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 arity 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
SOAH Docket N o . -
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.
000000012
PUC Docket No. 39896 Order Page 13 of43
SOAH Docket N o . -
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.
000000013
PUC Docket No. 39896 Order Page 14 of 43
SOAH Docket N o . -
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).
000000015
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.
000000016
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
SOAH Docket N o . -
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).
000000018
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.
000000019
PUC Docket No. 39896 Order Page 20 or4J
SOAH Docket N o . -
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.
000000020
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.
000000023
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 25.2%
$0.03834 $0.04799
1000)
OPC criticized ETI’s declining block rate structure as being contrary to energy efficiency
efforts. OPC witness Benedict noted that under ETI’s proposed rate structure, once kWh usage
exceeds 1,000 in a winter month, the per-kWh cost of consumption falls by 34 percent. Thus,
because a declining block rate structure lowers the per-unit rate for high levels of consumption,
heavy users are induced to consume more than they would otherwise. In his view, this runs contrary
to the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as
stated in PURA § 39.905:
(a) It is the goal of the legislature that: . . . (2) all customers, in all customer classes,
will have a choice of and access to energy efficiency alternatives and other choices
from the market that allow each customer to reduce energy consumption, summer
and winter peak, or energy costs.
Therefore, Mr. Benedict recommended that the declining block rate be phased out over time. He
stated this would ease the transition to a rate structure without a declining block, and it would allow
time for customers to switch to more efficient heating systems. Mr. Benedict proposed that the
phase-out take place over three rate cases, beginning with a one-third reduction in the block
differential proposed by ETI in this case. Reducing ETI’s proposed block differential from 2.469ȼ
1024
OPC Ex. 6 (Benedict Direct) at 42.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 317
PUC DOCKET NO. 39896
to 1.645ȼ accomplishes the initial one-third reduction, as illustrated below (using ETI’s requested
revenue requirement):1025
Reduced
ETI ETI Percent Block Rate Percent
Rate Element Current Proposed Increase Differential Increase
Customer Charge (per month) $5.00 $6.00 20.0% $6.00 20%
Energy Charge (Summer, all 25.3% 23.1%
$0.05802 $0.07268 $0.07141
kWh)
Energy Charge (Winter, kWh ≤ 25.3% 23.1%
$0.05802 $0.07268 $0.07141
1000)
Energy Charge (Winter, kWh > 25.2% 43.3%
$0.03834 $0.04799 $0.05496
1000)
Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended
to affect the amount of revenue to be collected from the residential class or any other class. If,
however, the Commission approves a different revenue requirement for the residential class to
reflect various proposed adjustments, rates for the class will need to be recomputed regarding a
reduced block differential1026
Staff generally agreed with OPC’s recommendation for a reduction in the rate differential
between the residential winter kWh ≤ 1000 block and the winter kWh > 1000 block, due to the
inconsistency between the incentives produced under declining block rates and the State’s energy
efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011
demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid
encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate
block differential is warranted to better encourage wintertime energy conservation at the margin.1027
ETI witness Talkington testified that the RS rates are cost-based with a declining block rate
in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage
increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She
1025
OPC Ex. 6 (Benedict Direct) at 43-45.
1026
OPC Ex. 6 (Benedict Direct) at 46.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 318
PUC DOCKET NO. 39896
provided analysis to support her position.1028 Ms. Talkington explained that residential rates do not
include demand charges because of the absence of residential demand meters. However, residential
energy rates can be structured the same as the non-residential classes; that is, customer charge,
demand charge and energy charge. She developed residential rates on this basis to show that the
declining block rate is appropriate to account for reductions in the cost of service to residential
customers as consumption increases. With no declining block rate, high load factor customers are
disadvantaged as the customer charge is reduced and the demand charge is moved into the energy
charge. She believes that declining block rates alleviate the disadvantage.1029
Ms. Talkington illustrated the impact of Mr. Benedict’s suggestion to phase out the declining
block rate for RS customers. Approximately 54 percent of ETI’s residential customers use more
than 1,000 kWh in January and February. For a customer using 3,000 kWh in a winter month of
November-April, this customer’s bill would increase by 16.28 percent or about $48 over current
rates. (Of ETI’s total number of RS customers, approximately 10 percent use 3,000 kWh or more in
the months of January and February.) For that same customer, ETI’s as-filed proposal shows an
increase of 11.96 percent or approximately $35. Mr. Benedict’s proposal is $13 greater than ETI’s
proposal for one winter month at 3,000 kWh. That dollar amount is over a third of the total increase
ETI is proposing.1030
After Mr. Benedict’s proposed phase-out is completed, based on the proposed residential
rates in the Company’s case, the residential rate would be $0.06887 per kWh in both summer and
winter. A customer using 3,000 kWh in a winter month of November-April would see an increase of
24.89 percent or about $73 over current rates. After the final phase out, Mr. Benedict’s proposal is
$38 per month greater than ETI’s as-filed proposal of $35 for one winter month at 3,000 kWh.1031
1027
Staff Ex. 7 (Abbott Direct) at 27.
1028
ETI Ex. 67 (Talkington Rebuttal) at 13, Ex. MLT-R-1.
1029
Id. at 14.
1030
Id. at 15.
1031
Id. at 15-16.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 319
PUC DOCKET NO. 39896
Ms. Talkington further noted that rate design professionals always take into consideration the
effect on customer bills. Even though Mr. Benedict proposes to implement the change over the next
three rate cases, she concludes there will still be winners and losers within the residential class as a
result of his proposed change. According to Ms. Talkington, some customers have made decisions
about investing in electric appliances based on the current rate design. The elimination of the
declining block in the winter time changes the economics of customer decisions that have already
been made. She believes that great caution needs to be exhibited and very good reasons need to be
demonstrated before changes are made to the rate design. She recommended that if a change to the
rate structure is recommended, the initial phase-in should be reduced to 10 percent rather than one-
third and subsequent reductions should be reviewed for consideration at the occurrence of each rate
case filing and not mandated at this time.1032
The ALJs concur with OPC and Staff that the structure of the declining block winter rates
provide a disincentive to energy efficiency. However, ETI provided evidence that OPC’s suggested
changes, combined with ETI’s proposed rate increase, will have too great an impact. OPC suggested
a one-third reduction in the differential, while Ms. Talkington suggested a 10 percent reduction, with
subsequent reductions reviewed before being mandated. The ALJs recommend an initial 20 percent
reduction, which should alleviate some of ETI’s concerns but still reduce the block differential
sufficiently to move towards compliance with the energy goals set out in PURA. The ALJs further
recommend that 20 percent subsequent reductions of the differential be required in the next three
rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable.
XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31]
In the application, ETI seeks to reconcile approximately $1.3 billion in fuel and purchased
power expenses incurred over the 24 month Reconciliation Period. Summaries of ETI’s total fuel
and purchased power expenses and over/under recovery balance are shown below.
1032
ETI Ex. 67 (Talkington Rebuttal) at 15-17.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 320
PUC DOCKET NO. 39896
Fuel Reconciliation
Gas and Oil $616,248,686
Emissions Allowance 360,236
Coal 90,821,317
Total Fuel: $707,430,239
Purchase Power Expense 990,041,434
Off-system Sales Revenues (376,671,969)
Total Purchased Power: $613,369,465
Total Fuel Costs: $1,321,799,704
Over-recovery Balance: $243,339,353
Special Circumstances $99,715
Sources: ETI Ex. 3 Schedules I-16, H-12.4a-g, H-12.5b-e, I-21; ETI Ex. 11 (McCloskey Direct); ETI Ex. 23 (Zakrzewski
Direct).
ETI contends, and the evidence presented at the hearing demonstrates, that these fuel factor
expenses were eligible for reconciliation and were reasonable and necessary to provide reliable
service to ETI’s customers during the Reconciliation Period. With the exception of three minor
issues that are discussed below, none of the intervenors raised a substantive issue with respect to
ETI’s fuel reconciliation request.
During the Reconciliation Period, ETI’s Texas fuel factor revenues over-recovered total fuel
and purchased power expense by $243,339,353, inclusive of interest. The Commission authorized
the refund of the fuel over-recovery balance in Docket Nos. 37580, 38403, and 38967. ETI proposes
that the amount of any fuel over-recovery balance not already refunded or authorized for refund be
rolled forward as the beginning balance for the next reconciliation period.1033
P.U.C. SUBST. R. 25.236(d)(1) states that in a fuel reconciliation proceeding, the utility has
the burden of showing that:
(A) its eligible fuel expenses during the fuel reconciliation period were
reasonable and necessary expenses incurred to provide reliable electric
service to retail customers;
1033
ETI Ex. 40 (Thiry Direct) at 7.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 321
PUC DOCKET NO. 39896
(B) if its eligible fuel expenses for the reconciliation period included an item or
class of items supplied by an affiliate of the electric utility, the prices charged
by the supplying affiliate to the electric utility were reasonable and necessary
and no higher than the prices charged by the supplying affiliate to its other
affiliates or divisions or to unaffiliated persons or corporations for the same
item or class of items; and
(C) it has properly accounted for the amount of fuel-related revenues collected
pursuant to the fuel factor during the reconciliation period.
In Docket No. 15102, an EGSI fuel reconciliation case, the Commission explained the
traditional prudence standard to be applied in reviewing decisions made by the utility:
The exercise of that judgment and the choosing of one of that select range of options
which a reasonable utility manager would exercise or choose in the same or similar
circumstances given the information or alternatives available at the point in time
such judgment is exercised or option is chosen.
There may be more than one prudent option within the range available to a utility in
any given context. Any choice within the select range of reasonable options is
prudent, and the Commission should not substitute its judgment for that of the utility
. . . . The reasonableness of an action or decision must be judged in light of the
circumstances, information, and available options existing at the time, without
benefit of hindsight.1034
ESI purchases power and procures fossil fuels on behalf of the individual Operating
Companies. Fossil fuel costs are borne directly by the Operating Company that contracts for and
uses the fuel. Once resources are procured to meet forecasted demand, the system is operated during
the current day using all of the resources available to the system to meet the total system demand.
Throughout the course of the day, system operators may modify planned operations to maintain
reliability, take advantage of less-expensive resources in the hourly wholesale power markets, or
make off-system sales. For example, when spot market power purchases are available at a cost
1034
Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on
Rehearing at 2 (Jun. 24, 1997).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 322
PUC DOCKET NO. 39896
lower than the cost of energy that can be generated by units owned by the Operating Companies, that
energy is purchased to displace owned generation, subject to operating constraints.1035
Expenses for coal, gas, power purchases, and fuel oil are incurred directly by the respective
Operating Company. For example, if coal is purchased for ETI’s share of Nelson Station, Unit 6,
then ETI is responsible for the invoiced cost and makes payment directly to the supplier. Wholesale
power, purchased and sold for the system, however, is accounted for per the terms of the System
Agreement. After dispatch, or after-the-fact, the System Agreement prescribes an accounting
protocol to bill the costs of operating the system to the individual Operating Companies.1036
The following Fuel Reconciliation-related issues were uncontested:
Natural Gas Purchases
ETI witness Karen McIlvoy presented direct testimony describing ETI’s natural gas
procurement policies and strategies. She explained that the Company buys gas through a long-term
contract with Enbridge, through participation in the monthly and daily markets depending on fuel
needs, and on a delivered-to-plant basis or arrange for transportation to the plant. Ms. McIlvoy
described how the gas buyers for ETI survey the markets and solicit offers for gas supplies.
Ms. McIlvoy also provided a comparison of the Company’s gas costs to the Inside FERC and Gas
Daily published indices for the Houston Ship Channel.1037 No party challenged the Company’s
natural gas purchases.
Fuel Oil
Ms. McIlvoy testified that the Company purchased fuel oil for start-up and flame
stabilization at certain units. Fuel oil can also be used for emergency back-up fuel or as an economic
alternative to natural gas at certain units. During the Reconciliation Period, the Company purchased
1035
ETI Ex. 40 (Thiry Direct) at 18-21.
1036
ETI Ex. 39 (Cicio Direct) at 31-37.
1037
ETI Ex. 28 (McIlvoy Direct) at 23, Ex. KDM-3.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 323
PUC DOCKET NO. 39896
all fuel oil on a short-term basis from spot market sources after solicitation of bids from multiple
potential suppliers.1038 No party contested ETI’s fuel oil costs.
Longer-Term Purchased Power
ETI witness Robert R. Cooper addressed the Entergy system’s long-term planning process
and described the Strategic Resource Plan process. He explained how the system determined its
capabilities and needs for additional resources to reliably serve system load requirements.
Mr. Cooper described the process by which the system developed requests for proposals and
analyzed a combination of capacity and firm energy contracts to satisfy the system’s identified
resource needs.1039 A portion of these system purchases was allocated to ETI. No party proposed a
disallowance of these purchases on the basis of prudence.
Short-Term Purchased Power
Ms. Thiry described the Power Marketing Team’s procurement strategies, practices and
procedures during the Reconciliation Period. Ms. Thiry testified that the Power Marketing Team
fulfilled its objective of purchasing energy in the wholesale market when it was more economical
than using the system’s generation and in order to maintain system reliability. Ms. Thiry
demonstrated that third-party purchases for the system compared favorably to market price indices
and to proxy costs of avoided generation.1040 The Power Marketing Team maintained effective cost
controls and procured a diverse portfolio of product to provide electricity for customers at a
reasonable cost.1041 No party contested the prudence of ETI’s short-term power purchases.
Coal Commodity and Transportation
ETI has ownership interest and/or obtains power through Schedule MSS-4 of the Entergy
System Agreement, in two coal-burning generating units – Nelson and BCII/U3. ETI owns a
1038
ETI Ex. 28 (McIlvoy Direct) at 5-6.
1039
ETI Ex. 34 (Cooper Direct) at 6-10.
1040
ETI Ex. 40 (Thiry Direct) at 24.
1041
Id.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 324
PUC DOCKET NO. 39896
29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in
BCII/U3, but the unit is operated by a third party. ETI witness Ryan Trushenski, the Manager of
Coal Supply for ESI, testified that ETI prudently managed its coal supply and transportation
expenses during the Reconciliation Period.1042
With respect to coal and transportation expenses at Nelson 6, ETI obtained coal during the
Reconciliation Period under a supply contract previously reviewed by the Commission, and entered
into a new coal supply contract after a competitive bid process. ETI chose the supplier with the
lowest priced coal that met the specifications necessary for use at Nelson 6. Similarly, ETI arranged
for transportation of coal according to transportation contracts previously reviewed in prior fuel
reconciliations. When those contracts expired, ETI initiated a competitive bid process and chose the
lowest cost option available that met its requirements. With respect to BCII/U3, ETI incurred costs
to run the unit and took reasonable steps to ensure that the third party operator properly charged for
coal and transportation expenses under an arrangement previously reviewed and approved in prior
fuel reconciliations.1043 No party challenged the reasonableness and necessity of ETI’s coal or
transportation expense during the Reconciliation Period
The three contested issues are discussed below.
A. Spindletop Gas Storage Facility
During the Reconciliation Period, ETI incurred $10,261,663 of non-fuel expense associated
with operating the Spindletop Facility. Cities challenged ETI’s use of the Spindletop Facility,
arguing that the costs of operating it outweigh the benefits gained from it. For the same reason he
challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also
challenges ETI’s non-fuel expense associated with the facility. Specifically, Mr. Nalepa
recommends that ETI’s total fuel reconciliation balance be reduced by $6,595,290, which he
calculates as the difference between the $10,261,633 non-fuel operational costs associated with the
Spindletop Facility over the Reconciliation Period and the costs of alternative sources of providing a
1042
ETI Ex. 33 (Trushenski Direct) at 2.
1043
Id. at 11-13.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 325
PUC DOCKET NO. 39896
reliable and flexible gas supply over the same period.1044 In Section V.H., above, the ALJs rejected
Cities’ contention that the Spindletop Facility is not used or useful. For the same reason they
rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject Cities’
Spindletop Facility arguments relevant to Fuel Reconciliation.
B. Use of Current Line Losses for Fuel Cost Allocation
Cities propose that the allocation of fuel costs incurred over the Reconciliation Period reflect
the current line loss study performed by ETI for this case and recommended for approval on a going
forward basis. In the fuel reconciliation case, ETI proposes to allocate costs to customers using a
line loss study performed in 1997, which Cities claim does not reflect the current cost of providing
service to the current wholesale customers and to the various retail customers.1045 According to
Cities, updating ETI’s allocation of fuel costs to reflect current line losses and the cost of providing
service to customers results in a $3,981,271 reduction to the Texas retail fuel expenses incurred over
the Reconciliation Period.1046
ETI responds that the Cities’ recommendation is unprecedented. It notes that the
Commission’s substantive rules require use of “a commission-approved adjustment to account for
line losses corresponding to the voltage at which the electric service is provided.”1047 Moreover,
ETI argues that retroactive use of new loss factors to calculate its fuel over/under-recovery balance
would result in a mismatch between the revenues recovered under the fuel factor and the costs billed
and allocated to the various customer classes.1048
Fuel costs are collected through Commission-approved fixed fuel factors. One of the
elements the fuel factor is required to take into account is line losses. P.U.C. SUBST.
R. 25.237(c)(2)(B) states that the utility must prove that: “the proposed fuel factors utilize a
1044
Cities Ex. 6 (Nalepa Direct) at 42-43; Cities Initial Brief at 84.
1045
Cities Ex. 6 (Napala Direct) at 44; see also Tr. at 1469-1470.
1046
Cities Ex. 6 (Napala Direct) at 47, Table 14.
1047
ETI Ex. 58 (McCloskey Rebuttal) at 2, quoting P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1048
Tr. at 1484.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 326
PUC DOCKET NO. 39896
commission-approved adjustment to account for line losses corresponding to the voltage at which the
electric service is provided.”1049 If the Commission were to adopt Cities’ recommendation that the
newly-developed line losses be used in the reconciliation of fuel costs, the allocation of those costs
would not match the collections (determined through the use of historical line losses). This
mismatch could result in some customers receiving more than they are entitled and others receiving
less than they are entitled. The ALJs find that the Commission’s rules require the use of
Commission-approved line losses that were in effect at the time fuel costs were billed to customers
in a fuel reconciliation. The ALJs, therefore, recommend that the Commission reject the Cities’
proposed adjustment.
