The opinion
ACCEPTED
03-14-00735-CV
4711647
THIRD COURT OF APPEALS
AUSTIN, TEXAS
3/31/2015 2:04:20 PM
JEFFREY D. KYLE
CLERK
FILED IN
NO. 03-14-00735-CV 3rd COURT OF APPEALS
AUSTIN, TEXAS
3/31/2015 2:04:20 PM
JEFFREY D. KYLE
Clerk
ENTERGY TEXAS, INC., ET AL.,
Appellants,
v.
PUBLIC UTILITY COMMISSION OF TEXAS, INC., ET AL.,
Appellees.
B RIEF OF A PPELLANT
Filed by: Public Utility Commission of Texas
KEN PAXTON JON NIERMANN
Attorney General of Texas Chief, Environmental Protection
Division
CHARLES E. ROY
First Assistant Attorney General ELIZABETH R. B. STERLING
Assistant Attorney General
JAMES E. DAVIS State Bar No. 19171100
Deputy Attorney General for elizabeth.sterling@texasattorneygeneral.gov
Civil Litigation
Environmental Protection Division
P.O. Box 12548, MC-066
Austin, Texas 78711-2548
512.463.2012
512.457.4616 (fax)
March 31, 2015
Oral Argument Requested
Identity of Parties and Counsel
Party Counsel
Entergy Texas, Inc., Plaintiff in the Marnie A. McCormick
district court, Appellant and Patrick J. Pearsall
Appellee in this Court 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
Cities of Anahuac, Beaumont, Daniel J. Lawton
Bridge City, Cleveland, Conroe, The Lawton Law Firm, P.C.
Dayton, Groves, Houston, 12600 Hill Country Blvd.,
Huntsville, Montgomery, Navasota, Ste. R-275
Nederland, Oak Ridge North, Austin, TX 78738
Orange, Pine Forest, Rose City, 512.322.0019
Pinehurst, Port Arthur, Port 855.298.7978 (fax)
Neches, Shenandoah, Silsbee, Sour dlawton@ecpi.com
Lake, Splendora, Vidor, and West (in district court, also Stephen
Orange, Plaintiffs in the district Mack)
court and Interested Parties before
this Court
Office of Public Utility Counsel, Sara J. Ferris
Plaintiff in the district court and Assistant Public Counsel
Appellant before this Court Office of Public Utility Counsel
P.O. Box 12397
Austin, Texas 78711-2397
512.936.7500
512.936.7520 (fax)
sara.ferris@opuc.texas.gov
i
State Agencies, Plaintiffs in the Katherine H. Farrell
district court and Interested Parties Assistant Attorney General
before this Court 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@texasattorneygen
eral.gov
(in district court, Susan M. Kelley
and Bryan L. Baker)
Texas Industrial Energy Rex VanMiddlesworth
Consumers, Intervenors in the Benjamin Hallmark
district court and Interested Parties Thompson & Knight LLP
before this Court 98 San Jacinto Blvd., Ste. 1900
Austin, Texas 78701
512.469.6100
512.469.6180 (fax)
rex.vanm@tklaw.com
benjamin.hallmark@tklaw.com
(in district court, Meghan Griffiths
at Andrews Kurth LLP)
ii
Public Utility Commission of Texas, Ken Paxton
Defendant in the district court, Attorney General of Texas
Appellant and Appellee before this (in district court, Greg Abbott)
Court
Charles E. Roy
First Assistant Attorney General
(in district court, Daniel Hodge)
James E. Davis
Deputy Attorney General for Civil
Litigation
(in district court, John B. Scott)
Jon Niermann
Chief, Environmental Protection
Division
Assistant Attorneys General:
Elizabeth R. B. Sterling
John R. Hulme
Daniel C. Wiseman
Megan Neal
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)
iii
Table of Contents
Identity of Parties and Counsel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i
Table of Contents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
Index of Authorities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii
Glossary.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix
Statement of the Case. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi
Statement Regarding Oral Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi
Issue Presented. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi
In a Fuel Reconciliation, the Commission determines the actual
reasonable and necessary amount that a utility spent on fuel
expenses. Do the Commission’s rules allow it to use a
contemporaneous line-loss study to determine how much
electricity was lost from the generator to the end user so that
the Commission can accurately determine how much the utility
had to spend on fuel to generate electricity for retail
customers? .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi
Statement of Facts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
A. The Commission uses a two-step process for a utility to
recover fuel expenses: first the Commission sets a
temporary rate called a fuel factor, and later the
Commission conducts a Fuel Reconciliation where the
actual fuel expenses that the utility may recover from
ratepayers are finally determined.. . . . . . . . . . . . . . . . . . . . . . . . . 1
B. Entergy asked to reconcile fuel expenses for July 2009
through June 2011, but wanted to use an old 1997 line-
loss study rather than the contemporaneous 2010 line-
loss study.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
iv
1. Entergy asked to reconcile fuel expenses for a two-
year period from July 2009 through June 2011.. . . . . . . 3
2. Because some electricity is lost as it travels over
wires, the utility must perform a line-loss study to
account for the total amount that must be generated
to meet demand... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
C. Cities argued that the contemporaneous line-loss study
would show actual fuel costs incurred during the
reconciliation period, and that contemporaneous line-loss
study showed that $4 million of fuel costs Entergy
assigned to retail ratepayers were incurred to serve
wholesale customers... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
D. The Commission decided that the contemporaneous line-
loss study should be used... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
E. Three Commission rules apply to a utility’s recovery of
fuel expenses: Rule 25.235, Rule 25.236, and Rule
25.237... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
F. The district court reversed the Commission’s decision
about using the contemporaneous line-loss study.. . . . . . . . . . 9
Summary of the Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Argument. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
A. Standard of Review. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
B. The Commission’s Order complies with its rules. . . . . . . . . . . 12
1. Rule 25.236(d) applies to this Fuel Reconciliation
and authorizes the Commission’s decision.. . . . . . . . . . . 12
2. None of the rules cited by the district court apply to
the Fuel Reconciliation in this case... . . . . . . . . . . . . . . . . 14
v
a. Rule 25.236(e)(3) does not apply to this Fuel
Reconciliation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
b. Rule 25.237(a) does not apply to a Fuel
Reconciliation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
c. Rule 25.237(c)(2)(B) does not apply to a Fuel
Reconciliation.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
C. Entergy has not shown prejudice to its substantial rights.. . . . 18
Conclusion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Prayer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Certificate of Compliance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Certificate of Service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
APPENDICES
District Court Judgment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A
Commission Order.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B
ALJ’s Proposal for Decision. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C
Entergy’s Statement of Intent and Application for Authority to Change
Rates and Reconcile Fuel Costs (pages 1–12). . . . . . . . . . . . . . . . . . . . D
Rules:
16 Tex. Admin. Code § 25.235.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E
16 Tex. Admin. Code § 25.236. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F
16 Tex. Admin. Code § 25.237.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G
vi
Index of Authorities
Cases Page(s)
CenterPoint Energy Houston Elec., LLC v. Pub. Util. Comm’n,
212 S.W.3d 389 (Tex. App.—Austin 2006, pet. granted, judgm’t
vacated w.r.m.).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
El Paso Elec. Co. v. Pub. Util. Comm’n,
917 S.W.2d 846 (Tex. App.—Austin 1995, writ dism’d by agr.).. . . 18
Gulf States Utils. Co. v. Pub. Util. Comm’n,
841 S.W.2d 459 (Tex. App.—Austin 1992, writ denied).. . . . . . . . . 19
Lewis v. Jacksonville Bldg. & Loan Ass’n,
540 S.W.2d 307 (Tex. 1976). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Pub. Util. Comm’n v. Gulf States Utils. Co.,
809 S.W.2d. 201 (Tex. 1991). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Pub. Util. Comm’n v. Tex. Utils. Elec. Co.,
935 S.W.2d 109 (Tex. 1997). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
RepublicBank Dallas, N.A. v. Interkal, Inc.,
691 S.W.2d 605 (Tex. 1985). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Rodriguez v. Serv. Lloyds Ins. Co.,
997 S.W.2d 248 (Tex. 1999). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Sw. Pharmacy Solutions, Inc. v. Tex. Health and Human Servs.,
408 S.W.3d 549 (Tex. App.—Austin 2013, pet. denied). . . . . . . . . 11
State v. Pub. Util. Comm’n,
883 S.W.2d 190 (Tex. 1994). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Tex. Bd. Of Chiropractic Exam’rs v. Tex. Med. Ass’n,
375 S.W.3d 464 (Tex. App.—Austin 2012, pet. denied).. . . . . . 11, 12
vii
Cases cont’d Page(s)
Tex. Utils. Elec. Co. v. Pub. Util. Comm’n,
881 S.W.2d 387 (Tex. App.—Austin 1994). . . . . . . . . . . . . . . . . . . . . 1
Statutes
Tex. Gov’t Code
§§ 2001.001–.902. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix
§ 2001.174(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Rules
16 Tex. Admin. Code
§§ 25.235-25.237.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
§ 25.236(b).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix
§ 25.236(d).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
§ 25.236(d)(1)(A).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13, 19
§ 25.236(d)(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2, 8, 9, passim
§ 25.236(e)(3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
§ 25.237(a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
§ 25.237(a)(1).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5, 16
§ 25.237(a)(3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix, 3, 9
§ 25.237(a)(3)(A).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
§ 25.237(a)(3)(B).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
§ 25.237(c)(2)(B).. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16, 17
viii
Glossary
ALJ Administrative Law Judge
APA Administrative Procedure Act, Tex. Gov’t Code
§§ 2001.001–.902.
