' s proposed Docket No. 37744 tariff had "a life-of-contract ratchet
                              [which] imposes a perpetual obligation to pay a minimum demand
                              charge throughout the term of the contract."957
      Etheridge               "A life-of-contract ratchet is a ratchet where you're not looking solely at
                              current loads but some other loads in some prior period, so it creates a
                              perpetual obligation to pay."958
      Abbott                  "[A] life of contract demand ratchet, which is based upon the highest
                              demand established in the time period.... is one type of life-of-contact
                              demand ratchet" 959

ETI argues that the above definitions all make reference to the demand actually imposed by the
operations of the customer's physical plant. But the contracted quantity provision it proposes is a
minimum kW amount contractually agreed between the two parties to the service agreement, which
is a required contract between the customer and ETI. 960 ETI argues the provision is not set by actual
events during the term of the contract or in a prior period of the term of the contract, or in a monthly
or 30-minute time period within the term of the contract; rather, it is set in the contract:

956
      Tr. at 1432-1433 (emphasis added).
957
      DOE Ex. 3 (Docket No. 37744 testimony excerpt) at 5-6.
958
      Tr. at 2004.
959
      Tr. at 1817.
960
   Mr. Etheridge testified that customers taking service under Schedule LIPS must sign a contract for service.
Tr. at 1991.
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PUC DOCKET NO. 39896

          That contracted quantity is set as, to use Mr. Etheridge's words, "an estimate" that
          cannot be unilaterally changed by the Company; instead, a change to that kW amount
          could only be made through negotiation between the two parties or through a
          proceeding before the Commission. To use Mr. Pollock's definition, it is not a
          demand "imposed by the customer during the term of the contract." It is instead a
          fixed, contractually agreed to amount that is set as a condition of service prior to the
          contract term. 961

          In sum, ETI argues the provision in question are not life-of-contract ratchets that lock the
customer into the highest demand ever imposed by the customer's actual load during the term of the
contract. Rather, they are, at most, 12-month ratchets that set the billing demand over a 12-month
period, but not the life of the contract, at 7 5 percent.

          Staff suggests that the Commission does not, fortunately, have to determine what contract
provision may or may not constitute a life-of-contract demand ratchet. Rather, the Commission must
ensure that ETI fulfilled its obligations under the Docket No. 37744 settlement. Staff believes that
the parties to that settlement understood the meaning of the life-of-contract term, ETI followed
through with compliance tariffs that evidenced its understanding, and now ETI should be required to
stick with its agreement.

               )- The service agreement and tariff are linked.

          According to TIEC, ETI tries to make the argument that its proposal is justified because ETI
and its large customers may sign an agreement for service that specifies a customer's contract power.
This does not justify ETI' s proposal because ETI' s form "Agreement for Electric Service" expressly
states that the agreement is subject to the terms of "applicable rate schedules."962 Thus, maintains
TIEC, the LIPS tariff billing load provisions impact a customer's contract power and can reasonably
reduce a customer's billing load below its contract power if the customer has a reduction in load
lasting longer than 12 months.

961
      ETI Initial Brief at 211 (footnotes omitted), citing Tr. at 1994, 2012.
962
      ETI Ex. 3, Schedule Q 8.8 at l 1.1.
                                                                               ~~-~·-----------

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PUC DOCKET NO. 39896

          ETI' s proposal should be rejected, argues TIEC, because it would allow the utility to
indefinitely seek revenue from a customer that has nothing to do with the customer's actual usage or
the utility's costs. For example, if a plant took 150 MW of load in its heyday, under ETI' s proposal,
the plant would be obligated to pay demand charges based on 60 percent of its original contract
power. This is because ETI' s standard agreement requires the utility's "express approval" to set a
new contract power and the utility therefore could choose not to negotiate (or negotiate in a timely
manner) a new contract power. 963 If LIPS billing load is tied to contract power, then its customers
would be completely at its mercy to negotiate a reasonable contract power based on the customer's
actual usage for the time period. TIEC contends this is a ridiculous result and would render the
parties' agreement to eliminate the life-of-contract ratchet meaningless.

              >    ETI's new demand ratchet is not equitable or cost-based.

          TIEC does not dispute that a 12-month ratchet is reasonable. However, Mr. Pollock, in
Docket No. 37744, explained why a perpetual obligation to pay demand costs for load that the utility
does not serve is objectionable:

          While it is appropriate to require customers to pay for the facilities they use, a
          perpetual obligation is both extreme and unnecessary. Typical demand ratchets reach
          back twelve months. A life-of-contract ratchet can reach back decades. This is
          particularly inappropriate when longstanding customers have permanently reduced
          operations. A customer that has reduced operations is not purchasing the same level
          of generation and transmission services as in the past, nor is ETI procuring the same
          level of generation and transmission services for the customer. Further, because of
          load growth on the ETI system, the capacity no longer being used by the customer
          would be used by other customers. Thus, a life-of-contract ratchet does not properly
          reflect cost-causation. 964

              >    Witness Recommendations.

          Staff witness Mr. Abbott recommended that ETI be required to eliminate from its LGS,
LGS-ToD, LIPS, and LIP-ToD tariffs the language that results in a ratchet based upon the current

963
      ETI Ex. 3, Schedule Q 8.8 at 11.2.
964
      DOE Ex. 3.
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PUC DOCKET NO. 39896

effective contract-specific demand.                Also, if the Commission approves Mr. Abbott's
recommendation, he stated that the billing determinants used to calculate the rates for the affected
customer classes will likely change. Therefore, ETI should be required to update the affected billing
determinants and reflect the resulting change in its rates in the compliance filing of this docket.965

          DOE witness Etheridge also recommends that same for the LIPS tariff. He specified
language that will exclude the life-of-contract ratchet language and retain the existing rolling
12-month ratchet language in Schedule LIPS. 966 Specifically, he proposed the following:

          VI.           DETERMINATION OF BILLING LOAD
                        The kW of Billing Load will be the greatest of the following:

          (A)           The Customer's maximum measured 30-minute demand during any
                        30-minute interval of the current billing month, subject to §§ III, IV and V
                        above; or
          (B)           [60%] of Contract Power as defined in § VII; or
          (C)           2,500 kW.

          VII.          DETERMINATION OF CONTRACT POWER
                        Unless Company gives Customer written notice to the contrary, Contract
                        Power will be as defined below:

                        Contract Power- the highest load established under § VI (A) above during the
                        12 months ending with the current month. For the initial 12 months of
                        Customer's service under the currently effective contract, the Contract Power
                        shall be the kW specified in the currently effective contract unless exceeded
                        in any month during the initial 12-month period.

                 )ii-   AI.Js Recommendation.

          The ALls find that ETI violated its agreement with the signatories in Docket No. 37744: the
tariff language proposed by ETI is a life-of-contract demand ratchet. ETI failed to explain how the
compliance tariffs adopted in Docket No. 37744 were in error. ETI' s argument that its new language
is not a life-of-contract demand ratchet was unpersuasive. To justify its modification, ETI relied

965
      Staff Ex. 7 (Abbott Direct) at 20.
966
      ETI can adopt similar language for its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs.
SOAHDOCKETNO.-                                PROPOSAL FOR DECISION                         PAGE297
PUC DOCKET NO. 39896

only on a portion of Mr. Pollock's Docket No. 37744 definition. Moreover, both Messrs. Abbott and
Etheridge were unequivocal that ETI, contrary to its agreement in the previous rate case, is imposing
a life-of-contract or perpetual obligation to pay. Finally, the weight of the evidence supports a
finding that the demand ratchet ETI proposes in this case is not equitable or cost based. The ALls
recommend that ETI' s proposed LIPS tariff be amended to include the language proposed by
Mr. Etheridge. The ALls concur with Mr. Etheridge that, with such language, ETI has a financial
incentive to negotiate the maximum possible contracted level of capacity, not the minimum, and the
result is consistent with the Docket No. 37744 agreement.

          3. Large Industrial Power Service (LIPS)

          TIEC witness Pollock explained that Schedule LIPS recovers base rates through a seasonally
adjusted demand charge (per kW) and a two-step non-fuel energy charge (per kWh). The demand
charges are also adjusted (either up or down) to reflect the differences in costs by delivery voltage.
ETI' s existing LIPS schedule has no customer charge. In its initial filing, ETI removed all purchased
power capacity costs from base rates and proposed recovering them through a PPR as a demand
charge. When it did so, the proposed demand charges were increased, but the proposed non-fuel
energy charges were substantially reduced. Following the Supplemental Preliminary Order, which
removed the PPR from further consideration, ETI proposed to roll these costs back into base rates.
The resulting rebundled demand and energy charges would increase by about the same percentage.967

          Mr. Pollock testified that the proposed structure of Schedule LIPS does not track costs as
derived in ETI's class cost-of-service study. Specifically, he complained: (1) there is no customer
charge, despite the fact that the customer costs allocated to the LIPS class would translate into a
monthly rate of over $6,000, and (2) the proposed non-fuel energy charges would recover a
significant amount of demand related costs. According to Mr. Pollock, production/transmission
demand-related costs are $8.47 per kW, and distribution costs add another $0.99 per kW, for a total
of $9.46 per kW. The proposed LIPS demand charges are $7.07 per kW for transmission delivery
and an additional $1.82 for distribution service, for a total of $8.89 per kW. Thus, in Mr. Pollock's

967
      TIEC Ex. L (Pollock Direct) at 68-69.
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PUC DOCKET NO. 39896

opinion, the proposed demand charges (given ETI's requested rate increase) are too low. By
contrast, he noted, non-fuel energy costs are about 0.226¢ per kWh, while the proposed non-fuel
energy charges would average over 0.600¢. Thus, these charges are 2.5 times higher than the
non-fuel energy costs based on ETI's filing. 968

                       (a) A New Customer Charge

           TIEC urged that any increase in Schedule LIPS should be used to create a customer charge.
Mr. Pollock calculated that a cost-based customer charge should be about $6,050 per month, and he
recommended an initial customer charge of $6,000 per month. This would collect approximately
$5.9 million ($6,000 x 984 bills). He added that any remaining increase not accounted for by the
initial customer charge should be collected in the demand charges. He also stated that the non-fuel
energy charges should not be changed unless the LIPS class is allocated less than a $5.9 million
increase. In that event, he recommended that the non-fuel energy charges should be decreased. This
would gradually correct the imbalance between the below-cost demand charges and above-cost
energy charges. Mr. Pollock further stated that the delivery voltage adjustment applicable to
distribution service should be retained so that the rate better reflects the cost. Should the LIPS class
not receive an increase or if base rates are decreased, Mr. Pollock recommended that the customer
charge should be reduced proportionally. Any remaining revenue surplus should be applied to
reduce the non-fuel energy charges to cost and then to reduce the demand charges. 969

           Staff witness Abbott also recommends the introduction of a customer charge, but a much
smaller one than that recommended by Mr. Pollock- $630. 970

           DOE supports Staff's proposed $630 customer charge. DOE witness Etheridge testified that
TIEC' s proposed $6,000 customer charge far exceeds a reasonable initial customer charge for
Schedule LIPS. For example, the existing Commission-approved monthly customer charge for

968
      TIEC Ex. I (Pollock Direct) at 69-70.
969
      Id. at 70.
970
      Staff Ex. 7 (Abbott Direct) at 27.
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PUC DOCKET NO. 39896

Schedule LGS is $425.05. Mr. Etheridge stated that the introduction of a $6,000 customer charge
will lead to large shifts in intra-class revenue responsibility from high load factor customers to low
load factor customers because a customer charge does not vary with usage. He noted, as an example,
that TIEC's proposal would increase DOE's Big Hill annual costs by $72,000 or nearly 10 percent.
Moreover, Mr. Etheridge pointed out that two parties are proposing to lower the Schedule LGS
customer charge-approving either of these recommendations and TIEC' s would levy
Schedule LIPS customers with a new customer charge that is over 23 times the level of the LGS
class. He believes such inconsistencies are inexplicable. Additionally, such disparity would present
                                                                          971
a challenge to any customer migrating from the LGS to the LIPS class.

          DOE witness Etheridge agreed that is appropriate to move toward cost-based rates, however,
he indicated that gradualism should be properly applied to move rates toward cost without undue
impact on low usage and low load factor customers in the LIPS class. If a new customer charge for
the LIPS class is to be imposed-it should be that recommended by Commission Staff. 972

          The Al.J s are persuaded by Mr. Etheridge' s testimony that the adoption of a $6,000 customer
charge far exceeds ETI' s existing customer charge in the LGS Schedule and results in a significant
and inappropriate impact to low load factor customers. Rather, Mr. Abbott's proposed customer
charge of $630 is an appropriate charge to this customer class, particularly as ETI' s current rates
applicable to LIPS customers do not include any customer charge. 973

                       (b)          Demand and Energy Charges

          In an effort to move more towards cost-based rates, Mr. Abbott recommends a slight decrease
                                                                                       974
in the LIPS energy charges and an increase in the demand charges from current rates.         Mr. Pollock
does not recommend an increase in energy charges. However, he recommends increasing demand

971
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 3-4.
972
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
973
      TIEC Ex. 1 (Pollock Direct) at 70.
974
      Staff Ex. 7 (Abbott Direct) at 27.
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PUC DOCKET NO. 39896

charges to cover any remaining revenue increase for the LIPS class that is not accounted for with the
customer charge. He suggested that such a change will gradually correct the imbalance between the
below-cost demand charges and above-cost energy charges. 975

          DOE witness Etheridge expressed concerns with both proposals.              He stated that
Schedule LIPS customers are, on average, substantially more energy intensive than customers taking
service under Schedule LIPS-TOD customers. He indicated that TIEC's proposed rate design (with
the $6,000 customer charge) would double the cost increase associated with base rates and the fuel
factor for LIPS-TOD customers compared with the average cost increase for the class as a whole.
Customers with lower load factors than Schedule LIPS-TOD customers would fare even worse. 976

          Mr. Etheridge also was concerned about Staffs proposed charges, noting that Mr. Abbott
failed to explain how the slight decrease in the LIPS energy charge and the large increase in the
demand charge would affect customers with changes in the revenue requirement ultimately assigned
to the class. Mr. Etheridge stated that even Staffs proposed changes will noticeably shift intra-class
cost responsibility toward Schedule LIPS customers with relatively low load factors. To address his
concern that changes in the revenue requirement may have a significant impact even with Staffs
gradual movement in rates, Mr. Etheridge recommended that Staffs proposal should set the limit on
intra-class cost responsibility shifts. 977

          The ALls find evidentiary support for and recommend the adoption of Mr. Abbott's proposed
changes to Schedule LIPS. There is sufficient evidence, based on Mr. Pollock's testimony, that
Mr. Abbott's suggested changes gradually move the rates towards cost without the risk of rate shock.
TIEC' s demand and energy proposals result in unreasonable large shifts in intra-class revenue
responsibility. However, the ALls also agree with Mr. Etheridge that Staffs proposal may need to
be adjusted depending on the ultimate revenue requirement adopted.

975
      TIEC Ex. 1 (Pollock Direct) at 70.
976
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
977
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
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PUC DOCKET NO. 39896

          4. Schedulable Intermittent Pumping Service (SIPS)

          DOE proposes that a new rider, Schedulable Intermittent Pumping Service (SIPS), be
included in the LIPS tariff. This will allow DOE and other customers with intermittent pumping
loads to avoid application of a demand ratchet to schedulable, temporary, increased demand during
off-peak months when ETI's costs are lowest. DOE suggests that the proposed rider will allow the
DOE to schedule important testing and oil exchanges, when possible, during off-peak months, is
consistent with existing riders, and does not adversely impact other customers.

          DOE explained that its Strategic Petroleum Reserve (Reserve) Texas sites-Big Hill in
Jefferson County and Bryan Mound in Brazoria County-play an important role in ensuring the
energy security of the United States. With a crude oil inventory of about 726.5 million barrels in
2010, the Reserve is the largest emergency supply of oil in the world. The Reserve was established
by Congress as a result of the oil supply disruption in the early 1970s.978

          DOE witness Etheridge testified that DOE takes service to its Big Hill site under
Schedule LIPS at an annual cost of approximately $770,000. Mr. Etheridge explained that the
Reserve' s sites typically operate in standby mode, with routine cyclical tests of pumping equipment.
The largest of these tests is performed every other year. These cyclical equipment tests can be
coordinated with ETI so that they occur during low peak periods. 979

          On rare occasions, the Reserve can also be tapped. In its nearly 35 years of operations, there
have been three Presidential-ordered drawdowns: January 1991, the beginning of Desert Storm;
September 2005, Hurricane Katrina; and July-August 2011, the International Energy Agency
coordinated release. The latter was the largest of the three drawdowns at 30.6 million barrels.
Additionally, the Reserve has provided support to the oil industry in localized emergency or
operational situations involving a disruption in supply, such as ship channel closures and hurricanes.

978
      DOE Ex. I (Etheridge Direct) at 3.
979
      DOE Ex. I (Etheridge Direct) at 3-4
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PUC DOCKET NO. 39896

When oil is exchanged during these situations, the Reserve will operate pumps at higher levels than
would occur during normal standby operations. 980

          Mr. Etheridge proposed a rider to Schedule LIPS where maximum demands during pre-
scheduled, non-summer month operations of a limited duration are not subject to demand ratchets.
For this new rider, he proposed that the non-summer months be classified as October through May to
give customers and ETI more flexibility. (Under Schedule LIPS, non-summer months are November
through April.) Key provisions of the proposed SIPS rider include:

                      A requirement that customers schedule with ETI limited duration
                      operations during non-summer months four weeks in advance.

                      ETI must approve scheduled operations.

                      Operations would not be allowed to exceed 10,000 kW in magnitude nor
                      last for more than 80 hours per year.

                      ETI could cancel operations at any time if a capacity constraint develops.
                      If a customer failed to comply, the customer would incur costs associated
                      with ETI' s ratchet.