C. ETI’s Special Circumstances Request
In the application, ETI seeks to include $99,715 in the Fuel Reconciliation to allow it to
recover “the reversal of certain credits that were previously included in the Company’s [Incremental
Purchased Capacity Rider] Rider IPCR.”1050 ETI witness Zakrzewski explained that the FERC
revised the amount of purchased capacity-related production costs allocable to ETI through the
FERC-approved Rough Production Cost Equalization mechanism for allocating production costs
among the Operating Companies. As Mr. Zakrzewski explained, the result of the decision was a
recalculation of ETI’s capacity costs recoverable through the Commission-approved Rider IPCR,
which expired during the Reconciliation Period.1051
During the hearing, no party contested ETI’s special circumstances request of $99,715 with
regard to the IPCR-related adjustment. For the first time in its Initial Brief, however, Cities opposed
the request, asserting that it conflicts with the settlement reached in Docket No. 37744.1052 The
ALJs are not swayed by Cities’ argument. As pointed out by ETI,1053 Cities provided no testimony
or other evidence to support its position. Furthermore, Cities failed to explain how a settlement
1049
P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1050
ETI Ex. 23 (Zakrzewski Direct) at 13.
1051
Id.
1052
Cities Initial Brief at 86.
1053
ETI Reply Brief at 93.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 327
PUC DOCKET NO. 39896
agreement reached in Docket No. 37744 could or should trump the FERC’s jurisdiction to determine
the amount of purchased capacity costs attributable to ETI. The only evidence in the record supports
ETI’s recovery of these costs. Accordingly, the ALJs recommend that these FERC-imposed costs
should be found to be recoverable and Cities’ request to deny their recovery should be rejected.
In summary, the ALJs conclude that, consistent with the requirements of P.U.C. SUBST.
R. 25.236(d)(1), ETI met its burden to prove that: (1) its eligible fuel expenses during the
Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric
service to its retail customers; (2) the prices charges by its affiliates were reasonable and necessary
and no higher than the prices charged by the supplying affiliates to other affiliates or to unaffiliated
persons; and (3) ETI has properly accounted for the amount of fuel-related revenues collected
pursuant to the fuel factor during the Reconciliation Period.
XII. OTHER ISSUES
A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket
No. 39741 Preliminary Order Issue Nos. 1-9]
Entergy is seeking to transfer operational control of the Entergy Operating Companies’
transmission assets to the MISO Regional Transmission Organization (RTO). ETI expects its share
of the costs for this transfer will include approximately $17 million of expense.1054 ETI has made
two alternate proposals to recover these expenses. ETI’s first proposal requests the Commission to
approve a deferred accounting of its transition expense incurred on or after January 1, 2011, and to
approve accrual of interest on the deferred amount at ETI’s overall rate of return. Under this
proposal, ETI would present the resulting regulatory asset for review in a future proceeding. ETI
originally requested this deferred accounting in Docket No. 39741, which was later consolidated into
this case for all purposes. In its Preliminary Order in Docket 39741, the Commission stated that it
had authority to allow such a deferral of costs “when it is necessary to carry out a provision of
PURA.” It also stated that whether ETI’s request met this requirement “hinges on the factual issue
of necessity . . . .”
1054
ETI Ex. 42 (Lewis Supplemental Direct) at 5.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 328
PUC DOCKET NO. 39896
As an alternative proposal, ETI requested the Commission to include $4 million of transition
expense in base rates set in the present case, based on a three-year amortization of a total of
$12 million in MISO transition expenses. ETI’s Test Year MISO transition expenses totaled only
$916,535, but ETI’s request for deferred accounting addressed expenses incurred on or after
January 1, 2011, which is after the Test Year concluded. ETI argues that its request is a
conservative known and measureable change because the post-Test-Year expenses will be
significantly more than $4 million per year. Further, these costs would be removed from ETI’s cost
of service if its deferred accounting proposal is approved.
As noted, ETI’s proposals concern MISO transition expenses incurred on or after January 1,
2011. However, ETI also incurred $263,908 in these expenses during the 2010 portion of the Test
Year. ETI has proposed a five-year amortization of this amount ($52,800 per year), assuming either
its primary proposal or its alternative proposal is adopted. However, if ETI’s primary and
alternative proposals are both rejected, ETI requested that no reduction be made to its total Test Year
amount of $916,535.1055
Cities, TIEC, State Agencies, and Staff opposed ETI’s requests. They argue that ETI failed
to establish that the proposed deferred accounting is necessary to carry out a provision of PURA, as
required by the Commission’s Preliminary Order. They also contended that ETI’s alternate request
to include $4 million in base rates is not a known and measureable change and should be disallowed.
The ALJs recommend that the Commission deny ETI’s request for deferred accounting of its
MISO transition expenses to be incurred on or after January 1, 2011. However, the ALJs do
recommend that the Commission authorize ETI to include $2.4 million of MISO transition expense
in base rates set in the present case, based on a five-year amortization of $12 million in total
projected expenses.
1055
ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 329
PUC DOCKET NO. 39896
1. Deferred Accounting
In support of its deferred accounting request, ETI cited State v. Public Utility Comm’n of
Texas.1056 In that case, the Texas Supreme Court stated that a deferred accounting is “necessary”
when it will “ensure that the requirements of [PURA] are met.”1057 In ETI’s opinion, deferred
accounting is necessary in the present case to ensure that PURA §§ 36.051 and 36.003(a) are met
(i.e., that utilities have a reasonable opportunity to recover their expenses and receive reasonable
rates). ETI also relied on Hammack v. Public Utility Commission of Texas, which stated that “a need
. . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1058
ETI-witness Brett Perlman testified that deferred accounting is also necessary to ensure the
requirements of PURA § 31.001(c) are carried out.1059 That section encourages development of a
competitive wholesale electric market. ETI noted that the Hammack opinion stated that
Section 31.001(c) amounts to a “legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market.”1060 Therefore, ETI asserted
that RTO membership and deferred accounting are necessary because they will ensure that the
Commission meets its obligation under Section 31.001(c). More specifically, ETI stated, both RTO
membership and deferred accounting itself constitute examples of policies required by section
31.001(c) to support wholesale competition. Therefore, ETI argues that its request for deferred
accounting should be approved because it is necessary to carry out PURA §§ 36.051, 36.003, and
31.001(c).1061
Cities argue that ETI’s request for deferred accounting of MISO transition expenses should
be denied because deferred accounting is not necessary to carry out any requirement of PURA.
1056
883 S.W.2d 190 (Tex. 1994).
1057
883 S.W.2d at 194.
1058
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1059
ETI Ex. 43 (Perlman Supplemental Direct) at 7.
1060
131 S.W.3d at 723.
1061
ETI’s Initial Brief at 231-234; ETI Ex. 42 (Lewis Supplemental Direct) at 2-4; ETI Ex. 43 (Perlman
Supplemental Direct) at 5-7.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 330
PUC DOCKET NO. 39896
Cities witness James Brazell stated that ETI’s proposed transition to MISO is not mandatory, and the
anticipated expenses are not extraordinary. He added that ETI has been exploring membership in an
RTO for over ten years and those costs have historically been included in ETI’s base rates; therefore,
he concluded that deferred accounting was not necessary in the past and is not necessary now. Cities
stressed that ETI conceded that deferred accounting of these expenses is not necessary to maintain
its financial integrity, and in Cities’ opinion, both State v. Public Utility Comm’n of Texas,1062 and
the Commission’s Preliminary Order require a showing of impairment of financial integrity to
conclude that deferred accounting is necessary to comply with PURA § 36.051. Cities also stated
that ETI failed to show that deferred accounting is necessary to comply with PURA §§ 36.003 and
31.001(c); therefore, Cities argues that ETI’s request for deferred accounting should be denied.
TIEC also opposed ETI’s request for deferred accounting, arguing that ETI failed to
demonstrate that it is necessary to carry out PURA §§ 36.051, 36.003, or 31.001(c). TIEC witness
Jeffry Pollock stated there is no indication that deferred accounting treatment is necessary for ETI to
earn a reasonable return on its invested capital or that denying the deferred accounting would
prevent ETI from having just and reasonable rates. Further, Mr. Pollock asserted there is no
evidence that a lack of deferred accounting treatment for ETI would prevent Entergy from pursuing
its MISO proposal.1063 Mr. Pollock added that ETI has incurred other similar costs to carry out
various purposes of PURA without deferred accounting. For example, since 2005, ETI has spent
nearly $20 million pursuing various similar activities, including transitioning to competition,
investigating RTO options, examining changes to the Entergy System Agreement, and supporting
the Entergy OATT. Yet, ETI did not seek deferred accounting for any of those costs. Finally,
Mr. Pollock testified that the projected transition costs are not material. He noted that ETI expects
to incur $17 million of transition costs.1064 This equates to $5.8 million per year, which is only
1 percent of ETI’s Test Year operating revenues, according to Mr. Pollock. In his opinion, this level
1062
883 S.W.2d 190 (Tex. 1994).
1063
TIEC Ex. 1 (Pollock Direct) at 46-47.
1064
ETI Ex. 42 (Lewis Supplemental Direct) at 5.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 331
PUC DOCKET NO. 39896
of MISO transition costs is easily subsumed in the normal variation in ETI’s year-to-year
expenses.1065
TIEC also disagreed with ETI’s interpretation of State v. Public Utility Comm’n of Texas.1066
In TIEC’s view, that case held that deferred accounting is necessary only when needed to protect
the financial integrity of the utility. Likewise, TIEC disagreed with ETI’s argument that
Hammack1067 held that “need” is a relative requirement that must be viewed in light of legislative
policy directives.1068 TIEC noted that Hammack had nothing to do with deferred accounting.
Instead, it was limited to the issue of whether, in granting a certificate of convenience and necessity
for a transmission line under PURA §37.056, the Commission should include evidence that
considered customers and market participants throughout the state.1069 In TIEC’s view, the
Hammack case is irrelevant in determining whether deferred accounting is necessary to carry out the
provisions of PURA §§ 36.003, 36.051, and 31.003(c). State Agencies made similar arguments.
Commission Staff also argues that ETI did not establish why deferred accounting is
necessary to carry out a provision of PURA. In Staff’s view, the applicable court cases and other
precedent required ETI to show that deferred accounting is necessary to maintain its financial
integrity, in order to carry out the provisions of PURA § 36.051. Staff argues that the Commission’s
Preliminary Order did not reject the financial integrity standard when it stated: “[t]his standard is
not appropriate, however, for all circumstances and the Commission has applied different standards
in various circumstances.”1070 Rather, Staff stated, the Commission merely declined to designate a
specific standard.
1065
ETI Ex. 1 (Pollock Direct) at 48-49 and Ex. JP-8.
1066
883 S.W.2d 190 (Tex. 1994).
1067
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1068
ETI Initial Brief at 232-233.
1069
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 724 (Tex .App.−Austin 2004, pet. denied).
1070
Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to
Membership in The Midwest Independent Transmission System Operator, Docket No. 39741 Preliminary
Order at 9 (Sep. 2, 2011).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 332
PUC DOCKET NO. 39896
Staff also rejected ETI’s argument that deferred accounting will “ensure that the Commission
meets its obligation under Section 31.001(c) to support the achievement of a competitive wholesale
market.”1071 First, Staff noted, the Commission stated in the Preliminary Order that merely showing
movement towards a policy goal is not a sufficient standard upon which to approve deferral.1072
Thus, ETI’s statement that deferred accounting will “support” wholesale competition addresses a
standard that the Commission already rejected. Second, Staff argues that ETI failed establish that
deferred accounting is “necessary” to support a competitive wholesale market or that failure to allow
deferred accounting would prevent that goal. In other words, ETI did not show that, absent deferral,
it would not join MISO; thus, ETI did not show how deferral would “ensure” that it joins an RTO.
Therefore, Staff concluded, because ETI failed to prove that deferred accounting is necessary to
carry out any provision of PURA, ETI’s request should be denied.
In response to these arguments, ETI noted that no party disputed that the Commission may
grant deferred accounting “when it is necessary to carry out a provision of PURA.” It also argues
that Staff and intervenors misinterpreted State v. Public Utility Comm’n of Texas1073 as holding that
deferred accounting is necessary to carry out PURA § 36.051 only when a utility’s financial integrity
is at stake. Although lack of financial integrity is an indication that PURA § 36.051 has not been
carried out, ETI noted that this section contains other express requirements that can be met through
deferred accounting, such as ensuring utilities a reasonable opportunity to recover their costs. ETI
also cited other Commission cases in which it authorized deferred accounting when financial
integrity was not at stake, such as deferral of rate case expenses and merger costs for subsequent
review and recovery.1074 ETI added that deferred accounting would permit the Commission to
review ETI’s transition expenses in a subsequent proceeding, after determining whether ETI’s
transition to MISO is in the public interest. Thus, under ETI’s proposal, there is no risk that ETI
would recover such costs absent a finding that they are reasonable and necessary.
1071
ETI Initial Brief at 234.
1072
Docket No. 39741, Preliminary Order at 11.
1073
883 S.W.2d 190 (Tex. 1994).
1074
ETI Reply Brief at 95-96.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 333
PUC DOCKET NO. 39896
As for Staff and TIEC’s argument that deferred accounting is not necessary to carry out
PURA § 31.001(c), ETI argues that the “necessary” standard is not a “but for” test. In response to
arguments that the proposed deferred accounting will merely further policy objectives of
Section 31.001(c), which the Commission has deemed insufficient to meet the “necessary”
standard,1075 ETI reiterated that the Hammack opinion held that “the Commission’s interpretation of
need must be viewed in light of the legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market,” as well as “overall policy
objectives.”1076 Thus, ETI argues, that it has demonstrated that deferred accounting is necessary to
carry out Section 31.001(c) – i.e., it will “ensure” that the requirements of that provision are carried
out, and in particular ensure that the Legislature’s specific instruction to develop the wholesale
market is carried out.1077
Although ETI’s proposal for deferred accounting has some practical appeal, the ALJs
conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The ALJs
find that ETI was not required to show that a deferred accounting is necessary to maintain its
financial integrity, as argued by intervenors. In State v. Public Utility Comm’n of Texas,1078 the
Texas Supreme Court held that preserving the financial integrity of a utility was necessary to carry
out a provision of PURA, and thus justified deferred accounting for certain expenses in that case, but
the court did not hold that preserving financial integrity was the sole basis upon which a deferred
accounting could be approved. Likewise, in its Preliminary Order for the present case, the
Commission stated: “This standard [financial integrity] is not appropriate, however, for all
circumstances and the Commission has applied different standards in various circumstances,
although none of these standards or circumstances has been reviewed by any court.”1079 On the
other hand, the ALJs also find that ETI’s contention that deferred accounting of the MISO transition
expenses will help the development of a competitive wholesale electric market, as described in
1075
Docket No. 39741, Preliminary Order at 7.
1076
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1077
ETI Reply Brief at 97-99.
1078
883 S.W.2d 190 (Tex. 1994).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 334
PUC DOCKET NO. 39896
PURA § 31.001(c), is not sufficient to authorize deferred accounting. Again, the Commission stated
in the Preliminary Order that “to carry out a provision of PURA” means more than undefined
progress or movement towards a statutory objective.1080
The Commission made clear that ETI’s burden was not only to show that a provision of
PURA would be carried out by an accounting deferral of the MISO transition expenses, but that the
deferral is necessary to carry out that provision. The Commission added that necessity was a
question of fact that “can only be determined after development of an adequate factual record that
demonstrates the necessity, of whatever degree.”1081 Intervenors argue that Entergy’s efforts to
transfer operational control of the Entergy Operating Companies’ transmission assets to MISO will
proceed with or without the deferred accounting requested by ETI; thus, deferred accounting is not
necessary. Likewise, intervenors argue that ETI’s alternate proposal to recover the transition costs
through base rates shows that deferred accounting is not necessary. ETI, however, asserted that
necessity should not be considered a “but for” requirement. It noted that no provision of PURA
would be impossible to carry out absent a deferral of rate case expenses or merger expenses, yet the
Commission has allowed deferred accounting of such expenses in other cases. ETI also cited the
statement in Hammack v. Public Utility Commission of Texas that “a need . . . is a relative
requirement, ranging from an imperative need to one that is minimal . . . .”1082 Intervenors criticized
ETI’s reliance on the Hammack case because it concerned a transmission line. While that is correct,
the case does make the general point that the question of need is not an absolute “but for” test. This
is also consistent with the Commission’s statement in the Preliminary Order that ETI’s burden was
to demonstrate necessity, “of whatever degree.”
ETI’s complaint is that its MISO transition expenses will soon increase above the Test Year
amount, from $916,535 for the Test Year to over $5 million per year, but it will not be able to
recover the increased costs through normal Test Year cost-of-service ratemaking principles. Thus,
1079
Docket No. 39741, Preliminary Order at 9 (Nov. 22, 2011).
1080
Id. at 11.
1081
Id. at 8.
1082
Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 335
PUC DOCKET NO. 39896
although ETI’s financial integrity may not be jeopardized, ETI argues that it nevertheless will not be
able to have a reasonable opportunity to recover its expenses and receive reasonable rates as
required by PURA §§ 36.051 and 36.003(a). Therefore, ETI believes the proposed deferred
accounting is necessary to carry out those provisions of PURA.
The ALJs find that the essence of ETI’s complaint is that regulatory lag works against it in
this particular situation. But as noted by the court in State v. Public Utility Comm’n of Texas,
regulatory lag is an ordinary element of risk for utilities.1083 One of the characteristics of Test Year
cost-of-service ratemaking is that some expenses upon which rates are based may go up and others
may go down during the time the rates are in effect. Such changes can be corrected in future
ratemaking proceedings, but in this case ETI desires to ensure that it will recover all of its MISO
transition costs. But State v. Public Utility Comm’n of Texas and the Commission’s Preliminary
Order in this case make clear that eliminating the normal effects of regulatory lag by allowing a
deferred accounting should not be undertaken lightly. If ETI’s arguments were taken to their
extreme, a utility could obtain deferred accounting any time it anticipated a post Test Year increase
in a particular expense, under the argument that it must be allowed to recover all of its expenses to
carry out the requirements of PURA §§ 36.051 and 36.003(a). In this case, ETI’s estimated MISO
transition costs will equal about $5.8 million per year. As Mr. Pollock noted, this is only
one percent of ETI’s Test Year operating revenues, which may easily be subsumed in the normal
variation in ETI’s year-to-year expenses. Under these circumstances, ETI has not shown that
granting its requested deferred accounting is necessary to carry out the requirements of PURA
§§ 36.051 and 36.003(a) that it receive just and reasonable rates. Therefore, the ALJs recommend
that the Commission deny ETI’s request for deferred accounting treatment of its MISO transition
expenses to be incurred on or after January 1, 2011.