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
Entergy Entergy Texas, Inc., the utility that asked the
Commission to reconcile fuel expenses in this case
ERCOT Electric Reliability Council of Texas
Fuel Factor A temporary rate set by the Commission to recover
the utility’s fuel costs See 16 Tex. Admin. Code
§ 25.237(a)(3).
Fuel Reconciliation After the utility has collected for fuel costs using the
Fuel Factor, it returns to the Commission to
reconcile actual fuel costs with amounts recovered
under the Fuel Factor. See 16 Tex. Admin. Code
§ 25.236(b).
Line Losses Electricity that the utility generates but is “lost” as it
travels along the wires from the generator to the
customer; more electricity is generated than is
metered where it is used
Order The Commission’s order on rehearing that is the
subject of this lawsuit. (AR, Item 244.)
ix
PFD Proposal for Decision prepared by the ALJ in this
case (AR, Item 185.)
x
Statement of the Case
Entergy Texas, Inc., an electric utility in the southeastern part of the
state, together with several groups of its customers, filed an administrative
appeal of the Public Utility Commission’s order setting rates for Entergy.
The district court affirmed the Commission’s order on all but one issue.
The Commission appeals on that issue; several other parties are appealing
different issues.
Statement Regarding Oral Argument
Each of the three appellants in this rate case bring separate issues.
Looking at the entire case, the number of parties, the number of issues, and
the complexity of many of the issues, oral argument would help the Court.
Issue Presented
In a Fuel Reconciliation, the Commission determines the actual reasonable
and necessary amount that a utility spent on fuel expenses. Do the
Commission’s rules allow it to use a contemporaneous line-loss study to
determine how much electricity was lost from the generator to the end user
so that the Commission can accurately determine how much the utility had
to spend on fuel to generate electricity for retail customers?
xi
Statement of Facts
Although the Commission set base rates and determined a Fuel
Reconciliation in its Order, the Commission’s sole appellant’s issue
concerns Entergy fuel costs for retail service.
A. The Commission uses a two-step process for a utility to
recover fuel expenses: first the Commission sets a
temporary rate called a fuel factor, and later the
Commission conducts a Fuel Reconciliation where the
actual fuel expenses that the utility may recover from
ratepayers are finally determined.
Because fuel costs are so volatile and such a large part of an electric
utility’s expenses,1 the Commission sets a temporary rate called a Fuel
Factor but determines the actual amount that the utility should have
recovered for fuel expenses in a later Fuel Reconciliation. The practice is so
long-standing that this Court recognized it in a 1994 case that discussed
reconciling fuel costs dating back to 1983. See Tex. Utils. Elec. Co., v. Pub.
Util. Comm’n , 881 S.W.2d 387, 411–12 (Tex. App.—Austin 1994) aff’d in
1
For example, in this case, Entergy estimated that its over-recovery balance
was $243,339,353. SAR, Item 1 at 9. 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
part, rev’d in part sub nom. Pub. Util. Comm’n v. Tex. Utils. Elec. Co., 935
S.W.2d 109 (Tex. 1997). This Court explained: “Fuel reconciliation is a
term used to describe periodic adjustments to a utility’s fuel costs made to
account for the difference between previously anticipated costs and actual,
reasonable costs incurred. The Commission makes these adjustments on a
periodic basis because of the practical difficulty of deciding a new rate case
with each variation in fuel prices.” The two-step process allows the utility
to recover its reasonable fuel expenses and not over-recover for those
costs.2
Without the Fuel Factor followed by a reconciliation, either the utility
might lose a significant amount because the rates in place assumed much
too low a fuel cost or the ratepayers might have paid exorbitant rates
because the rates in place assumed much too high a fuel price. And if fuel
costs were included in regular rates, the rule against retroactive ratemaking
would prohibit the Commission from determining whether the utility had
recovered too much or too little.3 The Commission avoids these problems
2
16 Tex. Admin. Code § 25.236(d)(2) (“The scope of a fuel reconciliation
proceeding includes any issue related to determining the reasonableness of the electric
utility’s fuel expenses during the reconciliation period and whether the electric utility
has over- or under-recovered its reasonable fuel expenses.”).
3
The rule against retroactive ratemaking “prohibits a utility commission from
making a retrospective inquiry to determine whether a prior rate was reasonable and
imposing a surcharge when rates were too low or a refund when rates were too high.”
State v. Pub. Util. Comm’n, 883 S.W.2d 190, 199 (Tex. 1994).
2
by setting a temporary rate called a Fuel Factor.4 Periodically, the utility
returns for a Fuel Reconciliation, where the Commission reconciles the
amounts the utility received under the Fuel Factor with the actual,
reasonable expenses it incurred for fuel to generate electricity for retail
customers. The utility can then ask to refund any over-recovery or
surcharge any under-recovery.5 In effect, the Fuel Factor is a forward-
looking, estimated rate and the reconciliation determines the actual rate.
B. Entergy asked to reconcile fuel expenses for July 2009
through June 2011, but wanted to use an old 1997 line-loss
study rather than the contemporaneous 2010 line-loss
study.
1. Entergy asked to reconcile fuel expenses for a two-year
period from July 2009 through June 2011.
Entergy’s application to change rates and reconcile fuel costs6 (its
“pleading” before the Commission) includes several statements important
to this appeal.
4
See 16 Tex. Admin. Code § 25.237(a)(3).
5
16 Tex. Admin. Code § 25.237(a)(3)(A) (“The reasonableness of the fuel costs
that an electric utility has incurred will be periodically reviewed in a reconciliation
proceeding, as described in §25.236 of this title, and any disallowed costs resulting from
a reconciliation proceeding will be reflected in the calculation of the utility’s recoverable
fuel and over/(under) collections.”).
6
SAR, Item 1. A copy without exhibits is attached as Appendix D.
3
• Entergy asked, pursuant to Rule 25.236 to reconcile its fuel and
purchased power costs to its Fuel Factor revenues during the
Reconciliation Period,7 but Entergy did not ask to change its Fuel Factor.
• Entergy’s Reconciliation Period for this case is a two-year period—July
2009 through June 2011.8
• Entergy’s fuel-reconciliation request applies only to retail customers:
“This Application will affect all of [Entergy]’s retail customers taking
service under its fixed fuel factor (‘Schedule FF’) by reconciling the fuel
and purchased power costs incurred and the fuel factor revenue received
in providing service to these customers during the Reconciliation
Period.”9
• Entergy asked to postpone refunds or surcharges even though the utility
estimated that it had over-recovered $243 million during the
reconciliation period: “[Entergy] does not seek to implement a refund
or surcharge of eligible fuel or purchased power costs at the conclusion
of this case; rather, [Entergy] proposes to roll any ending fuel balances
7
SAR, Item 1 at 8.
8
SAR, Item 1 at 1 (“Reconciliation Period from July 1, 2009 to June 30, 2011”);
see also AR, Item 244 (Order) FF 214. In the Order, findings of fact will be cited as
“FF__” and conclusions of law will be cited as “CL __.” A copy of the Order is attached
as Appendix B.
9
SAR, Item 1 at 8 (emphasis added).
4
forward to serve as the beginning balance for the next Reconciliation
Period.”10 Thus, the Commission’s Order does not include refunds.
2. Because some electricity is lost as it travels over wires, the
utility must perform a line-loss study to account for the
total amount that must be generated to meet demand.
To recover all of its fuel costs, a utility must account for line losses
because not all the electricity generated reaches the utility’s customers;
some is “lost” as electricity travels over wires from generation to
consumption. The Commission’s Rule 25.237 explains that “[f]uel factors
must account for system losses and for the difference in line losses
corresponding to the voltage at which the electric service is provided.”11
Entergy did not use the line-loss study conducted during the
reconciliation period to calculate actual fuel costs during that period; it
used one thirteen years older. The utility conducted a line-loss study for
the calendar year 2010—the middle of the 24-month reconciliation period
of July 2009 through June 2011. 12 Thus, this study showed actual Fuel
Reconciliation during the reconciliation period. But Entergy proposed to
10
Id. at 9 (emphasis added).
11
16 Tex. Admin. Code § 25.237(a)(1).
12
AR, Order at 9.
5
determine fuel expenses for retail customers using a line-loss study
performed in 1997.13
C. Cities argued that the contemporaneous line-loss study
would show actual fuel costs incurred during the
reconciliation period, and that contemporaneous line-loss
study showed that $4 million of fuel costs Entergy assigned
to retail ratepayers were incurred to serve wholesale
customers.
Cities, parties in the rate case, argued that the fuel costs incurred during
the reconciliation period should reflect the contemporaneous line-loss
study.14 Cities calculated that, using the current line-loss study, retail
customers paid nearly $4 million for fuel expenses that were not incurred
to serve retail customers. Cities’ witness Nalepa testified: “[Entergy]’s own
analysis demonstrates that adjusting the allocation of fuel costs over the
reconciliation period to reflect the actual line losses for each voltage level
for the reconciliation period results in retail customers subsidizing
wholesale customers by approximately $3.98 million.”15
13
AR, Order at 9.