                      A customer in compliance would not be subject to ETI' s demand ratchets
                      for loads established during those operations, but would pay the demand
                      charge in the month in which the operations occur. 981

          Mr. Etheridge gave an example of charges under Schedule LIPS versus charges if the rider
were adopted. In September 2010, Big Hill conducted a test and established a maximum measured
demand of 11,640 kW, well above the site's average maximum demand of approximately 3,000 kW.
DOE paid demand charges on the 11,640 kW in September 2010. In October 2010, ETibilled DOE
for 75 percent of that level of demand or 8,730 kW based on the rolling 12-month ratchet. Its actual
demand was 2,520 kW. In terms of actual costs, DOE paid $683,000 for its September usage. Under
the 75 percent ratchet, DOE would pay $609,000 per month. Mr. Etheridge estimated that the

980
      DOE Ex. 1 (Etheridge Direct) at 3-4.
981
      DOE Ex. 1 (Etheridge Direct) at 18.
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PUC DOCKET NO. 39896

charges amounted to $59/k:W per year, which could easily represent nearly one-half of the annual
carrying cost of a combustion turbine. Whereas, under the proposed rider, if DOE conducted the test
in February as it intended to, it would have paid ETI for the 11,640 kW level of demand, but the
usage would not be used in conjunction with ETI' s ratchets. Mr. Etheridge concluded ETI' s tariff is
not equitable. At the hearing, Mr. Etheridge estimated that the rider's impact on other customer
classes at approximately $500,000, where Schedule LIPS base rate revenues are approximately
                982
$110 million.

          According to DOE, for 15 years, June 1996-June 2011, ETI, by contract, accommodated the
Reserve's intermittent load by allowing the DOE to, once annually, "reset" the demand level to be
used by ETI when applying demand ratchets. The DOE was able to avoid significant demand
charges when typical demand was very low. After June 2011, ETI declined to apply the terms of the
long-time contract and allow the reset. DOE concedes that cost-based rates to reflect the Reserve' s
unique operations should ultimately be addressed by contract and/or new tariffs.

          DOE notes that the very purpose of some riders is to address specific customer
characteristics. For instance, Standby and Maintenance Service is available only to those customers
that co-generate electricity; the Optional Rider to Schedule LIPS for Pipeline Pumping Service alters
the designation of on peak-hours only for customers with pipeline pumping stations. Other riders,
claims DOE, seek a win-win for all customers. For instance, the Rider to LIPS for Planned
Maintenance rewards customers for scheduling routine maintenance and idling facilities during ETI' s
peak summer months of June through September by waiving the demand ratchet. DOE argues that
the proposed SIPS rider mirrors Planned Maintenance by waiving the demand ratchet if customers
are able to schedule intermittent loads outside of ETI's peak summer months. Moving toward
cost-based rates is not discriminatory, claims DOE. Nor is rewarding customers who use their load
scheduling flexibility for the benefit of all customers.

          DOE's proposed SIPS rider is opposed by ETI, TIEC, and Staff.

982
      DOE Ex. I (Etheridge Direct) at 19-20; Tr. at 2034.
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PUC DOCKET NO. 39896

          ETI witness Talkington testified that the actual Reserve load, as Mr. Etheridge described,
does not appear to match the parameters of his proposed SIPS rider. As recently as July and August
2011, the Reserve sites had significant load requirements in order to pump vast quantities of oil. She
further testified that the Reserve loads are random in occurrence and are significant. ETI must at all
times maintain generation resources to meet this significant and randomly occurring load. In
addition, the Company has invested in transmission and other facilities to serve this customer even if
there is no or very little consumption. She believed it would not be appropriate or equitable to other
customers to remove or forgive the 12-month ratchet provision after the Company made these
investments to serve the Reserve and while the Company has maintained generation to meet its load.
If the 12-month ratchet were forgiven, then the costs incurred to serve DOE would have to be borne
by other customers in the LIPS rate class. 983

          TIEC witness Pollock complained that Mr. Ethridge failed to analyze the impact on other
LIPS customers. Mr. Pollock contended the rider would discriminate against both Schedule LIPS
customers (by redefining the summer billing period) and Schedule SMS customers (whose ability to
schedule maintenance power could be subordinate to LIPS customer taking advantage of the new
Rider). 984

          Staff is concerned that the rider's unusual eligibility requirements-that a customer must
schedule load four weeks in advance, limit the high load occurrence to "off-peak months" (which is
redefined in the rider), and limit the yearly hours of load-indicate it is tailored solely to meet the
unique needs of the Reserve. According to Staff, DOE conceded that, although other customers with
intermittent loads might take advantage of the proposed SIPS rider, Mr. Etheridge was not aware of
any other actual customer that could do so. 985 Staff argues the rider appears to offer unreasonably
preferential treatment to the DOE and should be rejected.

983
      ETI Ex. 67 (Talkington Rebuttal) at 41.
984
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 9-10, 44-46.
985
    Tr. at 2008 ("Q: Now, who else would take advantage of this SIPS rate schedule, other than DOE? A: It's
written such that any other customer that would have an intermittent schedulable load could take advantage of
it. But I'm not sure if there are other customers on Entergy' s system that could take advantage of it. Q: So you
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PUC DOCKET NO. 39896

        Beyond issues of discrimination, Staff is also concerned that the rider would shift costs from
the DOE to other LIPS customers. Although DOE indicates that any shift would have a small overall
impact on the LIPS class, Staff argues that the Commission should not endorse any discriminatory
rate rider.

        Although Staff and TIEC claim the proposed rider is discriminatory, other riders applicable to
Schedule LIPS customers are available at different times of the year as well (Planned Maintenance is
available only during the months of June through September) and others are limited to
customer-specific needs-such as PPS for pipeline customers. Mr. Etheridge testified that this rider
could apply to any customer-it is not restricted solely to the DOE. The ALJs do not find this rider
to be unreasonably discriminatory. As to ETI' s concern on this issue, it was focused on whether the
DOE' s load met the proposed rider's requirements. However, if a customer taking service under the
rider is unable to schedule its maintenance and oil exchanges with ETI, then the usage would be
under the SIPS Schedule and the SIPS tariffed demand ratchet would apply. Moreover, Mr.
Etheridge testified that the impact on other customer classes is limited. As to ETI' s cost recovery,
the LIPS rider customers will pay a demand charge to cover the costs they impose on the system in
the month SIPS service is taken. The ALJs agree with DOE that the SIPS rider is reasonable and
should be adopted.

        5. Standby Maintenance Service (SMS)

        TIEC witness Pollock explained that Schedule SMS applies to customers that use
self-generation to supply a portion of their electricity requirements. These customers contract with ·
ETI for either standby and/or maintenance power service to replace capacity or energy normally
generated by the customer's on-site generation. Standby (or backup) power is electric energy or
capacity supplied to replace energy or capacity that is unavailable due to an unscheduled or forced
outage of the facility. Thus, backup power must be available at any time. Maintenance power is
electric energy or capacity supplied during a scheduled outage. Unlike backup power, maintenance
power must be arranged with 24-hour notice and only during such times and at such locations that, in

don't know that there are others who could use it. This could apply just to DOE? A: It could.").
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PUC DOCKET NO. 39896

ETl' s opinion, will not result in adversely affecting or jeopardizing firm service to other customers,
prior commitments, or commitments to other utilities. In addition, the customer must make
arrangements and schedule maintenance power in writing in advance and confirmed in writing by
ETI. ETI can also limit requests for maintenance power and allocate and schedule available service,
if requests are made from more than one customer. Thus, Mr. Pollock stated that maintenance power
is of a lower quality of service than backup or standby power. He also indicated that, because the
Company can limit the amount of maintenance power, it is more likely that customers would prefer
                                                                   986
to schedule maintenance power during the non-summer months.

          ETI witness Talkington explained that standby service includes both the readiness to serve
and the actual delivery of power and energy delivered when a customer requires service due to a
forced outage or a planned maintenance period. She indicated that many utilities offer a combination
of pricing and terms for demand and energy service as well as a form of reservation charge dealing
with the readiness to serve. She further indicated that the actual rate design may differ, but standby
tariffs usually contain provisions for back-up (forced outage) or maintenance (planned outage). She
concluded that ETI' s current rate schedule provides for these features, and ETI is not proposing to
change Schedule SMS in this proceeding.987

          TIEC proposes to redesign SMS service to better reflect the cost characteristics of standby
and maintenance power customers. Mr. Pollock provided his analysis to support TIEC's position.
Under the current Schedule SMS, customers pay a monthly demand (or billing load) charge of
$1.12 per kW for backup power. The corresponding charges for maintenance power are $1.12 per
kW for outages during the summer months (May through October) and $0.84 per kW for outages
during the non-summer months. Thus, the non-summer month charge is 75 percent of the summer
month charge. Energy is priced under an array of time-differentiated charges, as shown in the table
below: 988

986
      TIEC Ex. l (Pollock Direct) at 70-71.
987
      ETI Ex. 67 (Talkington Rebuttal) at 19-20.
988
      TIEC Ex. 1 (Pollock Direct) at 72-73.
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PUC DOCKET NO. 39896

                           Current Schedule SMS Non-Fuel Energy Charges
                                             (¢per kWh)
                               Delivery Voltage               On-Peak989      Off-Peak

                       Distribution (less than 69KV)          3.386¢          0.514¢

                       Transmission (69KV and !:!l'eater)     2.334¢          0.211¢

          Mr. Pollock examined P.U.C. SUBST. R. 25.242(k)(l) and concluded that, for Standby
Service, cost-based standby rates should recognize system-wide costing principles and must not be
discriminatory. According to his analysis, the SMS demand charges should be $0.82 per kW for
delivery at transmission and $2.64 per kW for delivery at distribution. He also determined that cost-
based energy charges should be as follows: 990

                         Cost-Based Schedule SMS Non-Fuel Energy Charges
                                           (¢per kWh)
                                 Delivery Voltage               On-Peak Off-Peak

                          Distribution (less than 69KV)          0.955¢       0.639¢
                        Transmission (69KV and !:!l'eater)       0.916¢       0.614¢

          Mr. Pollock explained that, on average, 7 percent of Schedule SMS billing demand was
coincident with ETI's summer month system peaks. This compares to 74 percent for Schedule LIPS;
thus, the ratio of the SMS to LIPS coincidence factors is 12 percent. By Mr. Pollock's calculations,
the resulting demand charge for transmission service would be $0.82 per kW ($7.07 x 12 percent),
and the corresponding SMS distribution demand charge would be the sum of the transmission charge
and the Schedule LIPS distribution demand charge, or $2.64 per kW ($0.82 + $1.82). 991

989
   On-peak hours are from 1:00 p.m. to 9:00 p.m., Monday through Friday of each week, beginning on May
15 and continuing through October 15. In addition, fuel charges are priced at avoided energy cost as calculated
under Schedule LQF. TIEC Ex. 1 (Pollock Direct) at 72.
990
      TIEC Ex. 1 (Pollock Direct) at 73-74 and Ex. JP-15.
991
      Id. at 72-74.
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PUC DOCKET NO. 39896

          Mr. Pollock testified that he combined production and transmission costs in deriving a
cost-based schedule SMS demand charge for transmission delivery, because both production and
transmission demand-related costs are allocated to customer classes using the A&E 4CP method.
This method recognizes that production/transmission plant is sized to meet the diversified summer
peak demands of all ETI customers. That is, Mr. Pollock stated, the 4CP demands are a primary
driver of the costs of the power plants, PPAs, and transmission facilities.      As noted above,
Mr. Pollock contended and verified by analysis that a cost-based Schedule SMS demand charge
                                                                                   992
should be only 12 percent of the corresponding demand charge for Schedule LIPS.

          Mr. Pollock also stated that he proposed to differentiate the standby demand charge by
delivery voltage because it more directly recognizes the different costs to provide service at
transmission and distribution voltage. He added that this recommendation is consistent with the
current Schedule SMS energy charges. 993 However, Mr. Pollock did not apply the 12 percent
coincidence ratio to determine the distribution-related schedule SMS demand charge. He explained
that distribution facilities are electrically closer to customers, so a customer's peak demand
determines how distribution facilities must be sized to ensure reliable service. He stated that ETI
recognized this driver by using maximum diversified demand to allocate distribution demand-related
costs. For this reason, Schedule SMS customers require the same amount of distribution capacity as
a similarly sized Schedule LIPS customer. Thus, according to Mr. Pollock, the Schedule SMS
distribution demand charge should be the same as the corresponding Schedule LIPS demand
charge. 994

          Concerning energy charges, Mr. Pollock testified that the Schedule SMS energy charge
should reflect the composite Schedule LIPS energy charges, or 0.614¢ per kWh. In his view, a
Schedule SMS customer should also pay additional demand charges during on-peak hours, because
this would recognize that an SMS customer that purchases more energy during on-peak hours would
more closely resemble a LIPS customer. For this reason, cost-based on-peak energy charge should

992
      Id. at 75-77.
993
      TIEC Ex. 1 (Pollock Direct) at 77.
994
      Id. at 77-78.
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PUC DOCKET NO. 39896

be a composite of the Schedule LIPS energy charge and the remaining demand charges (not collected
in the SMS demand charge). He calculated an additional on-peak energy charge of 0.303¢, which
yields a total on-peak energy charge of 0.917¢. Under this structure, an SMS customer that
experiences an outage would pay approximately the same for electricity as a LIPS customer.995

           In summary, Mr. Pollock contended that Schedule SMS should be reduced to more closely
reflect the cost of providing standby service as follows: 996

                                  Cost-Based Schedule SMS Charges
                            Based on ETI' s Proposed Schedule LIPS Design
                                            Distribution     Transmission
                             Charge
                                         (less than 69kV) (69kV and greater)
                                      Billing Load Charge ($/kW)
                            Standby            $2.64             $0.82
                           Maintenance         $2.44             $0.62
                                      Non-Fuel Enenzv Char e (¢/kWh)
                           On-Peak        0.955¢            0.916¢
                           Off-Peak       0.639¢            0.614¢

           Using his recommended Schedule LIPS rate design, he proposed Schedule SMS charges
shown in the table below: 997

                                          TIEC Proposed SMS Charges
                                                 Distribution       Transmission
                                 Charge
                                              (less than 69kV)   (69kV and greater)
                        Customer Charge
                                                        $6,000
                         (Stand Alone)
                                     Billing Load Charge ($/kW)
                            Standby            $2.46            $0.79
                          Maintenance          $2.27            $0.60
                                      Non-Fuel Energy Charge (¢/kWh)
                        On-Peak             0.881¢            0.846¢
                        Off-Peak            0.575¢            0.552¢

995
      Id. at 77-78; Ex. JP-15.
996
      Id. at 79.
997
      TIEC Ex. l (Pollock Direct) at 80.
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PUC DOCKET NO. 39896

            Mr. Pollock based his recommended charges on ETI' s proposed revenue requirements and
class revenue allocation. If the Schedule LIPS revenue requirement is reduced, the charges should be
correspondingly reduced. Mr. Pollock also added a customer charge, but he stated that the customer
charge should not apply if a Schedule SMS customer also purchased supplementary power under
another applicable rate. 998

            To determine maintenance power charges, Mr. Pollock maintained the same relationship; that
is, the current maintenance power demand charge is 75 percent of the standby power demand charge.
He stated that the 75 percent should apply to the production/transmission component of the
recommended standby power demand charge because distribution costs are caused by maximum
demands occurring at any time, as previously discussed. This would result in a $0.20 and
$0.19 per kW differential based on ETI's proposed and Mr. Pollock's recommended Schedule LIPS
designs, respectively. 999

            The AIJs note that Mr. Pollock's suggested changes to Schedule SMS are extensive. For
instance, he introduced a $6,000 customer charge and, for the monthly billing load (demand)
charges, he introduced separate rates for distribution and transmission customers. 1000

            Ms. Talkington testified that Mr. Pollock erred in using load data for the period of 2007
through 2011 to develop a coincidence factor that he then uses to develop a lower back-up and
maintenance demand charge for transmission-level customers, while significantly increasing the
charge for distribution-level customers. She also stated that Mr. Pollock's proposal fails to recognize
the "readiness to serve" aspect of standby service. ETI must be ready to serve the load represented
by the largest generation unit taking standby service, plus account for the forced outage rates for all
other existing customer-owned generators. 1001

998
       Id. at 79.
999
       TIEC Ex. 1 (Pollock Direct) at 80.
1000
       TIEC Ex. 1 (Pollock Direct) at 80.
1001
       ETI Ex. 67 (Talkington Rebuttal) at 20-21.
                                                                                                                    ---   ;

                                                                                                                          '

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PUC DOCKET NO. 39896

          Ms. Talkington also stated Mr. Pollock failed to recognize that standby load does not lend
itself to the typical rate design practices. She opined that the cost of providing SMS service is not
driven only by the degree to which standby customers contribute to peak demand, but also by the
Company's obligation to serve whenever called upon. This is the major reason Schedule SMS is not
included in the development of allocation factors. 1002

          Ms. Talkington admitted that she is not familiar with how ETI originally developed
Schedule SMS, but stated that she knows that when a customer takes back-up or maintenance
service, costing is generally designed to mimic what the customer would have paid on standard rates,
absent the use of its own generator. She concluded that Mr. Pollock's analysis is over-simplified and
incomplete. 1003

          In rebuttal testimony, Ms. Talkington proposed a new rate design for SMS service, including
a new service, Non-Reserved Service, which is an optional service designed to supplement
Maintenance Service. ETI's new SMS proposal increases ETis test year base rate revenues by
53.27 percent, with an overall increase of $5.1 million. ETI did not include this rate increase in its
notice. 1004 Accordingly, the ALls determine that ETI's new SMS proposal is not an option to be
considered in this case.

          Commission Staff does not oppose ETI's request to retain its current Schedule SMS.