1083
883 S.W.2d 190, 196 (Tex. 1994).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 336
PUC DOCKET NO. 39896
2. Base Rate Recovery
As mentioned above, if the Commission denies ETI’s request for deferred accounting, ETI
requested the Commission to include $4 million of MISO transition expense in base rates set in the
present case, based on a three-year amortization of $12 million in total projected expenses.
Cities disputed the amount of MISO expenses ETI requested in this proposal. Cities witness
Mark Garrett testified that a $4 million annual expense is inconsistent with ETI’s own projected
costs. The Test Year expenses were $916,535, and the actual expenses incurred during January
through November 2011 were only $2.513 million, which annualized would be $2.742 million..
For 2013, ETI projected MISO transition expenses of only $2.587 million, although ETI’s
projected 2012 level of $8.9 million. However, Mr. Garrett added that 2012 is an estimated level
and is not consistent with actual 2011 results. In his opinion, the actual 2011 level of about $2.7
million or the expected 2013 level of about $2.6 million should be the outside range of what the
Commission should use for setting prospective rates. In any event, however, Cities argue that these
projected levels are not sufficiently known and measurable to include for ratemaking purposes.
Cities pointed out that it is unknown whether ETI’s proposed move to MISO will even be approved,
or whether the ETI will even continue to incur costs toward a MISO transition. Therefore, Cities
argues that only the Test Year level of $916,535 should be included in rates, which would result in a
downward adjustment of $3,083,462 to ETI’s request.1084
TIEC also argues that ETI’s alternative proposal should be rejected. Mr. Pollock complained
that this proposal would allow ETI to recover post Test Year expenses that are not known and
measureable. Mr. Pollock noted that ETI’s own estimate of its share of transition costs has changed.
When ETI filed its request for deferred accounting in Docket No. 39741, it estimated transition costs
of $12 million. Now it estimates costs of $17 million, an increase of over 40 percent. Further,
Mr. Pollock stated, ETI based its share of the estimated transition costs by assuming a 17 percent
responsibility ratio, but ETI’s future responsibility ratios are not known because they are based on
projected growth rates of ETI relative other Entergy Operating Companies. Thus, Mr. Pollock
1084
Cities Ex. 2 (Garrett Direct) at 61-63 and Ex. MG2.14; Cities Initial Brief at 89-91; Cities Reply Brief
at 112-113.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 337
PUC DOCKET NO. 39896
concluded that ETI’s share of future MISO transition costs cannot be appropriately measured.1085 In
summary, TIEC argues that the Commission should deny ETI’s request for deferred accounting and
should allow ETI to recover only Test Year MISO transition expenses.1086 Commission Staff made
arguments similar to Cities and TIEC.1087
In response, ETI argues that the $4 million annual expense requested is known and
measurable. ETI noted that it already incurred over $3.6 million in transition expense in the nine
months since the end of the Test Year,1088 which equates to $4.8 million on an annual basis.
Furthermore, ETI’s expects $17 million in transition expenses to be incurred over three years, which
equates to $5.8 million annually.1089 In ETI’s view, the issue is whether it is sufficiently known that
ETI will incur at least $12 million in transition expense, not whether ETI can predict an exact level
of future expense.1090
The ALJs recommend that the Commission authorize ETI to include $2.4 million in base
rates set in the present case for MISO transition expense incurred on or after January 2, 2011, based
on a five-year amortization of $12 million in total projected expenses. The primary argument of
intervenors against the adjustment is that the total of $12 million is not a known and measurable
change. However, the ALJs find that ETI’s evidence established that such expenses will total at
least $12 million. It is true that the Test Year expenses were less, but ETI filed its application to
effectuate the transfer to MISO in 2012, so it is clear that those expenses will increase significantly
to levels well above the Test Year amount. It is true that ETI has not established the precise total
amount of MISO transition expenses it will incur, but the ALJs find that those expenses will likely
exceed the $12 million included in ETI’s request. ETI requested that the $12 million total be
amortized over three years, which would produce a $4 million annual cost. However, ETI also
1085
TIEC Ex. 1 (Pollock Direct) at 49-50.
1086
TIEC Initial Brief at 97-98; TIEC Reply Brief at 70-71.
1087
Staff Reply Brief at 65-66.
1088
ETI Ex. 46 (Considine Rebuttal), Ex. MPC-R-1.
1089
TIEC Ex. 1 (Pollock Direct) at 48:3-4.
1090
ETI Initial Brief at 236-239; ETI Reply Brief at 99-100.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 338
PUC DOCKET NO. 39896
requested to amortize over five years its $263,908 in MISO transition expenses that were incurred
during the 2010 portion of the Test Year ($52,800 per year). If a five-year amortization is
appropriate for those expenses, a five-year amortization would also be appropriate for the post Test
Year MISO transition expenses. Therefore, the ALJs recommend that the Commission authorize
ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test
Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800.
B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]
In its Supplemental Preliminary Order, the Commission found that it would be appropriate to
establish for ETI baseline values for a TCRF and a DCRF, which may be established in future
dockets. ETI’s filing package included worksheets for these baseline values,1091 and ETI attached
revised versions of the worksheets to its initial brief to reflect ETI’s revised depreciation
calculations. The revised version of the transmission worksheet calculated total transmission cost
baseline revenue requirements of $75,074,987-Total Company and $74,997,366-Retail.1092
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised
TCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of
the Commission.1093 TIEC, Cities, and Staff also point out that various items in ETI’s calculation
have been contested. Therefore, they also recommend that the baseline values be set during the
compliance phase of this case. The ALJs agree that TCRF baseline values should be set during the
compliance phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.
C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]
As discussed above, the Commission found in its Supplemental Preliminary Order that it
would be appropriate to establish for ETI baseline values for a DCRF, which may be established in a
1091
ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1092
ETI Initial Brief at 239 and Attachment 1.
1093
ETI Initial Brief at 239.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 339
PUC DOCKET NO. 39896
future docket. ETI’s filing package included worksheets for a DCRF baseline value,1094 and ETI
attached a revised version of the worksheet to its initial brief to reflect ETI’s revised depreciation
calculations. The revised version of the distribution worksheet calculated total distribution cost
baseline revenue requirements of $163,560,232-Total Company and $161,537,490-Retail.1095
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised
DCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions
of the Commission.1096 TIEC, Cities, and Staff also recommend that the baseline values be set
during the compliance phase of this case. The ALJs agree that DCRF baseline values should be set
during the compliance phase of this docket, after the Commission makes final rulings on the various
contested issues that may affect this calculation.
D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary
Order Issue No. 1]
ETI requested a PPR rider in its application, but the Commission held in its Supplemental
Preliminary Order that the proposed rider should not be considered due to the pending rulemaking
Project No. 39246, which was opened to consider purchased capacity riders. However, the
Commission did add the following issue to the present case: “What is the amount of purchased-
capacity costs that are proposed to be included in Entergy’s base rates?” ETI requested authority to
include $275,809,485 in its PPR rider, but because the Commission excluded the PPR rider from
consideration, this amount would now be included in base rates. ETI acknowledged that this amount
should be revised to correspond with the Commission’s final decision on purchased power capacity
recovery (See Section VII.A.). 1097
State Agencies noted that ETI’s purchased power request included the following:
1094
ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1095
ETI Initial Brief at 239 and Attachment 2.
1096
ETI Initial Brief at 239.
1097
ETI Initial Brief at 240.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 340
PUC DOCKET NO. 39896
1. Third-party contracts;
2. Legacy affiliate contracts;
3. Other affiliate contracts; and
4. Reserve Equalization.
The costs for all of these but third-party contracts are determined through various MSS Schedules in
the FERC-approved Entergy System Agreement. Therefore, State Agencies argue that if the
Commission decides to allow purchased capacity cost recovery riders in Project No. 39246, the
baseline costs for ETI should be limited to only the purchased capacity costs associated with
non-affiliate third-party contracts. In State Agencies’ opinion, ETI should not be allowed to pass
through purchased capacity costs associated with legacy and other affiliate contracts or reserve
equalization purchases, because those are not market competitive contracts. Instead, according to
State Agencies, the affiliate contracts and reserve equalization purchases are essentially agreements
to share centralized planned generation capacity resources among Entergy Operating Companies and
to allocate generation costs among those companies. State Agencies also noted that these capacity
payments are determined based on formulae in Service Schedules MSS-1 and MSS-4, included in
the FERC-approved Entergy System Agreement. In other words, these costs are not driven by
market prices and are not subject to market price volatility. Therefore, State Agencies argue that
purchases other than third-party contracts should not be used as a baseline for any rider intended to
address market price volatility and competitive wholesale market pressure for purchased generation
capacities.1098
Cities agree with the arguments of State Agencies. In addition, Cities stressed that if the
Commission establishes a baseline for purchased power capacity costs, the baseline should reflect
the unit cost of capacity rather than total dollars. Cities witness Nalepa testified that the unit cost
would provide a more accurate measure than total dollars. In Cities’ opinion, if a unit cost finding is
not made in this case, then Commission will be prevented from considering all options in the
rulemaking.
1098
State Agencies Ex. 2 (Pevoto Direct) at 17.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 341
PUC DOCKET NO. 39896
TIEC points out that the notice in Project No. 39246 provided that “[t]he purpose of this
rulemaking project is to address the recovery of purchased power capacity costs considering
generation embedded in base rates, load growth, and the impact of purchased power capacity
recovery on the financial standing of the utility.”1099 Accordingly, TIEC argues that the baseline set
in this proceeding should reflect ETI’s total purchased power and installed capacity costs determined
to be properly included in base rates on a total cost basis and on a per unit ($/MW) basis.1100
As discussed in Section VII.A., the ALJs find that the appropriate amount for ETI’s
purchased power capacity expense to be included in base rates is $245,432,884. This responds to the
issue included in the Commission’s Supplemental Preliminary Order. This amount includes third-
party contracts, legacy affiliate contracts; other affiliate contracts; and reserve equalization.
Whether the amounts for all contracts should be included in the baseline for a purchased capacity
rider that may be approved in Project No. 39246 is an issue that should be decided in that
proceeding, not in the present case. Therefore, the ALJs make no recommendation on that issue
raised by the intervenors.
XIII. CONCLUSION
The ALJs recommend that the Commission implement the findings of the ALJs set forth in
the discussion above by adopting the following proposed findings of fact and conclusions of law in
the Commission’s final order.
XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
ORDERING PARAGRAPHS
A. Findings of Fact
Procedural History
1. Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
service area located in southeastern Texas.
1099
Project No. 39246, Public Notice (May 10, 2011).
1100
TIEC Initial Brief at 99.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 342
PUC DOCKET NO. 39896
2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
Commission (FERC) regulates ETI’s wholesale electric operations.
3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted test year
revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing
Package for Generating Utilities (RFP) accompanying ETI’s application and including new
riders for recovery of costs related to purchased power capacity and renewable energy credit
requirements; (3) a request for final reconciliation of ETI’s fuel and purchased power costs
for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to
the instructions in RFP Schedule V accompanying ETI’s application.
4. The 12-month test year employed in ETI’s filing ended on June 30, 2011 (Test Year).
5. ETI provided notice by publication for four consecutive weeks before the effective date of
the proposed rate change in newspapers having general circulation in each county of ETI’s
Texas service territory. ETI also mailed notice of its proposed rate change to all of its
customers. Additionally, ETI timely served notice of its statement of intent to change rates
on all municipalities retaining original jurisdiction over its rates and services.
6. The following parties were granted intervenor status in this docket: Office of Public Utility
Counsel (OPC); the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton,
Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange,
Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour
Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co. (Kroger); State Agencies
(State Agencies); Texas Industrial Energy Consumers (TIEC); East Texas Electric
Cooperative, Inc. (ETEC); the United States Department of Energy (DOE); and Wal-Mart
Stores Texas, LLC, and Sam’s East, Inc. (Wal Mart). The Staff (Staff) of the Public Utility
Commission of Texas (Commission or PUC) was also a participant in this docket.
7. On November 29, 2011, the Commission referred this case to the State Office of
Administrative Hearings (SOAH).
8. On December 7, 2011, the Commission issued its order requesting briefing on threshold
legal/policy issues.
9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues
to be addressed in this proceeding.
10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2,
which approved an agreement among the parties to establish a June 30, 2012 effective date
for the Company’s new rates resulting from this case pursuant to certain agreed language and
consolidate Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its
Proposed Transition to Membership in the Midwest Independent System Operator, Docket
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 343
PUC DOCKET NO. 39896
No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose
the consolidation.
11. On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for
admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate
as counsel for Kroger and the motion for admission pro hac vice filed by Rick D.
Chamberlain to appear and participate as counsel for Wal-Mart.
12. On January 19, 2012, the Commission issued a Supplemental Preliminary Order identifying
two additional issues to be addressed in this case and concluding that the Company’s
proposed purchased power capacity rider should not be addressed in this case and that such
costs should be recovered through base rates.
13. ETI timely filed with the Commission petitions for review of the rate ordinances of the
municipalities exercising original jurisdiction within its service territory. All such appeals
were consolidated for determination in this proceeding.
14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues
into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket
No. 39896, Docket No. 40295 (pending).
15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
revenues to approximately $104.8 million over adjusted Test Year revenues.
16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.
17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012.
Rate Base
18. Capital additions that were closed to ETI’s plant-in-service between July 1, 2009, and June
30, 2011, are used and useful in providing service to the public and were prudently incurred.
19. ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).
20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when
Docket No. 37744 concluded because the asset would have then begun earning a rate of
return as part of rate base.
21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
Test Year in the present case, and less the amount of additional insurance proceeds received
by ETI after the conclusion of Docket No. 37744.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 344
PUC DOCKET NO. 39896
22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
remain in rate base, applying a five-year amortization rate beginning August 15, 2010.
23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.
24. The Company requested in rate base its Prepaid Pension Assets Balance of $55,973,545,
which represents the accumulated difference between the Statement of Financial Accounting
Standards (SFAS) No. 87 calculated pension costs each year and the actual contributions
made by the Company to the pension fund.
25. The Prepaid Pension Assets Balance includes $25,311,236 capitalized to construction work
in progress (CWIP).
26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
was insufficient evidence showing that major projects under construction were efficiently
and prudently managed.
27. The portion of the Prepaid Pension Assets Balance that is capitalized to CWIP should not be
included in ETI’s rate base.
28. The remainder of the Prepaid Pension Assets Balance should be included in ETI’s rate base.
29. ETI should be permitted to accrue an allowance for funds used during construction on the
portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.
30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48),
“Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of its uncertain
tax positions by evaluating the tax position on its technical merits to determine whether the
position, and the corresponding deduction, is more-likely-than-not to be sustained by the
Internal Revenue Service (IRS) if audited.
31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
purposes and record it as a potential liability with interest to better reflect the Company’s
financial condition.
32. At Test Year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 Liability) in reliance upon
tax positions that the Company believes will not prevail in the event the positions are
challenged, via an audit, by the IRS.
33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 Liability.
34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 Liability.
35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 345
PUC DOCKET NO. 39896
36. ETI may never have to pay the IRS the FIN 48 Liability.
37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48 Liability
funds.
38. Until actually paid to the IRS, the FIN 48 Liability represents cost-free capital and should be
deducted from rate base.
39. The amount of $4,621,778 (representing ETI’s full FIN 48 Liability of $5,916,461 less the
$1,294,683 cash deposit ETI has made with the IRS for the FIN 48 Liability) should be
added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.
40. ETI’s application and proposed tariffs do not include a request for a tracking mechanism or
rider to collect a return on the FIN 48 Liability.
41. ETI has not proven that a tracking mechanism or rider to collect a return on FIN 48 Liability
is necessary.
42. Investor-owned electric utilities may include a reasonable allowance for cash working
capital in rate base as determined by a lead-lag study conducted in accordance with the
Commission’s rules.
43. Cash working capital represents the amount of working capital, not specifically addressed in
other rate base items, that is necessary to fund the gap between the time expenditures are
made and the time corresponding revenues are received.
44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for
known and measurable changes, and is consistent with P.U.C. SUBST.
R. 25.231(c)(2)(B)(iii).
45. It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead-lag
study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved for
ETI in this case.
46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008)
and Docket No. 37744, the Commission did not approve ETI’s storm damage expenses since
1996 and its storm damage reserve balance.
47. ETI established a prima facie case concerning the prudence of its storm damage expenses
incurred since 1996.
48. Adjustments to the storm damage reserve balance proposed by intervenors should be denied.
49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
reserve.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 346
PUC DOCKET NO. 39896
50. ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.
51. The amount of $9,846,037, representing the value of the average coal inventory maintained
at ETI’s coal-burning facilities, is reasonable, necessary, and should be included in rate base.
52. The Spindletop gas storage facility (Spindletop Facility) is used and useful in providing
reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek generating
plants.
53. The Spindletop Facility is critical to the economic, reliable operation of the Sabine Station
and Lewis Creek generating plants due to their geographic location in the far western region
of the Entergy system.
54. It is reasonable and appropriate to include ETI’s share of the costs to operate the Spindletop
Facility in rate base.
55. Staff recommended updating ETI’s balance amounts for short-term assets to the 13-month
period ending December 2011, which was the most recent information available. Staff’s
proposed adjustments should be incorporated into the calculation of ETI’s rate base.
56. The following short-term asset amounts should be included in rate base: prepayments at
$8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.
57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the
Spindletop facility, represent actual costs incurred to process and close the acquisition, not
mere mark-up costs.
58. ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because
ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its
retail customers.
59. In its application, ETI capitalized into plant in service accounts some of the incentive
payments ETI made to its employees. ETI seeks to include those amounts in rate base.
60. A portion of those capitalized incentive accounts represent payments made by ETI for
incentive compensation tied to financial goals.
61. The portion of ETI’s incentive payments that are capitalized and that are financially-based
should be excluded from ETI’s rate base because the benefits of such payments inure most
immediately and predominantly to ETI’s shareholders, rather than its electric customers.