14
AR, Item 161 at 88–90 (Cities Initial Br.).
15
AR, Cities’ Ex. 6 at 44 ll.14–18.
6
D. The Commission decided that the contemporaneous line-
loss study should be used.
Although the ALJ proposed using the out-of-date 1997 line-loss study,
the Commission used the contemporaneous 2010 line-loss study to
determine fuel costs for service to retail customers during the reconciliation
period.16 The Commission recognized that Entergy used the 2010 line-loss
study to calculate the demand- and energy-related allocations the utility
relied on for new base rates it asked the Commission to set. The
Commission opined that those same, currently available line-loss factors
should have been utilized in Entergy’s Fuel Reconciliation.17 The
Commission found that using Entergy’s 2010 line-loss factors resulted in
$3,981,271 less in actual fuel costs that Entergy incurred to serve retail
customers during the reconciliation period. The Commission added the
following two conclusions of law to the ALJ’s proposed conclusions:
19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary
rates subject to revision in a reconciliation proceeding.
19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel
reconciliation proceeding to include any issue related to the
reasonableness of a utility’s fuel expenses and whether the
utility has over- or under-recovered its reasonable fuel
expenses. It is proper to use the new line-loss study to calculate
Entergy’s fuel reconciliation and over-recovery.
16
AR, Order at 9.
17
AR, Order at 9.
7
Entergy claimed that the Commission’s Order was contrary to the
Commission’s rules.18
E. Three Commission rules apply to a utility’s recovery of fuel
expenses: Rule 25.235, Rule 25.236, and Rule 25.237.
Three Commission rules address a utility’s recovery of fuel expenses:
Rule 25.235 entitled “Fuel Costs — General,” Rule 25.236 entitled
“Recovery of Fuel Costs,” and Rule 25.237, entitled “Fuel Factors.”19
Rule 25.235 explains the purpose for the system of allowing a utility to
recover its fuel costs through a Fuel Factor with periodic reconciliations.
Rule 25.236 explains that the Commission’s authority in a Fuel
Reconciliation proceeding is broad. “The scope of the proceeding below
allows consideration of ‘any issue related to determining the
reasonableness of the electric utility’s fuel expenses during the
reconciliation period.’” CenterPoint Energy Houston Elec., LLC v. Pub.
Util. Comm’n, 212 S.W.3d 389, 399 (Tex. App.—Austin 2006, pet. granted,
judgm’t vacated w.r.m.) (quoting 16 Tex. Admin. Code § 25.236(d)(2)).
That same rule explains that the scope of a reconciliation proceeding
18
Id.
19
16 Tex. Admin. Code §§ 25.235–25.237. Copies are attached as Appendices
E–G.
8
includes: “whether the electric utility has over- or under-recovered its
reasonable fuel expenses.”20
Rule 25.237 recognizes that Fuel Factors “are temporary rates … .”21 The
electric utility’s collection of revenues by Fuel Factors is subject to
adjustments. “To the extent that there are variations between the fuel costs
incurred and the revenues collected, it may be necessary or convenient to
refund overcollections or surcharge undercollections.”22
F. The district court reversed the Commission’s decision about
using the contemporaneous line-loss study.
In the administrative appeal of Entergy’s rates, the district court affirmed
the Commission on most issues, but it reversed on this one. The district
court’s judgment states:
Entergy’s Point of Error No. 1 addressing the use of a current line loss
study rather that a prior-approved line loss study in allocating line
loss costs among classes of customers establishes that the Commission
erred in applying the current study in violation of Commission rules
found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a) and (c)(2)(B).
Accordingly, the Court FINDS that the PUC’s ruling was arbitrary and
capricious and constitutes an error of Law. The Court REVERSES
such ruling and REMANDS this matter to the Commission for further
proceedings consistent with this Court’s Order.23
20
16 Tex. Admin. Code 25.236(d)(2).
21
16 Tex. Admin. Code § 25.237(a)(3).
22
16 Tex. Admin. Code § 25.237(a)(3)(B).
23
C.R. at 2118.
9
The Commission appeals the district court’s holding.
Summary of the Argument
None of the rules that were cited by the district court apply to the Fuel
Reconciliation the Commission performed. Because Entergy did not ask the
Commission to change its Fuel Factor, the two provisions of Rule 25.237
about setting a Fuel Factor do not apply. Because Entergy did not ask the
Commission to award refunds, Rule 25.236(e)(3) about how to allocate
refunds does not apply. Moreover, because Rule 25.236(e)(3) applies only
to Entergy’s retail rate classes, it does not concern allocating fuel costs
between retail and wholesale service. Thus, the district court erred to find
that the Commission’s order violated those inapplicable rules.
The Commission’s Order complies with the applicable rules. Rule
25.236(d) requires that the utility recover only reasonable and necessary
fuel costs to serve retail customers. Thus, the Commission reasonably
applied line-losses based on the line-loss study done contemporaneously
with the reconciliation period. That showed that $4 million of the fuel costs
Entergy wanted to recover were actually wholesale fuel costs that should not
be imposed on retail customers.
Moreover, Entergy has failed to show harm. It claims that it will be
harmed if it is not allowed to allocate the $4 million to retail customers
10
based on the 1997 line-loss study but fails to show that it does not collect
that $4 million from wholesale customers.
Argument
A. Standard of Review
“The Commission’s interpretation of its own regulations is entitled to
deference by the courts.” Pub. Util. Comm’n v. Gulf States Utils. Co., 809
S.W.2d 201, 207 (Tex. 1991). Courts “construe administrative rules, which
have the same force as statutes, in the same manner as statutes. ”
Rodriguez v. Serv. Lloyds Ins. Co., 997 S.W.2d 248, 254 (Tex. 1999) (citing
Lewis v. Jacksonville Bldg. & Loan Ass’n, 540 S.W.2d 307, 310 (Tex.
1976).). Therefore, the courts look first to the plain language of the rule.
“Unless the rule is ambiguous, we follow the rule’s clear language.”
Rodriguez, 997 S.W.2d at 254 (citing RepublicBank Dallas, N.A. v.
Interkal, Inc., 691 S.W.2d 605, 607 (Tex.1985)). But courts “defer to an
agency’s interpretation of its own rules unless it is plainly erroneous or
contradicts the text of the rule or underlying statute.” Sw. Pharmacy
Solutions, Inc. v. Tex. Health & Human Servs., 408 S.W.3d 549, 558 (Tex.
App.—Austin 2013, pet. denied) (citing Pub. Util. Comm’n v. Gulf States
Utils. Co., 809 S.W.2d at 207); see also Tex. Bd. of Chiropractic Exam’rs v.
11
Tex. Med. Ass’n, 375 S.W.3d 464, 475 (Tex. App.—Austin 2012, pet.
denied).
B. The Commission’s Order complies with its rules.
The Commission’s decision complies with its applicable rules. By their
plain language, the rules cited in the district court’s judgment do not apply
to this proceeding. Commission rules that do apply support the
Commission’s order.
1. Rule 25.236(d) applies to this Fuel Reconciliation and
authorizes the Commission’s decision.
The applicable Commission rule requires the Commission to determine
whether Entergy over- or under-recovered retail fuel costs. Rule
25.236(d)(2) states: “The scope of a fuel reconciliation proceeding includes
any issue related to determining the reasonableness of the electric utility’s
fuel expenses during the reconciliation period and whether the electric
utility has over- or under-recovered its reasonable fuel expenses.”24
Because Entergy was reconciling fuel costs and revenues that affect only its
retail customers,25 the question is whether Entergy “over-or under-
recovered its reasonable fuel expenses”26 incurred to serve retail customers.
24
16 Tex. Admin. Code § 25.236(d)(2).
25
SAR, Item 1 at 8.
26
16 Tex. Admin. Code § 25.236(d)(2).
12
The plain language of Rule 25.236(d)(1)(A) also shows that only retail fuel
expenses should be considered. The rule limits the Fuel Reconciliation to
expenses incurred to service retail customers stating: “In a proceeding to
reconcile fuel factor revenues and expenses, an electric utility has the
burden of showing that: (A) its eligible fuel expenses during the
reconciliation period were reasonable and necessary expenses incurred to
provide reliable electric service to retail customers.”27
By using the contemporaneous line-loss study, the Commission followed
those rules; it limited eligible fuel expenses to those incurred to serve retail
customers. Entergy, by using the out-of-date line-loss study, allocated to
retail customers nearly $4 million of fuel expenses that were actually
incurred to provide electricity to wholesale customers. The $4 million was
spent for fuel expenses Entergy incurred to generate electricity that was
lost transmitting electricity to wholesale customers. Fuel expenses to serve
wholesale customers are not “reasonable and necessary expenses incurred
to provide reliable electric service to retail customers.”28 Thus, the
Commission complied with its applicable rules by refusing to include those
wholesale fuel costs in the reconciliation.
27
16 Tex. Admin. Code § 25.236(d)(1)(A) (emphasis added).
28
Id.
13
2. None of the rules cited by the district court apply to the
Fuel Reconciliation in this case.