          ETI did not demonstrate how its current rates are just and reasonable. Rather, ETI' s evidence
on the reasonableness of Schedule SMS is conclusory and insufficient in light of Mr. Pollock's
testimony that the rates are not cost-based. Moreover, although Ms. Talkington indicated her
concern with Mr. Pollock's analysis, she provided no quantitative support for her concern. The
AUs, however, are concerned that Mr. Pollock's suggested changes are not accompanied by a rate

1002
       ETI Ex. 67 (Talkington Rebuttal) at 21.
1003
       ETI Ex. 67 (Talkington Rebuttal) at 21-22.
1004
    PURA§ 36.102 and P.U.C. PROC. R. 22.51 require a utility to publish notice of its intent to change rates,
with proposed revisions of tariffs and a detailed statement of each proposed change, the effect it is expected to
have on revenues, the class and number of customers affected by the change.
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PUC DOCKET NO. 39896

impact analysis.       And, as noted above, his suggested changes are extensive.         Mr. Pollock's
recommendations included a significant increase in the charge for distribution-level customers.
Consistent with his Schedule LIPS recommendation, Mr. Pollock also included a $6,000 customer
charge when no previous customer charge existed. Again, there is no analysis as to the effect such a
charge would have on customer bills. The testimony of witnesses Benedict, Abbott, Higgins, and
Pevoto caution that gradualism should be considered in rate design. As noted by Mr. Higgins, "full
movement to cost-based rates in a single step is sometimes opposed on the grounds of intra-class rate
impacts." 1005 However, the rate impact at this time is not known.

          Based on the evidence and discussion above, the AUs recommend adoption of Mr. Pollock's
suggested changes to Schedule SMS , with the exception of a $6,000 customer charge. Consistent
with the ALls' recommendation that a new LIPS charge of $630 is reasonable, the SMS charge
should be limited to $630 and, as suggested by Mr. Pollock, not apply if a Schedule SMS customer
also purchased supplementary power under another applicable rate.

          6. Additional Facilities Charge (AFC)

          Mr. Pollock testified that Schedule AFC is the mechanism for charging customers directly for
the costs of transformers, breakers and lines when those facilities provide service only to specific
customers. Some of these facilities are booked to transmission accounts while others are booked to
distribution accounts. Schedule AFC is applied as a percentage of the original (un-depreciated) cost
of the facilities. 1006

          TIEC contends that the Schedule AFC charges should be revised. According to Mr. Pollock,
the current charges exceed ETI' s ownership and O&M costs; therefore, he recommended th<"\t the
monthly charges in Schedule AFC be reduced. Under this rate schedule, there are two separate
pricing options. Option A charges 1.49 percent per month; Option B applies when a customer elects
to amortize the direct assigned facilities over a shorter term, ranging from one to ten years. Thus, the

1005
       Kroger Ex. l (Higgins Direct) at 10.
1006
       TIEC Ex. 1 (Pollock Direct) at 8 L
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PUC DOCKET NO. 39896

Option B Monthly Recovery Tenn charge varies depending on the length of the amortization period
of the directly assigned investment. A 0.453 percent Monthly Post-Recovery term charge also
applies after a facility has been fully depreciated. ETI did not propose to change either the Option A
or Option B charges in Schedule AFC. 1007

           According to Mr. Pollock's analysis, charges imposed under Option A should be 1.20 percent
per month under ETI's proposed revenue requirements. Under Option B, Mr. Pollock proposes
various changes to the Recovery Tenn charges, and reduces the Monthly Post-Recovery term to
0 .3 5 percent per month. Further, if the Commission approves a lower base revenue requirement than
ETI has proposed, Mr. Pollock stated that the recommended Schedule AFC charges (both Option A
and Option B) should be reduced in proportion to any authorized reduction in ETI' s proposed rate of
return, O&M expense, and property tax expense. 1008

           In reaching this recommendation, Mr. Pollock used two different methods to derive a cost-
based rate: a levelized cost analysis and a revenue requirement analysis. The former resulted in an
Option A rate of 1.20 percent per month, and the revenue requirement analysis resulted in a weighted
average rate of 1.18 percent. For Option B charges, Mr. Pollock also used a levelized cost analysis
for each of the Option B amortization periods, which resulted in lower charges. 1009

           ETI witness Talkington disagrees with Mr. Pollock's description of Schedule AFC. She
testified that the rate schedule encompasses the costs associated with the installation of facilities
other than those normally furnished. Or, under one option, the rates are like a monthly rental charge
paid for facilities that would not normally be supplied by the Company. She also stated that
Mr. Pollock's example of facilities (transformers, breakers and lines) is understated. 1010

1007
       Id. at 82-85.
1008
       TIEC Ex. l (Pollock Direct) at 81-85 and at Exs. JP-17 and JP-18. See ETI Ex. 3, Sch. Q-8-8 at 24.
1009
       TIEC Ex. 1 (Pollock Direct) at Ex. JP-18.
1010
       ETI Ex. 67 (Talkington Rebuttal) at 31.
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PUC DOCKET NO. 39896

          ETI contends that revisions to this discretionary rate are unwarranted at this time. The
Commission approved this rate structure (and rate) in Docket No. 16705. Moreover, ETI witness
Talkington testified that this rate is voluntary-a customer has alternatives beyond those offered by
ETI. Therefore, it is actually a market-driven rate. If a customer does not want to use this schedule
to obtain the services it provides, the customer can secure services through other sources--either
ETl-owned or otherwise. Ms. Talkington further stated that Mr. Pollock's suggested changes would
be detrimental to the customers who do not have AFC rates because the AFC revenue is treated as an
offset to the revenue requirement to the rate classes. 1011

          Staff does not oppose ETI' s request to retain the AFC rate as it is currently designed.

          The ALls find insufficient support in the record to retain ETI's Schedule AFC as-is. As
noted by TIEC, there is no evidence in this case to support ETI' s claim that: ( 1) the rate is a
voluntary rate; (2) there are other options in the market for customers; or (3) that the rate continues to
be based on a cost that the market will bear (as the Commission found years ago in Docket
No. 16705). 1012 While Ms. Talkington disagreed with Mr. Pollock's proposal because he did not
take into consideration the scope of facilities provided and that his proposal could be detrimental to
other ratepayers because ETI' s revenues from this rate will decrease, she did not quantify her
concems. 1013 The evidence supports a change to Schedule AFC that will move the rate more towards
costs, and TIEC's proposals are the only ones for which there is evidence in the record. The ALls
further agree with Mr. Pollock that his numbers should be reduced in proportion to any authorized
reduction in ETI' s proposed rate of return, O&M expense, and property tax expense.

          7. Large General Service (LGS)

          Kroger witness Kevin C. Higgins testified that the LGS rate schedule serves customers with
monthly billing demands between 300 kW and 2,500 kW. ETI proposes to increase the LGS demand

JOll   ETI Ex. 67 (Talkington Direct) at 27-28.
tol2   See Docket No. 16705, Final Order, FoFs 292-296.
1013
       Tr. at 1437, 1439-1440.
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PUC DOCKET NO. 39896

charge from $8.56 per kW-month to $10.25 per kW-month and to increase the energy charge from
$.00854 per kWh to $.01023 per kWh. The Company proposes no change in the customer charge of
$425.05 per month. 1014

           Mr. Higgins testified that ETI' s proposed LGS demand charge would recover only 72 percent
of LGS demand-related costs. To compensate for the resultant revenue shortfall, the LGS energy
charges proposed by ETI would significantly over-recover energy-related costs. Specifically, the
overall LGS energy charge is proposed to be 428 percent of base energy costs. In addition, although
the customer charge is proposed to be unchanged, it is set at 328 percent of cost. If, instead, the LGS
customer charge were set at cost, it would only be $129.60 per month. 1015

           Mr. Higgins illustrated his findings in the table below: 1016

                           LG Total Class Functionalized Cost Recovery

         Functions         Costs             Collected in     (Under)/Over         Percentage
                                                Rates          Collection          Recovered
         Demand         $46,266,083           $33,116,674      $(13,149, 409)            71.6%
         Energ:v        $3,6625,811           $15,556,253        $11,920,442            427.9%
         Customer          $561,445            $1,841,316         $1,279,871            328.0%
         Total          $50,463,339           $50,514,243            $50,904

           Mr. Higgins stated that if a utility proposes a demand charge that is below the cost, it is going
to seek to recover its class revenue requirement by over-recovering its costs in another area, typically
through an energy charge that is above unit energy costs. In his opinion, for LGS, when demand
charges are set below costs and energy charges are set above cost, customers with relatively higher
load factors are required to subsidize the costs of lower load factor customers within the rate class.
The subsidy is different for each higher load factor customer (a customer whose load factor is greater
than the average for the rate schedule) and consists of the net increase in rates paid by these

1014
       Kroger Ex. l (Higgins Direct) at 7.
1015
       Id. at 8.
1016
       Kroger Ex. 5.
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PUC DOCKET NO. 39896

customers as a result of setting energy charges above energy costs and demand charges below
demand related costs. When the customer charge is set significantly above costs, smaller customers
are overcharged and subsidize the larger customers. 1017

          Recognizing that a full movement towards cost-based rates (without gradualism) in a single
step may create intra-class rate impacts, Mr. Higgins proposed the following changes to better align
costs: 1018

                                         ETI                      Kroger
                                       Proposed       %of        Proposed         %of
                       Functions
                                        Charge        Cost        Charge          Cost
              Demand ($/kW)              $10.25       72%         $12.81          90%
              Energy ($/kWh)           $0.01023       428%       $0.00513         216%
              Customer ($/Mo)           $425.05       328%        $260.00         201%

          Mr. Higgins developed his proposed rate impacts, which indicated a smaller rate impact on
higher load factor customers than those with low load factors. He found them to be comparable to
the rate impact found in ETI's proposed rates. 1019

          ETI witness Talkington did not object to gradually moving rates toward setting demand
energy and customer components closer to cost of service in the LGS class. !020

          Based on principles of cost-based rates and of gradualism, Staff witness Abbott
recommended a decrease in the LGS customer charge to $397 .02 from the current (and Company

1017
       Kroger Ex. 1 (Higgins Direct) at 9.
1018
       ld. at 10-11.
1019
       ld. at 11, Ex. KCH-3.
1020
       Tr. at 1452.
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PUC DOCKET NO. 39896

proposed) $425.05, and an increase in the energy charges, which is less than the increase proposed by
the Company. 1021

                The AUs found Mr. Higgins' proposed changes reasonable and well supported.
Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet,
and the AU s' recommendation for the elimination of ETI' s LIPS demand ratchet is applicable to this
class.

                8. General Service (GS)

                Based on principles of cost-based rates and of gradualism, Staff witness Abbott
recommended a decrease in the GS customer charge to $39.91 from the current (and Company
proposed) rate of $41.09. Staff also recommended a decrease in the energy charges. 1022

                No party disputed Staffs recommendations, which the AU s adopt. Schedule GS also has a
demand ratchet, and the AUs' recommendation for the elimination of ETI' s LIPS demand ratchet is
applicable to this class.

                9. Residential Service (RS)

                ETI' s RS rate schedule is composed of two elements: a customer charge of $5 per month and
a consumption-based energy charge. The Energy charge is a fixed rate of 5.802¢ per kWh from May
through October (Summer). In the months November through April (Winter), the rates are structured
as a declining block, in which the price of each unit is reduced after a defined level of usage. For
instance, the same energy charge of 5.802¢ applies, but only for each of the first 1,000 kWh
consumed. Each kWh consumed beyond 1,000 is billed at a lower rate of 3.834¢. 1023

1021
          Staff Ex. 7 (Abbott Direct) at 25-27.
1022      Id.
     23
t0   OPC Ex. 6 (Benedict Direct) at 41, Ex. NAB-1, ETl's Response to State RFI No. 4-17; ETI Ex. 67
(Talkington Rebuttal) at 9.
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PUC DOCKET NO. 39896

          ETI proposes to retain the general structure of the RS rate design but proposes an increase in
the dollar amount of each rate element. OPC witness Benedict noted ETI' s proposed changes in his
                                1024
testimony, as set out below:

                                                          ETI               ETI             Percent
                       Rate Element                      Current          Proposed          Increase
             Customer Charge (per month)               $5.00              $6.00             20.0%
             Energy Charge (Summer, all                                                     25.3%
                                                       $0.05802           $0.07268
             kWh)
             Energy Charge (Winter, kWh S                                                   25.3%
                                                       $0.05802           $0.07268
             1000)
             Energy Charge (Winter, kWh>                                                    25.2%
                                                       $0.03834           $0.04799
             1000)

          OPC criticized ETI's declining block rate structure as being contrary to energy efficiency
efforts. OPC witness Benedict noted that under ETI's proposed rate structure, once kWh usage
exceeds 1,000 in a winter month, the per-kWh cost of consumption falls by 34 percent. Thus,
because a declining block rate structure lowers the per-unit rate for high levels of consumption,
heavy users are induced to consume more than they would otherwise. In his view, this runs contrary
to the Legislature's goal of reducing both energy demand and energy consumption in Texas, as stated
in PURA § 39.905:

          (a) It is the goal of the legislature that: ... (2) all customers, in all customer classes,
          will have a choice of and access to energy efficiency alternatives and other choices
          from the market that allow each customer to reduce energy consumption, summer
          and winter peak, or energy costs.

Therefore, Mr. Benedict recommended that the declining block rate be phased out over time. He
stated this would ease the transition to a rate structure without a declining block, and it would allow
time for customers to switch to more efficient heating systems. Mr. Benedict proposed that the
phase-out take place over three rate cases, beginning with a one-third reduction in the block
differential proposed by ETI in this case. Reducing ETI' s proposed block differential from 2.469¢ to

1024
       OPC Ex. 6 (Benedict Direct) at 42.
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PUC DOCKET NO. 39896

1.645¢ accomplishes the initial one-third reduction, as illustrated below (using ETI's requested
revenue requirement): 1025

                                                                              Reduced
                                         ETI          ETI       Percent      Block Rate     Percent
            Rate Element                Current     Prooosed    Increase     Differential   Increase
 Customer Charge (per month)                $5.00     $6.00      20.0%          $6.00         20%
 Energy Charge (Summer, all                                      25.3%                       23.1%
                                        $0.05802     $0.07268                 $0.07141
 kWh)
 Energy Charge (Winter, kWh~                                     25.3%                       23.1%
                                        $0.05802     $0.07268                 $0.07141
 1000)
 Energy Charge (Winter, kWh >                                    25.2%                       43.3%
                                        $0.03834     $0.04799                 $0.05496
 1000)

Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended
to affect the amount of revenue to be collected from the residential class or any other class. If,
however, the Commission approves a different revenue requirement for the residential class to reflect
various proposed adjustments, rates for the class will need to be recomputed regarding a reduced
block differential 1026

          Staff generally agreed with OPC's recommendation for a reduction in the rate differential
between the residential winter kWh :S 1000 block and the winter kWh> 1000 block, due to the
inconsistency between the incentives produced under declining block rates and the State's energy
efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011
demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid
encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate
block differential is warranted to better encourage wintertime energy conservation at the margin. 1027

          ETI witness Talkington testified that the RS rates are cost-based with a declining block rate
in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage

1025
       OPC Ex. 6 (Benedict Direct) at 43-45.
1026
       OPC Ex. 6 (Benedict Direct) at 46.
1027
       Staff Ex. 7 (Abbott Direct) at 27.
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PUC DOCKET NO. 39896

increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She
provided analysis to support her position. 1028 Ms. Talkington explained that residential rates do not
include demand charges because of the absence of residential demand meters. However, residential
energy rates can be structured the same as the non-residential classes; that is, customer charge,
demand charge and energy charge.· She developed residential rates on this basis to show that the
declining block rate is appropriate to account for reductions in the cost of service to residential
customers as consumption increases. With no declining block rate, high load factor customers are
disadvantaged as the customer charge is reduced and the demand charge is moved into the energy
charge. She believes that declining block rates alleviate the disadvantage. 1029

           Ms. Talkington illustrated the impact of Mr. Benedict's suggestion to phase out the declining
block rate for RS customers. Approximately 54 percent ofETI's residential customers use more than
1,000 kWh in January and February. For a customer using 3,000 kWh in a winter month of
November-April, this customer's bill would increase by 16.28 percent or about $48 over current
rates. (Of ETI' s total number of RS customers, approximately 10 percent use 3,000 kWh or more in
the months of January and February.) For that same customer, ETI's as-filed proposal shows an
increase of 11.96 percent or approximately $35. Mr. Benedict's proposal is $13 greater than ETI's
proposal for one winter month at 3 ,000 kWh. That dollar amount is over a third of the total increase
ETI is proposing. 1030

           After Mr. Benedict's proposed phase-out is completed, based on the proposed residential
rates in the Company's case, the residential rate would be $0.06887 per kWh in both summer and
winter. A customer using 3,000 kWh in a winter month of November-April would see an increase of
24.89 percent or about $7? over current rates. After the final phase out, Mr. Benedict's proposal is
$38 per month greater than ETI's as-filed proposal of $35 for one winter month at 3,000 kWh. 1031

1028
       ETI Ex. 67 (Talkington Rebuttal) at 13, Ex. MLT-R-1.
1029
       Id. at 14.
1030
       Id. at 15.
1031
       Id. at 15-16.
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PUC DOCKET NO. 39896

          Ms. Talkington further noted that rate design professionals always take into consideration the
effect on customer bills. Even though Mr. Benedict proposes to implement the change over the next
three rate cases, she concludes there will still be winners and losers within the residential class as a
result of his proposed change. According to Ms. Talkington, some customers have made decisions
about investing in electric appliances based on the current rate design. The elimination of the
declining block in the winter time changes the economics of customer decisions that have already
been made. She believes that great caution needs to be exhibited and very good reasons need to be
demonstrated before changes are made to the rate design. She recommended that if a change to the
rate structure is recommended, the initial phase-in should be reduced to 10 percent rather than one-
third and subsequent reductions should be reviewed for consideration at the occurrence of each rate
case filing and not mandated at this time. 1032

          The AUs concur with OPC and Staff that the structure of the declining block winter rates
provide a disincentive to energy efficiency. However, ETI provided evidence that OPC' s suggested
changes, combined with ETI' s proposed rate increase, will have too great an impact. OPC suggested
a one-third reduction in the differential, while Ms. Talkington suggested a 10 percent reduction, with
subsequent reductions reviewed before being mandated. The AU s recommend an initial 20 percent
reduction, which should alleviate some of ETI's concerns but still reduce the block differential
sufficiently to move towards compliance with the energy goals set out in PURA. The AUs further
recommend that 20 percent subsequent reductions of the differential be required in the next three rate
cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable.

