ACCEPTED
03-14-00735-CV
5109682
THIRD COURT OF APPEALS
AUSTIN, TEXAS
4/30/2015 5:15:27 PM
JEFFREY D. KYLE
CLERK
NO. 03-14-00735-CV
FILED IN
IN THE COURT OF APPEALS 3rd COURT OF APPEALS
AUSTIN, TEXAS
FOR THE THIRD DISTRICT OF TEXAS4/30/2015 5:15:27 PM
AUSTIN, TEXAS JEFFREY D. KYLE
Clerk
ENTERGY TEXAS, INC.
Appellants,
v.
PUBLIC UTILITY COMMISSION OF TEXAS
Appellee.
Appeal from the 353rd Judicial District Court, Travis County, Texas
The Honorable John K. Dietz, Judge Presiding
APPELLEE TEXAS INDUSTRIAL ENERGY CONSUMERS’ BRIEF
APRIL 30, 2015
Rex D. VanMiddlesworth
rex.vanmiddlesworth@tklaw.com
State Bar No. 20449400
Benjamin Hallmark
benjamin.hallmark@tklaw.com
State Bar No. 24069865
THOMPSON & KNIGHT LLP
98 San Jacinto Blvd., Suite 1900
Austin, TX 78701
Telephone: (512) 469-6100
Facsimile: (512) 469-6180
ATTORNEYS FOR APPELLEE TEXAS
INDUSTRIAL ENERGY CONSUMERS
ORAL ARGUMENT REQUESTED
TABLE OF CONTENTS
PAGE
TABLE OF AUTHORITIES .............................................................................................. iii
STATEMENT OF THE CASE .......................................................................................... iv
STATEMENT ON ORAL ARGUMENT ........................................................................... v
RESTATED ISSUES PRESENTED ................................................................................... v
STATEMENT OF FACTS .................................................................................................. 1
SUMMARY OF ARGUMENT ........................................................................................... 6
ARGUMENT AND AUTHORITIES ................................................................................. 9
I. The PUC properly applied its longstanding historical-test-year
standard. ........................................................................................................ 9
A. The known and measurable standard. .............................................. 11
B. ETI’s true complaint is with the PUC’s cost-of-service rules,
not the PUC’s application of them. .................................................. 14
II. Substantial evidence supports the PUC’s determination of ETI’s
purchased-capacity costs. ............................................................................ 15
A. The PUC properly found that ETI’s forecasted purchased-
capacity costs were not known and measurable. .............................. 16
1. ETI’s projected third-party contract costs were not reasonably
certain. ................................................................................... 20
2. ETI’s projected affiliate-contract costs were not reasonably
certain. ................................................................................... 25
3. ETI’s projected MSS-1 costs were not reasonably certain. .. 28
4. ETI’s proposal failed to account for revenues from load
growth. .................................................................................. 30
B. Having failed to meet its burden of proof, ETI is not entitled
to its proposed post-test-year adjustments. ...................................... 34
i
III. The PUC properly rejected ETI’s proposal to base transmission
equalization expense on projections of future costs. ................................... 36
A. Substantial evidence supports the PUC’s decision. ......................... 38
1. ETI’s transmission-equalization costs are variable and
uncertain. ............................................................................... 39
2. ETI’s projections were based on projects that were not yet in-
service. .................................................................................. 40
CONCLUSION AND PRAYER ....................................................................................... 42
CERTIFICATE OF COMPLIANCE ................................................................................ 43
CERTIFICATE OF SERVICE .......................................................................................... 44
ii
TABLE OF AUTHORITIES
PAGE
CASES
Amarillo Indep. Sch. Dist. v. Meno,
854 S.W.2d 950 (Tex. App.—Austin 1993, writ denied) ...................................16
Cent. Power & Light Co. v. Pub. Util. Comm’n of Texas,
36 S.W.3d 547 (Tex. App.—Austin 2001, pet. denied).............................. passim
City of El Paso v. Pub. Util. Comm’n of Texas,
883 S.W.2d 179 (Tex. 1994) ....................................................................... passim
City of El Paso v. Pub. Util. Comm’n,
344 S.W.3d 609 (Tex. App.—Austin 2011, no pet.) ............................................2
Gerst v. Guardian Sav. & Loan Ass’n,
434 S.W.2d 113 (Tex. 1968) ...............................................................................16
Lewis v. Metropolitan Sav. & Loan Ass’n,
550 S.W.2d 11 (Tex. 1977) .................................................................................16
Suburban Util. Corp. v. Pub. Util. Comm’n of Texas,
652 S.W.2d 358 (Tex. 1983) .................................................................... 2, 10, 12
Rodriguez v. Serv. Lloyds Ins. Co.,
997 S.W.2d 248 (Tex. 1999) ...............................................................................16
Texas Health Facilities Comm’n v. Charter Medical-Dallas, Inc.,
665 S.W.2d 446 (Tex. 1984) ...............................................................................16
STATUTORY AND REGULATORY AUTHORITIES
16 Tex. Admin. Code § 23.21...................................................................................13
16 Tex. Admin. Code § 25.5......................................................................................3
16 Tex. Admin. Code § 25.231 ....................................................................... passim
16 Tex. Admin. Code § 25.234.................................................................................13
iii
Tex. Util. Code §§ 11.001 .........................................................................................1
Tex. Util. Code § 11.003...........................................................................................10
Tex. Util. Code § 15.001 .........................................................................................16
Tex. Util. Code § 31.001 ...........................................................................................1
Tex. Util. Code § 36.003 ...........................................................................................1
Tex. Util. Code § 36.006. ................................................................................. 35, 36
Tex. Util. Code § 36.051. ..........................................................................................2
iv
STATEMENT OF THE CASE
This is an administrative appeal of a final order of the Public Utility
Commission of Texas (the PUC) in a contested-case proceeding. Entergy Texas,
Inc. (ETI) initiated the underlying proceeding, Docket No. 39896, seeking
authority to raise its electric rates and reconcile its fuel costs.