None of the rules cited by the district court apply to the Fuel
Reconciliation in this case. The district court’s judgment cited Rules
25.236(e)(3), 25.237(a), and 25.237(c)(B). By their plain language, the two
cited sections of Rule 25.237 apply to setting Fuel Factors—temporary fuel
rates—not to a Fuel Reconciliation where the Commission determines the
actual, final fuel rates. Because the Commission reconciled Entergy’s fuel
expenses but did not set a new Fuel Factor, Rule 25.237 cannot apply.
The cited provision in Rule 25.236 applies to “interclass allocations” of
refunds or surcharges in a Fuel Reconciliation. For two reasons, the plain
language of that rule does not apply. First, it addresses refunds and
surcharges, but Entergy specifically asked not to implement a refund or
surcharge in this case, but to postpone it to a later docket.29 Second,
“interclass allocations” refers to the retail rate classes for which the
Commission is determining an over- or under-recovery of fuel costs.
Because none of them are wholesale rate classes, the rule, by its plain
language, does not apply to a decision that $4 million was incurred for
service to wholesale rather than retail ratepayers.
29
SAR, Item 1, at 9.
14
a. Rule 25.236(e)(3) does not apply to this Fuel
Reconciliation.
Rule 25.236(e)(3) refers to “[i]nterclass allocations of refunds and
surcharges … .”30 But Entergy specifically asked to postpone refunding the
over-collected fuel expenses to a subsequent proceeding;31 there were no
refunds or surcharges in this proceeding. Thus, the plain language of Rule
25.236(e)(3) does not apply to this case.
In addition, the term “interclass allocations” in the rule applies to the
classes of customers included in Fuel-Factor rates that the Commission set.
Because the Commission does not set rates for Entergy’s wholesale
customers, the rule, by its plain language, does not apply to Entergy’s
wholesale customers. Thus, the Rule in no way prevents the Commission
from deciding that the contemporaneous line-loss study should be used to
decide whether the fuel costs were incurred for retail customers or for
wholesale customers. For this separate reason, the plain language of the
rule makes it inapplicable to this proceeding. The district court erred by
finding that the Commission violated this rule when it decided the Fuel
Reconciliation in this case.
30
Tex. Admin. Code § 25.236(e)(3) (emphasis added).
31
SAR, Item 1 at 9; AR, Item 185 at 320.
15
b. Rule 25.237(a) does not apply to a Fuel Reconciliation.
Rule 25.237(a) does not apply to this case because it addresses only Fuel
Factors. By its plain language, it does not apply to this Fuel Reconciliation.
A Fuel Factor is the forward-looking estimated rate; the reconciliation sets
the actual rate.
The reference to line losses in Rule 25.237(a) says nothing about how to
determine line losses in a Fuel Reconciliation. By requiring a Fuel Factor
to “account for system losses and for the difference in fuel reconciliation
corresponding to the voltage at which the electric service is provided,” Rule
25.237(a)(1) merely recognizes the importance of a line-loss study to
determine whether a utility has over- or under-recovered its fuel expenses.
The district court erred to find that the Commission violated this rule
about Fuel Factors when it decided the Fuel Reconciliation in this case.
c. Rule 25.237(c)(2)(B) does not apply to a Fuel
Reconciliation.
Rule 25.237(c)(2)(B) also applies only to Fuel Factors, not Fuel
Reconciliations. Thus, by its plain language, the rule does not apply to this
Fuel Reconciliation.
Similar to the rule above, the reference to line losses in Rule
25.237(c)(2)(B) says nothing about how to determine line losses in a Fuel
Reconciliation. To the extent that this Fuel-Factor rule mentions a line-loss
16
study, it shows how important a line loss is to determine the amount of fuel
expenses. The rule states 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.”32
The district court erred to find that the Commission violated this Fuel-
Factor rule when it decided the Fuel Reconciliation in this case.
Thus, the Commission cannot have violated Rules 25.236(e)(3),
25.237(a), and 25.237(c)(B) because, by their plain language, they do not
apply to this case. And the Commission complied with Rule 25.236(d),
which does apply. That rule explains that “[t]he scope of a fuel
reconciliation proceeding includes any issue related to determining the
reasonableness of the electric utility’s fuel expenses during the
reconciliation period and whether the electric utility has over- or under-
recovered its reasonable fuel expenses.”33 The Commission’s Order
complied with the applicable rule; it allowed Entergy to collect only for the
fuel expenses actually incurred to serve retail customers. The Commission
reasonably interpreted its rules, and that interpretation should be affirmed
by the Court.
32
16 Tex. Admin. Code § 25.237(c)(2)(B).
33
16 Tex. Admin. Code § 25.236(d)(2).
17
C. Entergy has not shown prejudice to its substantial rights.
The district court also erred in reversing the Commission’s fuel-
reconciliation decision because Entergy made no showing that the
Commission’s decision will harm Entergy, and showing prejudice to
substantial rights is a requirement for a plaintiff to prevail in a suit for
judicial review of an agency’s order. Tex. Gov’t Code § 2001.174(2)
(directing the court to “reverse or remand the case for further proceedings
if substantial rights of the appellant have been prejudiced” for stated
reasons) (emphasis added); El Paso Elec. Co. v. Pub. Util. Comm’n, 917
S.W.2d 846, 857 n.6 (Tex. App.—Austin 1995, writ dism’d by agr.)(“We
need not address the merits of the City’s argument for two reasons: (1) the
City has not demonstrated that its substantial rights in this case have been
prejudiced by the alleged superfluous findings, a prerequisite for reversal
or remand under APA …”).
Entergy asked the Commission to address only retail rates. Wholesale
rates for Entergy, which serves an area outside the Texas intrastate electric
grid called ERCOT, are usually set by the Federal Energy Regulatory
18
Commission.34 In addition, Rule 25.236(d)(1)(A) specifically speaks to
retail rates. 16 Tex. Admin. Code § 25.236(d)(1)(A).
Entergy failed to show harm because, although Entergy claims harm
based on treating wholesale fuel expenses differently than retail fuel
expenses, the utility refused to give any information about recovering fuel
expenses from wholesale customers. An Entergy witness maintained that
costs would be stranded if the contemporaneous line-loss study were used
for retail customers while maintaining that wholesale rates were irrelevant.
(See AR, Tr. 1466-75, (“[I]f you are retrospectively changing an allocation
factor, then, to me, no, you’re stranding those costs.” at 1470–71) (“[H]ow a
contract is written and that contract that’s entered into between ETEC or
any wholesale customer and the company again is totally separate and
distinct from a cost of service used to set retail rates for [Entergy] in the
state of Texas.” at 1466).) The Commission has evidence only about
Entergy’s retail fuel expenses. Based on that evidence, in addition to the
$243 million of fuel expenses that the utility estimated that it over-
recovered from retail customers, Entergy also recovered almost $4 million
34
See Gulf States Utils. Co. v. Pub. Util. Comm’n, 841 S.W.2d 459, 471 (Tex.
App.—Austin 1992, writ denied) (“FERC’s jurisdiction encompasses wholesale rates and
power allocations affecting those rates, as well as purchaser-prudence issues arising in
the context of integrated pooling agreements or sales between corporate affiliates.”).
19
for fuel costs that should have been allocated to wholesale rather than retail
customers.
Entergy failed to show that the Commission’s decision to use the
contemporaneous line-loss study would cause it harm.
Conclusion
The district court erred; it based its holding that the Commission’s
Order was arbitrary and capricious on rules that do not apply to this fuel-
reconciliation. And the Commission’s Order accords with the applicable
fuel-reconciliation rules.
Prayer
The Commission asks the Court to reverse the district court’s judgment
to the extent that it found error in the Commission’s order (that the
Commission erred in applying the current line-loss study) and to affirm 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
CHARLES E. ROY
First Assistant Attorney General
20
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
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
Certificate of Compliance
I certify that the foregoing computer-generated document has 4254
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
21
Certificate of Service
I hereby certify that on this the 31st day of March 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
22
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
23
APPENDIX A
District Court Judgment
CC l! Kl4~51'G U2
F'Ued In 'l'h , .
of Travis ~ 011mct Cow·:
oumy, 't!ixa£
EM OCT 1~ 2ui41
CAUSE NO. D-J-GN-lJ-000121 At (/ .J.if A
Amalia Rodrigu&z·Mend- . M
oza; Glerh
ENTERGY TEXAS, 1INC., § IN THE DISTRICT COURT OF
Pliaintiiff §
§
'V. § TRAVIS COUNTY, TEXAS
§
PU[JLIC UTILITY COMMISSION, §
Defendant § 353Ro JUDICIAL DISTRICT
ORDER ON ADMINISTRATIVE APPEAL
On July 22, 2014, the Court heard Plaintiffs appeal from Defendant's Order in PUC
Docket No. 39896, SOAH Docket No. . The administrative record was admitted
into evidence, and the Court lhe.ard oral argument. Entergy, the Cities, and OPUC each asserted
points of error challenging the Commission's order. Having considered the pleadings, the
evidence and the arguments of counsel, the Court makes the following rulings:
l. Entergy' s Point of Error No. I a<l<l1cssing the use of a current line loss study rather
tlhat a prior-approved line ~oss study in allocating line loss costs among classes of
customers establishes tha.t the Commission erred in applying the current study in
1
viola~ion of Commission rules found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a)
and (c)(2)(B). Accordingly, the Court FINDS that the PUC's ruling was arbitrary and
capricious and constitutes an error oflaw. The Court REVERSES such ruling and
REMANDS this matter to the Commission for further proceedi11gs consistent with
this Court's Order.