  XI.       FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31]

          In the application, ETI seeks to reconcile approximately $1.3 billion in fuel and purchased
power expenses incurred over the 24 month Reconciliation Period. Summaries of ETI' s total fuel
and purchased power expenses and over/under recovery balance are shown below.

1032
       ETI Ex. 67 (Talkington Rebuttal) at 15- l 7.
                                                                                                                                --,

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PUC DOCKET NO. 39896

                                                       Fuel Reconciliation
Gas and Oil                                                                                                    $616,248,686
Emissions Allowance                                                                                                 360,236
Coal                                                                                                             90,821,317
Total Fuel:                                                                                                    $707,430,239

Purchase Power Expense                                                                                           990,041,434
Off-system Sales Revenues                                                                                      (376,671,969)
Total Purchased Power:                                                                                         $613,369.465

Total Fuel Costs:                                                                                            $1,321,799,704

Over-recovery Balance:                                                                                         $243.,339,353

Special Circumstances                                                                                                 $99,715
Sources:     ETI Ex. 3 Schedules I-16, H-12.4a-g, H-l2.5b-e, 1-21; ETI Ex.   11 (McCloskey Direct); ETI Ex. 23 (Zakrzewski
Direct).

             ETI contends, and the evidence presented at the hearing demonstrates, that these fuel factor
expenses were eligible for reconciliation and were reasonable and necessary to provide reliable
service to ETI' s customers during the Reconciliation Period. With the exception of three minor
issues that are discussed below, none of the intervenors raised a substantive issue with respect to
ETI' s fuel reconciliation request.

             During the Reconciliation Period, ETI' s Texas fuel factor revenues over-recovered total fuel
and purchased power expense by $243,339,353, inclusive of interest. The Commission authorized
the refund of the fuel over-recovery balance in Docket Nos. 37580, 38403, and 38967. ETI proposes
that the amount of any fuel over-recovery balance not already refunded or authorized for refund be
rolled forward as the beginning balance for the next reconciliation period. 1033

             P.U.C. SUBST. R. 25.236(d)(l) states that in a fuel reconciliation proceeding, the utility has
the burden of showing that:

             (A)      its eligible fuel expenses during the fuel reconciliation period were
                      reasonable and necessary expenses incurred to provide reliable electric
                      service to retail customers;

     33
io        ETI Ex. 40 (Thiry Direct) at 7.
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PUC DOCKET NO. 39896

       (B)     if its eligible fuel expenses for the reconciliation period included an item or
               class of items supplied by an affiliate of the electric utility, the prices charged
               by the supplying affiliate to the electric utility were reasonable and necessary
               and no higher than the prices charged by the supplying affiliate to its other
               affiliates or divisions or to unaffiliated persons or corporations for the same
               item or class of items; and
       (C)     it has properly accounted for the amount of fuel-related revenues collected
               pursuant to the fuel factor during the reconciliation period.

       In Docket No. 15102, an EGSI fuel reconciliation case, the Commission explained the
traditional prudence standard to be applied in reviewing decisions made by the utility:

       The exercise of that judgment and the choosing of one of that select range of options
       which a reasonable utility manager would exercise or choose in the same or similar
       circumstances given the information or alternatives available at the point in time such
       judgment is exercised or option is chosen.

       There may be more than one prudent option within the range available to a utility in
       any given context. Any choice within the select range of reasonable options is
       prudent, and the Commission should not substitute its judgment for that of the utility
       . . . . The reasonableness of an action or decision must be judged in light of the
       circumstances, information, and available options existing at the time, without
       benefit of hindsight. 1034

       ESI purchases power and procures fossil fuels on behalf of the individual Operating
Companies. Fossil fuel costs are borne directly by the Operating Company that contracts for and
uses the fuel. Once resources are procured to meet forecasted demand, the system is operated during
the current day using all of the resources available to the system to meet the total system demand.
Throughout the course of the day, system operators may modify planned operations to maintain
reliability, take advantage of less-expensive resources in the hourly wholesale power markets, or
make off-system sales. For example, when spot market power purchases are available at a cost lower

1034
   Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on
Rehearing at 2 (Jun. 24, 1997).
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PUC DOCKET NO. 39896

than the cost of energy that can be generated by units owned by the Operating Companies, that
energy is purchased to displace owned generation, subject to operating constraints. 1035

          Expenses for coal, gas, power purchases, and fuel oil are incurred directly by the respective
Operating Company. For example, if coal is purchased for ETI' s share of Nelson Station, Unit 6,
then ETI is responsible for the invoiced cost and makes payment directly to the supplier. Wholesale
power, purchased and sold for the system, however, is accounted for per the terms of the System
Agreement. After dispatch, or after-the-fact, the System Agreement prescribes an accounting
protocol to bill the costs of operating the system to the individual Operating Companies. 1036

          The following Fuel Reconciliation-related issues were uncontested:

               ~   Natural Gas Purchases

          ETI witness Karen Mcllvoy presented direct testimony describing ETI' s natural gas
procurement policies and strategies. She explained that the Company buys gas through a long-term
contract with Enbridge, through participation in the monthly and daily markets depending on fuel
needs, and on a delivered-to-plant basis or arrange for transportation to the plant. Ms. Mcllvoy
described how the gas buyers for ETI survey the markets and solicit offers for gas supplies.
Ms. Mcllvoy also provided a comparison of the Company's gas costs to the Inside FERC and Gas
Daily published indices for the Houston Ship Channel. 1037 No party challenged the Company's
natural gas purchases.

               ~   Fuel Oil

          Ms. Mcllvoy testified that the Company purchased fuel oil for start-up and flame stabilization
at certain units. Fuel oil can also be used for emergency back-up fuel or as an economic alternative
to natural gas at certain units. During the Reconciliation Period, the Company purchased all fuel oil

1035
       ETI Ex. 40 (Thiry Direct) at 18-21.
1036
       ETI Ex. 39 (Cicio Direct) at 31-37.
1037
       ETI Ex. 28 (Mcllvoy Direct) at 23, Ex. KDM-3.
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PUC DOCK.ET NO. 39896

on a short-term basis from spot market sources after solicitation of bids from multiple potential
suppliers. 1038 No party contested ETI's fuel oil costs.

              ~    Longer-Term Purchased Power

          ETI witness Robert R. Cooper addressed the Entergy system's long-term planning process
and described the Strategic Resource Plan process. He explained how the system determined its
capabilities and needs for additional resources to reliably serve system load requirements.
Mr. Cooper described the process by which the system developed requests for proposals and
analyzed a combination of capacity and firm energy contracts to satisfy the system's identified
resource needs. 1039 A portion of these system purchases was allocated to ETI. No party proposed a
disallowance of these purchases on the basis of prudence.

               ~   Short-Term Purchased Power

          Ms. Thiry described the Power Marketing Team's procurement strategies, practices and
procedures during the Reconciliation Period. Ms. Thiry testified that the Power Marketing Team
fulfilled its objective of purchasing energy in the wholesale market when it was more economical
than using the system's generatio!l and in order to maintain system reliability.        Ms. Thiry
demonstrated that third-party purchases for the system compared favorably to market price indices
and to proxy costs of avoided generation. 1040 The Power Marketing Team maintained effective cost
controls and procured a diverse portfolio of product to provide electricity for customers at a
reasonable cost. 1041 No party contested the prudence of ETI' s short-term power purchases.

               ~   Coal Commodity and Transportation

          ETI has ownership interest and/or obtains power through Schedule MSS-4 of the Entergy
System Agreement, in two coal-burning generating units - Nelson and BCil/U3. ETI owns a

1038
       ETI Ex. 28 (Mcllvoy Direct) at 5-6.
1039
       ETI Ex. 34 (Cooper Direct) at 6-10.
1040
       ETI Ex. 40 (Thiry Direct) at 24.
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PUC DOCKET NO. 39896

29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in
BCWU3, but the unit is operated by a third party. ETI witness Ryan Trushenski, the Manager of
Coal Supply for ESI, testified that ETI prudently managed its coal supply and transportation
expenses during the Reconciliation Period. 1042

             With respect to coal and transportation expenses at Nelson 6, ETI obtained coal during the
Reconciliation Period under a supply contract previously reviewed by the Commission, and entered
into a new coal supply contract after a competitive bid process. ETI chose the supplier with the
lowest priced coal that met the specifications necessary for use at Nelson 6. Similarly, ETI arranged
for transportation of coal according to transportation contracts previously reviewed in prior fuel
reconciliations. When those contracts expired, ETI initiated a competitive bid process and chose the
lowest cost option available that met its requirements. With respect to BCWU3, ETI incurred costs
to run the unit and took reasonable steps to ensure that the third party operator properly charged for
coal and transportation expenses under an arrangement previously reviewed and approved in prior
fuel reconciliations. 1043 No party challenged the reasonableness and necessity of ETI's coal or
transportation expense during the Reconciliation Period

             The three contested issues are discussed below.

A.           Spindletop Gas Storage Facility

             During the Reconciliation Period, ETI incurred $10,261,663 of non-fuel expense associated
with operating the Spindletop Facility. Cities challenged ETI's use of the Spindletop Facility,
arguing that the costs of operating it outweigh the benefits gained from it. For the same reason he
challenged the Spindletop Facility costs associated with rate base, Cities witrtess Nalepa also
challenges ETI's non-fuel expense associated with the facility.             Specifically, Mr. Nalepa
recommends that ETI's total fuel reconciliation balance be reduced by $6,595,290, which he

1041   Id.
1042
       ETI Ex. 33 (Trushenski Direct) at 2.
1043
       Id. at 11-13.
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PUC DOCKET NO. 39896

calculates as the difference between the $10,261,633 non-fuel operational costs associated with the
Spindletop Facility over the Reconciliation Period and the costs of alternative sources of providing a
reliable and flexible gas supply over the same period. 1044 fu Section V .H., above, the AU s rejected
Cities' contention that the Spindletop Facility is not used or useful. For the same reason they
rejected Cities' Spindletop Facility arguments relevant to rate base, the AUs also reject Cities'
Spindletop Facility arguments relevant to Fuel Reconciliation.

B.        Use of Current Line Losses for Fuel Cost Allocation

          Cities propose that the allocation of fuel costs incurred over the Reconciliation Period reflect
the current line loss study performed by ETI for this case and recommended for approval on a going
forward basis. fu the fuel reconciliation case, ETI proposes to allocate costs to customers using a
line loss study performed in 1997, which Cities claim does not reflect the current cost of providing
service to the current wholesale customers and to the various retail customers. 1045 According to
Cities, updating ETI' s allocation of fuel costs to reflect current line losses and the cost of providing
service to customers results in a $3,981,271 reduction to the Texas retail fuel expenses incurred over
the Reconciliation Period. 1046

           ETI responds that the Cities' recommendation is unprecedented.              It notes that the
Commission's substantive rules require use of "a commission-approved adjustment to account for
line losses corresponding to the voltage at which the electric service is provided." 1047 Moreover, ETI
argues that retroactive use of new loss factors to calculate its fuel over/under-recovery balance would
result in a mismatch between the revenues recovered under the fuel factor and the costs billed and
allocated to the various customer classes. 1048

1044
       Cities Ex. 6 (Nalepa Direct) at 42-43; Cities Initial Brief at 84.
1045
       Cities Ex. 6 (Napala Direct) at 44; see also Tr. at 1469-1470.
1046
       Cities Ex. 6 (Napala Direct) at 47, Table 14.
1047
       ETI Ex. 58 (McCloskey Rebuttal) at 2, quoting P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1048
       Tr. at 1484.
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PUC DOCKET NO. 39896

             Fuel costs are collected through Commission-approved fixed fuel factors. One of the
elements the fuel factor is required to take into account is line losses.              P.U.C.   SUBST.

R. 25.237(c)(2)(B) states that the utility must prove that: "the proposed fuel factors utilize a
commission-approved adjustment to account for line losses corresponding to the voltage at which the
electric service is provided." 1049 If the Commission were to adopt Cities' recommendation that the
newly-developed line losses be used in the reconciliation of fuel costs, the allocation of those costs
would not match the collections (determined through the use of historical line losses). This
mismatch could result in some customers receiving more than they are entitled and others receiving
less than they are entitled. The AUs find that the Commission's rules require the use of
Commission-approved line losses that were in effect at the time fuel costs were billed to customers
in a fuel reconciliation. The AUs, therefore, recommend that the Commission reject the Cities'
proposed adjustment.

C.           ETl's Special Circumstances Request

             In the application, ETI seeks to include $99,715 in the Fuel Reconciliation to allow it to
recover "the reversal of certain credits that were previously included in the Company's [Incremental
Purchased Capacity Rider] Rider IPCR." 1050 ETI witness Zakrzewski explained that the FERC
revised the amount of purchased capacity-related production costs allocable to ETI through the
FERC-approved Rough Production Cost Equalization mechanism for allocating production costs
among the Operating Companies. As Mr. Zakrzewski explained, the result of the decision was a
recalculation of ETI' s capacity costs recoverable through the Commission-approved Rider IPCR,
which expired during the Reconciliation Period. 1051

             During the hearing, no party contested ETI's special circumstances request of $99,715 with
regard to the IPCR-related adjustment. For the first time in its Initial Brief, however, Cities opposed

1049
       P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1050
       ETI Ex. 23 (Zakrzewski Direct) at 13.
1051   Id.
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PUC DOCKET NO. 39896

the request, asserting that it conflicts with the settlement reached in Docket No. 37744. 1052 The ALJs
are not swayed by Cities' argument. As pointed out by ETI, 1053 Cities provided no testimony or other
evidence to support its position. Furthermore, Cities failed to explain how a settlement agreement
reached in Docket No. 37744 could or should trump the FERC's jurisdiction to determine the
amount of purchased capacity costs attributable to ETI. The only evidence in the record supports
ETI's recovery of these costs. Accordingly, the ALJs recommend that these FERC-imposed costs
should be found to be recoverable and Cities' request to deny their recovery should be rejected.

           In summary, the ALJs conclude that, consistent with the requirements of P.U.C.       SUBST.

R. 25.236(d)(l), ETI met its burden to prove that: (1) its eligible fuel expenses during the
Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric
service to its retail customers; (2) the prices charges by its affiliates were reasonable and necessary
and no higher than the prices charged by the supplying affiliates to other affiliates or to unaffiliated
persons; and (3) ETI has properly accounted for the amount of fuel-related revenues collected
pursuant to the fuel factor during the Reconciliation Period.

                                      XII.    OTHER ISSUES

A.         MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket
           No. 39741 Preliminary Order Issue Nos. 1-9]

           Entergy is seeking to transfer operational control of the Entergy Operating Companies'
transmission assets to the MISO Regional Transmission Organization (RTO). ETI expects its share
of the costs for this transfer will include approximately $17 million of expense. 1054 ETI has made
two alternate proposals to recover these expenses. ETI's first proposal requests the Commission to
approve a deferred accounting of its transition expense incurred on or after January 1, 2011, and to
approve accrual of interest on the deferred amount at ETI's overall rate of return. Under this
proposal, ETI would present the resulting regulatory asset for review in a future proceeding. ETI

1052
       Cities Initial Brief at 86.
1053
       ETI Reply Brief at 93.
1054
       ETI Ex. 42 (Lewis Supplemental Direct) at 5.
                               ""--~·-···--··---------------------------

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PUC DOCKET NO. 39896

originally requested this deferred accounting in Docket No. 39741, which was later consolidated into
this case for all purposes. In its Preliminary Order in Docket 39741, the Commission stated that it
had authority to allow such a deferral of costs "when it is necessary to carry out a provision of
PURA." It also stated that whether ETI's request met this requirement "hinges on the factual issue
of necessity .... "

          As an alternative proposal, ETI requested the Commission to include $4 million of transition
expense in base rates set in the present case, based on a three-year amortization of a total of
$12 million in MISO transition expenses. ETI's Test Year MISO transition expenses totaled only
$916,535, but ETI's request for deferred accounting addressed expenses incurred on or after
January 1, 2011, which is after the Test Year concluded. ETI argues that its request is a conservative
known and measureable change because the post-Test-Year expenses will be significantly more than
$4 million per year. Further, these costs would be removed from ETI' s cost of service if its deferred
accounting proposal is approved.

          As noted, ETI' s proposals concern MISO transition expenses incurred on or after January 1,
2011. However, ETI also incurred $263,908 in these expenses during the 2010 portion of the Test
Year. ETI has proposed a five-year amortization of this amount ($52,800 per year), assuming either
its primary proposal or its alternative proposal is adopted. However, ifETI's primary and alternative
proposals are both rejected, ETI requested that no reduction be made to its total Test Year amount of
$916,535. 1055

          Cities, TIEC, State Agencies, and Staff opposed ETI' s requests. They argue that ETI failed to
establish that the proposed deferred accounting is necessary to carry out a provision of PURA, as
required by the Commission's Preliminary Order. They also contended that ETI' s alternate request
to include $4 million in base rates is not a known and measureable change and should be disallowed.

          The AU s recommend that the Commission deny ETI' s request for deferred accounting of its
MISO transition expenses to be incurred on or after January 1, 2011. However, the ALls do

1055
       ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L.
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PUC DOCKET NO. 39896

recommend that the Commission authorize ETI to include $2.4 million of MISO transition expense
in base rates set in the present case, based on a five-year amortization of $12 million in total
projected expenses.