STATEMENT ON ORAL ARGUMENT
To the extent the Court grants any request for oral argument, TIEC requests
the opportunity to be heard.
RESTATED ISSUES PRESENTED
(1) Should the Court invalidate the PUC’s longstanding, rule-based
practice of setting future rates based on historical costs?
(2) Does substantial evidence support the PUC’s determination that ETI’s
projections of its future purchased-capacity costs were not known and measurable
changes to its historical-test-year costs?
(3) Does substantial evidence support the PUC’s determination that ETI’s
projections of its future transmission-equalization expense were not known and
measurable changes to its historical-test-year costs?
v
STATEMENT OF FACTS
Appellee Texas Industrial Energy Consumers (TIEC) is an association of
industrial consumers whose principal purpose is to address electricity matters at the
PUC. 1 TIEC, an intervenor in the underlying administrative proceeding, files this
brief in support of the PUC’s determination of ETI’s purchased-capacity and
transmission-equalization expenses.2
Regulatory background
Because ETI is a government-sanctioned monopoly in its service area, the
PUC regulates its rates, operations, and services as a substitute for competition. 3
As part of that system of regulation, the Public Utility Regulatory Act (PURA) 4
directs the PUC to ensure that utility rates are “just and reasonable.” 5 PURA does
not define “just and reasonable” rates, but provides that the PUC “shall establish
the utility’s overall revenues at an amount that will permit the utility a reasonable
opportunity to earn a reasonable return on the utility’s invested capital used and
useful in providing service to the public in excess of the utility’s reasonable and
1
AR Part I, Binder 1, Item 1 (Motion to Intervene of Texas Industrial Energy Consumers).
References to the administrative record are to the revised index submitted with the supplemental
administrative record on March 25, 2015. The administrative record (AR) is organized by
binders, exhibits, and transcripts.
2
TIEC thus responds to ETI’s second and third issues on appeal. See ETI Appellant’s Brief at x-
xi.
3
AR Part II, Binder 31, ETI Ex. 4 (Domino Direct at 1). Tex. Util. Code § 31.001(b).
4
PURA is codified at Tex. Util. Code §§ 11.001 et seq.
5
PURA § 36.003(a).
1
necessary operating revenues.” 6 In Texas, “future rates are made on the basis of
past costs,” and the PUC has long relied on a utility’s historical costs to meet the
objective of setting just and reasonable rates. 7 Thus, to calculate a utility’s revenue
requirement, the PUC’s rules provide that “rates are to be based upon an electric
utility’s cost of rendering service to the public during a historical test year,
adjusted for known and measurable changes.” 8
The PUC proceeding
ETI initiated the underlying proceeding at the PUC seeking authority to raise
its rates.9 One of the major issues in the case was the amount of purchased-
capacity costs to be included in ETI’s base rates. A utility’s purchased-capacity
costs are expenses recovered through base rates. 10 The record evidence established
that ETI had incurred approximately $246 million in purchased-capacity costs
during the historical test year for the case.11 ETI proposed to disregard this figure
in setting rates.
6
PURA § 36.051.
7
Suburban Util. Corp. v. Pub. Util. Comm’n of Texas, 652 S.W.2d 358, 366 (Tex. 1983).
8
16 Tex. Admin. Code § 25.231(a).
9
AR Part II, Binder 31, ETI Ex. 4 (Domino Direct at 7).
10
City of El Paso v. Pub. Util. Comm’n, 344 S.W.3d 609, 614 (Tex. App.—Austin 2011, no
pet.).
11
AR Part I, Binder 7, Item 244 (Order on Rehearing at 7); Tr. at 652-53; AR Part II, Binder 41
(TIEC Ex. 1B, Confidential Exhibits and Workpapers to Direct Testimony of Jeffry Pollock
(CONFIDENTIAL 62) Workpapers, Filename: “Exhibits JP-1 and JP-2 HS.xlsx,”
2
ETI’s primary position at the PUC was that the PUC should adopt a first-of-
its-kind rider that would treat purchased-capacity costs not as a component of base
rates but on a pass-through basis, much like the PUC treats fuel costs. 12 ETI also
submitted an alternative proposal under which the PUC would use ETI’s
projections of what its purchased-capacity costs would be during a future “rate
year” in setting rates. 13 ETI estimated its future purchased-capacity costs during
the “rate year” would be approximately $31 million higher than the actual costs it
incurred during the test year. 14
Typically, the term “rate year” is used to refer to the first year that new rates
would be in effect.15 ETI’s proposed effective date for its rates was June 30,
2012, 16 but the “rate year” it used in its proposal was not the 12 months following
that date, but instead June 1, 2012 through May 31, 2013. 17 Thus, ETI proposed to
spreadsheet/tab: “PPC Summary (Test Year)”).“PPC Summary (Test Year)” was also
Attachment A to TIEC’s Initial Brief at the District Court, AR Part II, Binder 4, Item 160
(Highly Sensitive Portions of Initial Brief of Texas Industrial Energy Consumers
(CONFIDENTIAL 2).
12
AR Part IV, Binder 43, Vol. L (Tr. at 1954, May 3, 2012).
13
AR Part IV, Binder 43, Vol. F (Tr. at 761, Apr. 27, 2012); AR Part II, Binder 35, ETI Ex. 34A
(Confidential Direct Testimony of Robert R. Cooper, Exhibit RRC-1).
14
Id.
15
16 Tex. Admin. Code § 25.5(102).
16
AR Part IV, Binder 43, Vol. K (Tr. at 1540, May 2, 2012).
17
AR Part IV, Binder 43, Vol. F (Tr. at 761, Apr. 27, 2012); AR Part II, Binder 35 ETI Ex. 34A
(Confidential Direct Testimony of Robert R. Cooper, Exhibit RRC-1).