2. All other points of error are DENIED. and the Commission's Order is in all other
respects AFHRMED.
Alil relief not granted. herein, is DENIED1~ 1 /
I( rL llc.,a ~...
S·igned th~s /" day of ~rem~r. 2014 .
J
APPENDIX B
Commission Order
PUC DOCKET NO. 39896
SOAH DOCKET NO
APPLICATION OF ENTERGY TEXAS, §
INC. FOR AUTHORITY TO CHANGE §
RATES, RECONCILE FUEL COSTS, §
AND OBTAIN DEFERRED §
ACCOUNTING TREATl\ilENT § \
ORDER
This Order addresses the application of Entergy Texas, lnc. 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 b:ise-
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 waive.rs to the rate-filing package requirements .
On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law
judges (AUs) 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 AUs also recommended approving total fuel costs of approximately $1.3 billion.
The A.Us 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, 20 12, 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.
1
Supplemental Preliminary Order at 2. 3 (Jan. 19, 2012).
? Letter from SOAHjudges to PUC (Aug. 8, 2012).
000000001
PUC Docket No. 39896 Order Page 2 of43
SOAH Docket N o . -
I. Discussion
A. Prepaid Pension Asset Balance
Entergy included in rate base an approximately $56 million item named Unfunded
Pension. 3 This amount represents the accumulated difference between the annual pension costs
calculated in accordance with the Statement of Financial Accounting Standards (SFAS) No. 87
and the actual contributions made by Entergy to the pension fund-Entergy contributed nearly
$56 million more to its pension fund than the minimum required by SFAS No. 87.4
In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding
the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued
deferred federal income taxes (ADFIT) to be included in rate base. 5 For the excluded portion,
the Commission allowed the accrual of an allowance for funds used during construction
(AFUDC).6 The Al.Js concluded that this approach was sound and should be followed in this
case. 7 Thus, the Al.Js recommended that the CWTP-related portion of Entergy's prepaid pension
asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However,
the ALls did not address ADFIT.
The Commission agrees that the CWIP-related portion of Entergy' s pension asset should
be excluded from the asset and that this excluded portion should accrue AFUDC. However, the
Commission also finds that the impact of this exclusion on Entergy' s AD FIT 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 raxes related to the excluded $25 million. The Commission adds
new finding of fact 28A to reflect this modification to Entergy's ADFIT.
3
Proposal for Decision at 23 (July 6, 2012) (PFD).
4
PFD at 23-24.
5
Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on
Rehearing (March 4, 2008).
6
Remand of Docket No. 33309 (Application of AEP Tems Central Company for Authority 10 Change
Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011).
7
PFD at 26.
8
Id. at 24-26.
000000002
PUC Docket No. 39896 Order Page 3 of 43
SOAH Docket N o -
B. FIN 48
The Financial Accounting Standards Board's lnterpretation 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
uncenain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on
Entergy' s balance sheet as a tax liabil ity. 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.q
The AUs concluded that Entergy's FIN 48 liability should be included in its ADFIT
balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy' s
FIN 48 liability should not be included in Entergy's ADFIT balance. Accordingly, the AUs
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 ADm balance and thus
be used to offset Entergy' s rate base. 10 The AUs did not recommend the addition of a deferred-
tax.-account riuer 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-lax-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--0n which companies must
describe, list, and rank each uncertain tax position- would provide the lRS auditors sufficient
information to quickly determine which uncenain tax positions are of a magnitude wonh
investigating and that an IRS audit would he more likely to occur on some uncenain 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 paiu to the IRS until the next rate
case.
~ PFD at 2&27 (citing Rebuttal Testimony of Roberts, Entergy fa. 64 at 6). 29 (citing Rebuttal Testimony
of Robens. Entergy Ex. 64 at 8).
10
PFDat29.
11
Id. at 29.
tl Application of CenterPoint Electric Deliv~ry Company. UC for Aurhoriry to Change Rote.,, Docket
No. 38339, Order on Rehearing at 3-4 CJuoe 23, 2011).
000000003
PUC Docket No. 39896 Order Page~ of 43
SOAH Docket No.-
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 tbe 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 FlN-48 unfavorable-tax-position
decision by the IRS, then any amounts collected under rider related to that ovenumed 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.
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 AUs determined that
Entergy should not be able to recover its financially based incentive-compensation costs. IJ
Therefore, the portion of Entergy's incentive-compensation costs capitalized during the period
July 1, 2009 through June 30, 2010 that were financially based was excluded from Entergy's rate
base. The AUs 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 AUs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for
calculating the amount of the financially based incentive costs. This method uses the actual
percentage reductions applicable to each of the annual incentive programs that included a
15
component of financially-based costs.
[nits exceptions regarding capitalized incentive compensation, Entergy advocated for the
use of TlEC's methodology to also calculate the amount of capitalized incentive compensation
that is financially based. Entergy also noted that the amount of the disallowance reflected in the
13
PFD at 171.
1
~ Id. at 72.
u Id. at 174: see also Entergy·s Exceptions to the Proposal for D«ision at 25-26 (July 23. 201 2).
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schedules, $ t ,333,352, was calculated using a disallowance factor that included incentive
compensation tied to cost-control measures, which the A.Us found to be recoverable in the
operating-cost incentive-compensation calculation. 16 When the TIEC methodology is applied to
the capitalized incentive-compensation costs in rate base, the net result under TIEC' s
methodology is that only $335,752.96 should be disallowed from capital costs. 17
The Commission agrees that capitalized incentive compensation that is financially based
should be excluded from rate base and that the exclusion only applies to incentive costs that
Entergy capitalized during the period from July t, 2009 through June 30, 2010. However, the
Commission finds that a consistent methodology should be used to calculate the amount to be
excluded and therefore that TlEC'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
determin:ition.
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 ta:ites is $24,921,022. 18 an adjustment of $1.222, l 06 to Entergy' s test year amount.
Finding of fact 151 is modified to reflect this adjustment to property taxes.
D. Rate of Return and Cost of Capital
The 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 AUs found
that the effect of unsettled economic conditions facing utilities on the appropriate return on
equity should be taken into account and that the effect would be to move the ultimate return on
equity towards the upper limits of the range that was determined to be reasonable. 20 The AUs
16
Entergy's Exceptions to the Proposal for Decision at 25-26.
11
Id. at 25-26.
18
Commission Number-Run Memorandum at 2 <Aug. 28, 2012).
19
PFD .:it 94.
10 Id.
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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 AUs that a utility's return on equity
should be determined using an adder to reflect unsettled economic conditions facing utilities.
The Commission agrees with the AUs. 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 AUs. A
return on equity of 9.80 percent is within the range of an acceptable return on equity found by
the AUs. Accordingly, the Commission adds new finding of fact 65A to retlect the
Commission's decision on this point.
E. Purchased-Power Capacity Expense
The AUs rejected Entergy's request to recover $31 million more in purchased-power
capacity costs than its actual test-year expenses because Entergy had failed to prove that the
adjustment was known and measurable, 23 and because the request violated the matching
principle.24 Consequently, the AUs recommended that Entergy's test-year expenses of
$245,432,884 be used to set rates in this docket. 25
Entergy pointed to an additional $533,002 of purchased-power capacity expenses that
were properly included in Entergy's rate-filing package, but not provided for in the proposal for
decision. 26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for
Southwest Power Pool fees, $654.082 for Toledo Bend hydro fixed-charges, and -$127,212 for
an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of
purchased-power capacity costs were incurred during the test-year and should be added to the
purchased-power capacity costs in Entergy' s revenue requirement. The Commission modifies
:i t fd. at 94.
22
PURA §§ 36.05 l, .052.
23
PfD at 108-09.
14
fd. at 109.
!S fd.
.?6 Entergy's Ex~ptions to the Proposal for Decision at 51 .
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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 AUs found that $6,196.037, representing Entergy's financially-based incentives paid
in the test-year. should be removed from Entergy's O&M expenses.27 The AUs agreed with
Commission Staff and Cities that an additional reduction s hould 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.
The Commission agrees with the AUs, but modifies finding uf fact 133 to specifically
include the decision that an additional reduction should be made to account for the FICA taxes
Entergy would have paid on the disallowed financially-based incentive compensation. The
Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this
Order.29
G. Affiliate Transactions
OPUC argued that Entergy's sales and marketing expenses exclusively benefit the larger
commercial and industrial customers, but the majority of the sales, marketing, and customer
service expenses are allocated to the operating companies based on customer counts. Therefore,
the majority of these expenses are ::illocated to residential and small business customers. OPUC
argued that it is inappropriate for residential and small business customers to pay for these
expenses.JO The AUs did not adopt OPUC's position on this issue.
The Commission agrees with OPUC ::ind 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 reaHocated using direct assignment. The Commiss ion has
27
PFD at 175.
!S Id. at 175-76.
19
See Commission Number Run-Memorandum at J (Aug. 28. 2012).
IO Direct Testimony of Carol Szerszen. OPUC Ex. I at 44-45.
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previously ex.pressed 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: (I) $46,490 for Project ElOPCR56224 - Sales and Marketing - EGSI Tex.as;
(2) $17,013 for Project F3PCD10049 - Regulated Retail Systems O&M; and (3) $30,167 for
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 164A is added to reflect the proper allocation of these
affiliate transactions.