62. The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the
reasonableness of ETI’s capital 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.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 347
PUC DOCKET NO. 39896
63. In this proceeding, ETI’s capitalized incentive compensation that is financially-based should
be excluded from rate base, but only for incentive costs that ETI capitalized during the
period from July 1, 2009 (the end of the prior Test Year) through June 30, 2010 (the
commencement of the current Test Year).
Rate of Return and Cost of Capital
64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity
to earn a reasonable return on its invested capital.
65. The results of the discounted cash flow model and risk premium approach support a ROE of
9.80 percent.
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-TERM DEBT 50.08% 6.74% 3.38%
COMMON EQUITY 49.92% 9.80% 4.89%
TOTAL 100.00% 8.27%
Operating Expenses
72. ETI’s Test Year purchased capacity expenses were $245,432,884.
73. ETI requested an upward adjustment of $30,809,355 as a post-Test Year adjustment to its
purchased capacity costs. This request was based on ETI’s projections of its purchased
capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
Rate Year).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 348
PUC DOCKET NO. 39896
74. ETI’s purchased capacity expense projections were based on estimates of Rate Year
expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments under
third-party capacity contracts; and (c) payments under affiliate contracts.
75. ETI’s projection of its Rate Year reserve equalization payments under Schedule MSS-1 is
based on numerous assumptions, including load growths for ETI and its affiliates, future
capacity contracts for ETI and its affiliates, and future values of the generation assets of ETI
and its affiliates.
76. There is substantial uncertainty with regard to ETI’s projection of its Rate Year reserve
equalization payments under Schedule MSS-1.
77. ETI’s projection of its Rate Year third-party capacity contract payments includes numerous
assumptions, one of which is that every single third-party supplier will perform at the
maximum level under the contract, even though that assumption is inconsistent with ETI’s
historical experience.
78. There is substantial uncertainty with regard to ETI’s projection of its Rate Year third-party
capacity contract payments.
79. ETI’s estimates of its Rate Year purchases under affiliate contracts are based on a
mathematical formula set out in Schedule MSS-4.
80. The MSS-4 formula for Rate Year affiliate capacity payments reflects that these payments
will be based on ratios and costs that cannot be determined until the month that the payments
are to be made.
81. Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI
WBL Contract) that was not signed until April 11, 2012.
82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.
83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the Rate
Year than it purchased in the Test Year.
84. ETI experienced substantial load growth in the two years before the Test Year, and it
continues to project similar load growth in the future.
85. ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment
of $30,809,355 should be made to its Test Year purchased capacity expenses.
86. ETI’s purchased capacity expense in this case should be based on the Test Year level of
$245,432,884.
87. ETI incurred $1,753,797 of transmission equalization expense during the Test Year.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 349
PUC DOCKET NO. 39896
88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense.
This request was based on ETI’s projections of its transmission equalization expenses
during the Rate Year.
89. The transmission equalization expense that ETI will pay in the Rate Year will depend on
future costs and loads for each of the Entergy operating companies.
90. ETI’s projection of its Rate Year transmission equalization expenses is uncertain and
speculative because it depends on a number of variables, including future transmission
investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
expenses, and loads of each of the Entergy operating companies.
91. ETI seeks increased transmission equalization expenses for transmission projects that are not
currently used and useful in providing electric service. ETI’s post-Test Year adjustment is
based on the assumption that certain planned transmission projects will go into service after
the Test Year. At the close of the hearing, none of the planned transmission projects had
been fully completed and some were still in the planning phase.
92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
expenses related to projects that are not yet in-service.
93. ETI’s request for a post-Test Year adjustment of $8,942,785 for Rate Year transmission
equalization expenses should be denied because those expenses are not known and
measurable. ETI’s post-Test Year adjustment does not with reasonable certainty reflect what
ETI’s transmission equalization expense will be when rates are in effect.
94. ETI’s transmission equalization expense in this case should be based on the Test Year level
of $1,753,797.
95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the accumulation
of recognized allocations of original cost, representing the recovery of initial investment
over the estimated useful life of the asset.
96. Except in the case of the amortization of the general plant deficiency, the use of the
remaining life depreciation method to recover differences between theoretical and actual
depreciation reserves is the most appropriate method and should be continued.
97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis
over the remaining, expected useful life of the item or facility.
98. Except as described below, the service lives and net salvage rates proposed by the Company
are reasonable, and these service lives and net salvage rates should be used in calculating
depreciation rates for the Company’s Production, Transmission, Distribution, and General
Plant assets.
99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production
plant depreciation rates.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 350
PUC DOCKET NO. 39896
100. The retirement (actuarial) rate method, rather than the interim retirement method, should be
used in the development of production plant depreciation rates.
101. Production plant net salvage is reasonably based on the negative five percent net salvage in
existing rates.
102. The net salvage rate of negative 10 percent for ETI’s transmission structures and
improvements (FERC Account 352) is the most reasonable of those proposed and should be
adopted.
103. The net salvage rate of negative 20 percent for ETI’s transmission station equipment (FERC
Account 353) is the most reasonable of those proposed and should be adopted.
104. The net salvage rate of negative five percent for ETI’s transmission towers and fixtures
(FERC Account 354) is the most reasonable of those proposed and should be adopted.
105. The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures (FERC
Account 355) is the most reasonable of those proposed and should be adopted.
106. The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors and
devices (FERC Account 356) is the most reasonable of those proposed and should be
adopted.
107. A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures and
improvements (FERC Account 361) are the most reasonable of those proposed and should be
approved.
108. A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles, towers,
and fixtures (FERC Account 364) are the most reasonable of those proposed and should be
approved.
109. A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead
conductors and devices (FERC Account 365) are the most reasonable of those proposed and
should be approved.
110. A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution underground
conductors and devices (FERC Account 367) are the most reasonable of those proposed and
should be approved.
111. A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line
transformers (FERC Account 368) are the most reasonable of those proposed and should be
approved.
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.
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PUC DOCKET NO. 39896
113. The net salvage rate of negative five percent for ETI’s distribution structures and
improvements (FERC Account 361) is the most reasonable of those proposed and should be
adopted.
114. The net salvage rate of negative 10 percent for ETI’s distribution station equipment (FERC
Account 362) is the most reasonable of those proposed and should be adopted.
115. The net salvage rate of negative seven percent for ETI’s distribution overhead conductors
and devices (FERC Account 365) is the most reasonable of those proposed and should be
adopted.
116. The net salvage rate of negative five percent for ETI’s distribution line transformers (FERC
Account 368) is the most reasonable of those proposed and should be adopted.
117. The net salvage rate of negative 10 percent for ETI’s distribution overhead services (FERC
Account 369.1) is the most reasonable of those proposed and should be adopted.
118. The net salvage rate of negative 10 percent for ETI’s distribution underground services
(FERC Account 369.2) is the most reasonable of those proposed and should be adopted.
119. A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and
improvements (FERC Account 390) are the most reasonable of those proposed and should be
approved.
120. The net salvage rate of negative 10 percent for ETI’s general structures and improvements
(FERC Account 390) is the most reasonable of those proposed and should be adopted.
121. It is reasonable to convert the $21.3 million deficit that has developed over time in the
reserve for general plant accounts to General Plant Amortization.
122. A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable
and should be adopted.
123. FERC pronouncement AR-15 requires amortization over the same life as recommended
based on standard life analysis. A standard life analysis determined that a five-year life was
appropriate for general plant computer equipment (FERC Account 390.2). Therefore, a five
year amortization for this account is reasonable and should be adopted.
124. ETI proposed adjustments to its Test Year payroll costs to reflect: (a) changes to employee
headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases
set to go into effect after the end of the Test Year.
125. The proposed payroll adjustments are reasonable but should be updated to reflect the most
recent available information on headcount levels as proposed by Commission Staff. In
addition to adjusting payroll expense levels, the more recent headcount numbers should be
used to adjust the level of payroll tax expense, benefits expense, and savings plan expense.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 352
PUC DOCKET NO. 39896
126. Staff has appropriately updated headcount levels to the most recent available data but errors
made by Staff should be corrected. The corrections related to: (a) a double counting of three
ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the
calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when
such costs were already included in the benefits percentage adjustments; and (d) corrections
for full-time equivalents calculations. Staff’s ETI headcount adjustment (AG-7) overstated
operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount
adjustment (AG-7) understated O&M payroll increase by $37,531.
127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.
128. The compensation packages that ETI offers its employees include a base payroll amount,
annual incentive programs, and long-term incentive programs. The majority of the
compensation is for operational measures, but some is for financial measures.
129. Incentive compensation that is based on financial measures is of more immediate and
predominant benefit to shareholders, whereas incentive compensation based on operational
measures is of more immediate and predominant benefit to ratepayers.
130. Incentives to achieve operational measures are necessary and reasonable to provide utility
services but those to achieve financial measures are not.
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.
134. The amount of incentive compensation that should be included in the cost of service is
$7,991,707.
135. To attract and retain highly qualified employees, the Entergy Companies provide a total
package of compensation and benefits that is equivalent in scope and cost with what other
comparable companies within the utility business and other industries provide for their
employees.
136. When using a benchmark analysis to compare companies’ levels of compensation, it is
reasonable to view the market level of compensation as a range rather than a precise, single
point.
137. ETI’s base pay levels are at market.
138. ETI’s benefits plan levels are within a reasonable range of market levels.
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PUC DOCKET NO. 39896
139. ETI’s level of compensation and benefits expense is reasonable and necessary.
140. ETI provides non-qualified supplemental executive retirement plans for highly compensated
individuals such as key managerial employees and executives that, because of limitations
imposed under the Internal Revenue Code, would otherwise not receive retirement benefits
on their annual compensation over $245,000 per year.
141. ETI’s non-qualified supplemental executive retirement plans are discretionary costs designed
to attract, retain, and reward highly compensated employees whose interests are more closely
aligned with those of the shareholders than the customers.
142. ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not
reasonable or necessary to provide utility service to the public, not in the public interest, and
should not be included in ETI’s cost of service.
143. For the employee market in which ETI operates, most peer companies offer moving
assistance. Such assistance is expected by employees, and ETI would be placed at a
competitive disadvantage if it did not offer relocation expenses.
144. ETI’s relocation expenses were reasonable and necessary.
145. The Company’s requested operating expenses should be reduced by $40,620 to reflect the
removal of certain executive prerequisites proposed by Staff.
146. Staff properly adjusted the Company’s requested interest expense of $68,985 by removing
$25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
2012), leaving a recommended interest expense of $43,047.
147. During the Test Year, ETI’s property tax expense equaled $23,708,829.
148. ETI requested an upward pro forma adjustment of $2,592,420, to account for the property
tax expenses ETI estimates it will pay in the Rate Year.
149. ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon the
prediction that ETI’s property tax rate will be increased in 2012, a change that is speculative
is not known and measurable.
150. Staff’s recommendation to increase ETI’s Test Year property tax expenses by $1,214,688 is
based on the historical effective tax rate applied to the known Test Year-end plant in service
value, consistent with Commission precedent, and based upon known and measurable
changes.
151. ETI’s Test Year property tax burden should be adjusted upward by $1,214,688.
152. Staff recommended reducing ETI’s advertising, dues, and contributions expenses by
$12,800. The recommendation, which no party contested, should be adopted.
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PUC DOCKET NO. 39896
153. The final cost of service should reflect changes to cost of service that affect other
components of the revenue requirement such as the calculation of the Texas state gross
receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
Expenses.
154. The Company’s requested Federal income tax expense is reasonable and necessary.
155. ETI’s request for $2,019,000 to be included in its cost of service to account for the
Company’s annual decommissioning expenses associated with River Bend is not reasonable
because it is not based upon “the most current information reasonably available regarding the
cost of decommissioning” as required by P.U.C. SUBST. R. 25.231(b)(1)(F)(i).
156. Based on the most current information reasonably available, the appropriate level of
decommissioning costs to be included in ETI’s cost of service is $1,126,000.
157. ETI’s appropriate total annual self-insurance storm damage reserve expense is $8,270,000,
comprised of an annual accrual of $4,400,000 to provide for average annual expected storm
losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its
current deficit.
158. ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.
159. ETI should continue recording its annual storm damage reserve accrual until modified by a
Commission order.
160. The operating costs of the Spindletop Facility are reasonable and necessary.
161. The operating costs of the Spindletop Facility paid to PB Energy Storage Services are
eligible fuel expenses.
Affiliate Transactions
162. ETI affiliates charged ETI $78,998,777 for services during the Test Year. The majority of
these O&M expenses—$69,098,041—were charged to ETI by ESI. The remaining affiliate
services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, L.L.C.;
Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy
Operations, Inc.; and non-regulated affiliates.
163. ESI follows a number of processes to ensure that affiliate charges are reasonable and
necessary and that ETI and its affiliates are charged the same rate for similar services. These
processes include: (a) the use of service agreements to define the level of service required
and the cost of those services; (b) direct billing of affiliate expenses where possible;
(c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting
processes and controls to provide budgeted costs that are reasonable and necessary to ensure
appropriate levels of service to its customers; and (e) oversight controls by ETI’s Affiliate
Accounting and Allocations Department.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 355
PUC DOCKET NO. 39896
164. Affiliates charged expenses to ETI through 1292 project codes during the Test Year.
165. ETI agreed to remove the following affiliate transactions from its application:
(1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
(2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and
(3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.
166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with
Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual
Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of
electric utility service and are not in the public interest.
167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement)
are not normally-recurring costs and should not be recoverable.
168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related
to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy
New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.
169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management
for ESI) are research and development costs related to energy efficiency programs. As such,
they should be recovered through the energy efficiency cost recovery factor rather than base
rates.
170. Except as noted in the above Findings of Fact Nos. 162-169, all remaining affiliate
transactions were reasonable and necessary, were allowable, were charged to ETI at a price
no higher than was charged by the supplying affiliate to other affiliates, and the rate charged
is a reasonable approximation of the cost of providing service.
Jurisdictional Cost Allocation
171. ETI has one full or partial requirements wholesale customer – East Texas Electric
Cooperative, Inc.
172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the
wholesale load results in a retail production demand allocation factor of 95.3838 percent.
173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by
the FERC to allocate between jurisdictions.
174. Using 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.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 356
PUC DOCKET NO. 39896
Class Cost Allocation 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 rates.
178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
public rights-of-way to locate its facilities within municipal limits.
179. ETI is an integrated utility system. ETI’s facilities located within municipal limits benefit all
customers, whether the customers are located inside or outside of the municipal limits.
180. Because all customers benefit from ETI’s rental of municipal right-of-way, municipal
franchise fees should be charged to all customers in ETI’s service area, regardless of
geographic location.
181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA) § 33.008(b)
that MFF be allocated to each customer class on the basis of in-city kilo-watt hour (kWH)
sales, without an adjustment for the MFF rate in the municipality in which a given kWH sale
occurred.
182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-
181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The
Company’s proposed allocation of these costs to all retail customer classes based on
customer class revenues relative to total revenues is appropriate.
183. The Average and Excess (A&E) 4CP method for allocating capacity-related production
costs, including reserve equalization payments, to the retail classes is a standard
methodology and the most reasonable methodology.
184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and
the most reasonable methodology.
185. ETI appropriately followed the rate class revenue requirements from its cost of service study
to allocate costs among customer classes. ETI’s revenue allocation properly sets rates at
each class’s cost of service.
186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
replacement of a functioning light with a lower-wattage bulb.
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PUC DOCKET NO. 39896
187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study
regarding the feasibility of instituting LED-based rates and, if the study shows that such rates
are feasible, ETI should file proposals for LED-based lighting and traffic signal rates it next
rate case.
188. An agreement was reached by the parties and approved by the Commission in Docket
No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial
Power Service-Time of Day, General Service, General Service-Time of Day, Large General
Service, and Large General Service-Time of Day rate schedules.
189. ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet from
these rate schedules consistent with the parties’ agreement in Docket No. 37744.
190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is
not reasonable.
191. ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
agreement that was adopted by the Commission as just and reasonable in Docket No. 37744.
Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194.
192. ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read:
DETERMINATION OF BILLING LOAD
The kW of Billing Load will be the greatest of the following:
(A) The Customer’s maximum measured 30-minute demand
during any 30-minute interval of the current billing month,
subject to §§ III, IV and V above; or
(B) 60% of Contract Power as defined in § VII; or
(C) 2,500 kW.
193. ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read:
DETERMINATION OF CONTRACT POWER
Unless Company gives customer written notice to the contrary,
Contract Power will be defined as below:
Contract Power - the highest load established under § VI(A) above
during the 12 months ending with the current month. For the initial
12 months of Customer’s service under the currently effective
contract, the Contract Power shall be the kW specified in the
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 358
PUC DOCKET NO. 39896
currently effective contract unless exceeded in any month during the
initial 12-month period.
194. The Large General Service and Large General Service-Time of Day schedules should be
similarly revised to eliminate ETI’s life-of-contract demand ratchet.
195. In its proposed rate design for the LIPS class, the Company took a conservative approach
and increased the current rates by an equal percentage. This minimized customer bill
impacts while maintaining cost causation principles on a rate class basis.
196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS
rate schedule with subsequent increases to be considered in subsequent base rate cases.
197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges
and increase the demand charges as proposed by Staff witness William B. Abbott.
198. DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent Pumping
Service” (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-
season (November through April), that can be cancelled at any time, and for load not lasting
more than 80 hours in a year. For customers whose loads match these SIPS characteristics
(for example, DOE’s Strategic Petroleum Reserve), the 12-month demand ratchet provision
of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The
monthly demand set under the SIPS provisions would be applicable for billing purposes only
in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in
that month, it would be forgiven and not applicable in the succeeding 12 months.
199. DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It
more closely addresses specific customer characteristics and provides for cost-based rates, as
does another ETI rider applicable to Pipeline Pumping Service.
200. Standby Maintenance Service (SMS) is available to customers who have their own
generation equipment and who contract for this service from ETI.
201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance
power to qualifying facilities should recognize system wide costing principles and should not
be discriminatory.
202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing
supplementary power under another applicable rate; and (b) revising the tariff as follows:
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 359
PUC DOCKET NO. 39896
Distribution Transmission
Charge (less than (69KV and
69KV) greater)
Billing Load Charge ($/kW):
Standby $2.46 $0.79
Maintenanc
e $2.27 $0.60
Non-Fuel Energy Charge (¢/kWh)
On-Peak 0.881¢ 0.846¢
Off-Peak 0.575¢ 0.552¢
203. ETI’s Additional Facilities Charge Rider (Schedule AFC) prescribes the monthly rental
charge paid by a customer when ETI installs facilities for that customer that would not
normally be supplied, such as line extensions, transformers, or dual feeds.