          1. Deferred Accounting

          In support of its deferred accounting request, ETI cited State v. Public Utility Comm'n of
Texas. 1056 In that case, the Texas Supreme Court stated that a deferred accounting is "necessary"
when it will "ensure that the requirements of [PURA] are met." 1057 In ETI's opinion, deferred
accounting is necessary in the present case to ensure that PURA§§ 36.051and36.003(a) are met
{i.e., that utilities have a reasonable opportunity to recover their expenses and receive reasonable
rates). ETI also relied on Hammack v. Public Utility Commission of Texas, which stated that "a need
... is a relative requirement, ranging from an imperative need to one that is minimal ...." 1058

          ETl-witness Brett Perlman testified that deferred accounting is also necessary to ensure the
requirements of PURA § 31.001 (c) are carried out. 1059 That section encourages development of a
competitive wholesale electric market.           ETI noted that the Hammack opinion stated that
Section 31.00l(c) amounts to a "legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market." 1060 Therefore, ETI asserted
that RTO membership and deferred accounting are necessary because they will ensure that the
Commission meets its obligation under Section 31.00l(c). More specifically, ETI stated, bothRTO
membership and deferred accounting itself constitute examples of policies required by section
31.00l(c) to support wholesale competition. Therefore, ETI argues that its request for deferred

1056
       883 S.W.2d 190 (Tex. 1994).
1057
883 S.W.2d at 194.
1058
     Hammack v. Pub. Util. Comm'n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.-Austin 2004, pet.
denied).
1059
       ETI Ex. 43 (Perlman Supplemental Direct) at 7.
1060
       131 S.W.3dat723.
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PUC DOCKET NO. 39896

accounting should be approved because it is necessary to carry out PURA§§ 36.051, 36.003, and
31.00l(c). 1061

          Cities argue that ETI' s request for deferred accounting of MISO transition expenses should
be denied because deferred accounting is not necessary to carry out any requirement of PURA.
Cities witness James Brazell stated that ETI' s proposed transition to MISO is not mandatory, and the
anticipated expenses are not extraordinary. He added that ETI has been exploring membership in an
RTO for over ten years and those costs have historically been included in ETI' s base rates; therefore,
he concluded that deferred accounting was not necessary in the past and is not necessary now. Cities
stressed that ETI conceded that deferred accounting of these expenses is not necessary to maintain its
financial integrity, and in Cities' opinion, both State v. Public Utility Comm'n of Texas, 1062 and the
Commission's Preliminary Order require a showing of impairment of financial integrity to conclude
that deferred accounting is necessary to comply with PURA § 36.051. Cities also stated that ETI
failed to show that deferred accounting is necessary to comply with PURA §§ 36.003 and 31.001 (c);
therefore, Cities argues that ETI' s request for deferred accounting should be denied.

          TIEC also opposed ETI' s request for deferred accounting, arguing that ETI failed to
demonstrate that it is necessary to carry out PURA§§ 36.051, 36.003, or 31.00l(c). TIEC witness
Jeffry Pollock stated there is no indication that deferred accounting treatment is necessary for ETI to
earn a reasonable return on its invested capital or that denying the deferred accounting would prevent
ETI from having just and reasonable rates. Further, Mr. Pollock asserted there is no evidence that a
lack of deferred accounting treatment for ETI would prevent Entergy from pursuing its MISO
proposaI. 1063 Mr. Pollock added that ETI has incurred other similar costs to carry out various
purposes of PURA without deferred accounting. For example, since 2005, ETI has spent nearly
$20 million pursuing various similar activities, including transitioning to competition, investigating
RTO options, examining changes to the Entergy System Agreement, and supporting the Entergy

1061
   ETI' s Initial Brief at 231-234; ETI Ex. 42 (Lewis Supplemental Direct) at 2-4; ETI Ex. 43 (Perlman
Supplemental Direct) at 5-7.
1062
       883 S.W.2d 190 (Tex. 1994).
1063
       TIEC Ex. 1 (Pollock Direct) at 46-47.
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PUC DOCKET NO. 39896

OATT. Yet, ETI did not seek deferred accounting for any of those costs. Finally, Mr. Pollock
testified that the projected transition costs are not material. He noted that ETI expects to incur
$17 million of transition costs. 1064 This equates to $5.8 million per year, which is only l percent of
ETI's Test Year operating revenues, according to Mr. Pollock. In his opinion, this level of MISO
                                                                                               1065
transition costs is easily subsumed in the normal variation in ETI's year-to-year expenses.

                                                                                                      1066
          TIEC also disagreed with ETI's interpretation of State v. Public Utility Comm'n ofTexas.
In TIEC' s view, that case held that deferred accounting is necessary only when needed to protect the
financial integrity of the utility. Likewise, TIEC disagreed with ETI' s argument that Hammack 1067
held that "need" is a relative requirement that must be viewed in light of legislative policy
directives. 1068 TIEC noted that Hammack had nothing to do with deferred accounting. Instead, it
was limited to the issue of whether, in granting a certificate of convenience and necessity for a
transmission line under PURA §37.056, the Commission should include evidence that considered
customers and market participants throughout the state. 1069 In TIEC' s view, the Hammack case is
irrelevant in determining whether deferred accounting is necessary to carry out the provisions of
PURA§§ 36.003, 36.051, and 31.003(c). State Agencies made similar arguments.

          Commission Staff also argues that ETI did not establish why deferred accounting is necessary
to carry out a provision of PURA. In Staff's view, the applicable court cases and other precedent
required ETI to show that deferred accounting is necessary to maintain its financial integrity, in order
to carry out the provisions of PURA § 36.051. Staff argues that the Commission's Preliminary Order
did not reject the financial integrity standard when it stated: "[t]his standard is not appropriate,
however, for all circumstances and the Commission has applied different standards in various

1064
       ETI Ex. 42 (Lewis Supplemental Direct) at 5.
1065
       ETI Ex. 1 (Pollock Direct) at 48-49 and Ex. JP-8.
1066
       883 S.W.2d 190 (Tex. 1994).
1067
     Hammack v. Pub. Util. Comm'n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.-Austin 2004, pet.
denied).
1068
       ETI Initial Brief at 232-233.
1069
       Hammack v. Pub. Util. Comm'n of Texas, 131S.W.3d713, 724 (Tex .App.-Austin 2004, pet. denied).
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PUC DOCKET NO. 39896

circumstances." 1070 Rather, Staff stated, the Commission merely declined to designate a specific
standard.

          Staff also rejected ETI' s argument that deferred accounting will "ensure that the Commission
meets its obligation under Section 31.00 l (c) to support the achievement of a competitive wholesale
market." 1071 First, Staff noted, the Commission stated in the Preliminary Order that merely showing
movement towards a policy goal is not a sufficient standard upon which to approve deferral. ion
Thus, ETI' s statement that deferred accounting will "support" wholesale competition addresses a
standard that the Commission already rejected. Second, Staff argues that ETI failed establish that
deferred accounting is "necessary" to support a competitive wholesale market or that failure to allow
deferred accounting would prevent that goal. In other words, ETI did not show that, absent deferral,
it would not join MISO; thus, ETI did not show how deferral would "ensure" that it joins an RTO.
Therefore, Staff concluded, because ETI failed to prove that deferred accOlmting is necessary to cairy
out any provision of PURA, ETI' s request should be denied.

          In response to these arguments, ETI noted that no party disputed that the Commission may
grant deferred accounting "when it is necessary to carry out a provision of PURA." It also argues
that Staff and intervenors misinterpreted State v. Public Utility Comm'n ofTexas 1013 as holding that
deferred accounting is necessary to carry out PURA § 36.051 only when a utility's financial integrity
is at stake. Although lack of financial integrity is an indication that PURA § 36.051 has not been
carried out, ETI noted that this section contains other express requirements that can be met through
deferred accounting, such as ensuring utilities a reasonable opportunity to recover their costs. ETI
also cited other Commission cases in which it authorized deferred accounting when financial
integrity was not at stake, such as deferral of rate case expenses and merger costs for subsequent

1070
   Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to
Membership in The Midwest Independent Transmission System Operator, Docket No. 39741 Preliminary
Order at 9 (Sep. 2, 2011).
1071
       ETI Initial Brief at 234.
1072
       Docket No. 39741, Preliminary Order at 11.
1073
       883 S.W.2d 190 (Tex. 1994).
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PUC DOCKET NO. 39896

review and recovery. 1074 ETI added that deferred accounting would permit the Commission to
review ETI's transition expenses in a subsequent proceeding, after determining whether ETI's
transition to MISO is in the public interest. Thus, under ETI's proposal, there is no risk that ETI
would recover such costs absent a finding that they are reasonable and necessary.

          As for Staff and TIEC's argument that deferred accounting is not necessary to carry out
PURA§ 31.00l(c), ETI argues that the "necessary" standard is not a "but for" test. In response to
arguments that the proposed deferred accounting will merely further policy objectives of
Section 31.001 (c), which the Commission has deemed insufficient to meet the "necessary"
standard, 1075 ETI reiterated that the Hammack opinion held that "the Commission's interpretation of
need must be viewed in light of the legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market," as well as "overall policy
objectives." 1076 Thus, ETI argues, that it has demonstrated that deferred accounting is necessary to
carryout Section 31.00l(c)- i.e., it will "ensure" that the requirements of that provision are carried
out, and in particular ensure that the Legislature's specific instruction to develop the wholesale
market is carried out. 1077

          Although ETI's proposal for deferred accounting has some practical appeal, the ALls
conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The AU s
find that ETI was not required to show that a deferred accounting is necessary to maintain its
financial integrity, as argued by intervenors. In State v. Public Utility Comm 'n of Texas, 1078 the
Texas Supreme Court held that preserving the financial integrity of a utility was necessary to carry
out a provision of PURA, and thus justified deferred accounting for certain expenses in that case, but
the court did not hold that preserving financial integrity was the sole basis upon which a deferred

1074
       ETI Reply Brief at 95-96.
1075
       Docket No. 397 41, Preliminary Order at 7.
1076
     Hammack v. Pub. Util. Comm'n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.-Austin 2004, pet.
denied).
1077
       ETI Reply Brief at 97-99.
1078
       883 S.W.2d 190 (Tex. 1994).
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PUC DOCKET NO. 39896

accounting could be approved.          Likewise, in its Preliminary Order for the present case, the
Commission stated:        "This standard [financial integrity] is not appropriate, however, for all
circumstances and the Commission has applied different standards in various circumstances,
although none of these standards or circumstances has been reviewed by any court." 1079 On the other
hand, the ALls also find that ETI's contention that deferred accounting of the MISO transition
expenses will help the development of a competitive wholesale electric market, as described in
PURA § 31.001 (c ), is not sufficient to authorize deferred accounting. Again, the Commission stated
in the Preliminary Order that "to carry out a provision of PURA" means more than undefined
progress or movement towards a statutory objective. 1080

           The Commission made clear that ETI' s burden was not only to show that a provision of
PURA would be carried out by an accounting deferral of the MISO transition expenses, but that the
deferral is necessary to carry out that provision. The Commission added that necessity was a
question of fact that "can only be determined after development of an adequate factual record that
demonstrates the necessity, of whatever degree." 1081 Intervenors argue that Entergy's efforts to
transfer operational control of the Entergy Operating Companies' transmission assets to MISO will
proceed with or without the deferred accounting requested by ETI; thus, deferred accounting is not
necessary. Likewise, intervenors argue that ETI's alternate proposal to recover the transition costs
through base rates shows that deferred accounting is not necessary. ETI, however, asserted that
necessity should not be considered a "but for" requirement. It noted that no provision of PURA
would be impossible to carry out absent a deferral of rate case expenses or merger expenses, yet the
Commission has allowed deferred accounting of such expenses in other cases. ETI also cited the
statement in Hammack v. Public Utility Commission of Texas that "a need . . . is a relative
requirement, ranging from an imperative need to one that is minimal ...." 1082 Intervenors criticized
ETI' s reliance on the Hammack case because it concerned a transmission line. While that is correct,

1079
       Docket No. 39741, Preliminary Order at 9 (Nov. 22, 2011).
1080
       Id. at 11.
1081
       Id. at 8.
1082
       Hammack v. Pub. Util. Comm'n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.-Austin 2004, pet.
denied).
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PUC DOCKET NO. 39896

the case does make the general point that the question of need is not an absolute "but for" test. This
is also consistent with the Commission's statement in the Preliminary Order that ETI' s burden was to
demonstrate necessity, "of whatever degree."

       ETI' s complaint is that its MISO transition expenses will soon increase above the Test Year
amount, from $916,535 for the Test Year to over $5 million per year, but it will not be able to
recover the increased costs through normal Test Year cost-of-service ratemaking principles. Thus,
although ETI' s financial integrity may not be jeopardized, ETI argues that it nevertheless will not be
able to have a reasonable opportunity to recover its expenses and receive reasonable rates as required
by PURA§§ 36.051 and 36.003(a). Therefore, ETI believes the proposed deferred accounting is
necessary to carry out those provisions of PURA.

       The AU s find that the essence of ETI' s complaint is that regulatory lag works against it in
this particular situation. But as noted by the court in State v. Public Utility Comm'n of Texas,
regulatory lag is an ordinary element of risk for utilities. 1083 One of the characteristics of Test Year
cost-of-service ratemaking is that some expenses upon which rates are based may go up and others
may go down during the time the rates are in effect. Such changes can be corrected in future
ratemaking proceedings, but in this case ETI desires to ensure that it will recover all of its MISO
transition costs. But State v. Public Utility Comm'n of Texas and the Commission's Preliminary
Order in this case make clear that eliminating the normal effects of regulatory lag by allowing a
deferred accounting should not be undertaken lightly. If ETI's arguments were taken to their
extreme, a utility could obtain deferred accounting any time it anticipated a post Test Year increase
in a particular expense, under the argument that it must be allowed to recover all of its expenses to
carry out the requirements of PURA§§ 36.051and36.003(a). In this case, ETI's estimated MISO
transition costs will equal about $5.8 million per year. As Mr. Pollock noted, this is only one percent
of ETI' s Test Year operating revenues, which may easily be subsumed in the normal variation in
ETI's year-to-year expenses. Under these circumstances, ETI has not shown that granting its
requested deferred accounting is necessary to carry out the requirements of PURA §§ 36.051 and
36.003(a) that it receive just and reasonable rates. Therefore, the ALls recommend that the
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PUC DOCKET NO. 39896

Commission deny ETI' s request for deferred accounting treatment of its MISO transition expenses to
be incurred on or after January 1, 2011.

        2. Base Rate Recovery

        As mentioned above, if the Commission denies ETI's request for deferred accounting, ETI
requested the Commission to include $4 million of MISO transition expense in base rates set in the
present case, based on a three-year amortization of $12 million in total projected expenses.

        Cities disputed the amount of MISO expenses ETI requested in this proposal. Cities witness
Mark Garrett testified that a $4 million annual expense is inconsistent with ETI' s own projected
costs. The Test Year expenses were $916,535, and the actual expenses incurred during January
through November 2011 were only $2.513 million, which annualized would be $2.742 million..
For 2013, ETI projected MISO transition expenses of only $2.587 million, although ETI's
projected 2012 level of $8.9 million. However, Mr. Garrett added that 2012 is an estimated level and
is not consistent with actual 2011 results. In his opinion, the actual 2011 level of about $2. 7 million
or the expected 2013 level of about $2.6 million should be the outside range of what the Commission
should use for setting prospective rates. In any event, however, Cities argue that these projected
levels are not sufficiently known and measurable to include for ratemaking purposes. Cities pointed
out that it is unknown whether ETI' s proposed move to MISO will even be approved, or whether the
ETI will even continue to incur costs toward a MISO transition. Therefore, Cities argues that only
the Test Year level of $916,535 should be included in rates, which would result in a downward
adjustment of $3,083,462 to ETI's request. 1084

        TIEC also argues that ETI' s alternative proposal should be rejected. Mr. Pollock complained
that this proposal would allow ETI to recover post Test Year expenses that are not known and
measureable. Mr. Pollock noted that ETI' sown estimate of its share of transition costs has changed.
When ETI filed its request for deferred accounting in Docket No. 39741, it estimated transition costs

t0s 3 883 S.W.2d 190, 196 (Tex. 1994).
1084
     Cities Ex. 2 (Garrett Direct) at 61-63 and Ex. MG2.14; Cities Initial Brief at 89-91; Cities Reply Brief
at 112-113.
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PUC DOCKET NO. 39896

of $12 million. Now it estimates costs of $17 million, an increase of over 40 percent. Further,
Mr. Pollock stated, ETI based its share of the estimated transition costs by assuming a 17 percent
responsibility ratio, but ETI's future responsibility ratios are not known because they are based on
projected growth rates of ETI relative other Entergy Operating Companies. Thus, Mr. Pollock
concluded that ETI' s share of future MISO transition costs cannot be appropriately measured. toss In
summary, TIEC argues that the Commission should deny ETI' s request for deferred accounting and
should allow ETI to recover only Test Year MISO transition expenses. to86 Commission Staff made
arguments similar to Cities and TIEC. 1087

          In response, ETI argues that the $4 million annual expense requested is known and
measurable. ETI noted that it already incurred over $3.6 million in transition expense in the nine
months since the end of the Test Year, 1088 which equates to $4.8 million on an annual basis.
Furthermore, ETI' s expects $17 million in transition expenses to be incurred over three years, which
equates to $5.8 million annually. 1089 lnETI's view, the issue is whether it is sufficiently known that
ETI will incur at least $12 million in transition expense, not whether ETI can predict an exact level
of future expense. 1090

          The AUs recommend that the Commission authorize ETI to include $2.4 million in base
rates set in the present case for MISO transition expense incurred on or after January 2, 2011, based
on a five-year amortization of $12 million in total projected expenses. The primary argument of
intervenors against the adjustment is that the total of $12 million is not a known and measurable
change. However, the AUs find that ETI's evidence established that such expenses will total at
least $12 million. It is true that the Test Year expenses were less, but ETI filed its application to
effectuate the transfer to MISO in 2012, so it is clear that those expenses will increase significantly

1085
       TIEC Ex. 1 (Pollock Direct) at 49-50.
1086
       TIEC Initial Brief at 97-98; TIEC Reply Brief at 70-71.
1087
       Staff Reply Brief at 65-66.
1088
       ETI Ex. 46 (Considine Rebuttal), Ex. MPC-R-1.
1089
       TIEC Ex. 1 (Pollock Direct) at 48:3-4.
1090
       ETI Initial Brief at 236-239; ETI Reply Brief at 99-100.
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PUC DOCKET NO. 39896

to levels well above the Test Year amount. It is true that ETI has not established the precise total
amount of MISO transition expenses it will incur, but the ALJs find that those expenses will likely
exceed the $12 million included in ETI's request. ETI requested that the $12 million total be
amortized over three years, which would produce a $4 million annual cost. However, ETI also
requested to amortize over five years its $263,908 in MISO transition expenses that were incurred
during the 2010 portion of the Test Year ($52,800 per year). If a five-year amortization is
appropriate for those expenses, a five-year amortization would also be appropriate for the post Test
Year MISO transition expenses. Therefore, the ALJs recommend that the Commission authorize
ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test
Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800.