H. Fuel Reconciliation
Entergy proposed to allocate costs for the fuel reconciliation to customers using a line-
loss study performed in 1997. Entergy conducted a line-loss study for the year ending December
31. 20 l 0, which falls in the middle of the two year fuel reconciliation period-July 2009 through
June 20 ll-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 retle.ct the current line-loss study performed by Entergy for this case
and recommended approval on a going-foiward 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. SunST. R. 25.236. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel
reconciliation proceeding to include any issue related to the reasonableness of a utility's fuel
expenses and whether the utility has over- or under-recovered its reasonable fuel expenses.33
Cities calculated a $3,981.27 l reduction to the Texas retail fuel ex.penses incurred over the
reconciliation period using the current line-losses. The AUs rejected Cities' proposed
adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission-
31
Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965.
Second Order on Reheaiing o.t 87, COL 29 (Oct. 16, 1997).
32
Direct Testimony of Carol Szerszen, OPUC Ex.. I at Schedule CAS-7.
)) Cities' Exceptions to lhe Proposal for Decision at 20-21 (July 23. 2012).
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PUC Docket No. 39896 Order Page 9 of 43
SOAH Docket No
approved line losses that were in effect at the time fuel costs were billed to customers in a fue l
reconciliation. 34
The Commission agrees with Cities and reverses the proposal for decision regarding
which line-loss factors should be used in Entergy's fuel reconciliation. Entergy used the 2010
study line-loss calculations to calculate the demand- and energy-related allocations in its cost of
service analysis supporting its requested base rates. These same currently available line-loss
factors should have been utilized in Entergy's fuel reconciliation. The Commission finds that
Entergy's 2010 line-loss factors should be used to calculate Entergy's fuel reconciliation
over-recovery. As a result, Entergy's fuel reconciliation over-recovery should be reduced by
$3,981.271. Finding of fact 246A and conclusions of law l 9A and 198 are added to reflect the
Commission's finding that the 2010 line-loss factors be used to reconcile Entergy' s fue l costs.
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 m 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.
3
~ PFD at 327-328.
35
Open Meeting Tr. at 138 (Aug. 17. 2012).
.)6 Id.
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K. Other Issues
New findings of fact 17A, l7B, 17C, 170, and 17 E are added to retlect procedural
:.ispects of the case after issuance of the proposal for decision.
In addition, to reflect corrections recommended by the AUs, 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. Findin.gs 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, 201 l. 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: (I) a proposed
increase in annual base rate revenues of approximately $11 l.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 errs 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
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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,
Da.yton, Groves, Houston, Huntsville, Montgomery, · Navasota, Nederland, Oak Ridge
North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah,
Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co.
(Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric
Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores
Texas. LLC, and Sam's East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility
Commission of Texas (Commission or PUC) was also a participant in this docket.
7. On November 29, 2011, the Commission referred this case to the State Office of
Administrative Hearings (SOAH).
8. On December 7. 2011. the Commission issued its order requesting briefing on threshold
legal/pol icy 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 Auth<>rity 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 l3, 2012, the AUs 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 panicipate as counsel for Wal-Mart.
000000011
PUC Docket No. 398% Order Page 12 of 43
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12. On January 19, 20 12, 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 Conunission petitions for review of the rate ordinances of the
municipalities e)(ercising original jurisdiction within its service territory. All such
appeals were consolidated for determination in this proceeding.
14. On April 4, 2012, the AUs issued SOAH Order No. 13 severing rate case expense issues
into Application of Entergy Texas, Inc. for Rate Case Expenses Severed f rom 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.
l7A. On August 7, 2012, the SOAH ALls filed a letter with the Commission recommending
changes to the PFD.
17B At the July 27, 2012 open meeting, ETI agreed to extend the effective date of rates to
August 31, 2012 to provide the Commission sufficient time to c.onsider the issues in this
proceeding.
l7C. The Commission considered the proposal for decision at the August 17, 2012 and August
JO. 2012 open meetings.
l 70 . At the August 30, 20 l 2 open meeting, ETI agreed to ex.tend the effective date of rates to
September 14, 20 l 2.
l 7E. At the August 17. 2012 open meeting, parties announced on the record a settlement of the
amount of costs for the trnnsition to MISO.
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PUC Docket No. 39896 Order Page 13 of43
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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 re.c;olved 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 amonization 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 CWTP in rate base, and there
was insufficient evidence showing that major projects under construction were efficiently
and prudently managed.
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PUC Docket No. 39896 Order Page 14 of 43
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27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not
be included in ETl's rate base.
28. The remainder of the prepaid pension assets balance should be included in ETr 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 $8,858,913. 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 constmction on the
portion of ETI's Prepaid Pension Assets Balance capitalized to CWIP.
30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48
(FIN 48), "Accounting for Uncertainty in Income Taxes," requires ETI to identify each of
its uncertain tax positions by evaluating the taK 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.
3 l. FIN 48 requires ETI to remove the amount of its uncenain 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 ha.s, 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 lhe IRS.
33. ETl has deposited $1,294,683 with the lRS in connection with the FlN 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.
000000014
PUC Docket No. 39896 Order Pnge 15 of43
SOAH Docket N o . -
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 lRS for the FIN 48 liability) should be
added to ETI's ADFIT and thus be used to reduce ETl's rate base.
40. ETr s application and proposed tariffs do not indude a request for a tracking mechanism
or rider to collect a return on the FIN 48 liability.
40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to
recover on a prospective basis an after~tax return of 8.27 % on the amounts paid to the
IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN
48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by
an IRS audit after such amounts are actually paid to the federal government. If ETI
prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider
related to that decision should be credited back to ratepayers.
4 t. Deleted.
42. [nvestor-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 3mount of working capital, not specifically oddressed
in other rate base items, that is necessary to fund the gap between the time expenditures
are made and the time corresponding revenues are received.
44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted
for known and measurable changes, and is consistent with P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii).
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PUC Docket No. 39896 Order Page 16 0143
SOAH Docket No.-
45. It is reasonable to establish ETl's cash working capital requirement based on ETI's lead-
lag study as updated in lay 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 focie case concerning the prudence of its stonn 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 stonn reserve balance was negative $59,799,744.
51. The amount of $9,846,037, representing the value of the average coal inventory
maintained at ETl'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 for 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-tenn assets to the 13-
month period ending December 2011, which was the most recent information available.
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PUC Docket No. 391196 Order Page 17 of4J
SOAH Docket No.
Staffs proposed adjustments should be incorporated into the calculation of ETI' s rate
base.
56. The following short-term asset amounts should be included in rate base: prepayments at
$8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.
57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the
Spindletop facility, represent actual costs incurred to process and close the acquisition.
not mere mark-up costs.
58. ETI' s $ I.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 payme.nts made by ETI for
incentive compensation tied to financial goals.
61. The portion of ETl' s incentive payments that are capiralized and that are financially-
based should be excluded from ETI' s race base because the benefits of such payments
inure most immediately and predominantly to ETI's shareholders, rather than its electric
customers. ETI's capitalized incentive compensation that is financially based is
$335,752.96 and should be removed for rate base.
62. The test-year for ETI's prior ratemaking proceeding ended on June 30, 2009, and the
reasonableness of ETI's capital costs (including capitalized incentive compensation) for
that prior period was dealt with by the Commission in that proceeding and is not at issue
in this proceeding.
63. In this proceeding, ETI's capitalized incentive compensation that is financially-hased
should be excluded from rate base, but only for incentive costs that ETI capitalized
during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010
(the commencement of the current test~ year).
000000017
PUC Docket No. 39896 Order Page 18 or43
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Rate o(Retur11 and Cost of Capital
64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable
opportunity to earn a reasonable return on its invested capital.
65. The results of the discounted cash flow model and risk premium approach support a ROE
of 9 .80 percent.
65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions
facing utilities.
66. A 9.80 percent ROE is consistent with ETI's business and regulatory risk.
67. ETI's proposed.6.74 percent embedded cost of debt is reasonable.
68. The appropriate capital structure for ETI is 50.08 percent long-term debt and
49.92 percent common equity.
69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is
reasonable in light of ETI's business and regulatory risks .
70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help
ETI attract capital from investors.
71. ETI's overall rate of return should be set as follows:
CAPITAL WEIGHTED AVG
COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL
LONG· TER!'1 DEBT 50.08% 6.74% 3.38%
COMMON EQUITY 49.92% 9.80% 4.89%
TOTAL 100.00% 8.27%
Ooera#ng Expenses
72. ETI's test-year purchased capacity expenses were $245,965,886.
73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its
purchased capacity costs. This request was based on ETI's projections of its purchased
capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
rate-year).
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PUC Docket No. J9896 Order Page 19 or43
SOAH Docket No.-
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
ETl 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 tmder the contract, even though that assumption is inconsistent
with ETI's historical experience.
78. There is substantial uncenainty with regard to ETI's projection of its rate-year third-party
capacity-contract payments.
79. ETI's estimates of its rate-year purchases under affiliate contracts are based on a
mathematical formula set out in Schedule MSS-4.
80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments
will be based on ratios and costs that cannot be determined until the month that the
payments are to be made.
81. Over $11 million of ETI' s affiliate transactions were based on a 2013 contract (the EA[
WBL Contract) that was not signed until April 11, 2012.