204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
Option B, which applies when a customer elects to amortize the directly-assigned facilities
over a shorter term ranging from one to ten years, has a variable monthly charge. There is
also a term charge that applies after the facility has been fully depreciated.
205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per
month of the installed cost of all facilities included in the agreement for additional facilities.
206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the
Post Term Recovery Charge as follows:
Selected Recovery Term Recovery Term Charge Post Recovery Term Charge
1 10.88% 0.35%
2 5.39% 0.35%
3 3.92% 0.35%
4 3.20% 0.35%
5 2.76% 0.35%
6 2.48% 0.35%
7 2.28% 0.35%
8 2.14% 0.35%
9 1.97% 0.35%
10 1.94% 0.35%
207. The revisions in the above Findings of Fact to Schedule AFC rates reasonably reflect the
costs of running, operating, and maintaining the directly-assigned facilities.
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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. Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS
customers towards their cost of service by recommending a decrease in the customer charge
from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable
and should be adopted.
210. ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer
charge of $5 per month and a consumption-based energy charge. The Energy charge is a
fixed rate of 5.802ȼ per kWh from May through October (Summer). In the months
November through April (Winter), the rates are structured as a declining block, in which the
price of each unit is reduced after a defined level of usage.
211. ETI’s Schedule RS declining block rate structure is contrary to energy efficiency efforts and
the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as
stated in PURA § 39.905.
212. Schedule RS winter block rates should be modified consistent with the goal set out in PURA
§ 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed
by ETI and subsequent reductions should be reviewed for consideration at the occurrence of
each rate case filing.
213. Other elements of Schedule RS are just and reasonable.
Fuel Reconciliation
214. ETI incurred $616,248,686 in natural-gas expenses during the Reconciliation Period, which
is from July 2009 through June 2011.
215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
negotiated operational balancing agreements with various pipeline companies.
216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its
natural-gas requirements, and ETI prudently managed its gas-supply contracts.
217. ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide
reliable electric service to retail customers.
218. ETI incurred $90,821,317 in coal expenses during the Reconciliation Period.
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PUC DOCKET NO. 39896
219. ETI prudently managed its coal and coal-related contracts during the Reconciliation Period.
220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at
the Big Cajun II, Unit 3 facility.
221. ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable
electric service to retail customers.
222. ETI incurred $990,041,434 in purchased-energy expenses during the Reconciliation Period.
223. The Entergy System’s planning and procurement processes for purchased power produced a
reasonable mix of purchased resources at a reasonable price.
224. During the Reconciliation Period, ETI took advantage of opportunities in the fuel and
purchased-power markets to reduce costs and to mitigate against price volatility.
225. ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to
provide reliable electric service to retail customers.
226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its
purchased-power planning and procurement processes and its actual power purchases during
the Reconciliation Period.
227. The Entergy system sold power off system when the revenues were expected to be more than
the incremental cost of supplying generation for the sale, subject to maintaining adequate
reserves.
228. The System Agreement is the tariff approved by the FERC that provides the basis for the
operation and planning of the Entergy system, including the six Operating Companies. The
System Agreement governs the wholesale-power transactions among the Operating
Companies by providing for joint operation and establishing the bases for equalization
among the Operating Companies, including the costs associated with the construction,
ownership, and operation of the Entergy system facilities.
229. Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues
and expenses from off-system sales.
230. During the Reconciliation Period, ETI recorded off-system sales revenue in the amount of
$376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues
and margins from off-system sales to eligible fuel expenses.
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PUC DOCKET NO. 39896
231. ETI properly recorded revenues from off-system sales and credited those revenues to eligible
fuel costs.
232. The Entergy system consists of six Operating Companies, including ETI, which are planned
and operated as a single, integrated electric system under the terms of the System
Agreement.
233. Service Schedule MSS-1 of the System Agreement determines how the capability and
ownership costs of reserves for the Entergy system are equalized among the Operating
Companies. These inter-system “reserve equalization” payments are the result of a formula
rate related to the Entergy system’s reserve capability that is applied on a monthly basis.
234. Reserve capability under Service Schedule MSS-1 is capability in excess of the Entergy
system’s actual or planned load built or acquired to ensure the reliable, efficient operation of
the electric system.
235. By approving Service Schedule MSS-1, the FERC has approved the method by which the
Operating Companies share the cost of maintaining sufficient reserves to provide reliability
for the Entergy system as a whole.
236. Service Schedule MSS-3 of the System Agreement determines the pricing and exchange of
energy among the Operating Companies. By approving Service Schedule MSS-3, the FERC
has approved the method by which the Operating Companies are reimbursed for energy sold
to the exchange energy pool and how that energy is purchased.
237. Service Schedule MSS-4 of the System Agreement sets forth the method for determining the
payment for unit power purchases between Operating Companies. By approving Service
Schedule MSS-4, the FERC has approved the methodology for pricing Inter-Operating
Company unit power purchases.
238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
horizons. Once the planning process has identified the most economical resources that can
be used to reliably meet the aggregate Entergy system demand, the next step is to procure the
fuel necessary to operate the generating units as planned and acquire wholesale power from
the market.
239. Once resources are procured to meet forecasted load, the Entergy system is operated during
the current day using all the resources available to meet the total Entergy system demand.
240. After current-day operation, the System Agreement prescribes an accounting protocol to bill
the costs of operating the system to the individual Operating Companies. This protocol is
implemented via the Intra-System Bill (ISB) to each Operating Company on a monthly basis.
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PUC DOCKET NO. 39896
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.
247. ETI’s proposed loss factors are reasonable and shall be implemented on a prospective basis
as a result of this final order.
248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC’s
reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat
such costs as eligible fuel expense.
249. Special circumstances exist and it is appropriate for recovery of the rough production cost
equalization costs reallocated to ETI as a result of the FERC’s decision in Order No. 720-A.
Other Issues
250. A deferred accounting of ETI’s Midwest Independent Transmission System Operator
(MISO) transition expenses is not necessary to carry out any requirement of PURA.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 364
PUC DOCKET NO. 39896
251. ETI should include $2.4 million in base rates for MISO transition expense incurred on or
after January 2, 2011, based on a five-year amortization of $12 million in total projected
expenses.
252. ETI should include an additional $52,800 in base rates for MISO transition expenses
incurred during the 2010 portion of the Test Year, based on a five-year amortization of
$263,908 in such expenses.
253. Transmission Cost Recovery Factor baseline values should be set during the compliance
phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.
254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase
of this docket, after the Commission makes final rulings on the various contested issues that
may affect this calculation.
255. The appropriate amount for ETI’s purchased power capacity expense to be included in base
rates is $245,432,884.
256. The amount of ETI’s purchased power capacity expense includes third-party contracts,
legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
amounts for all contracts should be included in the baseline for a purchased capacity rider
that may be approved in Project No. 39246 is an issue that should be decided in that project.
B. Conclusions of Law
1. ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric utility”
as that term is defined in PURA § 31.002(6).
2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject
matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
36.101–.111, and 36.203.
3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation
of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. GOV’T CODE
ANN. § 2003.049.
4. This docket was processed in accordance with the requirements of PURA and the Texas
Administrative Procedure Act, TEX. GOV’T CODE ANN. Chapter 2001.
5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 365
PUC DOCKET NO. 39896
6. Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded
jurisdiction to the Commission has jurisdiction over the Company’s application, which seeks
to change rates for distribution services within each municipality.
7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
municipality’s rate proceeding.
8. ETI has the burden of proving that the rate change it is requesting is just and reasonable
pursuant to PURA § 36.006.
9. In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding
permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used
and useful in providing service to the public in excess of its reasonable and necessary
operating expenses.
10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original
cost, less depreciation, of property used and useful to ETI in providing service.
11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and
P.U.C. SUBST. R. 25.231(c)(2)(C)(i).
12. Including the cash working capital approved in this proceeding in ETI’s rate base is
consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
allowance for cash working capital to be included in rate base.
13. The ROE and overall rate of return authorized in this proceeding are consistent with the
requirements of PURA §§ 36.051 and 36.052.
14. The affiliate expenses approved in this proceeding and included in ETI’s rates meet the
affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.—Austin
1984, no writ).
15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and
P.U.C. SUBST. R. 25.231(c)(2)(C)(i).
16. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in
this case is based on the most current information reasonably available regarding the cost of
decommissioning, the balance of funds in the decommissioning trust, anticipated escalation
rates, the anticipated return on the funds in the decommissioning trust, and other relevant
factors.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 366
PUC DOCKET NO. 39896
17. ETI has demonstrated that its eligible fuel expenses during the Reconciliation Period were
reasonable and necessary expenses incurred to provide reliable electric service to retail
customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted for
the amount of fuel-related revenues collected pursuant to the fuel factor during the
Reconciliation Period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).
18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during
the Reconciliation Period.
19. The Reconciliation Period level operating and maintenance expenses for the Spindletop
Facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).
20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover
rough production equalization payments reallocated to ETI by the FERC.
21. ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with
PURA § 36.003.
C. Proposed Ordering Paragraphs
In accordance with these findings of fact and conclusions of law, the Commission issues the
following orders:
1. The Proposal for Decision prepared by the SOAH ALJs is adopted to the extent consistent
with this Order.
2. ETI’s application is granted to the extent consistent with this Order.
3. ETI shall file tariffs consistent with this Order within 20 days of the date of this Order. No
later than ten days after the date of the tariff filings, Staff shall file its comments
recommending approval, modification, or rejection of the individual sheets of the tariff
proposal. Responses to the Staff’s recommendation shall be filed no later than 15 days after
the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff
sheet, effective the date of the letter.
4. The tariff sheets shall be deemed approved and shall be become effective on the expiration
of 20 days from the date of filing, in the absence of written notification of modification or
rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed
revisions of those sheets in accordance with the Commission’s letter within ten days of the
date of that letter, and the review procedure set out above shall apply to the revised sheets.
SOAH DOCKET NO. PROPOSAL FOR DECISION PAGE 367
PUC DOCKET NO. 39896
5. Copies of all tariff-related filings shall be served on all parties of record.
6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of
instituting LED-based rates and, if the study shows that such rates are feasible, ETI should
file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED
lighting customers taking service, the study shall include detailed information regarding
differences in the cost of serving LED and non-LED lighting customers. ETI shall provide
the results of this study to Cities and interested parties as soon as practicable but no later
than the filing of its next rate case.
7. All other motions, requests for entry of specific findings of fact and conclusions of law, and
any other requests for general or specific relief, if not expressly granted, are denied.
SIGNED July 6, 2012.
Attachment A
SOAHDOCKETNO. 11111111 ALJ Schad ule I
PUC DOCKET NO. 39896 Revenue Requirement
COMPANY NAME Entergy Texas, Inc
TEST YEAR END 30-Jun-1 1
Company ALJ
Company Requested Adjustments ALJ
Test Year Adjustments Test Year To Company Adjusted
Total To Test Year Total Electric Reguest Tota l Electric
(a) (b) (c) (d) (•) = (c) • (d)
REVENUE REQUIREMENT
Operahons & Marnlenance s 1,291,684,714 $ (1,075, 148.117) $ 216,536,597 $ (24,241,866) $ 192,294.731
Regulatory Debits and Credrts 40700 ......
""'
.... $ (6. 784,608) s 12,030.533 $ 5.245,925 $ (32~ .121) ,., $ 4,92 1,804
Accretion Expense $ 212,783 s (212,783) s s $
Interest on Customer Deposits s s 68,985 $ 68,085 s (25.938) •• $ 43.047
Decommissioning Expense .....
Sd>•
$ s $ $ $
Depreclalion & Amortization Expense ..... $ 76,072.459 $ 22.558.698 $ 98,631 ,157 $ (6.761,585) $ 91.869,572
Taxes Other Than Income Taxes StllO•t $ 63,023,906 $ (2.533, 159) 60.490.747 $ (2.953,747) $ 57,537,000
Federal Income Taxes Sell A $ (23,407 ,031) $ 67,296,739 43,889.708 $ 5,920,966 $ 49,810,674
Currant State Income Taxes $1;1'1,.,, $ (127,519) $ 69,767 (37,732) $ 37,732 $
Oererred Federal Income Taxes
Deferred State Income Taxes
'". $
$
67,051,463
812.265
$
$
(52 ,089,274)
(727,9 18) $
14,962,189
84,347
$
$
(14.962.189)
(64,347)
$
$
Investment Tax Credits 4 11.00 ..... $ ( 1.e11 ,1n1 $ (46.429) s (1,657.606) $ 1,657,606 $
Consolidated Tax Savings Adjustment $ $ $ $ $
Return on Invested Capital $ 155, 182,991 $ 155,162,991 $ (15,379,778J i 139, 783,213
TOTAL 1,466,927 ,255 $ (873,649,947) $ 593,377 ,308 $ (57,117,267) $ 636,260,041
Plus:
Addbaci<: Purchased Power Rider 555.00 $ 244,539,864 et ttO
Addbaclc Interruptible Services 555.00 $ . ,,
Total Add backs $ 244,539,884
Total ALJ Revenue Requirement $ 760,799,925
Attachment A
SOAH DOCKET NO. A W Schedule U
P UC DOCKET NO. 39896 O&MEx por,.ge
COMPANY NAME Entetgy Texas, tnc.
TEST YEAR ENO 30-Jun-11
Company ALJ
OPE RATIONS AND MAINTENANCE E XPENSE .... Tost Ye.ar
Total
Company
Adjustmonta
To Test Year
Reque~te d
Test Year
Total Eloc1ric
Adjuatmentl
ToCo mp.;_iiny
ReguHt
ALJ
Adjusted
Total Electric
(• } (b) (<) (d) (•) • (c) • (d)
~
Ope1at!on1 &- Maintenance:
PrOd Oporalton and Supr 500 s S,338,227 $ 52,2 15 $ 5,390.442 $ (96,382) $ 5.294.080
Fuel 501 s (255 2•2) $ $ (255.242) $ s (255,242)
Fuel· Oll 501 s 66•.7•5 s (663,89 1) s 854 $ $ 85•
Fuel..,•iu<•l Gas 50 1 s 330,035,996 s (330.035,&ge) $ $ $
Fuel.Coot 501 $ 49, 170,094 s ('6,e•8,7•8l $ 2,$51,346 $ (1,•06) $ 2, 5"9,880
S\-..m Eipen1et. 502 $ 3,900,803 40,940 $ 3,941,7<3 $ (81.223) $ 3,880.520
E leClllC Expenses 505 $ 2,529,473 9.516 $ 2. 538.989 $ 684 s 2, 539.673
MISC Steam Powe• Expenses 506 $ 8,135.921 31.297 $ 8,167.218 $ (74 347) $ 8.092.871
Renis 507 $ 131.131 $ 131,131 $ s 131,131
NOX Emmis•IOns Allowan"" E1CPOnse 509 $ (43.244) 0 .244 $ s $
NOX Soasonal Allowance E.xpe-nse 509 $ 11,904 (11,90•} $ $ s
Motntenanco Supv a n:d Eng 510 $ 1,156,596 21,037 1,187,633 $ (18,303) $ 1,169,330
Maintenance o1 sto¥.'91-from Others
Co-GenerabOf\
555
555 $
159.034.737
148,658.981
$
$
(159.03'1.737]
(148.658.981) $ '' s
Rsrc Plan Puf>ow.A~1La1ed s
Purcnased Pa..er Entergy Alfilates
555
555
$
$
308,866,766
25,558,973
$
$
(308,868,766)
(25,558,973)
$
$ $' s
Renewable Energy Credd 555 $ $ s $ 623.303 s 623.303
System Control & Load Dispatch 556 $ 951.691 $ 19,686 s g71,377 $ (19,11 1) s ~2 .266
System ContfOI &_Dispatch 01.he• 557 $ 321,455 $ 4,301 $ 325,756 $ (8,391) $ 319 ,365
Deterred E~ctric: fuel Coit 557 $ (52, 121.822) $ 52, 121,822 $ $ $
Oe' erred TX capacity rider 557 $ (12,448) $ 12 ,448 $ s $
Traolimlss100 Ops Supra. El\gr 560 $ 5,668,076 $ (117,800) $ S,450,276 $ (31,045) $ 5,419,231
Load Dispatching 561 $ 842,620 $ 8,987 $ 851,60 7 $ (79,413) $ 772,194
l oad Dlspatching-rellabilily 561 $ 231,424 $ 5,608 $ 237,032 $ 1,191 $ 23a,223
l.oao Dlspalchino·transmisslon syslom 561 $ 1.422.924 $ 3 1,890 $ 1,454,814 s 6 ,365 $ 1,461, 179
load Oispatching-Ttans Serv & Sch 561 s 577.8Q5 s t2,964 $ 590,859 s 2,886 $ 593.745
$ygtem Plannlng & Standatd-$ Dev 561 $ 385.664 $ 7,677 $ 393,561 $ 1,755 $ 395,3t6
Transmission Se1vice Studie~ 561 $ 52.780 $ 1 139 $ 53,919 $ 242 $ 54.181
Transm1sslor. Slaton Equipment 562 $ 142.626 s 925 143,551 $ (1,813) s 141,738
Trans OH Line E:xpense 563 $ 483,385 s 66 483,451 $ (129) s "83,322
Transmissiorl Equata!ion 565 $ 1,377.103 s 9.319, 479 s 10.696.582 $ (8.942,785) s 1.753,797
l.isc. Transr.-.iHion Expenses 566 $ 924.736 s (19.401) $ 905.335 s (11,518) s 893.817
Rents 567 $ 987,823 $ s 9B7,e23 s s 907,023
t.\aint. SUp-.t. And Eng. 568 $ 3.041 ,227 $ 313, 096 3 ,35',323 $ (29,859) $ 3 .32•.•&<
.Y.ainl Of Strucues 509 $ 100,642 $ 42 s toe.ea• $ (6,215) $ 100,469
Maint T:an s Computer & Te'ecom 569 $ • 48.842 s 6 ,2 15 455,057 s 155 $ •SS,212
Transmission M a~nt Station Eq1.11p 570 $ 1,692,713 $ 7 .266 1,599,979 $ (14,177) $ 1.685.802
Transmission Mainl OH Une Exp 571 $ 1.790,44 7 $ 40 1.790.•87 $ (79) $ 1,790.408
Maint. Of M isc. Transminion 573 $ 52.814 $ 52,81t s 52,81 4
Region~! Energy Mkts·Optt Supv 575 $ 18,998 $ ..034,420 •.053,418 $ (1 ,E00.189) 2.453,229
OayAhead 8 Real Time Mkts W PP 575 $ 37,069 $ 810 37,679 s (397) $ 37,462
Maint of ComptJter So Hwan~ WPP 576 $ 3,168 $ 3, 166 $ s 3,168
Distribution OP• suor 8 Ensir 500 $ 5,357,005 $ 26,983 5,383,988 $ (66,797) $ 5,317,191
Distribution load Dispatching 581 $ 448,718 $ 4.367 453,085 $ (8.488) $ 444 .597
Distribution Stalion Expenso-s 582 $ 471,976 $ 2.931 •74.909 s (5,715) $ <89.194
Distribution Of.I Line Expensu 583 103.3J2 $ 77 1 104, 103 $ (1.511) $ 102.592
Underground Lile ExpenH• 534 746, 886 $ 2,638 749,624 $ (5,173) $ 744 .351
Sireet Ll!Jhtitlg & Signal Sy• 585 $ 286.809 $ 2,296 289,105 $ (4.152) $ 284.953
h\etef E.c:penses 586 $ 2.086 758 s 13,593 2.102,349 $ (25.176) $ 2 .on.113
Customer insta1ai.ons 587 s •70.238 $ 3,787 • 7•.023 $ (7,3"9) s 466.674
Miscellaneous DiWlbu'on Exp 588 s 1,503.004 $ 4 .505 1,507 509 $ ( Hl.425) $ 1 •118.084
Rems 5S9 s 3 925.628 $ s 3.925.826 s s 3 .925,626
Oisuibuion Mani Supr g Ergr 590 s 1,455,611 $ (<,009) $ 1.451 .602 $ (23.447) $ 1,•28,155
Maim Of Structures 591 s ·,s0.•88 $ s 180,408 $ s 1eo.•ae
Oi'5--tribution Mani Station Equrp 592 $ 860.084 $ 6,186 $ 1!6&,270 $ (11,078) $ 655,192
Distribution Ma~1 OH tines 593 $ 10,544, 165 $ 20.91 4 $ 10,565,079 $ (43,524) $ 10.521,555
Underground Lne Ex~nsea 594 $ 802,465 $ 5.293 $ 807,758 $ (10,732) $ 797.026
Dist Main! Line Trnf, Regu(a1011 595 $ 15,851 $ 51 $ 15,902 $ (36) $ 15.866
MalntSt1ee1 llghl &Signal Sys 596 $ 635.209 $ 4 .176 $ 639,385 $ (8, 188) $ 831 ,197
Maintenance-Non RoActwey Sec Ltg 596 s 392,358 $ 2, 678 s 395,03e $ (5,252) s 389,784
Malr\lenanoe of Moters 597 $ 159,166 $ 1,366 $ 160,552 $ (2,678) s 157.874
Maint of Misc Olstr Plant 598 s 449,000 $ 1,928 $ 451,794 $ (3,039) $ 448,755
Supervisjoo • Customer Accts 901 $ 256,934 $ 2.4 58 $ 261,392 $ (4,552) $ 256,840
Meter Reading Exp 902 $ 3,843,502 $ 8.762 s 3,852,26" $ (9,366) $ 3,842.ege
Customer Reoo'd• 900 $ 5,250,761 $ 71,989 $ 5.322.750 $ (66,377) s 5,256.373
s s 38. 181 4,784,002 4, 784,002
Customer Colleclion
Customer Oepos1 lntertst
903
903.2 s
4,7•5.821
$
$
$
$
$ 's
Vncofec;t;b'9 Accounlll
Elfective Rate
904 $ 2,835.831
0~000000000000
$ 2,051.289 $ • .887,120
0 008236 IOMS5
$ (470.424)
' 4,416.896
0 00623611)8685
uncorectAbte AccQ.inls~eveoue atij $ (3l>7.648) s (307.1148) s 307,6<18 $
Uncolect10le Accooots Eleel-Wriie Ott 904 (1, 108,887) s $ (1. lO'l,887) $ $ (1,106,887)
Mfsoetiarleous 905 $ 33, 149 $ 610 s 33,759 $ (670) s 33,089
Fac.torino Expense 426.5 $ $ $ s
Factonng Factor 0.0000000000000 0.0000000000000 0.0000000000000
Supor\flsion 007 392.505 $ (2,721) 389,78« (5.629) 384,155
Attachment A
SOAH DOCK ET NO. AW Schedule II
PUC DOC KET NO. 39896 O &M Expense
COMPANY NAME Entorgv Ton a, Inc.