3
set rates based on neither its historical-test-year costs nor its projected costs for the
first 12 months after its new rates were implemented.
ETI’s primary proposal of a purchased-capacity rider was presented in 17
pages of ETI witness Robert May’s testimony, while its fallback proposal to use
projected costs from what it termed “the rate year” was presented in a single
sentence.18 The PUC rejected ETI’s rider proposal in a prehearing order, from
which ETI does not appeal,19 and ETI proceeded with its fallback proposal.
While ETI’s actual test-year purchased-capacity costs were undisputed, the
PUC Staff and multiple intervenors, including TIEC, challenged ETI’s proposal to
use estimates of future costs in setting rates. 20 The PUC found that there was
substantial uncertainty regarding the accuracy of ETI’s cost projections and that
ETI had not met its burden of proof to show that its projections constituted known
and measurable changes to the test-year costs. 21 The PUC also rejected ETI’s
proposed adjustments for an additional reason. To set rates, ETI proposed to
compare its projected expenses for a future year (June 1, 2012 through May 31,
2013) with its sales revenue from the historical test year (July 1, 2010 through June
18
AR Part II, Binder 31, ETI Ex. 7 (Direct Testimony of Phillip May at 5-23).
19
AR Part I, Binder 1, Item 52 (Supplemental Preliminary Order at 2) (“The PUC finds that
Entergy’s proposed purchased-power recovery rider should not be considered in this docket due
to the related rulemaking that is pending in Project No. 39246.”).
20
AR Part I, Binder 5, Item 185 (Proposal for Decision at 101).
21
AR Part I, Binder 7, Item 244 (Order on Rehearing at Findings of Facts (“FoFs”) 72-85).
4
30, 2011). 22 The PUC found that this mismatch between the period for calculating
costs and the period for calculating revenues was a violation of fundamental
ratemaking principles. 23 For these reasons, the PUC rejected ETI’s proposal to use
its forecasted purchased-power costs and instead set ETI’s rates based on the costs
it actually incurred during the test year. 24
The PUC reached a similar result with respect to ETI’s transmission-
equalization expense. 25 As with its purchased-capacity costs, ETI proposed to
disregard the transmission-equalization expense it actually incurred during the test
year in favor of its projected expense during the future rate year. 26 The PUC found
that ETI failed to meet its burden of demonstrating that its proposed adjustments to
the actual test-year data were known and measurable. 27 The PUC therefore
rejected ETI’s forecasted transmission-equalization costs and used ETI’s historical
expense from the test year in setting rates.28
22
AR Part I, Binder 5, Item 185 (Proposal for Decision at 109) (discussing mismatch of rate-year
costs with test-year billing determinants).
23
AR Part I, Binder 5, Item 185 (Proposal for Decision at 109); AR Part I, Binder 7, Item 244
(Order on Rehearing at 7).
24
AR Part I, Binder 7, Item 244 (Order on Rehearing at FoFs 72, 86).
25
Id. at FoF 88-93.
26
AR Part II, Binders 21-30 (ETI Ex. 3, Schedule P Workpapers at AJ23).
27
AR Part I, Binder 5, Item 185 (Proposal for Decision at 116).
28
AR Part I, Binder 7, Item 244 (Order on Rehearing at FoFs FoF 87, 94).
5
ETI appealed the PUC’s decision on both purchased-capacity costs and
transmission-equalization expense. The district court, Judge John K. Dietz
presiding, affirmed the PUC on both points. 29 ETI now appeals that decision to
this Court.
SUMMARY OF ARGUMENT
Texas is a historical-test-year state. For many years, the PUC has set future
rates based on past costs. Under its cost-of-service rule, the PUC determines the
utility’s reasonable and necessary expenses during a historical test year. The PUC
may make adjustments to the test-year data to account for known and measurable
changes in the utility’s expenses, but, as both the Texas Supreme Court 30 and this
Court31 have acknowledged, the decision of whether to do so is within the PUC’s
discretion.
Calling it an “anachronism,” ETI asked the PUC to abandon this regulatory
construct and provide for ETI’s purchased-capacity cost recovery through a rider.32
As a fallback proposal, ETI argued that the PUC should make an “adjustment” to
its test-year data for these costs by substituting in their place ETI’s projected levels
29
CR 2118.
30
City of El Paso v. Pub. Util. Comm’n of Texas, 883 S.W.2d 179, 188 (Tex. 1994).
31
Cent. Power & Light Co. v. Pub. Util. Comm’n of Texas, 36 S.W.3d 547, 563 (Tex. App.—
Austin 2001, pet. denied).
32
AR Part IV, Binder 43, Vol. B (Tr. at 35, Apr. 24, 2012); see also AR Part I, Binder 3, Item
157 (Initial Brief of ETI at 86).
6
of expense for a future year. The PUC rejected the rider proposal and determined
that ETI had not met its burden of proving that its future projections were known
and measurable changes to the test-year costs. ETI appeals the latter point only.
While ETI is careful to couch its appeal in terms of “substantial evidence”
and legal standards, it is evident that its true complaint is with the PUC’s practice
of setting rates based on historical data rather than future projections. Indeed,
ETI’s appeal on these points is premised on the notion that the PUC was required
to make a post-test-year adjustment despite the fact that such adjustments are
within the discretion of the PUC and despite the fact that ETI’s proposed
“adjustment” to test-year expenses was to disregard them entirely and use
projections of future costs. Were the Court to grant ETI’s appeal and hold that the
PUC had no choice but to use ETI’s projections, it would be effectively
invalidating the PUC’s practice of setting rates based on past costs and revenues
and mandating that Texas become a future-test-year state. Such policy
determinations are for the Legislature and PUC, not the judiciary.