82. There is uncenainty about whether the EAI WBL Contract will ever go into effect.
83. ETI projects purchasing over JOO 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.
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PUC Docket No. 39896 Order Page 20 or4J
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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. ETl's projection of its rate-year transmission equalization expenses is uncertain and
speculative because it depends on a number of variables, including future transmission
investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
expenses, and loads of each of the Entergy operating companies.
91. ETI seeks increased transmission equalization expenses for transmission projects that are
not currently used and useful in providing electric service. ETI's post-test-year
adjustment is based on the assumption that certain planned transmission projects will go
into service after the test-year. At the close of the hearing. none of the planned
transmission projects had been fully completed and some were still in the planning phase.
92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
expenses related to projects that are not yet in-service.
93. ETI's request for a post-test-year adjustment of $8,942,785 for rate-year transmission
equalization expenses should be denied because those expenses are not known and
measurable. ETI's post-test-year adjustment does not with reasonable certainty reflect
what ETI's transmission equalization expense will be when rates are in effect.
94 . ETI's transmission equalization expense in this case should be based on the test-year
level of $1,753,797.
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PUC Docket No. 39896 Order Page 21 of 43
SOAH Docket N o -
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 amonization 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.
10 t. Production plant net salvage is reasonably based on the negative five percent net salvage
in existing rates.
102. The net salvage rate of negative 10 percent for ETI's transmission structures and
improvements (FERC Account 352) is the most reasonable of those proposed and should
be adopted.
103. The net salvage rate of negative 20 percent for ETI's transmission station equipment
(FERC Account 353) is the most reasonable of those proposed and should be adopted.
104. The net salvage rate of negative five percent for ETr 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.
000000021
PUC Docket No. 39896 Order Page 22 or43
SOAH Docket No.
106. The net salvage rate of negative 30 percent for ETI's transmission overhead conductors
and devices (FERC Account 356) is the most reasonable of those proposed and should be
adopted.
107. A service life of 65 years and a dispersion curve of R3 for ETI' s distribution structures
and improvements (FERC Account 361) are Lhe 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 ETrs 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 of L4 for ETI's distribution overhead
service (FERC Account 369.1) are the most reasonable of those proposed and should be
approved.
l l3 . 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.
000000022
PUC Docket No. 39896 Order Page 2.1 of43
SOAH Docket N o - - -
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 sal,vage rate of positive five. percent for ETI's distribution line transformers
(FERC Account 368) is the most reasonable of those proposed and should be adopted.
117. The net salvage rate of negative lO 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 LO percent for ETl'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 ETJ' 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 reasom1ble of those proposed and should
be adopted.
121. lt is reasonable to conven 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 lif'e 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.
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PUC Docket No. 39896 Order Page 2.a of 43
SOAH Docket No.-
ln 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
cowiting of three ETI and one ESI employee; (h) 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) pa.yroll
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.
armual 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 predominnnt benefit to ratepayers.
130. Incentives to achieve operational measures are necessary and reasonable to provide utility
services but those to achieve financial measures are not.
131. The $5,376,975 that was paid for long term incentive programs was tied to financial
measures and. therefore. should not be included in ETI's cost of service.
132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
was tied to financial measures and, therefore. should be disallowed.
133. In total, the amount of incentive compensation that should be disallowed is $6,196,037
because it was related to financial measures that are not reasonable and necessary for the
provision of electric service. An additional reduction should be made to account for the
000000024
PUC Docket No. 39896 Order Page 25 or 43
SOAH Docket No.
FICA taxes ETI woul<l have pai<l 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 Enterg y companies provi<le 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.
l 36. 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. Erl's benefits plan levels are within a reasonable rnnge 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 tmder the Internal Revenue Code, would otherwise not receive
retirement benefits on their annual compensation over $245,000 per year.
141. ETl'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 $2,114,93 1 are not
reasonable or necessary to provide utility service to the public. not in the public interest,
and should not be included in ETl'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.
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PUC Docket No. 39896 Order Page 26 of .a3
SOAH Docket N o -
L44. ETI's relocation expenses were reasonable and necessary.
145. The company's requested operating expenses should be reduced by $40,620 to reflect the
removal of certain executive prerequisites proposed by Staff.
146. Staff properly adjusted the company's requested interest expense of $68,985 by removing
$25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
2012), leaving a recommended interest expense of $43,047.
147. During the test-year, ETI's property tax expense equaled $23,708,829.
148. ETI requested an upward pro Jonna adjustment of $2,592,420, to account for the property
tax expenses ETI estimates it will pay in the rate-year.
149. ETl's requested pro Jonna adjustment is not reasonable because it is based, in part·, upon
the prediction that ETI's propeny tax rate will be increased in 2012, a change that is
speculative is not known and measurable.
150. Staffs 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. ETl's test-year prope.rty tax burden should be adjusted upward by $1,222,106 for a total
expense of $24,921.022.
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 retlect changes to cost of service that affect other
components of the revenue requirement such as the calculation of the Texas state gross
receipts tax, lhe local gross receipts tax, lhe PUC Assessment Tax and the Uncollec;tible
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
000000026
PUC Docket No. 39896 Order Page 27 of4J
SOAH Docket N o . -
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 .23 l (b)( 1)(f)(i).
156. Based on the most current information reasonably available, the appropriate level of
decommissioning costs to be included in ETI' s cost of service is $1, 126,000.
157. ETI's appropriate total annual self-insurance storm damage reserve expense is
$8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual
expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the
reserve from its current deficit.
158. ETI's appropriate target self-insurance storm damage reserve is $17,595,000.
159. ETl should continue recording its annual storm damage reserve accrual until modified by
a Commission order.
160. The operating costs of the Spindletop focili.ty are reasonable and necessary.
16 l. The operating costs of the Spindletop facility paid to PB Energy Storage Services are
eligible fuel expenses.
AfflliaU Traflsaclions
162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of
these O&M expenses-$69,098,041-were charged to ETI by ESI. The remaining
affiliate services were charged (or credited) to ETl 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. ESl 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
000000027
PUC Docket No. 39896 Order Page 28 or43
SOAH Docket N o . -
necessary to ensure appropriate levels of service to its customers; and (e) overs ight
controls by ETl's Affiliate Accounting and Allocations Department.
164. Affiliates charged expenses to ETI through 1292 project codes during the test-year.
164A. The $2,086, 145 in affiliate transactions related to sales and marketing expenses should be
reallocated using direct assignment. The following amounts should be allocated to all
retail classes in proportion to number of customers: (1) $46.490 for Project
ElOPCR56224 - 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) Genernl Service, (2) Large General Service and (3) Large Industrial
Power Service.
165. ETI agreed to remove the following affiliate transactions from its application:
(l) 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 (Stonn Cost Processing & Review) in the amount of $929.
166. The $356, 151 (which figure includes the $112,531 agreed to by ETD of costs associated
with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and FSPPZNQBDU (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.
161. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts
Settlement) are not normally-recurring costs and should not be recoverable.
168. The $19.714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are
related to ESI' s operations, it is more immediately related to Entergy Louisiana, Inc. and
Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.
169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy
Management for ESl) 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.
000000028
PUC Docket No. 39896 Order Page 29 of43
SOAH Docket No.
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 Allocadon
171. ETI has one full or panial 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 l50 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 AllocalWn and Rate Design
175. There is no express statutory authorization for ETI's proposed Renewable Energy Credits
rider (REC rider).
176. REC rider constitutes improper piecemeal ratemaking and should be rejected.
177. ETI's test-year expense for renewable energy credits, $623,303, is reasonable and
necessary and should be included in base rares.
178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
public rights-of-way to loc:ite 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 limit~ .
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PUC Docket No. 39896 Order Page JO or43
SOAH Docket N o . -
180. Because all customers benefit from ETI's rental of municipal right-of-way, municipal
franchise fees should be charged to all customers in ETl'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
Ta;ir;es. The company's proposed allocation of these costs to all retail customer classes
based on customer class revenues relative to total revenues is appropriate.
l 82A. 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.
l 86. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
replacement of a functioning light with a lower-wattage bulb.
187. It is appropriate to require ETI to prepare and file. as part of its next base rate case, a
study regarding the feasibility of instituting LED-based rates and, if the study shows that
such rates are feasible, ETI should file, proposals for LED-based lighting and traffic
signal rates in its next rate case.
000000030
PUC Docket No. 39896 Order Page Jl of43
SOAH Docket No-
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-o f-contract demand
ratchet for existing customers in the Large Industrial Power Service (LIPS), Large
Industrial Power Service-Time of Day, General Service, General Service,-Time of Day,
Large General Service, and Large General Service-Time of Day rate schedules.
189. ETI's proposed tariffs in this case did not remove the life-of-contract demand ratchet
from these rate schedules consistent with the parties ' agreement in Docket No. 37744.
190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI
proposed, is not reasonable.
191 . ETI' s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
agreement that was adopted by the Commission as just and reasonable in Docket
No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact
No. 192- 194.
192. ETI's Schedule LIPS and LIPS Time of Day§ VI should be changed to read:
DETERMINATCON 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 § § lll, IV and V above; or
(B) 75% of Contract Power as defined in§ VII: or
(C) 2,500 kW.