TEST YEAR END 30.Ju n-11
company AW
Company Requested A.d1u1tmonls ALJ
OPERATIONS ANO MAINTENANCE EXPENSE T es t Year Adjustments Tes1 Year To Company Ad)ullld
Total To TestYoar Total Electrlc R!9UHt Total Sloctric
l•l (b) (c) (d ) (•) • (c) • (d)
Adm1niatrative & GencttGI:
Admin & GeneraJSa1ales 920 s 18.405,832 $ (1,4EO, 140) s 16,945.792 l (5,773,70Sl s 11.1n.08<
Office 5 '1)lpi"'5 & fl(j) 921 $ 1.590, 193 $ (<59. 339) s 1.130 8S< $ (5.<00) $ 1,125,<5<
Admin Expenses T ransfened 922 s 1,059,901 $ 1.006 s 1 060.947 $ 21• $ 1,061.161
Outstde Services 923 $ 14.921 .589 $ (S.•31 , 183) 9 ,490,406 $ (89,762) $ 9.<00.64•
Property Insurance 92• $ 1,134.432 $ 1.287 $ 1. 135,119 $ $ 1. 1 ~.71 9
Provii ion for Propol1y l nGur~noe 92• $ 3.6 99,996 $ s.oeo,004 $ 8,750,000 $ (491, 172) $ 8,268.828
Environmental Reservei Ac;c;rUiti 924' $ 1 . 1~M7e $ $ 1,153,576 $ $ 1,153.576
ln11.uie$ & Damages 925 $ 1,859,658 $ 7A 2 4 $ 1,867,-082 $ (5.43 7) $ 1.861,64 5
Em plOjlee Pen .,001 & Benefl1$ 926 $ 27,027,557 $ (17.96 1) $ 27.009.596 $ (2.678.305) $ 24,33 1,291
Regu.atory Commosslcn E)!jl 928 s 7.703.335 $ (1.1164.403) $ 5.723,932 $ (4.150,717) s 1,573,215
General Ad""'1iSIA9 Elll> 9301 s 62.(140 $ (65) $ 61,975 $ ( 343) s 6 1.632
l.hcellaneous 9302 $ 798,138 224,312 $ 1,020,450 s (9, 181) s 1,011 ,269
Active Oevetopmenl E>rP8f'ISM 0302 s 21 $ $ 21 s $ 21
Directors' Fooa ond Expenses 9302 $ 10.•1a $ (79.476) $ $
Rems 931 $ 3 ,264,4 25 $ 1,164 $ 3,.265.589 $ 3 ,265,589
Maint. 01 General P lant 935 1 1.s~q22 1 2. 9 79 1 1660 301 1 (3,940) 1 656,361
TOTAL Adrrinislralive &General 84.420.631 (4. 134,391) 80,286.240 (13,207.751) 6 7,0 76,489
TOTAL 0 & M EXPE NSE 1,29 1,6M.714 (1,075,148,117) 216,536 ,597 (24,241,866) 192,294,731
Attachment A
SOAH DOCKET NO. ALJ Schodute II
PUC DOCKET NO. 39896 lnvt11ed Capital
COMPANY NAME Entergy Tous, lne.
TEST YEAR ENO 30.Jun-11
Company ALJ
Company Requested Adju&tment1 ALJ
Teat Yetr Adjustmentt Test Year To Company Adjusted
Total ToTit•tYtar Total EJoctrlc Reguest Total Eloctric
{• ) (b) (C) {cf) (t) • (c) • {d)
INVESTED CAPITAL
Plant In Service $ 3,52 1,388, 18 7 (251,5t 2,4 9 1) 3,269,855,GGE> $ (1,333,352) . .. 3,268,522, 34•
Accumu1ate0 Oeprediltion $ /l 4 '11.94$172) 148,061.290 (1.269,884.882) (1.269/!84.6ll2)
H•t Plent I" Se.Mee $ 2,103,422,015 $ (t03,4 51,201 ) 1,999,970,81 4 (1.333,352) t ,998,637,462
$
Consuuction W011< ln Ptogres.s $ $ $ $ s
Plant Held tor fl/lure Use s $ $ $ s
Working Casn AUOY1ince s s (2.0t3,921) $ (2.689.275) $ {3,72S.159) s (6,414,434)
Fuel lnventones s 53,759.975 s $ 53.759.975 $ {1,066,490) ... s 52,693.485
Malorlllls end Supplies
Prepayments
Prape1ty Insurance Reserve
s
s
s
29.252.574
7,368,433
$
$
$
( 14 8, 3~)
59,7Qfl,744
s
s
$
29.252. 574
7,218,037
59,'IW, 744
$
$
$
n.a•1
916, 313 ..
... $
$
s
29,285,421
8, 134.350
59,799,744
lnjvne& and Damages Reserve $ (5,560,243) $ $ (5,569,2•3) $ s (5.569,2•3)
Coal Cai Maintenance Re.erve $ 1,400,350 $ $ 1,• 00,350 . $ s 1,400.350
Unfunded Pension $ (53, 715,94 1) $ 109,689,386 $ 55,97M45 s (25,311.236) .. $ 30,562,309
Alkw.i1ncea $ 68,9 14 $ $ 88,91 4 $ $ 68.914
En-Aronmental Re.setve$ $ 3,412,379 $ (4,474,569) $ (1,06 2, 190) $ $ (1,002,190)
Customer Deposits $ (JS,872,4 76) $ $ (35.872.476) $ $ (35,872.476)
Rogulatory As._ts aM Llal>ilobes $ $ 26,366,859 $ 26. 366,859 $ (1 1.054.064) "' $ 15.312 ,795
Accumulated DFIT s (824,33',691) $ 369,967. 144 $ (454,371,547) $ (2.460,528) . ..... " $ (456,932.075)
Ral• Case Expenses $ s 6 ,175000 $ 6, 175,000 $ (6,175,000) O• 13 $
TOTAL INVESTED CAPITAL {RATE BASE) 1,279,186,389. "61,910,0•6 1,7•0,421,091 (S0,176,669) $ 1,690.244,4 12
RATE OF R ETURN 5.H0% 8.92% 8.2700% •
RETURN ON ttNESTEO CAPITAL 155.162,991 155,16U91 (15,379,178) 139,783,213
Attachment A
SOAH DOCKET NO. ALJ Schoduto UIA
PUC DOCKET NO. 39896 Eloctr1c Pl1nt 1n Service
COMPANY NAME Entergy Te)(H, Inc.
TES T YEAR ENO 30.Jun·1 1
Company AW
Company Requested Adjustment& AW
Test Year Adju stment• Te• tYou ToComp•ny A dju1ted
Total To Teat Year Totaf Eloc::ttJc Reguetl Total E'9c1.ric
(• ) (b) (C) (d) (a)• (c) + (d)
Electric Plttl\t In Service .,.,
fntaf'lgit.10 Plant
Organtzaucn 301 $ 1.346,899 $ 4,958.233 $ 6, 305,132 8, 305, 132
Misc Intangible Plant 303 J 95 786 717 ~ ~ 122§~9 $ 1gg 2§§ 406 100,9116 406
Total ln!angible Pl&nl $ 98.133,616 $ 9.157.922 107,291, 538 107, 291,538
Procfli.x:aon Planl-Steam
Land and Lano R ghts 310 $ 4,512.873 $ 4 ,512,873 $ $ 4 ,512,873
Siructures and Improve 311 $ 172.930,626 $ 1.0llil,019 174,029,645 $ $ 174,029,645
Solle• Plant Eq1,;ipment 312 $ 388,•77,0•2 $ 10.838.< 17 399,315,•59 $ $ 399,315,459
Turt>ogonoralor& 314 $ 189,17~.1 1 1 $ e.787,919 197,963,030 $ $ 197,963,030
Aoceasory Equ!prne:ml 31& $ 96,272, 189 $ 10,750,419 107,022,608 $ $ 107.022,608
Misc Power Plan1Equip 318 $ 10,848,083 $ 1,864,4 64 12,712,547 $ $ 12,712.547
As.set Retit e Coils 317 $ <19,21 I $ (419,211) $ $
Accessory Elec. Equip 334 $ 218,538 $ 218,538 $ $ 216.538
t.11sc Power Plant Equ:p 335 $ 37.2e9 $ 37,269 s s 37.259
Total Producllon Plant $ 862,890,94 2 s 32 921 0 27 8116 811,969 s s 8116.~
TransmtSsion Plant
Land 350.1 $ g,579,870 $ 4,2'7,242 $ 13,827, 121 $ $ 13.827.1 21
Easomonts 350.2 $ 33,822,888 s 358,7 3 5 $ 33,9 79,623 $ s 33.9 79,6 23
Structures And lmprov 352 $ 21,Q!7
0v.meaa cono,::IOrS &o JM $ 166,088.991 s 12,570240 $ 178.669,231 s $ 178.669.231
UndO!ground CoooUJI 357 $ s $ $ s
Underground Conductor 35a $ 321,717 s s 321,717 $ $ 321,717
Roads and Trails 359 $ 202.785 s s 202,785 $ $ 202,785
s
Total Transmisslor\ Plant 768,528.803 42.082,3•2 $ 810,591 ,235 810,591,235
Dislributioo Plant
Land 360 I $ • . 178,055 $ 4, 178.955 $ $ • . 178,955
Euements 380.2 $ 11,759,529 $ 11,759,5l9 $ $ \l,759,5l9
Sttu.ctute and Improve 361 s 7,M7,8 17 s 157.089 5 8.01•.906 s $ 5,014,906
Sta!loo Equlpment 362 $ 156,70.,009 s 7,565169 s 164,269.178 $ $ 164,269, 178
POies, Towers S Fooures 36• $ 185, 114,784 s 36,287,319 $ 221.402,103 $ $ 221.<02. 103
OH Conduc,ocs & Oevlcos ' 356 $ 170, 5•1,014 $ 44,147,418 $ 214,688.•32 $ $ 214.688.•32
1,Jnderground Conduit 366 $ 22,067,426 s 1,103,8 70 $ 23.171 .296 $ $ 23, 171,2116
UG Con & Del/fees 367 $ 84 ,221,923 $ 7.121 ,687 $ 91.343,590 $ $ 91 ,343,590
Llne Trans formers 368 $ 285. 357,209 s 73,111 .16 7 $ 358.•68,376 $ $ 358.468,376
S.rvloos·Ove i 1, 127,77~
$ 460, 104.801 {385,581,394) s 74 ,523,4 07 $ s 7-4,523.407
Toto! Electric P IS 3,317, 266,928 (107,411,230) 3 ,269,86 5,098 (1,333,.352) ... 3,266,$22,346
Attachment A
SOAH DOCKET NO. AlJ S<:hodul&1118
PUC DOCKET NO. 39896 Ooprod:atJon E>32,494 $ $ 8 .332.494
lowers and FlxtufOYomenlc 361 127,Q1 1 $ 33,069 $ 160,960 $ (9.512) $ 15 1.468
Station Eqwpmont .162 3,BOe,715 $ 363 ,57~ s 3,970.290 $ (399,946) $ 3 ,570,344
Poles, Tower& & F'1>1;a,,res 36• 8,809,4~4 $ 1,4:18,154 $ 8,24 7,6 18 s (1,192,611) s 7,C55,007
OH Cond..,1011 & Devices 365 3,600,4 24 s 3,244,7 56 $ 6,845,180 $ s 6.845, 180
IJodergroWon s 31 ,1en.123 s 10,776 623 $ 4 2,537,3<6 s (2,606,542) s 39,930,804
Regional Trans &Mkt Ops Hatdwara 382 12,125 12,125 12,125
Regkm al Trana & Mkt Op$ Software 383 673,827 (60 1) 673,226 673, 226
Structures & hnprovements 390 $ t,359,296 s (272,045) 1,087,251 $ $ 1.087,251
Office Furniture & Equipmerit 391 s 2,61 4,238 $ 3,316,559 5,832.797 s s 5.832.797
Transportanon Equipment 392 $ 955 $ 44,724 4 5,679 s s 4 5.679
SIDmenl 394 s 558.547 s 66,440 622,S87 s s 622.987
~boratOtY Equrpment 395 22,505 s 254,860 177.365 s s 277,365
Powef Qperaied Equipment 396 J0,044 $ (17,172) s 12,8 72 s s 12.872
Communication Equip(t>ent 39 7 s 1,697,976 s (310.5 01 ) $ 1,387.477 s s 1.387.4 77
Misc Equipmem 398 $ 471 55 $ 123.991 $ 17 1 146 s $ 171148
Subco1al Geneq>enoe 301 $ 735,599 $ 525426 s 1.261,027 s 1.261,027
Contra AFUOC 303 $ (117,485) $ 142.641 $ 25.356 $ 25,350
Customer Accounting 303 $ 18 9,797 $ (17,552) $ 172,245 $ 172,245
Cu stom e< CCS 303 $ 233,9 24 $ (51,3 05) $ 18 2.6 19 $ $ 182,6 10
Customer CIS 303 $ 18.386 $ (1 .437) $ 16,940 $ $ 16,049
Customer Service 303 $ 11 7,625 $ 456 $ 11 8,081 $ $ 118,061
Distribution 303 $ 240,3'15 $ (68011) $ 172,334 s $ 172,334
A&GIMISC 303 s 2,587,529 s (835.7«) s 1.751,785 s s 1,751,785
A&GIMISC·!Jbof Reia!Bd 303 $ 531 .~20 s (43,000) s •e6,420 $ $ 488 4 20
" "on ~udear ?rod Fue4 303 $ 3,31• $ {674) s 2,840 $ $ 2640
Non Nuclear ?rod Ncro-F'uel 303 5 70• .512 s (68,483) s 636,029 s $ 636,029
Regionol Trana & Mrl1S • l eK8S s 111.932. 527 (2,257,405) s 17,675,122 $ (1,701,371) 15,973,751
Elecit...,Ra1e 0 0000000000000 0 02073C191 2847 O.C297e732378
Locat Gres& Reretpls - Olher $ s (76,933) $ (76,933) $ 76,933 $
Stale Gross Margins ~ Tex as $ s $ s s
E tff!ctNe Rate 0 0
3 3,380,321 $ (5,227, 792) 28 ,132,529 (1.4 12,3n) 26. 720, 152
PUC As-!es3rnent ~ Toxos 1,526,789 $ 320,528 $ 1,8•7,3 17 (177.819) 1.669.•96
PUC Assess-mer( Cffed!Vti Rate 0 0.001667 0 .00311322488
P UC AsS&SSmer\I - 01'et s $ Q 10, 76~ G10763l 212 763
s 1,526,789 $ 109,765 1.636. 5 ~ 32,94• 1,669,498
TOTAL TAXES OTHER THAN 63.023.906 (2,533,159) 60,490,747 (2,953,747) 57,537,000
INCOME TAXES
Attachm ent A
SOAH OOCKl!T NO. AU SChedult V
PUC DOCKET NO. 39896 Federal Income Taxes
COM PANY NAME Ent ergy Texas. Inc.