Once ETI’s misdirected attempts to overhaul longstanding Texas policy are
rejected, what is left is a straightforward substantial-evidence inquiry. The
historical-test-year costs ETI actually incurred for purchased capacity were
established in the record and undisputed. The evidence showed that ETI’s
7
projected future costs, on the other hand, were mere estimates based on numerous
interrelated variables that cannot be known with certainty ahead of time. For
example, ETI’s third-party contracts do not contain fixed price or quantity terms,
and the price ETI will ultimately pay will be based on the availability and
performance of its suppliers’ power-plants. Further, the evidence showed that ETI
did not take into account all the attendant impacts of its proposed changes to the
test-year data, as is required under the PUC’s rules. Among other things, ETI
failed to account for increased sales revenue from increased demand, i.e., “load
growth,” when calculating its estimated increase over test-year costs. Substantial
evidence supports the PUC’s finding that ETI’s projected future purchased-
capacity costs were not known and measurable changes to the test year.
Similarly, ETI’s transmission-equalization expense projections were not
reasonably certain. The evidence showed that the level of this expense that ETI
would actually incur in the rate year is based on numerous variables that would not
be known until the future. Indeed, projecting future transmission-equalization
expense requires making estimates regarding not only ETI’s future operations and
demand, but also about those of every other Entergy affiliate on the Entergy
system. Additionally, ETI’s transmission-equalization expense projections were
based in large part on transmission projects that had not yet been completed, even
though ETI will not incur any expense as a result of such projects until they
8
actually go into service. Substantial evidence supports the PUC’s finding that
ETI’s projected future transmission-equalization expenses were not a known and
measurable change to the test year.
ARGUMENT AND AUTHORITIES
I. The PUC properly applied its longstanding historical-test-year
standard.
Under its cost-of-service rule, the PUC sets rates based on a historical test
year, adjusted for known and measurable changes. 33 With respect to expenses, the
rule provides that “only the electric utility’s historical test year expenses as
adjusted for known and measurable changes will be considered . . . .”34 As the
Texas Supreme Court has acknowledged, “PURA requires utilities to file for a rate
increase by presenting revenue and expense data from the same 12-month period
using a historical test year.” 35 PURA defines “test year” as “the most recent 12
months, beginning on the first day of a calendar or fiscal year quarter, for which
operating data for a public utility are available.” 36
The use of a historical test year in ratemaking is important for at least two
reasons. First, it allows the PUC to look at a utility’s actual costs, rather than
various competing predictions about what its costs will be in some future period.
33
16 Tex. Admin. Code § 25.231(a).
34
16 Tex. Admin. Code § 25.231(b) (emphasis added).
35
City of El Paso, 883 S.W.2d at 188 (citations omitted).
36
PURA § 11.003(20).
9
Rates are set for “an indefinite period into the future.” 37 And, as ETI
acknowledges, there is no true-up or reconciliation for expenses recovered in a
utility’s base rates.38 Consequently, the use of a utility’s unreliable projections of
future expenses could result in captive ratepayers being overcharged for years with
no possibility of a refund even if the projections turn out to be inflated.
Second, test-year ratemaking allows for an accurate matching of a utility’s
costs in a particular period with its sales in the same period. 39 This is important
because a utility recovers its non-fuel costs through the base rates it charges its
customers. Specifically, each kilowatt hour (kWh) billed to customers recovers a
certain amount of expenses.40 Accordingly, any change in the number of kWh a
utility sells also changes the amount of expenses it recovers. In other words, when
a utility sells more kWh, it recovers more expenses in its base rates, without any
change to its rates. Utilities experiencing load growth will generally experience an
increase over time in their total costs, even if their per-unit costs remain the same,
simply because they are serving more load. But they will also receive more
revenues from additional sales to cover these costs. Thus, in setting rates, the time
37
Suburban Util. Corp., 652 S.W.2d at 366.
38
ETI Appellant’s Brief at 20.
39
See, e.g., Cent. Power & Light Co., 36 S.W.3d at 563-64 (upholding the PUC’s decision to
deny a post-test-year adjustment that failed to take into account the attendant impacts of
increased electricity sales from load growth).
40
For some customers, costs are recovered through a kilowatt charge in addition to a kWh
charge.
10
period used for expenses must match the time period used for revenues. This
fundamental tenet of ratemaking, called the “matching principle,” 41 was
acknowledged in the PUC’s order when it found that ETI’s proposal to establish its
purchased power costs based on estimates in the future while simultaneously using
historical test year sales level to develop the per-unit rates was “logically
inconsistent.” 42
A. The known and measurable standard.
While ratemaking in Texas is based on a historical test year, the PUC has
discretion to adjust the test year for known and measurable changes if (i) the
proposed changes can be identified with reasonable certainty, and (ii) all attendant
impacts can be accurately identified with reasonable certainty and taken into
account.43 ETI’s brief cites to several cases where the PUC’s adoption of known
and measurable changes has been approved on appeal. But ETI ignores the fact
that changes to the test year are within the discretion of the PUC. For instance,
ETI’s quote from the City of El Paso case leaves out the Supreme Court’s explicit
statement that “it is within the discretion of the PUC to consider expenditures that
occur outside the test year . . . .” 44 The Suburban Utility case similarly states that
41
AR Part I, Binder 5, Item 185 (Proposal for Decision at 105).
42
AR Part I, Binder 5, Item 185 (Proposal for Decision at 109), adopted by AR Part I, Binder 7,
Item 244 (Order on Rehearing at 1).
43
See 16 Tex. Admin. Code § 25.231(a); Cen. Power & Light Co., 36 S.W.3d at 564.
44
City of El Paso, 883 S.W.2d at 188 (emphasis added).