B.         TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]

           In its Supplemental Preliminary Order, the Commission found that it would be appropriate to
establish for ETI baseline values for a TCRF and a DCRF, which may be established in future
dockets. ETI' s filing package included worksheets for these baseline values, 1091 and ETI attached
revised versions of the worksheets to its initial brief to reflect ETI' s revised depreciation
calculations. The revised version of the transmission worksheet calculated total transmission cost
baseline revenue requirements of $75,074,987-Total Company and $74,997,366-Retail. 1092
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI' s requested costs, ETI proposes filing another revised
TCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of
the Commission. 1093 TIEC, Cities, and Staff also point out that various items in ETI's calculation
have been contested. Therefore, they also recommend that the baseline values be set during the
compliance phase of this case. The ALJ s agree that TCRF baseline values should be set during the
compliance phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.

1091
       ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1092
       ETI Initial Brief at 239 and Attachment 1.
1093
       ETI Initial Brief at 239.
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PUC DOCKET NO. 39896

C.        DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]

          As discussed above, the Commission found in its Supplemental Preliminary Order that it
would be appropriate to establish for ETI baseline values for a DCRF, which may be established in a
future docket. ETI' s filing package included worksheets for a DCRF baseline value, 1094 and ETI
attached a revised version of the worksheet to its initial brief to reflect ETI' s revised depreciation
calculations. The revised version of the distribution worksheet calculated total distribution cost
baseline revenue requirements of $163,560,232-Total Company and $161,537,490-Retail. 1095
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI' s requested costs, ETI proposes filing another revised
DCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of
the Commission. 1096 TIEC, Cities, and Staff also recommend that the baseline values be set during
the compliance phase of this case. The ALl s agree that DCRF baseline values should be set during
the compliance phase of this docket, after the Commission makes final rulings on the various
contested issues that may affect this calculation.

D.        Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary
          Order Issue No. 1]

          ETI requested a PPR rider in its application, but the Commission held in its Supplemental
Preliminary Order that the proposed rider should not be considered due to the pending rulemaking
Project No. 39246, which was opened to consider purchased capacity riders.              However, the
Commission did add the following issue to the present case: "What is the amount of purchased-
capacity costs that are proposed to be included in Entergy' s base rates?" ETI requested authority to
include $275,809,485 in its PPR rider, but because the Commission excluded the PPR rider from
consideration, this amount would now be included in base rates. ETI acknowledged that this amount

1094
       ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1095
       ETI Initial Brief at 239 and Attachment 2.
1096
       ETI Initial Brief at 239.
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PUC DOCKET NO. 39896

should be revised to correspond with the Commission's final decision on purchased power capacity
                                    1097
recovery (See Section VII.A.).

           State Agencies noted that ETI' s purchased power request included the following:

                      1.    Third-party contracts;
                      2.    Legacy affiliate contracts;
                      3.    Other affiliate contracts; and
                      4.    Reserve Equalization.

The costs for all of these but third-party contracts are determined through various MSS Schedules in
the FERC-approved Entergy System Agreement. Therefore, State Agencies argue that if the
Commission decides to allow purchased capacity cost recovery riders in Project No. 39246, the
baseline costs for ETI should be limited to only the purchased capacity costs associated with
non-affiliate third-party contracts. In State Agencies' opinion, ETI should not be allowed to pass
through purchased capacity costs associated with legacy and other affiliate contracts or reserve
equalization purchases, because those are not market competitive contracts. Instead, according to
State Agencies, the affiliate contracts and reserve equalization purchases are essentially agreements
to share centralized planned generation capacity resources among Entergy Operating Companies and
to allocate generation costs among those companies. State Agencies also noted that these capacity
payments are determined based on formulae in Service Schedules MSS-1 and MSS-4, included in the
FERC-approved Entergy System Agreement. In other words, these costs are not driven by market
prices and are not subject to market price volatility. Therefore, State Agencies argue that purchases
other than third-party contracts should not be used as a baseline for any rider intended to address
market price volatility and competitive wholesale market pressure for purchased generation
         . •   1098
capacities.

1097
       ETI Initial Brief at 240.
1098
       State Agencies Ex. 2 (Pevoto Direct) at 17.
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PUC DOCKET NO. 39896

          Cities agree with the arguments of State Agencies. fu addition, Cities stressed that if the
Commission establishes a baseline for purchased power capacity costs, the baseline should reflect the
unit cost of capacity rather than total dollars. Cities witness Nalepa testified that the unit cost would
provide a more accurate measure than total dollars. fu Cities• opinion, if a unit cost finding is not
made in this case, then Commission will be prevented from considering all options in the
rulemak:ing.

          TIEC points out that the notice in Project No. 39246 provided that "[t]he purpose of this
rulemak:ing project is to address the recovery of purchased power capacity costs considering
generation embedded in base rates, load growth, and the impact of purchased power capacity
recovery on the financial standing of the utility." 1099 Accordingly, TIEC argues that the baseline set
in this proceeding should reflect ETI' s total purchased power and installed capacity costs determined
to be properly included in base rates on a total cost basis and on a per unit ($/MW) basis. 1100

          As discussed in Section VII.A., the ALJ s find that the appropriate amount for ETI' s
purchased power capacity expense to be included in base rates is $245,432,884. This responds to the
issue included in the Commission's Supplemental Preliminary Order. This amount includes third-
party contracts, legacy affiliate contracts; other affiliate contracts; and reserve equalization. Whether
the amounts for all contracts should be included in the baseline for a purchased capacity rider that
may be approved in Project No. 39246 is an issue that should be decided in that proceeding, not in
the present case. Therefore, the ALJ s make no recommendation on that issue raised by the
intervenors.

                                     XIII.     CONCLUSION

          The AUs recommend that the Commission implement the findings of the AUs set forth in
the discussion above by adopting the following proposed findings of fact and conclusions of law in
the Commission's final order.

1099
       Project No. 39246, Public Notice (May 10, 2011).
1100
       TIEC Initial Brief at 99.
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PUC DOCKET NO. 39896

     XIV.   PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
                          ORDERING PARAGRAPHS

A.     Findings of Fact

Procedural History

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

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

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

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

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

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

7.     On November 29, 2011, the Commission referred this case to the State Office of
       Administrative Hearings (SOAH).
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PUC DOCKET NO. 39896

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 (AUs) 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 AU s 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.   OnApril4, 2012, theAUs issued SOAH Order No. 13 severingratecaseexpenseissues into
      Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket
      No. 39896, Docket No. 40295 (pending).

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

16.   The hearing on the merits commenced on April 24 and concluded on May 4, 2012.

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

Rate Base

18.   Capital additions that were closed to ETI's plant-in-service between July 1, 2009, and June
      30, 2011, are used and useful in providing service to the public and were prudently incurred.
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PUC DOCKET NO. 39896

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

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

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

22.   A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
      remain in rate base, applying a five-year amortization rate beginning August 15, 2010.

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

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

25.   The Prepaid Pension Assets Balance includes $25 ,311,236 capitalized to construction work
      in progress (CWIP).

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

27.   The portion of the Prepaid Pension Assets Balance that is capitalized to CWIP should not be
      included in ETI' s rate base.

28.   The remainder of the Prepaid Pension Assets Balance should be included in ETI' s rate base.

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

30.   The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48),
      "Accountingfor 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.
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31.   FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
      Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting purposes
      and record it as a potential liability with interest to better reflect the Company's financial
      condition.

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

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

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

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

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

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

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

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

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

41.   ETI has not proven that a tracking mechanism or rider to collect a return on FIN 48 Liability
      is necessary.

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

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

44.   The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for
      known and measurable changes, and isconsistentwithP.U.C. SUBST. R. 25.231(c)(2)(B)(iii).
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PUC DOCKET NO. 39896

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 primafacie 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.

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

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

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

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

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

57.   The amount of $1,127,778, representing costs incurred by ETI when it acquired the
      Spindletop facility, represent actual costs incurred to process and close the acquisition, not
      mere mark-up costs.
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58.   ETI' s $1, 127,778 in capitalized acquisition costs should be included in rate base because ETI
      incurred these costs in conjunction with the purchase of a viable asset that benefits its retail
      customers.

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

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

61.    The portion of ETI' s incentive payments that are capitalized and that are financially-based
       should be excluded from ETI' s rate base because the benefits of such payments inure most
       immediately and predominantly to ETI's shareholders, rather than its electric customers.

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

63.    In this proceeding, ETI' s capitalized incentive compensation that is financially-based should
       be excluded from rate base, but only for incentive costs that ETI capitalized during the period
       from July 1, 2009 (the endofthepriorTest Year)throughJune30, 2010 (the commencement
       of the current Test Year).

Rate of Return and Cost of Capital

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

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

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

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

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

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

70.    A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI
       attract capital from investors.
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PUC DOCKET NO. 39896

71.   ETI'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%

Operating Expenses

72.    ETI's Test Year purchased capacity expenses were $245.432,884.

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

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

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

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

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

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

79.    ETI' s estimates of its Rate Year purchases under affiliate contracts are based on a
       mathematical formula set out in Schedule MSS-4.

80.    The MSS-4 formula for Rate Year affiliate capacity payments reflects that these payments
       will be based on ratios and costs that cannot be determined until the month that the payments
       are to be made.
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PUC DOCKET NO. 39896

81.   Over $11 million ofETI's affiliate transactions were basedona2013 contract(theEAIWBL
      Contract) that was not signed until April 11, 2012.

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

83.   ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the Rate
      Year than it purchased in the Test Year.

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

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

86.   ETI's purchased capacity expense in this case should be based on the Test Year level of
      $245 ,432,884.

87.   ETI incurred $1,753,797 of transmission equalization expense during the Test Year.

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

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

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

91.   ETI seeks increased transmission equalization expenses for transmission projects that are not
      currently used and useful in providing electric service. ETI's post-Test Year adjustment is
      based on the assumption that certain planned transmission projects will go into service after
      the Test Year. At the close of the hearing, none of the planned transmission projects had
      been fully completed and some were still in the planning phase.

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

93.   ETI's request for a post-Test Year adjustment of $8,942,785 for Rate Year transmission
      equalization expenses should be denied because those expenses are not known and
      measurable. ETI' s post-Test Year adjustment does not with reasonable certainty reflect what
      ETI' s transmission equalization expense will be when rates are in effect.
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PUC DOCKET NO. 39896

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

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

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

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

98.    Except as described below, the service lives and net salvage rates proposed by the Company
       are reasonable, and these service lives and net salvage rates should be used in calculating
       depreciation rates for the Company's Production, Transmission, Distribution, and General
       Plant assets.

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

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

101.   Production plant net salvage is reasonably based on the negative five percent net salvage in
       existing rates.

102.   The net salvage rate of negative 10 percent for ETI's transm1ss10n structures and
       improvements (FERC Account 352) is the most reasonable of those proposed and should be
       adopted.

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

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

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

106.   The net salvage rate of negative 30 percent for ETI' s transmission overhead conductors and
       devices (FERC Account 356) is the most reasonable of those proposed and should be
       adopted.
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PUC DOCKET NO. 39896

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

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

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

110.   A service life of 35 years and a dispersion curve of Rl.5 for ETI's distribution underground
       conductors and devices (FERC Account 367) are the most reasonable of those proposed and
       should be approved.

111.   A service life of 33 years and a dispersion curve of L0.5 for ETI's distribution line
       transformers (FERC Account 368) are the most reasonable of those proposed and should be
       approved.

112.   A service life of 26 years and a dispersion curve ofL4 for ETI' s distribution overhead service
       (FERC Account 369.1) are the most reasonable of those proposed and should be approved.

113.   The net salvage rate of negative five percent for ETI's distribution structures and
       improvements (FERC Account 361) is the most reasonable of those proposed and should be
       adopted.

114.   The net salvage rate of negative 10 percent for ETI' s distribution station equipment (FERC
       Account 362) is the most reasonable of those proposed and should be adopted.

115.   The net salvage rate of negative seven percent for ETI' s distribution overhead conductors and
       devices (FERC Account 365) is the most reasonable of those proposed and should be
       adopted.

116.   The net salvage rate of negative five percent for ETI' s distribution line transformers (FERC
       Account 368) is the most reasonable of those proposed and should be adopted.

117.   The net salvage rate of negative 10 percent for ETI' s distribution overhead services (FERC
       Account 369.1) is the most reasonable of those proposed and should be adopted.

118.   The net salvage rate of negative 10 percent for ETI's distribution underground services
       (FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119.   A service life of 45 years and a dispersion curve of R2 for ETI's general structures and
       improvements (FERC Account 390) are the most reasonable of those proposed and should be
       approved.
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PUC DOCKET NO. 39896

120.   The net salvage rate of negative 10 percent for ETI's general structures and improvements
       (FERC Account 390) is the most reasonable of those proposed and should be adopted.

121.   It is reasonable to convert the $21.3 million deficit that has developed over time in the
       reserve for general plant accounts to General Plant Amortization.

122.   A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable
       and should be adopted.

123.   FERC pronouncement AR-15 requires amortization over the same life as recommended
       based on standard life analysis. A standard life analysis determined that a five-year life was
       appropriate for general plant computer equipment (FERC Account 390.2). Therefore, a five
       year amortization for this account is reasonable and should be adopted.

124.   ETI proposed adjustments to its Test Year payroll costs to reflect: (a) changes to employee
       headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases
       set to go into effect after the end of the Test Year.

125.   The proposed payroll adjustments are reasonable but should be updated to reflect the most
       recent available information on headcount levels as proposed by Commission Staff. In
       addition to adjusting payroll expense levels, the more recent headcount numbers should be
       used to adjust the level of payroll tax expense, benefits expense, and savings plan expense.

126.   Staff has appropriately updated headcount levels to the most recent available data but errors
       made by Staff should be corrected. The corrections related to: (a) a double counting of three
       ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the
       calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when
       such costs were already included in the benefits percentage adjustments; and (d) corrections
       for full-time equivalents calculations. Staffs ETI headcount adjustment (AG-7) overstated
       operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount
       adjustment (AG-7) understated O&M payroll increase by $37,531.

127.   ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128.   The compensation packages that ETI offers its employees include a base payroll amount,
       annual incentive programs, and long-term incentive programs. The majority of the
       compensation is for operational measures, but some is for financial measures.

129.   Incentive compensation that is based on financial measures is of more immediate and
       predominant benefit to shareholders, whereas incentive compensation based on operational
       measures is of more immediate and predominant benefit to ratepayers.

130.   Incentives to achieve operational measures are necessary and reasonable to provide utility
       services but those to achieve financial measures are not.
                             ~~···--····--------------------------

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PUC DOCKET NO. 39896

131.   The $5,376,975 that was paid for long term incentive programs was tied to financial
       measures and, therefore, should not be included in ETI' s cost of service.

132.   Of the amounts that were paid pursuant to the Exeeutive Annual Incentive Plan, $819,062
       was tied to financial measures and, therefore, should be disallowed.

133.   In total, the amount of incentive compensation that should be disallowed is $6,196,037
       because it was related to financial measures that are not reasonable and necessary for the
       provision of electric service.

134.   The amount of incentive compensation that should be included in the cost of service is
       $7,991,707.

135.   To attract and retain highly qualified employees, the Entergy Companies provide a total
       package of compensation and benefits that is equivalent in scope and cost with what other
       comparable companies within the utility business and other industries provide for their
       employees.

136.   When using a benchmark analysis to compare companies' levels of compensation, it is
       reasonable to view the market level of compensation as a range rather than a precise, single
       point.

137.   ETI's base pay levels are at market.

138.   ETI' s benefits plan levels are within a reasonable range of market levels.

139.   ETI's level of compensation and benefits expense is reasonable and necessary.

140.   ETI provides non-qualified supplemental executive retirement plans for highly compensated
       individuals such as key managerial employees and executives that, because of limitations
       imposed under the Internal Revenue Code, would otherwise not receive retirement benefits
       on their annual compensation over $245,000 per year.

141.   ETI' s non-qualified supplemental executive retirement plans are discretionary costs designed
       to attract, retain, and reward highly compensated employees whose interests are more closely
       aligned with those of the shareholders than the customers.

142.   ETI's non-qualified executive retirement benefits in the amount of $2,114,931 are not
       reasonable or necessary to provide utility service to the public, not in the public interest, and
       should not be included in ETI' s cost of service.

143.   For the employee market in which ETI operates, most peer companies offer moving
       assistance. Such assistance is expected by employees, and ETI would be placed at a
       competitive disadvantage if it did not offer relocation expenses.

144.   ETI's relocation expenses were reasonable and necessary.
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PUC DOCKET NO. 398%

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 $1,214,688.

152.   Staff recommended reducing ETI's advertising, dues, and contributions expenses by $12,800.
       The recommendation, which no party contested, should be adopted.

153.   The final cost of service should reflect changes to cost of service that affect other
       components of the revenue requirement such as the calculation of the Texas state gross
       receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
       Expenses.