193. ETI'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 contra<;t, the Contract Power shall be the kW specified in
000000031
PUC Docket No. J9K96 Order Page32 of4J
SOAH Docket N o . -
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 ETl'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. lt 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
Will iam B. Abbott.
198. DOE proposed a new Schedule LIPS rider-Schedule "Schedulable Intermittent
Pumping Service" (SIPS) for load schedulable at least four weeks in advance, that occurs
in the off-season (November through April), that can be cancelled at any time, and for
load not lasting more than 80 hours in a year. For customers whose loads match these
SIPS characteristics (for example, DOE's Strategic Petroleum Reserve). the 12-month
demand ratchet provision of Schedule LIPS does not apply to demands set under the
provisions of the SIPS rider. The monthly demand set under the SIPS provisions would
be applicable for billing purposes only in the month in which it occurred. ln 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. OOE's proposed Schedule SlPS 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.
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PUC Docket No. 39896 Order Page 33 of ~3
SOAH Docket No
201. P.U.C. SUBST. R. 25.242(k)(l) provides that rates for sales of standby an<l maintenance
power to qualifying facilities should recognize system wide costing principles and should
not be discriminatory.
202. lt 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 Transmiss ion
Charge
(less than 69KV) (69KV and greater)
Billing Load Charge ($/kW):
Standby $2.46 $0.79
Maintenance $2.27 $0.60
Non-Fuel Enen~v Chante (¢/kWh)
On-Peak 4.245¢ 4.074¢
Off-Peak 0 .575¢ 0.552¢
203. ETI's Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental
charge paid by a customer when ETI installs facilities for that customer that would not
normally be supplied. such as line extensions, transformers, or dual feeds.
204. ETI ex:isting Schedule AFC provides two pricing options. Option A is a monthly charge.
Option B. which applies when a customer elects to amortize the directly-assigned
facilities over a shorter term ranging from one to ten years, has a variable monthly
charge. There is also a term charge that applies after the facility has been fully
depreciated.
205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent
per month of the installed cost of all facilities included in the agreement for additional
facilities.
000000033
PUC Docket No. 39896 Order Page 34 of 43
SOAH Docket No. -
206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rnte and
the Post Term Recovery Charge as follows:
Selected Recovery Term Recovery Term Charge Post Recovery Term Charge
l 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 l .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). [n 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
Tex.as, as stated in PURA § 39.905.
000000034
PUC Docket No. 39896 Order P:ige 35 of 43
SOAH Docket No
212. Schedule RS winter block rates should be modified consistent with the goal set out in
PURA § 39.905, with the initial ph~e- 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.
2 13. Other elements of Schedule RS are just and reasonable.
Fuel Reconciliation
2 14. ETI incurred $61 6,248,686 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 transponation 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 $90,821,317 in coal eApenses during the reconciliation period .
219. ET[ prudently managed its coal and coal-related contracts during the reconciliation
period.
220 . ETI monitored and audited coal invoices fro m 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
ele·ctric 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.
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PUC Docket No. 39896 Order Page J6 of 43
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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 rhe reasonableness of
ils purchased-power planning and procurement processes and its actual power purchases
<luring the reconciliation period.
227. The Entergy system sold power off system when the revenues were expected to be more
lhan 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 govems 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.
2JJ. 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
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PUC Docket No. 39896 Order Page 37 of 43
SOAR Docket No.-
companies. These inter-system "reserve equalization" payments are the result of a
formula rate related to the Entergy system's reserve capability that is applied on a
monthly basis.
234. Reserve capability under service schedule MSS-1 is capability in excess of the Entergy
system's actual or planned load built or acquired to ensure the reliable, efficient operation
of the electric system.
235. By approving service schedule MSS-1, the FERC has approved the method by which the
operating companies share the cost of maintaining sufficient reserves to provide
reliability for the Entergy system as a whole.
236. Service schedule MSS-3 of the System Agreement determines the pricing and exchange
of energy among the operating companies. By approving service schedule MSS-3, the
FERC has approved the method by which the operating companies are reimbursed for
energy sold to the exchange energy pool and how that energy is purchased.
237. Service schedule MSS-4 of the System Agreement sets forth the method for determining
the payment for unit power purchases between operating companies. By approving
service schedule MSS-4, the FERC has approved the methodology for pricing
inter-operating company unit power purchases.
238. The Entergy system is planned using multi-year. annual, seasonal. monthly. and next-day
horizons. Once the planning process has identified the most economical resources that
can be used to reliably meet the aggregate Entergy system demand, the next step is to
procure the fuel necessary to operate the generating units as planned and acquire
wholesale power from the market.
239. Once resources are procured to meet forecasted load, the Entergy system is operated
during the current day using all the resources available to meet the total Entergy system
demand.
240. After current-day operation, the System Agreement prescribes an accounting protocol to
bill the costs of operating the system to the individual operating companies. This
protocol is implemented via the intra-system bill to each operating company on a
monthly basis.
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PUC Docket No. 39896 Order Page 38 of43
SOAH Docket N o . -
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.
246A. ETI's 2010 line-loss factors should be used to reconcile ETl's fuel costs. Therefore,
ETI's fuel reconciliation over-recovery should be reduced by $3,981,271.
247. ETI's proposed loss factors are reasonable and shall be implemented on a prospective
basis as a result of this final order.
248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the
FERC' s reallocation of rough production equalization costs in FERC Order No. 720-A,
and to treat such costs as eligible fuel expense.
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PUC Docket No. 39896 Order Page 39 or 43
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249. Special circumstances exist and it is appropriate for ETI to_recover the rough production
cost equalization costs reallocated to ETI as a result of the FERC's decision in Order
No. 720-A.
Other Issues
250. A deferred accounting of ETl'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 MlSO transition expense.
252. Deleted.
253. Transmission Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.
254. Distribution Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.
255. The appropriate amount for ETI's purchased-power capacity expense to be included in
base rates is $245,965,886.
256. The amount of ETI's purchased-power capacity expense includes tbird-pany 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.
III. Conclusions of Law
1. ETI is a "public utility" as that term is defined in PURA § l l.004(1) and an "electric
utility" as that term is defined in PURA § 3 l.002(6).
2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 14.00 1, 32.001, 32.101, 33.002, 33.051,
36.101-.111, and 36.203.
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PUC Docket No. 39896 Order Page 40 of 43
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3. SOAH has jurisdiction over matters related to the conduct of the hearing an<l 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 <locket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act. Tex. Gov't Code Ann. Chapter 200 I.
5. ETI provided notice of its application in compliance with PURA§ 36.103, P.U.C. PROC.
R. 22.Sl(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 ha~ jurisdiction over an appeal from a
municipality's rate proceeding.
8. ETI has the burden of proving that the rate change it is requesting is just and reasonable
pursuant to PURA§ 36.006.
9. In compliance with PURA § 36.051, ETI' s overall revenues approved in this proceeding
permit ETI a reasonable opportunity to earn a reasonable return on its invested capital
used and useful in providing service to the public in excess of its reasonable and
necessary operating expenses.
10. Consistent with PURA § 36.053, the rates approved in this proceeding are. based on
original cost, less depreciation. of property used and useful to ETI in providing service.
11 . The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
and P.U.C. SUBST. R. 25.23l(c)(2)(C)(i).
12. lnduding the cash working capital approved in this proceeding in ETI's rate base is
consistent with P.U.C. SUBST. R. 25.23l(cX2)(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.
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PUC Docket No. 39896 Order Page4l of 43
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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 Grcznde 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. Suesr. R. 25.23l(b)(l)(F), the decommissioning expense approved in
this case is based on the most current infonnation 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).
l8. ETI prudently managed the dispatch. operations. and maintenance of its fossi l plants
during the reconciliation period.
19. The reconciliation perio<l level operating and maintenance expenses for the Spindletop
facility are eligible fuel expenses pursuant to P.U.C. S UBST. R. 25.236(a).
19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision
in a reconciliation proceeding.
19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to
include any issue related to the reasonableness of a utility's fuel expenses and whether
the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use
the new line-loss study to calculate Entergy's fuel reconciliation and over-recovery.
20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to
recover rough production equalization payments reallocated to ETI by the FERC.
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PUC Docket No. 39896 Order Page 42 or .&3
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21. ETI's rates, as approved in this proceeding, are just and reasonable in accordance with
PURA § 36.003.
IV. Ordering Paragraphs
(n 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 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 in Tariff Control No. 40742 Compliance Tariff Pursuant to Final Order in
Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates,
Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with
this Order within 20 days of the date of this Order. No later than ten days after the date
of the tariff filings, Staff shall file its comments recommending approval, modification,
or rejection of the individual sheets of the tariff proposal. Responses to the Stnff's
recommendation shall be filed no later than 15 days after the filing of the tariff. The
Commission shall by letter approve, modify, or reject each tariff sheet, effective the date
of the letter.
4. The tariff sheets shall be deemed approved and shall become effective on the expi.ration
of 20 days from the date of filing, in the absence of written notification of modific::ition or
rejection by the Conunission. If any sheets are modified or rejected, Erl 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 pan of its next base rate case a study regarding the
feasibility of instituting LED-based rates and, if I.he study shows I.hat such rates are
feasible. ETI should file proposols for LED-based lighting and traffic signal rates in that
case. If ETI h11s LED lighting customers taking service, the study sha ll include detailed
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PUC Docket No. 39896
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