11
changes occurring after the test year if known, may be taken into account.45
Notably, the Supreme Court explicitly upheld the PUC’s use of a historical test
year in that case, overruling a challenge to the use of past data instead of future
projections in setting rates.46 The Central Power & Light case recognizes the
same, holding that “the [PUC’s] authority to allow post-test-year adjustments for
‘known and measurable changes to the historical test year data’ is discretionary,
and its own substantive rules permit such changes only where ‘the attendant
impacts on all aspects of a utility’s operations can be with reasonable certainty
identified, quantified, and matched.’” 47
There is good reason for the broad discretion given to the PUC in deciding
when to deviate from a historical test year. Prospective increases in one cost may
be offset with decreases in other costs. Or prospective changes in costs may be
due to the prospective increases in sales revenues, which may more than offset
those costs. For these reasons, the PUC’s rules reflect that adjustments to
historical test year costs are appropriate only when the proposed changes are
45
Suburban Util. Corp., 652 SW.2d at 366 (emphasis added).
46
Id.
47
Cent. Power & Light Co., 36 S.W.3d at 563 (citing 16 Tex. Admin. Code § 23.21(b). In a
1998 reorganization of the PUC’s rules, the referenced language was moved to what is now 16
Tex. Admin Code § 25.231(c)(2)(F)(IV), the portion of the cost-of-service rule related to
invested capital. The Texas Register states: “The post test year language currently appearing in
§23.21(b) will be modified and moved to §23.21(d)(2)(G)(i)(IV) and thus apply only to invested
capital items. The post test year adjustment language is superfluous in §23.21(b) because the
‘test year, adjusted for known and measurable changes’ language already allows for such
adjustments.” 23 Tex. Reg. 11515 (proposed Nov. 13, 1998), adopted 24 Tex. Reg. 1377 (Feb.
26, 1999).
12
known and measurable with reasonable certainty and where the attendant impacts
on the utility’s revenues, expense, and invested capital can be quantified and
matched with reasonable certainty. 48
In this case, ETI argues that the PUC misapplied the known-and-measurable
standard by requiring that changes to test year costs be proven with “absolute
certainty,” rather than reasonable certainty. 49 ETI offers no cite to the PUC’s order
to support its extraordinary claim that the PUC applied such a standard, nor is there
anything in the record that indicates that the PUC did so. To the contrary, a review
of the PUC’s order demonstrates that the PUC properly applied the same
“reasonable certainty” standard it has applied in numerous other cases and that ETI
acknowledges is the proper standard. 50 The PUC explained at length that there was
“substantial uncertainty” in ETI’s purchased capacity projections, and the PUC so
found as to each of the elements of ETI’s request.51 ETI ignores the actual
language of the PUC’s order in asserting that the PUC must have secretly applied
an unachievable standard of absolute certainty.
48
16 Tex. Admin. Code §§ 25.231(b), 25.234(b).
49
ETI Appellant’s Brief at 26.
50
Id.
51
AR Part I, Binder 7, Item 244 (Order on Rehearing at FoFs at 72-85).
13
B. ETI’s true complaint is with the PUC’s cost-of-service rules, not
the PUC’s application of them.
It is apparent that ETI’s goal is the invalidation of the PUC’s longstanding
practice of setting rates based on historical data. Indeed, ETI argued throughout
the administrative hearing that the PUC’s historical-test-year approach was a
“regulatory model that’s an anachronism” that the PUC should abandon.52 And
ETI’s primary position, which the Commission rejected, was that its purchased-
capacity expenses should be recovered through a rider without reference to
historical data.53 ETI’s fallback proposal also would have disregarded the
historical-test-year data by completely displacing it with ETI’s speculative future
projections. ETI admitted that its proposal to apply purchased-capacity projections
from a future period to test year sales was without precedent. 54
Setting aside the evidentiary problems with ETI’s request, which are
explained in greater detail below, its appeal suffers from an additional fatal flaw.
ETI contends that the PUC was required to make the proposed post-test-year
adjustments. But as set forth above, the decision of whether to make such
adjustments is a matter that is within the discretion of the PUC. ETI cannot cite a
52
AR Part IV, Binder 43, Vol. B (Tr. at 35, Apr. 24, 2012). See also AR Part I, Binder 3, Item
157 (Initial Brief of ETI at 86).
53
AR Part I, Binder 1, Item 52 (Supplemental Preliminary Order of Public Utility PUC of Texas
at 2) (“The PUC finds that Entergy’s proposed purchased-power recovery rider should not be
considered in this docket due to the related rulemaking that is pending in Project No. 39246.”).
54
AR Part IV, Binder 43, Vol. L (Tr. at 1957-58, May 3, 2012).
14
singe case in which a court held that the PUC was required to make a post-test-year
adjustment. Nor can ETI point to any statutory requirement that the PUC make
such adjustments, though the Legislature could certainly enact one. ETI’s appeal
fails for this reason alone.
The PUC and the district court saw ETI’s arguments for what they are—a
thinly veiled attack on the PUC’s longstanding practice of making future rates
based on past costs. What ETI actually sought at the PUC, and now seeks here, is
to change Texas from a historical-test-year state to a future-test-year state (at least
as to expenses). Whatever the policy merits of such an argument, it should be
addressed in an agency rulemaking or directed to the Legislature, not to the
courts. 55
II. Substantial evidence supports the PUC’s determination of ETI’s
purchased-capacity costs.
Substantial evidence supports the amount of ETI’s purchased-capacity costs
the PUC included in ETI’s rates. The scope of review under the substantial-
55
Rodriguez v. Serv. Lloyds Ins. Co., 997 S.W.2d 248, 255 (Tex. 1999) (citations omitted) (“A
presumption favors adopting rules of general applicability through the formal rulemaking
procedures as opposed to administrative adjudication. Allowing an agency to create broad
amendments to its rules through administrative adjudication rather than through its rulemaking
authority undercuts the Administrative Procedure Act (APA).”); Amarillo Indep. Sch. Dist. v.
Meno, 854 S.W.2d 950, 957 (Tex. App.—Austin 1993, writ denied) (“When an administrative
agency implements new requirements of general applicability, it ordinarily does so through
formal rule-making procedures . . . .”).