154.   The Company's requested Federal income tax expense is reasonable and necessary.

155.   ETI's request for $2,019,000 to be included in its cost of service to account for the
       Company's annual decommissioning expenses associated with River Bend is not reasonable
       because it is not based upon "the most current information reasonably available regarding the
       cost of decommissioning" as required by P.U.C. SUBST. R. 25.23l(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.
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PUC DOCKET NO. 39896

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, 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
       neces'sary 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.

165.   ETI agreed to remove the following affiliate transactions from its application:
       (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
       (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and
       (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166.   The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with
       Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual
       Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of
       electric utility service and are not in the public interest.

167.   The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement)
       are not normally-recurring costs and should not be recoverable.

168.   The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related
       to ESI's operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy
       New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.
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PUC DOCKET NO. 39896

169.    The $171,032 of costs associated with Project F3PPE9981 S (futegrated 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, fuc.

172.    ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
        docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the
        wholesale load results in a retail production demand allocation factor of 95.3838 percent.

173.    The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by
        the FERC to allocate between jurisdictions.

174.    Using 12CP methodology to allocate production costs between the wholesale and retail
        jurisdictions is the best method to reflect cost responsibility and is appropriate based on
        ETI's reliance on capacity purchases.

Class Cost Allocation and Rate Design

17 5.   There is no express statutory authorization for ETI' s proposed Renewable Energy Credits
        Rider (REC Rider).

176.    REC Rider constitutes improper piecemeal ratemaking and should be rejected.

177.    ETI' s Test Year expense for renewable energy credits, $623,303, is reasonable and necessary
        and should be included in base rates.

178.    Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
        public rights-of-way to locate its facilities within municipal limits.

179.    ETI is an integrated utility system. ETI' s facilities located within municipal limits benefit all
        customers, whether the customers are located inside or outside of the municipal limits.

180.    Because all customers benefit from ETI's rental of municipal right-of-way, municipal
        franchise fees should be charged to all customers in ETI' s service area, regardless of
        geographic location.
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181.   It is reasonable and consistent with the Public Utility Regulatory Act (PURA)§ 33.008(b)
       that MFF be allocated to each customer class on the basis of in-city kilo-watt hour (kWH)
       sales, without an adjustment for the MFF rate in the municipality in which a givenkWH sale
       occurred.

182.   The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-
       181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The
       Company's proposed allocation of these costs to all retail customer classes based on
       customer class revenues relative to total revenues is appropriate.

183.   The Average and Excess (A&E) 4CP method for allocating capacity-related production costs,
       including reserve equalization payments, to the retail classes is a standard methodology and
       the most reasonable methodology.

184.   The A&E 4CP method for allocating transmission costs to the retail classes is standard and
       the most reasonable methodology.

185.   ETI appropriately followed the rate class revenue requirements from its cost of service study
       to allocate costs among customer classes. ETI' s revenue allocation properly sets rates at each
       class's cost of service.

186.   It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
       Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
       replacement of a functioning light with a lower-wattage bulb.

187.   It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study
       regarding the feasibility of instituting LED-based rates and, if the study shows that such rates
       are feasible, ETI should file proposals for LED-based lighting and traffic signal rates it next
       rate case.

188.   An agreement was reached by the parties and approved by the Commission in Docket
       No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
       ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial
       Power Service-Time of Day, General Service, General Service-Time of Day, Large General
       Service, and Large General Service-Time of Day rate schedules.

189.   ETl's proposed tariffs in this case did not remove the life-of-contract demand ratchet from
       these rate schedules consistent with the parties' agreement in Docket No. 37744.

190.   A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is
       not reasonable.

191.   ETI's proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
       agreement that was adopted by the Commission as just and reasonable in Docket No. 37744.
       Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194.
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192.   ETI' s Schedule LIPS and LIPS Time of Day § VI should be changed to read:

                      DETERMINATION OF BILLING LOAD

                      The kW of Billing Load will be the greatest of the following:

                      (A) The Customer's maximum measured 30-minute demand
                      during any 30-minute interval of the current billing month,
                      subject to§§ III, IV and V above; or

                      (B) 60% of Contract Power as defined in § VII; or

                      (C) 2,500 kW.

193.   ETI' s Schedule LIPS and LIPS Time of Day § VII should be changed to read:

                      DETERMINATION OF CONTRACT POWER

                      Unless Company gives customer written notice to the contrary,
                      Contract Power will be defined as below:

                      Contract Power - the highest load established under § Vl(A) above
                      during the 12 months ending with the current month. For the initial
                      12 months of Customer's service under the currently effective
                      contract, the Contract Power shall be the kW specified in the
                      currently effective contract unless exceeded in any month during the
                      initial 12-month period.

194.   The Large General Service and Large General Service-Time of Day schedules should be
       similarly revised to eliminate ETI's life-of-contract demand ratchet.

195.   In its proposed rate design for the LIPS class, the Company took a conservative approach and
       increased the current rates by an equal percentage. This minimized customer bill impacts
       while maintaining cost causation principles on a rate class basis.

196.   It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS
       rate schedule with subsequent increases to be considered in subsequent base rate cases.

197.   It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges
       and increase the demand charges as proposed by Staff witness William B. Abbott.

198.   DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent Pumping
       Service" (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-
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PUC DOCKET NO. 39896

       season (November through April), that can be cancelled at any time, and for load not lasting
       more than 80 hours in a year. For customers whose loads match these SIPS characteristics
       (for example, DOE's Strategic Petroleum Reserve), the 12-month demand ratchet provision
       of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The
       monthly demand set under the SIPS provisions would be applicable for billing purposes only
       in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in
       that month, it would be forgiven and not applicable in the succeeding 12 months.

199.   DOE' s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It
       more closely addresses specific customer characteristics and provides for cost-based rates, as
       does another ETI rider applicable to Pipeline Pumping Service.

200.   Standby Maintenance Service (SMS) is available to customers who have their own
       generation equipment and who contract for this service from ETI.

201.   P.U.C. SUBST. R. 25.242(k)(l) provides that rates for sales of standby and maintenance
       power to qualifying facilities should recognize system wide costing principles and should not
       be discriminatory.

202.   It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
       charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing
       supplementary power under another applicable rate; and (b) revising the tariff as follows:

                                        Distribution         Transmission
                        Charge
                                     (less than 69KV)     (69KV and greater)
                     Billing Load Charge ($/kW):
                     Standby            $2.46                    $0.79
                     Maintenance        $2.27                    $0.60
                     Non-Fuel Enernv Charge (¢/kWh)
                     On-Peak           0.881¢                   0.846¢
                     Off-Peak          0.575¢                   0.552¢

203.   ETI's Additional Facilities Charge Rider (Schedule AFC) prescribes the monthly rental
       charge paid by a customer when ETI installs facilities for that customer that would not
       normally be supplied, such as line extensions, transformers, or dual feeds.

204.   ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
       Option B, which applies when a customer elects to amortize the directly-assigned facilities
       over a shorter term ranging from one to ten years, has a variable monthly charge. There is
       also a term charge that applies after the facility has been fully depreciated.
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PUC DOCKET NO. 39896

205.   It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per
       month of the installed cost of all facilities included in the agreement for additional facilities.

206.   It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the
       Post Term Recovery Charge as follows:

       Selected Recovery Term        Recovery Term Charge        Post Recovery Term Charge
                    1                        10.88%                          0.35%
                   2                         5.39%                           0.35%
                   3                         3.92%                           0.35%
                   4 '                       3.20%                           0.35%
                   5                         2.76%                           0.35%
                   6                         2.48%                           0.35%
                   7                         2.28%                           0.35%
                   8                         2.14%                           0.35%
                   9                          1.97%                          0.35%
                   10                         1.94%                          0.35%

207.   The revisions in the above Findings of Fact to Schedule AFC rates reasonably reflect the
       costs of running, operating, and maintaining the directly-assigned facilities.

208.   It is reasonable to modify the Large General Service rate schedule by increasing the demand
       charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to $.00513; and
       maintaining the customer charge at $425.05.

209.   Staffs proposed change to the General Service (GS) rate schedule to gradually move GS
       customers towards their cost of service by recommending a decrease in the customer charge
       from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable
       and should be adopted.

210.   ETI's Residential Service (RS) rate schedule is composed of two elements: a customer
       charge of $5 per month and a consumption-based energy charge. The Energy charge is a
       fixed rate of 5.802¢ per kWh from May through October (Summer). In the months
       November through April (Winter), the rates are structured as a declining block, in which the
       price of each unit is reduced after a defined level of usage.

211.   ETI' s Schedule RS declining block rate structure is contrary to energy efficiency efforts and
       the Legislature's goal of reducing both energy demand and energy consumption in Texas, as
       stated in PURA§ 39.905.
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PUC DOCKET NO. 39896

212.   Schedule RS winter block rates should be modified consistent with the goal set out in PURA
       § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed
       by ETI and subsequent reductions should be reviewed for consideration at the occurrence of
       each rate case filing.

213.   Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation

214.   ETI incurred $616,248,686 in natural-gas expenses during the Reconciliation Period, which
       is from July 2009 through June 2011.

215.   ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
       contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
       negotiated operational balancing agreements with various pipeline companies.

216.   ETI employed a diversified portfolio of gas supply and transportation agreements to meet its
       natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217.   ETI's natural gas expenses were reasonable and necessary expenses incurred to provide
       reliable electric service to retail customers.

218.   ETI incurred $90,821,317 in coal expenses during the Reconciliation Period.

219.   ETI prudently managed its coal and coal-related contracts during the Reconciliation Period.

220.   ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at
       the Big Cajun II, Unit 3 facility.

221.   ETI's coal expenses were reasonable and necessary expenses incurred to provide reliable
       electric service to retail customers.

222.   ETI incurred $990,041,434 in purchased-energy expenses during the Reconciliation Period.

223.   The Entergy System's planning and procurement processes for purchased power produced a
       reasonable mix of purchased resources at a reasonable price.

224.   During the Reconciliation Period, ETI took advantage of opportunities in the fuel and
       purchased-power markets to reduce costs and to mitigate against price volatility.
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PUC DOCKET NO. 39896

225.   ETI's purchased-energy expenses were reasonable and necessary expenses incurred to
       provide reliable electric service to retail customers.

226.   ETI provided sufficient contemporaneous documentation to support the reasonableness of its
       purchased-power planning and procurement processes and its actual power purchases during
       the Reconciliation Period.

227.   The Entergy system sold power off system when the revenues were expected to be more than
       the incremental cost of supplying generation for the sale, subject to maintaining adequate
       reserves.

228.   The System Agreement is the tariff approved by the FERC that provides the basis for the
       operation and planning of the Entergy system, including the six Operating Companies. The
       System Agreement governs the wholesale-power transactions among the Operating
       Companies by providing for joint operation and establishing the bases for equalization
       among the Operating Companies, including the costs associated with the construction,
       ownership, and operation of the Entergy system facilities.

229.   Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues
       and expenses from off-system sales.

230.   During the Reconciliation Period, ETI recorded off-system sales revenue in the amount of
       $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues
       and margins from off-system sales to eligible fuel expenses.

231.   ETI properly recorded revenues from off-system sales and credited those revenues to eligible
       fuel costs.

232.   The Entergy system consists of six Operating Companies, including ETI, which are planned
       and operated as a single, integrated electric system under the terms of the System Agreement.

233.   Service Schedule MSS-1 of the System Agreement determines how the capability and
       ownership costs of reserves for the Entergy system are equalized among the Operating
       Companies. These inter-system "reserve equalization" payments are the result of a formula
       rate related to the Entergy system's reserve capability that is applied on a monthly basis.

234.   Reserve capability under Service Schedule MSS-1 is capability in excess of the Entergy
       system's actual or planned load built or acquired to ensure the reliable, efficient operation of
       the electric system.
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PUC DOCKET NO. 39896

235.   By approving Service Schedule MSS-1, the FERC has approved the method by which the
       Operating Companies share the cost of maintaining sufficient reserves to provide reliability
       for the Entergy system as a whole.

236.   Service Schedule MSS-3 of the System Agreement determines the pricing and exchange of
       energy among the Operating Companies. By approving Service Schedule MSS-3, the FERC
       has approved the method by which the Operating Companies are reimbursed for energy sold
       to the exchange energy pool and how that energy is purchased.

237.   Service Schedule MSS-4 of the System Agreement sets forth the method for determining the
       payment for unit power purchases between Operating Companies. By approving Service
       Schedule MSS-4, the FERC has approved the methodology for pricing Inter-Operating
       Company unit power purchases.

238.   The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
       horizons. Once the planning process has identified the most economical resources that can
       be used to reliably meet the aggregate Entergy system demand, the next step is to procure the
       fuel necessary to operate the generating units as planned and acquire wholesale power from
       the market.

239.   Once resources are procured to meet forecasted load, the Entergy system is operated during
       the current day using all the resources available to meet the total Entergy system demand.

240.   After current-day operation, the System Agreement prescribes an accounting protocol to bill
       the costs of operating the system to the individual Operating Companies. This protocol is
       implemented via the Intra-System Bill (ISB) to each Operating Company on a monthly basis.

241.   ETI purchased power from affiliated Operating Companies per the terms of Service
       Schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to
       affiliated Operating Companies are reasonable and necessary, and the FERC has approved
       the pricing formula and the obligation to purchase the energy. ETI pays the same price per
       megawatt hour for energy under Service Schedule MSS-3 as does any other Operating
       Company purchasing energy under Service Schedule MSS-3 during the same hour.

242.   The Spindletop Facility is used primarily to ensure gas-supply reliability and guard against
       gas-supply curtailments that can occur as a result of extreme weather or other unusual events.

243.   The Spindletop Facility provides a secondary benefit of flexibility in gas supply. ETI can
       back down gas-fired generation to take advantage of more economical wholesale power, or
       use gas from storage to supplement gas-fired generation when load increases during the day
       and thereby avoid more expensive intra-day gas purchases.
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PUC DOCKET NO. 39896

244.   ETI' s customers received benefits from the Spindletop Facility during the Reconciliation
       Period through reliable gas supplies and ETI's monthly and daily storage activity.

245.   ETI prudently managed the Spindletop Facility to provide reliability and flexibility of gas
       supply for the benefit of customers.

246.   ETI proposed new loss factors, based on a December 2010 line loss study, to be applied for
       the purpose of allocating its costs to its wholesale customers and retail customer classes.

247.   ETI's proposed loss factors are reasonable and shall be implemented on a prospective basis
       as a result of this final order.

248.   ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC's
       reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat
       such costs as eligible fuel expense.

249.   Special circumstances exist and it is appropriate for recovery of the rough production cost
       equalization costs reallocated to ETI as a result of the FERC' s decision in Order No. 720-A.

Other Issues

250.   A deferred accounting of ETI' s Midwest Independent Transmission System Operator (MISO)
       transition expenses is not necessary to carry out any requirement of PURA.

251.   ETI should include $2.4 million in base rates for MISO transition expense incurred on or
       after January 2, 2011, based on a five-year amortization of $12 million in total projected
       expenses.

252.   ETI should include an additional $52,800 in base rates for MISO transition expenses incurred
       during the 2010 portion of the Test Year, based on a five-year amortization of $263,908 in
       such expenses.

253.   Transmission Cost Recovery Factor baseline values should be set during the compliance
       phase of this docket, after the Commission makes final rulings on the various contested
       issues that may affect this calculation.

254.   Distribution Cost Recovery Factor baseline values should be set during the compliance phase
       of this docket, after the Commission makes final rulings on the various contested issues that
       may affect this calculation.
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PUC DOCKET NO. 39896

25 5.   The appropriate amount for ETI' s purchased power capacity expense to be included in base
        rates is $245,432,884.

256.     The amount of ETI's purchased power capacity expense includes third-party contracts,
        legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
        amounts for all contracts should be included in the baseline for a purchased capacity rider
        that may be approved in Project No. 39246 is an issue that should be decided in that project.

B.      Conclusions of Law

1.      ETI is a "public utility" as that term is defined in PURA § 11.004( 1) and an "electric utility"
        as that term is defined in PURA§ 31.002(6).

2.      The Commission exercises regulatory authority over ETI and jurisdiction over the subject
        matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
        36.101-.111, and 36.203.

3.      SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation
        of a proposal for decision in this docket, pursuant to PURA§ 14.053 and TEX. GOY'TCODE
        ANN. § 2003.049.

4.      This docket was processed in accordance with the requirements of PURA and the Texas
        Administrative Procedure Act, TEX. Gov'T CODE ANN. Chapter 2001.

5.      ETI provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC.
        R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).

6.      Pursuant to PURA § 33.001, each municipality in ETI's service area that has not ceded
        jurisdiction to the Commission has jurisdiction over the Company's application, which seeks
        to change rates for distribution services within each municipality.

7.      Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
        municipality's rate proceeding.

8.      ETI has the burden of proving that the rate change it is requesting is just and reasonable
        pursuant to PURA § 36.006.

9.      In compliance with PURA§ 36.051, ETI's overall revenues approved in this proceeding
        permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used
        and useful in providing service to the public in excess of its reasonable and necessary
        operating expenses.
                                                                                      ----------------

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PUC DOCKET NO. 39896

10.   Consistent with PURA § 36.053, the rates approved in this proceeding are based on original
      cost, less depreciation, of property used and useful to ETI in providing service.

11.   The ADFIT adjustments approved in this proceeding are consistent with PURA§ 36.059 and
      P.U.C. SUBST. R. 25.23l(c)(2)(C)(i).

12.   Including the cash working capital approved in this proceeding in ETI's rate base is
      consistent with P.U.C. SUBST. R. 25.23l(c)(2)(B)(iii)(IV), which allows a reasonable
      allowance for cash working capital to be included in rate base.

13.   The ROE and overall rate of return authorized in this proceeding are consistent with the
      requirements of PURA §§ 36.051 and 36.052.

14.   The affiliate expenses approved in this proceeding and included in ETI's rates meet the
      affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
      Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.-Austin
      1984, no writ).