TEST YEAR END 3ChJun·11
FEDERAL IN COME TA)(ES · METHOD I Requested ALJ
At Proposed Adjustments ALJ
Test Year To Company Adjusted
--~
Tot
= al~E.i.ctric Resueot Total Electric
(C) (d) (• )
Return Total $ 139,763.213
l.est
l"'ClfHl tnduded in Returr. kftK·• 57,075,778 •
Amoe< - ConsolCclusively to Entergy
Operating Companies other than ETI.
Entergy Services, Inc. and Entergy Operations, Inc.
2
2011 ETI Rate Case l-2
2
9. ETI requests that the Commission, the presiding officers, the State
Office of Administrative Hearings, the Commission Staff, and the parties serve all
papers (orders, discovery, motions, etc.) regarding this Application on Mr.
Neinast's office, as listed in the previous paragraph.
Ill. Proposed Tariffs
10. ETl's proposed revisions to its tariffs are provided in RFP Schedule
Q-8.8. ETl's complete Rate Filing Package is filed contemporaneous with this
Application.
IV. Summary of Filing
11 . The prefiled direct testimony of ETI witness Joseph F. Domino
explains the structure of this filing and introduces each of the witnesses. ETl's
•
filing addresses: (1) base rates and riders; (2) class cost allocation and rate
design; (3) rate case expenses; and (4) fuel and purchased power reconciliation.
A. Base rate revenue requirement and riders
12. This Application affects all of ETl's retail electric customers, and
each proposed change is reflected in the proposed revisions to the tariffs that are
provided in RFP Schedule Q-8.8. ETI has presented its revenue requirement
based on an adjusted twelve-month test year ending on June 30, 2011 . The
proposed base rates and riders produce an increase of approximately $111.8
million, or 8.09%, over adjusted test year revenues. Excluding fuel costs, the
proposed change produces an increase in revenues of approximately 15.32%.
Please see Attachment A for the details of how the revenue requirement affects
each rate class.
13. The Company's request includes two new riders for which the
Company seeks Commission approval in this case:
(a) A Purchased Power Recovery Rider ("'Rider PPR"), which is
designed to recover all existing purchased capacity costs as well as
future purchased capacity costs. As set in this case, Rider PPR will
4
201 I f.TI Rate Case 1-4
4
Company is also seeking to replenish its property insurance
reserve.
(b) ETI proposes a number of pro forma adjustments to its test
year results, as explained in the direct testimony of Company
witnesses.
(c) ETI is seeking to include in rate base capital additions closed
to plant in service from July 1, 2009 through the end of the test
year.
(d) In regard to affiliate transactions, ETI has divided its affiliate
payments into classes of service and is presenting testimony and
documentary evidence (e.g., discussion of budgeting and cost
control efforts, benchmarking results as available, review of the
costs of major components for each class, and headcount and
historical cost trends) for each class, demonstrating that the affiliate
transaction payments satisfy the standard for recovery set out in
PURA § 36.058. The prefiled direct testimony of ETI witness
Stephanie B. Tumminello explains how the evidence supporting
affiliate payments is organized.
•
18. To summarize, ETl's filing proposes that the Commission establish
the Company's revenue requirement as set out in the Rate Filing Package,
including a determination that the Company has satisfied PURA's standards for
recovery of affiliate costs. ETI further requests that the Commission approve its
proposed rate riders, and ETI seeks good cause exceptions to the extent
necessary to comply with the Commission's rules.
B. Class cost allocation and rate design
19. ETl's filing also addresses cost allocation and rate design. This
includes: (1) inter- and intra-class cost allocation, (2) rate design, and (3) the
tariff schedules in RFP Schedule Q-8.8. The Company is proposing revisions to
its tariffs and rate schedules, including making modifications to eleven schedules,
adding two new rate schedule riders, and discontinuing two riders. The
Company also proposes minor modifications to a number of rate schedules,
6
2011 ETJ Rare Case 1-6
6
23. The new rate schedules/riders are:
(a) Rider PPR
(b) Rider REC
24. In addition, the production costs associated with the Company's
CGS program will change as a result of this proceeding.
25. Consistent with the final order in ETl's last rate case, Application of
Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 37744, the life-of-contract demand ratchet provision in rate schedules
Large Industrial Power Service, Large Industrial Power Service-Time of Day,
General Service, General Service-Time of Day, Large General Service, and
Large General Service-Time of Day shall be excluded from those rate schedules.
C. Rate case expenses
26. ETl 's fifing also addresses rate case expenses. ETI is seeking to
•
recover its rate case expenses associated with this docket and any rate case
expenses associated with this docket that it must reimburse to local regulatory
authorities.
D. Fuel and purchased power reconciliation
27. Pursuant to P.U.C. Suesr. R. 25.236, ETI seeks reconciliation of its
fuel and purchased power costs and fuel factor revenues for the Reconciliation
Period. This Application will affect all of ETl'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 revenues received in providing service to
these customers during the Reconciliation Period.
28. During the Reconciliation Period, ETI incurred over $1 .3 billion in
retail eligible fuel and purchased power expenses to generate and purchase
electricity, net of certain revenues properly credited to such expenses and other
adjustments. The following tables summarize the calculation, by fuel type, of
ETl's total eligible fuel and purchased power costs to be reconciled in this
proceeding:
8
2011 ETI Rate Case 1-8
8
to Change Rates and Reconcile Fuel Costs. Docket No. 37744. Final Order at
FoF 30 (Dec. 13, 2010). ETI seeks the same treatment in this case because the
repayment is a residual amount of Rider IPCR costs , except that ETI proposes to
allocate the costs among customer classes on an energy basis in light of the
nominal amount.
31 . ETl's Rate Filing Package demonstrates that: (1) ETl's fuel and
purchased power expenses were reasonable and necessary expenses incurred
to provide reliable electric service; and (2) to the extent fuel and purchased
power expenses included an item or class of items supplied by an affiliate of ETI ,
the price charged by the affiliate satisfies the standard for recovery set out in
PURA § 36.058.
V. Notice
32. ETI will provide notice in accordance with PURA§ 36.103, P.U.C.
PROC. R. 22.51(a), and P.U.C. Suasr. R. 25.235. The proposed notice is
provided as Attachment B to this Application.
VI. Municlpal Filings
33. Simultaneously with filing this Application with the Commission, ETI
is filing a Statement of Intent to change its rates with all local regulatory
authorities that retain jurisdiction over ETl's rates to the extent consistent with the
provisions of PURA. Depending on the actions taken by the local regulato,Y
authorities. ETI may appeal the municipal rate ordinances to the Commission
and request that the Commission consolidate those appeals with this docket and,
if necessary, set the rates that the local regulatory authorities should have set,
pursuant to PURA§ 33.054.
VII. Request for Waiver of Rate Filing Package Requirements
34. For the reasons stated in RFP Schedule V, ETI requests that the
Commission waive certain Rate Filing Package filing requirements.
10
!0 11 El'l Rare Case 1·1 0
10
..
Respectfully submitted,
Steven H. Neinast
Paula Cyr
Assistants General Counsel
ENTERGY SERVICES, INC.
919 Congress Avenue, Suite 701
Austin, Texas 78701
(512) 487·3957 telephone
(512) 487·3958 facsimile
DUGGINS WREN MANN & ROMERO, LLP
One American Center
600 Congress, Suite 1900
P.O. Box 1149
Austin, Texas 78767-1149
(512) 744-9300 telephone
(512) 744-9399 facsimile
John F. Williams
Jay Breedveld
12
2011 F:TI Rate Cast? l - 12
12
APPENDIX E
Rules
16 Tex. Admin. Code § 25.235
16 TAC § 25.235 Page 1
Tex. Admin. Code tit. 16, § 25.235
Texas Administrative Code Currentness
Title 16. Economic Regulation
Part 2. Public Utility Commission of Texas
Chapter 25. Substantive Rules Applicable to Electric Service Providers
Subchapter J. Costs, Rates and Tariffs
Division 1. Retail Rates
§ 25.235. Fuel Costs--General
(a) Purpose. The commission will set an electric utility's rates at a level that will permit the
electric utility a reasonable opportunity to earn a reasonable return on its invested capital and
to recover its reasonable and necessary expenses, including the cost of fuel and purchased
power. The commission recognizes in this connection that it is in the interests of both electric
utilities and their ratepayers to adjust charges in a timely manner to account for changes in
certain fuel and purchased-power costs. Pursuant to the Public Utility Regulatory Act (PURA)
§ 36.203 this section establishes a procedure for setting and revising fuel factors and a proced-
ure for regularly reviewing the reasonableness of the fuel expenses recovered through fuel
factors.
(b) Notice of fuel proceedings. In addition to the notice required by the Administrative Pro-
cedure Act (APA) to be given by the commission, the electric utility is required to give notice
of a fuel proceeding at the time the petition is filed.
(1) Method of notice. Notice of fuel proceedings will be given by the electric utility as fol-
lows:
(A) Notice in all proceedings involving refunds, surcharges, or a proposal to change
the fuel factor, shall be by one-time publication in a newspaper having general circula-
tion in each county of the service area of the electric utility or by individual notice to
each customer and by individual notice to parties that participated in the electric util-
ity's prior fuel reconciliation proceeding;
(B) Notice in all reconciliation proceedings shall be by publication once each week for
two consecutive weeks in a newspaper having general circulation in each county of the
service area of the electric utility and by individual notice to each customer and to
parties that participated in the electric utility's prior fuel reconciliation proceeding.
(2) Contents of notice.
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.235 Page 2
Tex. Admin. Code tit. 16, § 25.235
(A) All notices required by this section shall provide the following information:
(i) the date the petition was filed;
(ii) a general description of the customers, customer classes, and territories affected
by the petition;
(iii) the relief requested;
(iv) the statement, “Persons with questions or who want more information on this
petition may contact (utility name) at (utility address) or call (utility toll-free tele-
phone number) during normal business hours. A complete copy of this petition is
available for inspection at the address listed above”; and
(v) the statement, “Persons who wish to formally participate in this proceeding, or
who wish to express their comments concerning this petition should contact the
Public Utility Commission of Texas, Office of Customer Protection, P.O. Box
13326, Austin, Texas 78711-3326, or call (512) 936-7120 or toll-free at (888)
782-8477. Hearing and speech-impaired individuals with text telephones (TTY)
may call (512) 936-7136 or use Relay Texas (toll-free) 1-800-735-2989.”
(B) Notices to revise fuel factors must also state the proposed fuel factors by type of
voltage and the period for which the proposed fuel factors are expected to be in effect.
(C) Notices to revise fuel factors, to refund, or to surcharge must contain the statement
that, “these changes will be subject to final review by the commission in the electric
utility's next reconciliation,” unless, in the case of refunds or surcharges, the change is
a result of a reconciliation proceeding.
(D) Notices to reconcile fuel expenses must also state the period for which final recon-
ciliation is sought.
(3) Proof of notice may be demonstrated by appropriate affidavit. In fuel proceedings initi-
ated by a person other than an electric utility, the notice required in this subsection must
be provided in accordance with a schedule ordered by the presiding officer.
(c) Reports; confidentiality of information. Matters related to submitting reports and confiden-
tial information will be handled as follows:
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.235 Page 3
Tex. Admin. Code tit. 16, § 25.235
(1) The commission will monitor each electric utility's actual and projected fuel-related
costs and revenues on a monthly basis. Each electric utility shall maintain and provide to
the commission, in a format specified by the commission, monthly reports containing all
information required to monitor monthly fuel-related costs and revenues, including gener-
ation mix, fuel consumption, fuel costs, purchased power quantities and costs, and system
and off-system sales revenues.
(2) Contracts for the purchase of fuel, fuel storage, fuel transportation, fuel processing, or
power are discoverable in fuel proceedings, subject to appropriate confidentiality agree-
ments or protective orders.
(3) The electric utility shall prepare a confidentiality disclosure agreement to be included
as part of the fuel reconciliation petition. The format for the agreement shall be the same
as that contained in the commission approved rate filing package. In addition to the agree-
ment itself, Attachment 1 of the agreement shall present a complete listing of the informa-
tion required to be filed which the electric utility alleges is confidential. Upon request and
execution of the confidentiality agreement, the electric utility shall provide any informa-
tion which it alleges is confidential. If the electric utility fails to file a confidentiality
agreement, the deadline for a commission final order in the case is tolled until a protective
order is entered or a confidentiality agreement is filed. Use of the confidentiality disclos-
ure agreement does not constitute a finding that any information is proprietary and/or con-
fidential under law, or alter the burden of proof on that issue. The form of agreement con-
tained in the commission approved rate filing package does not bind the examiner or the
commission to accept the language of the agreement in the consideration of any sub-
sequent protective order that may be entered.
(4) A party that cannot view a confidential document without receiving advantage as a
competitor or bidder may hire outside counsel and consultants to view the document sub-
ject to a protective order.
Source: The provisions of this § 25.235 adopted to be effective July 5, 1999, 24 TexReg
4998.
16 TAC § 25.235, 16 TX ADC § 25.235
Current through 40 Tex.Reg. No. 866, dated February 20, 2015, as effective on or before Feb-
ruary 27, 2015
Copr. (C) 2015. All rights reserved.
END OF DOCUMENT
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
APPENDIX F
Rules
16 Tex. Admin. Code § 25.236
16 TAC § 25.236 Page 1
Tex. Admin. Code tit. 16, § 25.236
Texas Administrative Code Currentness
Title 16. Economic Regulation
Part 2. Public Utility Commission of Texas
Chapter 25. Substantive Rules Applicable to Electric Service Providers
Subchapter J. Costs, Rates and Tariffs
Division 1. Retail Rates
§ 25.236. Recovery of Fuel Costs
(a) Eligible fuel expenses. Eligible fuel expenses include expenses properly recorded in the
Federal Energy Regulatory Commission Uniform System of Accounts, numbers 501, 502,
503, 509, 518, 536, 547, and 555, as modified in this subsection, as of April 1, 2013, and the
items specified in paragraph (8) of this subsection. Any later amendments to the System of
Accounts are not incorporated into this subsection. Subject to the commission finding special
circumstances under paragraph (7) of this subsection, eligible fuel expenses are limited to:
(1) For any account, the electric utility may not recover, as part of eligible fuel expense,
costs incurred after fuel is delivered to the generating plant site, for example, but not lim-
ited to, operation and maintenance expenses at generating plants, costs of maintaining and
storing inventories of fuel at the generating plant site, unloading and fuel handling costs at
the generating plant, and expenses associated with the disposal of fuel combustion resid-
uals. Further, the electric utility may not recover maintenance expenses and taxes on rail
cars owned or leased by the electric utility, regardless of whether the expenses and taxes
are incurred or charged before or after the fuel is delivered to the generating plant site. The
electric utility may not recover an equity return or profit for an affiliate of the electric util-
ity, regardless of whether the affiliate incurs or charges the equity return or profit before
or after the fuel is delivered to the generating plant site. In addition, all affiliate payments
must satisfy the Public Utility Regulatory Act (PURA) § 36.058.
(2) For Accounts 501 and 547, the only eligible fuel expenses are the delivered cost of fuel
to the generating plant site excluding fuel brokerage fees. For Account 501, revenues asso-
ciated with the disposal of fuel combustion residuals will also be excluded.
(3) For Account 502, the only eligible fuel expenses are environmental consumables that
are: properly recorded in the Account as chemicals; required to comply with applicable
state or federal emission reduction statutes, orders, and regulations; and whose use is dir-
ectly proportional to the fuel consumed to generate electricity.
(4) For Account 509, the only eligible fuel expenses are allowances expensed concurrent
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.236 Page 2
Tex. Admin. Code tit. 16, § 25.236
with the monthly emissions of sulfur dioxide and nitrogen oxides.
(5) For Accounts 518 and 536, the only eligible fuel expenses are the expenses properly
recorded in the Account excluding brokerage fees. For Account 503, the only eligible fuel
expenses are the expenses properly recorded in the Account, excluding brokerage fees, re-
turn, non-fuel operation and maintenance expenses, depreciation costs and taxes.
(6) For Account 555, the electric utility may not recover demand or capacity costs.
(7) Upon demonstration that such treatment is justified by special circumstances, an elec-
tric utility may recover as eligible fuel expenses fuel or fuel related expenses otherwise ex-
cluded in paragraphs (1)-(6) of this subsection. In determining whether special circum-
stances exist, the commission shall consider, in addition to other factors developed in the
record of the reconciliation proceeding, whether the fuel expense or transaction giving rise
to the ineligible fuel expense resulted in, or is reasonably expected to result in, increased
reliability of supply or lower fuel expenses than would otherwise be the case, and that
such benefits received or expected to be received by ratepayers exceed the costs that rate-
payers otherwise would have paid or otherwise would reasonably expect to pay.