15
evidence rule is limited.56 The issue for the reviewing court is not whether the
agency reached the correct conclusion, but whether there is some reasonable basis
in the record for the action taken by the agency. 57 A court may not substitute its
judgment for that of the agency. 58 Substantial evidence requires only more than a
mere scintilla, and “the evidence in the record actually may preponderate against
the decision of the agency and nonetheless amount to substantial evidence.” 59 “At
its core, the substantial evidence rule is a reasonableness test or a rational basis
test.”60
A. The PUC properly found that ETI’s forecasted purchased-
capacity costs were not known and measurable.
The historical test year in this proceeding was July 1, 2010 through June 30,
2011. 61 During this test year, ETI had purchased-capacity costs of $246 million.
This amount consists of purchases from third parties, purchases from affiliates, and
56
PURA § 15.001; Tex. Gov’t Code §§ 2001.174, 2001.176.
57
See City of El Paso, 883 S.W.2d at 185.
58
Texas Health Facilities Comm’n v. Charter Medical-Dallas, Inc., 665 S.W.2d 446, 452 (Tex.
1984) (citing Gerst v. Guardian Sav. & Loan Ass’n, 434 S.W.2d 113, 115 (Tex. 1968)).
59
Id. at 452 (citing Lewis v. Metropolitan Sav. & Loan Ass’n, 550 S.W.2d 11, 13 (Tex. 1977)).
60
City of El Paso, 883 S.W.2d at 185.
61
AR Part II, Binder 31 (ETI Ex. 4, Direct Testimony of Joseph F. Domino at 8).
16
reserve-equalization payments. 62 ETI’s test year costs were actually incurred
during the historical test year, were established in the record, and were undisputed.
Nevertheless, ETI sought to ignore them. In the place of its actual historical
test year costs, ETI proposed to use its forecast of the purchased-capacity costs it
would incur in what it called a future “rate year,” June 1, 2012 through May 31,
2013. 63 Thus, ETI did not truly seek to include in rates its “historical test year
expenses as adjusted for known and measurable changes.” 64 Rather, ETI’s
proposal was to discard its actual test-year expenses altogether and substitute
speculative projections of future costs, based on a number of estimates about future
usage and contracts. Based on a vast administrative record, the PUC determined
that ETI’s projections were not “known and measurable” changes to the historical
test year costs. The PUC set forth its determination in the following findings of
fact:
72. ETI's test-year purchased capacity expenses were
$245,965,886.
62
AR Part II, Binder 41 (TIEC Ex. 1B, Confidential Exhibits and Workpapers to Direct
Testimony of Jeffry Pollock (CONFIDENTIAL 62) Workpapers, Filename: “Exhibits JP-1 and
JP-2 HS.xlsx,” spreadsheet/tab: “PPC Summary (Test Year)”).
63
AR Part IV, Binder 43, Vol. F (Tr. at 761, Apr. 27, 2012); AR Part II, Binder 35 (ETI Ex.
34A, Confidential Direct Testimony of Robert R. Cooper, Exhibit RRC-1). As noted above, the
period ETI chose did not actually correspond to the rate year as that term is commonly
understood. See supra, p. 3-4.
64
See 16 Tex. Admin. Code § 25.231(b) (emphasis added).
17
73. ETI requested an upward adjustment of $30,809,355 as a post-
test-year adjustment to its purchased capacity costs. This
request was based on ETI's projections of its purchased capacity
expenses during a period beginning June 1, 2012 and ending
May 31, 2013 (the rate-year).
74. ETI's purchased capacity expense projections were based on
estimates of rate-year expenses for: (a) reserve equalization
payments under Schedule MSS-1; (b) payments under third-
party capacity contracts; and (c) payments under affiliate
contracts.
75. ETI's projection of its rate-year reserve equalization payments
under Schedule MSS-1 is based on numerous assumptions,
including load growths for ETI and its affiliates, future capacity
contracts for ETI and its affiliates, and future values of the
generation assets of ETI and its affiliates.
76. There is substantial uncertainty with regard to ETI's projection
of its rate-year reserve equalization payments under Schedule
MSS-1.
77. ETI’s projection of its rate-year third-party capacity contract
payments includes numerous assumptions, one of which is that
every single third-party supplier will perform at the maximum
level under the contract, even though that assumption is
inconsistent with ETI's historical experience.
78. There is substantial uncertainty with regard to ETI's projection
of its rate-year third-party capacity-contract payments.
79. ETI's estimates of its rate-year purchases under affiliate
contracts are based on a mathematical formula set out in
Schedule MSS-4.
80. The MSS-4 formula for rate-year affiliate capacity payments
reflects that these payments will be based on ratios and costs
that cannot be determined until the month that the payments are
to be made.
18
81. Over $11 million of ETI's affiliate transactions were based on a
2013 contract (the EAI WBL Contract) that was not signed
until April 11, 2012.
82. There is uncertainty about whether the EAI WBL Contract will
ever go into effect.
83. ETI projects purchasing over 300 megawatts (MW) more in
purchased capacity in the rate-year than it purchased in the test-
year.
84. ETI experienced substantial load growth in the two years before
the test-year, and it continues to project similar load growth in
the future.
85. ETI did not meet its burden of proof to demonstrate that a
known and measurable adjustment of $30,809,355 should be
made to its test-year purchased capacity expenses.
86. ETI's purchased capacity expense in this case should be based
on the test-year level of $245,965,886.
In an effort to detract from the PUC’s detailed and thoroughly supported
factual findings, ETI focuses in its brief on three new third-party contracts totaling
618 MW. 65 But ETI fails to acknowledge that all elements of its purchased-
capacity projections are interrelated, such that when one component increases, the
others will decrease.66 In fact, ETI’s proposal to the PUC consisted of estimating
its costs under three new third-party contracts, recalculating the costs of three other
third-party contracts based on these estimates, making concomitant changes to the
65
ETI Appellant’s Brief at 38.