15.   The ADFIT adjustments approved in this proceeding are consistent with PURA§ 36.059 and
      P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16.   Pursuant to P.U.C. SUBST. R. 25.231(b)(l)(F), the decommissioning expense approved in
      this case is based on the most current information reasonably available regarding the cost of
      decommissioning, the balance of funds in the decommissioning trust, anticipated escalation
      rates, the anticipated return on the funds in the decommissioning trust, and other relevant
      factors.

17.   ETI has demonstrated that its eligible fuel expenses during the Reconciliation Period were
      reasonable and necessary expenses incurred to provide reliable electric service to retail
      customers as required by P.U.C. SUBST. R. 25.236(d)(l)(A). ETihas properly accounted for
      the amount of fuel-related revenues collected pursuant to the fuel factor during the
      Reconciliation Period as required by P.U.C. SUBST. R. 25.236(d)(l)(C).

18.   ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during
      the Reconciliation Period.

19.   The Reconciliation Period level operating and maintenance expenses for the Spindletop
      Facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

20.   Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover
      rough production equalization payments reallocated to ETI by the FERC.
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PUC DOCKET NO. 39896

21.    ETI' s rates, as approved in this proceeding, are just and reasonable in accordance with PURA
       § 36.003.

C.     Proposed Ordering Paragraphs

       In accordance with these findings of fact and conclusions of law, the Commission issues the
following orders:

1.     The Proposal for Decision prepared by the SOAH ALls is adopted to the extent consistent
       with this Order.

2.     ETI' s application is granted to the extent consistent with this Order.

3.     ETI shall file tariffs consistent with this Order within 20 days of the date of this Order. No
       later than ten days after the date of the tariff filings, Staff shall file its comments
       recommending approval, modification, or rejection of the individual sheets of the tariff
       proposal. Responses to the Staffs recommendation shall be filed no later than 15 days after
       the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff
       sheet, effective the date of the letter.

4.     The tariff sheets shall be deemed approved and shall be become effective on the expiration of
       20 days from the date of filing, in the absence of written notification of modification or
       rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed
       revisions of those sheets in accordance with the Commission's letter within ten days of the
       date of that letter, and the review procedure set out above shall apply to the revised sheets.

5.     Copies of all tariff-related filings shall be served on all parties of record.

6.     ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of
       instituting LED-based rates and, if the study shows that such rates are feasible, ETI should
       file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED
       lighting customers taking service, the study shall include detailed information regarding
       differences in the cost of serving LED and non-LED lighting customers. ETI shall provide
       the results of this study to Cities and interested parties as soon as practicable but no later than
       the filing of its next rate case.
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PUC DOCKET NO. 39896

7.   All other motions, requests for entry of specific findings of fact and conclusions of law, and
     any other requests for general or specific relief, if not expressly granted, are denied.

     SIGNED July 6, 2012.

                                       THOMAS H. WALSTON
                                       ADMINISTRATIVE LAW JUDGE
                                       STATE OFFICE OF ADMINISTRATIVE HEARINGS

                                      ST · li:N D. ARNOLD
                                      ADMINISTRATIVE LAW JUDGE
                                      STATE OFFICE OF ADMINISTRATIVE HEARINGS

                                            ER BU,..,.,.....&.., ......
                                        ADMINISTRAT                     A.W JUDGE/MEDIATOR
                                        STATE OFFICE OF ADMINISTRATIVE HEARINGS

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                                        ,, . /Jvi~,.,.e~ . ._
                                      "titO D. 10MERLEAU
                                       ADMlNISTRi.\.TIVE LAW JUDGE
                                       STATE OFFICE OF ADMINISTRATIVE HEARINCS
                                                                                                                                                                                Attachment A

    SOAH DOCKET NO.                                                                                                                                              ALJ Schedule I

•
    PUC DOCKET NO. 39896                                                                                                                                   Revenue Requirement
    COMPANY NAME    Entergy Texas, Inc
    TEST YEAR END   30..Jun·11

                                                                                                                 Company                 AW
                                                                                       Company                   Requested           Adjustments                        AW
                                                               Test Year              Adjustmenlll               Test Year           To Company                      AdJusted
                                                                 Total                To Test Year              Total Electric         Reguest                     Total Electric
                                                                  (a)                      (b)                        (c)                (d)                       (e) = (c) + (d)

    REVENUE REQUIREMENT

    Operations & Maintenance                    CM!        $   1,291,684,714      $     (1,075; 148, 117)   $        216,536,597     $   (24,241,886)         $        192,294,731
    Regulatoiy Debits and Credits      407.00              $      (6,784,608)     $         12,030,533      $          5,245,925     $      (324,121) "       $          4,921,804
    Accretion Expense
                                                """''
                                                .......    $         212,783      $           (212,783)     $                        $                        $
    Interest on Customer Deposits               .......    $                      $              68,985     $             68,985     $       (25.938) "'      $              43,047
     Decommissioning Expense                               $                      $                         $                        $                        $
    Depreciation & Amortization Expense
                                                ''"'       $       76,072,459     $         22,558,698      $         98,631,157     $    (6, 761,585)        $         91,869,572
    Taxes Other Than Income Taxes
                                                """
                                                Si:h G-9   $       63,023,906     $         (2,533, 159)    $         60,490,747     $    (2,953,747)         $         57,537,000
    Federal Income Taxes                        SQh·A      $      (23,407,031)    $         67,296,739      $         43,889,708     $     5,920,966          $         49,810.674
    Current State Income Taxes                  .,,. ...   $          (127,519)   $              89,787     $             (37,732)   $          37,732        $
    Deferred Federal Income Taxes               S¢hA       $       67,051,463     $        (52,089,274)     $         14,962, 189    $   (14,962,189)         $
    Deferred State Income Taxes                 ......     $           812,265    $           (727,918)     $              64,347    $         (84,347)       $
     Investment Tax Credits            411 00   Sd>A       $        (1,611,177)   $             (46,429)    $          (1,657,606)   $     1,657,606          $
    Consolidated Tax Sa11109s Adjustment                   $                      $                         $                        $                        $
    Return on Invested Capital                             $                      $        155,162,991      ~        155,182,991     ~   {15,379,778)         $        139,783,213
    TOTAL                                                  $    1,466,927,255     $       (873,649,947)     $        593,377,308     $   (67,117,267)         $        536,260,041

     Plus:
     Addback: Purchased Power Rider    55500                                                                                                                   $       244,539,884       C1 C10

     Addback: Interruptible Services   555 00                                                                                                                  $                     •   Cl

•
              Total Addbacks                                                                                                                                   $       244,539,884

     Total ALJ Revenue Requirement                                                                                                                             $       780,799,926

•
                                                                                                                                                   Attachment A

           Customer Assistance                  908   $      9,189,638    $       (7,250,909)      $    1,938,729    $      (67,298)    $     1,871.43~

•
           Customer Assistance over/under       908   $      1,747,892    $       (1,747,892)      $                 $                  $
           Information & lnstr Advertising      909   $        937,069    $             (876)      $       936,193   $        (4,056)   $       932,137
           Misc. Cust Serv1ce and Information   910   $      1,151,988    $            4,764       $     1,156,752   $                  $     1,156,752
           Sales Supervision                    911   $            829    $                7       $           836   $      (17.467)    $       (16,631)
           OemonstratinQ & Sellinq Exo          912   $        730,161    $           14,522       $       744,683   $      (16,597)    $       728,086
           Advertising Expense                  913   $        110,202    $           (2,379)      $       107,823   $          (58)    $       107,765
           M1sc Sates Expense                   916   $        256,775    $            1,715       $       258,490   $       (1,390)    $       257,100
                                                                                                                                        $

    TOTAL Operations & Maintenance                        1,207,264,083       (1 ,071 ,013, 726)       136,250,357       (11,034,115)       125,216,242

•

•
                                                                                                                                                                                      Attachment A

•   SOAH DOCKET NO,
    PUC DOCKET NO.
    COMPANY NAME
    TEST YEAR END
                            39896
                            Entergy Texaa, Inc.
                            30.Jun-11

                                                            Teat Year
                                                              Total
                                                               (a)
                                                                                      Company
                                                                                     Adjuslmenta
                                                                                     To Test Year
                                                                                          (b)
                                                                                                                Company
                                                                                                                Requestsd
                                                                                                                Test Year
                                                                                                               Total Electrlc
                                                                                                                    (c)
                                                                                                                                                ALJ
                                                                                                                                            Adjustmenta
                                                                                                                                            To Company
                                                                                                                                              Raguast
                                                                                                                                                 fd)
                                                                                                                                                                          ALJ Schedule IU
                                                                                                                                                                          lnvoted Capital

                                                                                                                                                                             ALJ
                                                                                                                                                                           Adjusted
                                                                                                                                                                         Total Eleetrlc
                                                                                                                                                                         !•I= {c) + (dl

    INVESTED CAPITAL

     Plant in Servi;e
     Ae<:umulaled Depraciallon
                                                  ..,   $
                                                        $
                                                              3,521,368, 187
                                                             (1,417 946,172)
                                                                                 $
                                                                                 $
                                                                                           (251,512,491)
                                                                                            148,061,290
                                                                                                           $
                                                                                                           $
                                                                                                                    3.269,855.696
                                                                                                                   (1 269,8(14,882)
                                                                                                                                                (1,333,352) "'       $
                                                                                                                                                                     $
                                                                                                                                                                            3,266,522,344
                                                                                                                                                                           11 269 684.882)

     Net Plant In Service                                     2.103,422,015      $         (103,451,201)   $        1,999,970,814               ( 1,333,352)                1,998,637,462
                                                                                 $
     Construction Work in Progress                      $                        $                         $                            $                            $
     Plant Held 10! Future Use                          $                        $                         $                            $                            $
     Working Cash Allowance                             $                        $           (2,013,921)   $           (2,669,275)      s       {3, 725, 159)        $          (6,414,434)
     Fuel Inventories                                   $        53,759,975      $                         $           53,759,975       $       {1,066,490) ..       $          52,693,485
                                                                                                                                                               ...
     Materials and Supplies
     Prepayments
     Property Insurance Reserve
                                                        $
                                                        $
                                                        $
                                                                 29,252,574
                                                                  7,366,433
                                                                                 $
                                                                                 $
                                                                                 $
                                                                                               {148,396)
                                                                                             59,799,744
                                                                                                           $
                                                                                                           $
                                                                                                           $
                                                                                                                       29,252,574
                                                                                                                        7,218,037
                                                                                                                       59,799,744
                                                                                                                                        $
                                                                                                                                        $
                                                                                                                                        $
                                                                                                                                                     32,847
                                                                                                                                                    916,313    .     $
                                                                                                                                                                     $
                                                                                                                                                                     $
                                                                                                                                                                                29.265,421
                                                                                                                                                                                 8,134,350
                                                                                                                                                                                59,799,744
     lnjunes and Damages Reserve                        $        (5,589,243)     $                         $           (5,569,243)      $                            $          (5,569,243)
     Coal Car Maintenance Reserve                       $         1,400,350      $                         $            1,400,350       $                            $           1,400,350
     UnfUnded Pension                                   $       (53,715,841)     $          109,689,386    $           55,97U45         $      (25,311,236) "'       $          30,662,309
     Allowance$                                         $            68,914      $                         $               68,914       s                            $              68,914
     Envuonmenla! Reserves                              $         3,412,379      $           (4,474,569)   $           {1.062, 1QO)     $                            $          (1,062,190)
     Customer Deposit&                                  $       (35,872,476)     $                         $          (35,812,476)      $                            $         {35,872,476)
     Regulatory Assets and Uabilltles                   $                        $           26,366,859    $           26,366.859       $      (11,054,084) ..       $          15,312,795
     Accumulated OFIT                                   $      {824,338,691)     $          369,007, 144   $         (454,37\,547)      $       (2,460,528) M. Onl   $        (458,832,075)
    Rate Case Expenses                                  $                        $            6,175,000    $            6,175,000       $       (6,175,000) """      $
                                                        $                                                                                                            $

    TOT Al. INVESTED CAPITAL (RATE llASE)                     1,279,1tll!,389               461,910,046    $        1,740,421,081              (50,176,6119)                 1,690,244,412

    RATE OF RETURN                                                      5.140%                                                  6.92%                                              8.2700%.

    RETURN ON INVESTED CAPITAL                          $                                   155,162,991               155,162,991              (15,379,7781                    139,783,213

•

•
                                                                                                                                                                                          Attachment A

•
    SOAH DOCKET NO.                                                                                                                                                       AW Schedule 1118
    PUC DOCKET NO.           39B!Hi                                                                                                                                    Depreciation ex:panse
    COMPANY NAME             Entergy Texas,   Inc~
    TEST YEAR END            30.Jun-11
                                                                                                                           Company                      AW
                                                                                             Company                       Requested                AdJuatmenlt                  AW
                                                                     THtYear                Adjustmento                    Teat Year                To Company                AdJU$1ed
                                                                                            ToTestYoar                    Total Electric             Roguest                Toll!! Electric
                                                                                                (b)                             (cl                 (d)z <•H•l                    (•}

    Depreciation Expanse
               Structures & Improvement&                  311    $        1,095,067     $               616,683      $             1,711,750    $         (424,581)    $            1,287, 169
               BOiler Plant Equipmen!                     312    $        8,765,278     $               845,956      $             9,611,234    $       (2,028,662}    $            7,582,572
               TurboGenerator Units                       314    $        2.482,980     $             2,045,957      $             4,528,937    $       (1, 105,324}   $            3,423,613
               Accessory Electric Equipment               315    $        2,262,265     $               395,683      $             2,657,948    $         (430,004)    $            2,227,944
               Misc Power Piant Equip                     316    $          238.086     $                66,386      $               302.472    $           (53,873)   $              248.599
               Asset R~t11ement ObligatiOn                317    $         (331,958)    $               331,958      $                          $                      $
               Misc Power Plan! Eq'"p                     335    $            1,188     $                  (943)     $                   245    $                      $                  245
                              Subtotal Production                $       14,510,906     $             4,301,660      $            18,612,586    $       (4,042,444)     $          14,770,142

               Land Easements                            350.2   $          483,058     $               (65,666)                     397,392    $                      $              397,392
               Sb'uciures & Improvements                   352   $          417.724     $                  (315)                     417,409    $                      $              417,409
               Station E.qu1pment                          353   $        5,379,875     $             2.952,519      $             8,332,494    $                      $            8,332,494
               Towers and Fixtures                         354   $          416,765     $                46,647      $               463,412    $         (107,469)    $              355,943
               POkas and Fixtures                          355   $        4,182.575     $               779,244      $             4,961,819    $                      $            4,961,819
               OH COnduclors & Devices                     356   $        2.860,208     $             1,162,693      $             4,022,901    $                      $            4,022,901
               Underground Conductors & Oevtces            358   $            1.409     $                 5,014      $                 6,423    $                      $                6,423
               Roads and Trail&                            359   $              860     $                 2.224      $                 3084                            $                3084
                              Sublotal Transmission              $       13,722.474     $             4,882,460       $           18,604,934                           $           18,497,465

                Land Rights                              300 2   $          240,953     $                (30,175)    $               210,778    $                       $             210,778
                Structures & lmprovementa                 361    $          127,911     $                 33,069     $               180,980    $           (9,512)     $             151,468
                Slation Equipment                          J62   $        3,606,715     $                363,575     $             3,970,290    $         (399.946)     $           3,570,344
                Poles, Towers & Flxtures                   354   $        6,809,464     $              1.438,154     $             8,247,618    $       (1,192,611)     $           7,055,007
                OH Conductors & Oevlces                    365   $        3,600,424     $              3,244,756     $             6,845,180    $                       $           6,845,180
                Underground Conduit                        366   $          438,899     $                 32,544     $               489,443    $                       $             469,443
                Underground Conductors & Devices           367   $        2,277,438     $                960,620     $             3,238,058    $                       $           3,238,056
                Line Transformers                          368   $       10,285,939     $              3,068,781     $            13,374,720    $       (1,285,193}     $          12,089,527
                OH Services                                389   $        2,735,305     $              1.272, 163    $             4,007,469    $          280,720      $           4,288,189
                MetetG                                     370   $        1,020,813     $                394,834     $             1,415,547    $                       $           1,415,547
                install on Customet Premises               371   $          556,198     $                    919     $               557,117    $                       $             557,117
                S!reel Lighting and Signal                 373   $           62,565     $                !22,617]    $                40048     $                       $              40,048
                               Subto!al D1stribu«on              $       31,760,723     $             10,776,623     $            42,537,346    $       (2,606,542)     $          39,930,804

•
                Regional Trans & Mkt Ops Hardware          382 $             12.125                                                    12,125                           $               12,125
                Regional Trans & Mk! Ops Soflware          383 $            673,827                         (601)                     673,226                           $              673,226

                Structur&& & Improvements                  390   $        1,359,296     $               (272,045)    $              1,087,251   $                       $            1,087,251
                Office Furniture & Equipment               391   $        2,514,238     $              3,318,559     $              5,832,797   $                       $            5,832,797
                Transportation Equlpment                   392   $              955     $                 44,724     $                 45,679   $                       $               45,679
                Stores Equipment                           393   $          150,556     $                176,112     $                326,668   $                       $              326,668
                Tools, Shop. & Garage Eqoipment            394   $          556,547     $                 66.440     $                622,987   $                       $              622,987
                Laboratory Equipment                       395   $           22,505     $                254,660     $                277.365   $                       $              277,365
                Power Operated Equipment                   396   s           30.044     $                (17, 172)   $                 12,872   $                       $               12.672
                Commurncation Equipment                    397   $        1,897,978     $               (310,501)    $              1,387,477   $                       $            1,387,477
                Misc Equipment                             398   $           47155      $                123,991     $                171,146   $                       $              171146
                               Subtotal General Plant            $        6,379,274     $              3,364.968     $              9,764,242   $                       $            9,764.242

                ESI DepreclaUon Ee