(8) Eligible fuel expenses shall not be offset by revenues by affiliated companies for the
purpose of equalizing or balancing the financial responsibility of differing levels of invest-
ment and operation costs associated with transmission assets. In addition to the expenses
designated in paragraphs (1)-(7) of this subsection, unless otherwise specified by the com-
mission, eligible fuel expenses shall be offset by:
(A) revenues from steam sales included in Accounts 504 and 456 to the extent ex-
penses incurred to produce that steam are included in Account 503;
(B) revenues from off-system sales in their entirety, except as permitted in paragraph
(9) of this subsection; and
(C) revenues from disposition of allowances properly recorded in Account 411.8.
(9) Shared margins from off-system sales. An electric utility may retain 10% of the mar-
gins from an off-system energy sales transaction if the following criteria are met:
(A) the electric utility participates in a transmission region governed by an independent
system operator or a functionally equivalent independent organization;
(B) a generally-applicable tariff for firm and non-firm transmission service is offered
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.236 Page 3
Tex. Admin. Code tit. 16, § 25.236
in the transmission region in which the electric utility operates; and
(C) the transaction is not found to be to the detriment of its retail customers.
(b) Reconciliation of fuel expenses. Electric utilities shall file petitions for reconciliation on a
periodic basis so that any petition for reconciliation shall contain a maximum of three years
and a minimum of one year of reconcilable data and will be filed no later than six months after
the end of the period to be reconciled.
(c) Petitions to reconcile fuel expenses. In addition to the commission prescribed reconcili-
ation application, a fuel reconciliation petition filed by an electric utility must be accompanied
by a summary and supporting testimony that includes the following information:
(1) a summary of significant, atypical events that occurred during the reconciliation period
that affected the economic dispatch of the electric utility's generating units, including but
not limited to transmission line constraints, fuel use or deliverability constraints, unit oper-
ational constraints, and system reliability constraints;
(2) a general description of typical constraints that limit the economic dispatch of the elec-
tric utility's generating units, including but not limited to transmission line constraints, fuel
use or deliverability constraints, unit operational constraints, and system reliability con-
straints;
(3) the reasonableness and necessity of the electric utility's eligible fuel expenses and its
mix of fuel used during the reconciliation period;
(4) a summary table that lists all the fuel cost elements which are covered in the electric
utility's fuel cost recovery request, the dollars associated with each item, and where to find
the item in the prefiled testimony;
(5) tables and graphs which show generation (MWh), capacity factor, fuel cost (cents per
kWh and cents per MMBtu), variable cost and heat rate by plant and fuel type, on a
monthly basis; and
(6) a summary and narrative of the next-day and intra-day surveys of the electricity mar-
kets and a comparison of those surveys to the electric utility's marginal generating costs.
(d) Fuel reconciliation proceedings. Burden of proof and scope of proceeding are as follows:
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.236 Page 4
Tex. Admin. Code tit. 16, § 25.236
(1) 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 ne-
cessary expenses incurred to provide reliable electric service to retail customers;
(B) if its eligible fuel expenses for the reconciliation period included an item or class
of items supplied by an affiliate of the electric utility, the prices charged by the supply-
ing affiliate to the electric utility were reasonable and necessary and no higher than the
prices charged by the supplying affiliate to its other affiliates or divisions or to unaf-
filiated persons or corporations for the same item or class of items; and
(C) it has properly accounted for the amount of fuel-related revenues collected pursu-
ant to the fuel factor during the reconciliation period.
(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.
(e) Refunds. All fuel refunds and surcharges shall be made using the following methods.
(1) Interest shall be calculated on the cumulative monthly ending under- or over-recovery
balance at the rate established annually by the commission for overbilling and underbilling
in § 25.28(c) and (d) of this title (relating to Bill Payment and Adjustments). Interest shall
be calculated based on principles set out in subparagraphs (A)-(E) of this paragraph.
(A) Interest shall be compounded annually by using an effective monthly interest
factor.
(B) The effective monthly interest factor shall be determined by using the algebraic
calculation x = (1 + i) (1/12)-1; where i = commission-approved annual interest rate,
and x = effective monthly interest factor.
(C) Interest shall accrue monthly. The monthly interest amount shall be calculated by
applying the effective monthly interest factor to the previous month's ending cumulat-
ive under/over recovery fuel and interest balance.
(D) The monthly interest amount shall be added to the cumulative principal and in-
terest under/over recovery balance.
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.236 Page 5
Tex. Admin. Code tit. 16, § 25.236
(E) Interest shall be calculated through the end of the month of the refund or surcharge.
(2) Rate class as used in this subparagraph shall mean all customers taking service under
the same tariffed rate schedule, or a group of seasonal agricultural customers as identified
by the electric utility.
(3) Interclass allocations of refunds and surcharges, including associated interest, shall be
developed on a month-by-month basis and shall be based on the historical kilowatt-hour
usage of each rate class for each month during the period in which the cumulative under-
or over-recovery occurred, adjusted for line losses using the same commission-approved
loss factors that were used in the electric utility's applicable fixed or interim fuel factor.
(4) Intraclass allocations of refunds and surcharges shall depend on the voltage level at
which the customer receives service from the electric utility. Retail customers who receive
service at transmission voltage levels, all wholesale customers, and any groups of seasonal
agricultural customers as identified by the electric utility shall be given refunds or as-
sessed surcharges based on their individual actual historical usage recorded during each
month of the period in which the cumulative under- or over-recovery occurred, adjusted
for line losses if necessary. All other customers shall be given refunds or assessed sur-
charges based on the historical kilowatt-hour usage of their rate class.
(5) Unless otherwise ordered by the commission, all refunds shall be made through a one-
time bill credit and all surcharges shall be made on a monthly basis over a period not to
exceed 12 months through a bill charge. However, refunds may be made by check to mu-
nicipally-owned electric utility systems if so requested. Retail customers who receive ser-
vice at transmission voltage levels, all wholesale customers, and any groups of seasonal
agricultural customers as identified by the electric utility shall be given a one-time credit
or assessed a surcharge made on a monthly basis over a period not to exceed 12 months
through a bill charge. All other customers shall be given a credit or assessed a surcharge
based on a factor which will be applied to their kilowatt-hour usage over the refund or sur-
charge period. This factor will be determined by dividing the amount of refund or sur-
charge allocated to each rate class by forecasted kilowatt-hour usage for the class during
the period in which the refund or surcharge will be made.
(6) A petition to surcharge or refund a fuel under- or over-recovery balance not associated
with a proceeding under subsection (d) of this section shall be processed in accordance
with the filing schedules in § 25.237(d) of this title (relating to Fuel factors) and the dead-
lines in § 25.237(e) of this title.
(f) Procedural schedule. Upon the filing of a petition to reconcile fuel expenses in a separate
proceeding, the presiding officer shall set a procedural schedule that will enable the commis-
sion to issue a final order in the proceeding within one year after a materially complete peti-
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.236 Page 6
Tex. Admin. Code tit. 16, § 25.236
tion was filed. However, if the deadlines result in a number of electric utilities filing cases
within 45 days of each other, the presiding officers shall schedule the cases in a manner to al-
low the commission to accommodate the workload of the cases irrespective of whether such
procedural schedule enables the commission to issue a final order in each of the cases within
one year after a materially complete petition is filed.
Source: The provisions of this §25.236 adopted to be effective July 5, 1999, 24 TexReg 4998;
amended to be effective September 30, 1999, 24 TexReg 8162; amended to be effective May
16, 2001, 26 TexReg 3486; amended to be effective June 10, 2014, 39 TexReg 4421.
16 TAC § 25.236, 16 TX ADC § 25.236
Current through 40 Tex.Reg. No. 866, dated February 20, 2015, as effective on or before Feb-
ruary 27, 2015
Copr. (C) 2015. All rights reserved.
END OF DOCUMENT
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
APPENDIX G
Rules
16 Tex. Admin. Code § 25.237
16 TAC § 25.237 Page 1
Tex. Admin. Code tit. 16, § 25.237
Texas Administrative Code Currentness
Title 16. Economic Regulation
Part 2. Public Utility Commission of Texas
Chapter 25. Substantive Rules Applicable to Electric Service Providers
Subchapter J. Costs, Rates and Tariffs
Division 1. Retail Rates
§ 25.237. Fuel Factors
(a) Use and calculation of fuel factors. An electric utility's fuel costs will be recovered from
the electric utility's customers by the use of a fuel factor that will be charged for each kilo-
watt-hour (kWh) consumed by the customer.
(1) An electric utility may determine its fuel factor in dollars per kilowatt-hour pursuant to
either subparagraph (A) or (B) of this paragraph. Fuel factors must account for system
losses and for the difference in line losses corresponding to the voltage at which the elec-
tric service is provided. An electric utility may have different fuel factors for different
times of the year to account for seasonal variations. A different method of calculation may
be allowed upon a showing of good cause by the electric utility.
(A) Fuel factors may be determined by dividing the electric utility's projected net eli-
gible fuel expenses, as defined in § 25.236(a) of this title (relating to Recovery of Fuel
Costs), by the corresponding projected kilowatt-hour sales for the period in which the
fuel factors are expected to be in effect.
(B) Fuel factors may be determined using a commission-approved, utility-specific fuel
factor formula. Fuel factor formulas may be approved or revised only in a general rate
change proceeding or a proceeding to consider an application to establish a fuel factor
formula with notice and an opportunity for a hearing.
(2) An electric utility may initiate a change to its fuel factor as follows:
(A) Pursuant to subsection (a)(1)(A) of this section, an electric utility may petition to
adjust its fuel factor as often as once every four months according to the schedule set
out in subsection (d) of this section.
(B) Pursuant to subsection (a)(1)(B) of this section, an electric utility may petition to
adjust its fuel factor in accordance with its approved fuel factor formula no sooner than
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.237 Page 2
Tex. Admin. Code tit. 16, § 25.237
four months after the filing of its most recent fuel factor adjustment petition.
(C) Notwithstanding subsection (a)(2)(A) of this section, an electric utility may peti-
tion to change its fuel factor at times other than provided in the schedule if an emer-
gency exists as described in subsection (f) of this section.
(D) An electric utility's fuel factor may be changed in any general rate proceeding.
(3) Fuel factors are temporary rates, and the electric utility's collection of revenues by fuel
factors is subject to the following adjustments:
(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 re-
flected in the calculation of the utility's recoverable fuel and over/(under) collections.
(B) To the extent that there are variations between the fuel costs incurred and the rev-
enues collected, it may be necessary or convenient to refund overcollections or sur-
charge undercollections. Refunds or surcharges may be made without changing an
electric utility's fuel factor. Nothwithstanding § 25.236(e)(6) of this title, an electric
utility may petition for a surcharge any time it has materially undercollected its fuel
costs and projects that it will continue to be in a state of material undercollection.
Nothwithstanding § 25.236(e)(6) of this title, an electric utility shall petition to make a
refund any time it has materially overcollected its fuel costs and projects that it will
continue to be in a state of material overcollection. “Materially” or “material,” as used
in this section, shall mean that the cumulative amount of over- or under-recovery, in-
cluding interest, is greater than or equal to 4.0% of the annual actual fuel cost figures
on a rolling 12-month basis, as reflected in the utility's monthly fuel cost reports as
filed by the utility with the commission.
(b) Petitions to revise fuel factors.
(1) An electric utility using the fuel factor methodology set forth under subsection
(a)(1)(A) of this section may file a petition requesting revised fuel factors pursuant to sub-
section (a)(2)(A) of this section during the first five business days of the months specified
in subsection (d) of this section. A copy of the complete petition package shall be served
on each party in the utility's most recent fuel reconciliation and on the Office of Public
Utility Counsel. Service shall be accomplished by email if possible. Each complete filing
package shall include the commission-prescribed fuel factor application, a tariff sheet re-
flecting the proposed fuel factors and supporting testimony that includes the following in-
formation:
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.237 Page 3
Tex. Admin. Code tit. 16, § 25.237
(A) For each month of the period in which the fuel-factor has been in effect and has
not been reconciled up to the most recent month for which information is available,
(i) the revenues collected pursuant to fuel factors by customer class;
(ii) any other items that to the knowledge of the electric utility have affected fuel
factor revenues and eligible fuel expenses; and
(iii) the difference, by customer class, between the revenues collected pursuant to
fuel factors and the eligible fuel expenses incurred.
(B) For each month of the period for which the revised fuel factors are expected to be
in effect, provide system energy input and sales, accompanied by the calculations un-
derlying any differentiation of fuel factors to account for differences in line losses cor-
responding to the voltage at which the electric service is provided.
(2) An electric utility using the fuel factor formula methodology set forth under subsection
(a)(1)(B) of this section may file a petition requesting revised fuel factors pursuant to sub-
section (a)(2)(B) of this section at least 15 days prior to the first billing cycle in the billing
month in which the proposed fuel factors are requested to become effective. A copy of the
complete petition package shall be served on each party in the utility's most recent fuel re-
conciliation and on the Office of Public Utility Counsel. Service shall be accomplished by
email if possible. Each complete filing package shall include:
(A) a tariff sheet reflecting the proposed fuel factors;
(B) workpapers supporting the calculation of the revised fuel factors;
(C) calculations underlying any differentiation of fuel factors to account for differ-
ences in line losses corresponding to the voltage at which the electric service is
provided; and
(D) any computer generated documents must be provided in their native electronic
format with all cells and internal formulas disclosed.
(c) Fuel factor revision proceeding. Burden of proof and scope of proceeding are as follows:
(1) In a proceeding to revise fuel factors pursuant to subsection (a)(1)(A) of this section,
an electric utility has the burden of proving that:
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.237 Page 4
Tex. Admin. Code tit. 16, § 25.237
(A) the expenses proposed to be recovered through the fuel factors are reasonable es-
timates of the electric utility's eligible fuel expenses during the period that the fuel
factors are expected to be in effect;
(B) the electric utility's estimated monthly kilowatt-hour system sales and off-system
sales are reasonable estimates for the period that the fuel factors are expected to be in
effect; and
(C) the proposed fuel factors are reasonably differentiated to account for line losses
corresponding to the voltage at which the electric service is provided.
(2) The scope of a fuel factor revision proceeding under subsection (a)(1)(B) of this sec-
tion is limited to the issue of whether the petitioning electric utility has appropriately cal-
culated its proposed fuel factors. In a proceeding to revise fuel factors pursuant to subsec-
tion (a)(1)(B) of this section, an electric utility has the burden of proving that:
(A) the electric utility has calculated its proposed fuel factors in compliance with the
commission-approved fuel factor formula; and
(B) 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.
(d) Schedule for filing petitions to revise fuel factors. A petition to revise fuel factors or to ini-
tiate or revise a fuel factor formula may be filed with any general rate proceeding.
(1) Otherwise, except as provided by subsection (f) of this section which addresses emer-
gencies, petitions by an electric utility to revise fuel factors pursuant to subsection
(a)(1)(A) of this section may only be filed in accordance with the following schedule:
(A) February, June and October: El Paso Electric Company;
(B) March, July and November: Entergy Texas, Inc.;
(C) April, August and December: Southwestern Public Service Company;
(D) May, September and January: Southwestern Electric Power Company; and
(E) March, July and November: any other electric utility not named in this subsection
that uses one or more fuel factors.
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.237 Page 5
Tex. Admin. Code tit. 16, § 25.237
(2) Petitions by an electric utility to revise fuel factors pursuant to subsection (a)(1)(B) of
this section may be filed in any month except December.
(e) Procedural schedules.
(1) Upon the filing of a petition to revise fuel factors pursuant to subsection (a)(1)(A) of
this section, the presiding officer shall set a procedural schedule that will enable the com-
mission to issue a final order in the proceeding as follows:
(A) within 60 days after the petition was filed, if no hearing is requested within 30
days of the petition; and
(B) within 90 days after the petition was filed, if a hearing is requested within 30 days
of the petition. If a hearing is requested, the hearing will be held no earlier than the
first business day after the 45th day after the application was filed.
(2) Upon the filing of a petition to revise fuel factors pursuant to subsection (a)(1)(B) of
this section, the presiding officer shall set a procedural schedule as follows:
(A) the presiding officer shall issue an order approving the proposed fuel factors on an
interim basis no later than 12 days after the date the petition was filed, if no objection
to interim approval is filed within 10 days after the date the petition was filed;
(B) if no hearing is requested within 30 days after the petition was filed, the presiding
officer shall, after submission of proof of notice by the electric utility, issue an order
approving the fuel factors without hearing or action by the commission; and
(C) if a hearing is requested within 30 days after the petition was filed, the hearing will
be held no earlier than the first business day after the 45th day after the petition was
filed and a final order will be issued within 90 days after the petition was filed, subject
to submission of proof of notice by the electric utility.
(f) Emergency revisions to the fuel factor. If fuel curtailments, equipment failure, strikes, em-
bargoes, sanctions, or other reasonably unforeseeable circumstances have caused a material
under-recovery of eligible fuel costs, the electric utility may file a petition with the commis-
sion requesting an emergency interim fuel factor. Such emergency requests shall state the
nature of the emergency, the magnitude of change in fuel costs resulting from the emergency
circumstances, and other information required to support the emergency interim fuel factor.
The commission shall issue an interim order within 30 days after such petition is filed to es-
tablish an interim emergency fuel factor. If within 120 days after implementation, the emer-
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
16 TAC § 25.237 Page 6
Tex. Admin. Code tit. 16, § 25.237
gency interim factor is found by the commission to have been excessive, the electric utility
shall refund all excessive collections with interest calculated on the cumulative monthly end-
ing under- or overrecovery balance in the manner and at the rate established by the commis-
sion for overbilling and underbilling in § 25.28(c) and (d) of this title (relating to Bill Payment
and Adjustments Billing). If, after full investigation, the commission determines that no emer-
gency condition existed, a penalty of up to 10% of such over-collections may also be imposed
on investor-owned electric utilities.
Source: The provisions of this § 25.237 adopted to be effective July 5, 1999, 24 TexReg
4998; amended to be effective December 30, 1999, 24 TexReg 11727; amended to be effect-
ive September 4, 2008, 33 TexReg 7155.
16 TAC § 25.237, 16 TX ADC § 25.237
Current through 40 Tex.Reg. No. 866, dated February 20, 2015, as effective on or before Feb-
ruary 27, 2015
Copr. (C) 2015. All rights reserved.
END OF DOCUMENT
© 2015 Thomson Reuters. No Claim to Orig. US Gov. Works.
Entergy Texas, Inc.// Office of Public Utility Counsel and Public Utility Commission of Texas v. Public Utility Commission of Texas and Texas Industrial Energy Consumers// Office of Public Utility Counsel and Entergy Texas, Inc.
Combined Opinion