66
AR Part I, Binder 5, Item 185 (Proposal for Decision at 101). See also AR Part IV, Binder 43,
Vol. L (Tr. at 1946-47, May 3, 2012).
19
amounts of the payments under seven different affiliate contracts, and adjusting the
amount of its reserve-equalization payments based on its forecasted capacity
purchases.67 All told, ETI’s forecast of its rate year purchased-capacity costs
involves fourteen separate and interrelated sources of purchased capacity.
ETI’s brief highlights three of the fourteen moving parts and asserts that
ETI’s projections under each of those contracts were known with reasonable
certainty. That was not the case, as the PUC found. But even if it were true, ETI
would still not have met its burden to show an increase in its overall purchased
capacity, because a post-test-year-adjustment may only be made if all of the
attendant impacts can be identified and accounted for with reasonable certainty. 68
1. ETI’s projected third-party contract costs were not
reasonably certain.
The evidence showed that ETI’s third-party contracts do not contain fixed
price terms and that the amount ETI will ultimately pay is subject to fluctuation
based on a variety of factors.69 Indeed, ETI admits in its brief that there is
uncertainty concerning the payments it will make under the third-party contracts in
67
AR Part II, Binder 35, ETI Ex. 34A (Direct Testimony of Robert R. Cooper, Exhibit RRC-1
(HS)); AR Part II, Binder 41 (TIEC Ex. 1B, Confidential Exhibits and Workpapers to Direct
Testimony of Jeffry Pollock (CONFIDENTIAL 62) Workpapers, Filename: “Exhibits JP-1 and
JP-2 HS.xlsx,” spreadsheet/tab: “PPC Summary (Test Year)”).
68
16 Tex. Admin. Code § 25.231(c)(2)(F)(i)(IV); See Cent. Power & Light Co., 36 S.W.3d at
564.
69
AR Part I, Binder 5, Item 185 (Proposal for Decision at 108).
20
the future. 70 Nevertheless, ETI asked the PUC—and now asks the Court—to
simply trust that any differences between its forecasted rate year costs and the costs
it will actually incur will be “very, very small.” 71 The record, however, supports
the PUC’s finding that ETI’s predictions were unreliable.
ETI’s third-party contracts are associated with generation units from specific
suppliers. As such, each contract contains numerous provisions that will affect
whatever payments ETI will eventually make when the time comes, based in part
on the supplier’s actual availability and future performance. 72 ETI witness
Richard Cooper acknowledged that historically there have been adjustments to the
payments ETI makes under third-party contracts due to availability. 73 Despite this
real-world experience, ETI made no attempt whatsoever to adjust its third-party
contract projections to reflect the availability and performance of the plants in
question. Instead, ETI simply assumed that the performance and the availability of
70
ETI Appellant’s Brief at 32.
71
AR Part I, Binder 5, Item 185 (Proposal for Decision at 108); ETI Appellant’s Brief at 32
(arguing that the deviations from the contract will be “very, very small”).
72
AR Part IV, Binder 43, Vol. D (Tr. at 682, 704-05, Apr. 26, 2012).
73
AR Part IV, Binder 43, Vol. D (Tr. at 704, Apr. 26, 2012); see also AR Part II, Binder 41
(TIEC Ex. 1B, Confidential Exhibits and Workpapers to Direct Testimony of Jeffry Pollock
(CONFIDENTIAL 62) Workpapers, Filename: “Exhibits JP-1 and JP-2 HS.xlsx,”
spreadsheet/tab: “PPC Summary (Test Year)”).
21
the supplier power plants would be at their maximum, with no disallowances
whatsoever. 74
Accordingly, ETI’s projections assumed consistent numbers, generally an
even number, for each month of the contracts, subject to the weighting for seasonal
differentials.75 ETI’s actual historical payments for third-party contracts, however,
show wide month-to-month variations in purchased power costs, and the round
numbers reflecting the maximum contractual payments are largely absent.76
Mr. Cooper admitted that, with respect to these third-party contracts, ETI
would not know the amount of the actual payments made until the rate year comes
and goes. 77 Moreover, ETI made no effort to take historical performance
characteristics into account when making its projections of future costs. 78 Indeed,
when cross-examined about the variability in purchased-capacity contracts in the
past, ETI’s witness admitted that he was not familiar with the variance in the test-
year purchased-capacity contracts. 79 Thus, not only were ETI’s proposed
74
AR Part IV, Binder 43, Vol. D (Tr. at 705, Apr. 26, 2012); AR Part I, Binder 5, Item 185
(Proposal for Decision at 108).
75
AR Part II, Binder 35 (ETI Ex. 34A, Confidential Direct Testimony of Robert. R. Cooper
Exhibit, RRC-1 at lines 1-7).
76
AR Part II, Binder 41 (TIEC Ex. 1B, Confidential Exhibits and Workpapers to Direct
Testimony of Jeffry Pollock (CONFIDENTIAL 62) Workpapers, Filename: “Exhibits JP-1 and
JP-2 HS.xlsx,” spreadsheet/tab: “PPC Summary (Test Year)”).
77
AR Binder 43, Vol. E (Tr. at 607-09, April 26, 2012) (Confidential).
78
ETI Initial Br at 33, 35; AR Binder 43, Vol. F (Tr. at 705, Apr. 26, 2012); AR Binder 43, Vol.
L Tr. at 1942, May 3, 1942).
79
AR Binder 43, Vol. L (Tr. at 1960-62, May 3, 2012).
22
purchased-capacity costs mere projections, they were projections that ignored
ETI”s historical experience.
Mindful of its burden to establish that its proposed post-test-year
adjustments were known and measurable, ETI implies that its projected future
costs are somehow fixed simply because the contracts were in place. 80 However,
the signed contracts provide for variations in costs based on future performance.81
Indeed, at the administrative hearing, ETI counsel’s attempted to draw a dichotomy
between (1) projections and (2) a fixed contractual payment in questioning Mr.
Cooper. Unfortunately for ETI, Mr. Cooper confirmed that the purchased-capacity
estimates fall on the “projections” side of that dichotomy:
Q. (by Mr. Westerburg) Now, are the costs that we’re
looking at here projections or are they contractually
based?
A. Well, they are contractually based projections . . . 82
No matter how ETI tries spin it, the third-party purchased-capacity
projections for the future are just that—projections. They are based on numerous
assumptions, including that, contrary to history, every supplier performs at the
80
ETI Appellant’s Brief at 28.
81
AR Item IV, Binder 43, Vol. D (Tr. at 682, 704-05, Apr. 26, 2012).
82
AR Item IV, Binder 43, Vol. D (Tr. at 682, Apr. 26, 2012) (emphasis added).
23
maximum level throughout every month of the future period. The PUC properly
found that the projections were not reasonably certain.
Multiple times in its brief, ETI asserts, in italics, that “no witness”
challenged ETI’s calculations of projected costs under a particular contract. 83 As
an initial matter, ETI itself scarcely addressed these issues in its direct testimony,
because its primary proposal was to recover these costs under a rider. 84 Further, it
cannot be disputed that intervenor witnesses opposed the use of ETI’s proposed
test-year adjustment for purchased-capacity costs.85 For example, TIEC witness
Jeffry Pollock explicitly asserted that ETI’s substitution of projected “rate year”
costs for actual test-year costs violated the PUC’s rules, “which require that rates
be set using an historical Test Year adjusted for known and measurable changes.” 86
Moreover, the record does not consist merely of the prefiled testimony of
intervenor or PUC Staff witnesses. The administrative hearing in this case lasted
two weeks, and much of the examination and cross-examination concerned ETI’s
proposed purchased-capacity projections. The record as a whole demonstrates that
ETI’s projections were substantially uncertain. As set out above, this was shown
by: (i) the admissions of ETI’s own witnesses that the actual costs could not be
83
ETI Appellant’s Brief at 29, 30, 32.
84
AR Part II, Binder 31, ETI Ex. 7 (Direct Testimony of Phillip May at 23).
85
AR Part I, Binder 5, Item 185 (Proposal for Decision at 106-107).
86
AR Part II, Binder 41, TIEC Ex. 1 (Direct Testimony of Jeffry Pollock at 8).
24
known, (ii) the dramatic contrast between the highly variable purchased capacity
costs that ETI’s has actually incurred in the past and the round number future
projections, and (iii) the absence of anything other than conclusory assertions
about what the future purchased capacity costs would be. Substantial evidence
supports the PUC’s finding that ETI’s projected rate-year costs for third-party
contracts were not reasonably certain.
2. ETI’s projected affiliate-contract costs were not reasonably
certain.
ETI’s projections of its purchases from affiliates under schedule MSS-4
make up the largest component of its projected $276 million in future purchased
capacity costs.87 As with ETI’s third-party contracts, ETI’s projected future costs
under its agreements with its affiliates were substantially uncertain. The affiliate
contracts do not set fixed price or quantity terms, and their costs will fluctuate
based on the operational conditions that will be experienced in the future.88
Accordingly, ETI made assumptions about unknown variables to come up with its
projected MSS-4 costs for the rate year. 89 Notably, ETI’s brief offers no response
87
AR Part II, Binder 35, ETI Ex. 34A (Confidential Direct Testimony of Robert R. Cooper,
Exhibit RRC-1).
88
AR Part I, Binder 5, Item 185 (Proposal for Decision at 102), AR Part IV, Binder 43, Vol. D.
(Tr. at 606, Apr. 26, 2012).
89
Id.
25
to the PUC’s finding that the future costs for these affiliate contracts will fluctuate
based on numerous operational conditions that cannot be predicted. 90
The evidence showed that ETI’s projections were unreliable. The witness
that ETI offered in support of its projected MSS-4 cost calculations, Mr. Cooper,
admitted that he was not familiar with how capacity charges are calculated under
MSS-4.91 In fact, he had never even dealt with how capacity charges under MSS-4
were calculated.92 Yet ETI asked the PUC to accept the projections given to Mr.
Cooper without any support whatsoever for that calculation.
Further, the MSS-4 formula contains complicated and interrelated variables
for calculating affiliate-capacity costs that are dependent on numerous inputs that
cannot be determined until some future time. 93 The determination of the monthly
per-unit capacity charge is only part of the equation. There are similar
complexities involved in any attempt to project the actual amount of capacity in
kW that ETI would purchase in the future.94 Given the complicated nature of the
formula and the fact that numerous inputs are based on events in the future, it is
90
AR Part I, Binder 5, Item 185 (Proposal for Decision at 108), adopted by AR Part I, Binder 7,
Item 244 (Order on Rehearing at 1).
91
AR Part IV, Binder 43, Vol. D (Tr. at 634-36, Apr. 26, 2012).
92
Id.
93
AR Part II, Binder 42, TIEC Ex. 22 (“Service Schedule MSS-4 Unit Power Purchase, Exhibit
PJC-1, 2011 TX Rate Case” at 68-69).
94
AR Part II, Binder 42, TIEC Ex. 22 (“Service Schedule MSS-4 Unit Power Purchase, Exhibit
PJC-1, 2011 TX Rate Case” at 62-63); AR Part IV, Binder 43, Vol. E (Tr. at 628-29, Apr. 26,
2012) (Confidential).
26
little wonder that Mr. Cooper could offer no support or explanation for the
projection he was given. 95 ETI’s evidence in support of the MSS-4 projections
amounts to little more than Mr. Cooper’s statement that someone else at ETI had
made these calculations and that, even though he could not support them, the PUC
should accept them. 96
ETI’s brief asserts that the uncertainty about the affiliate purchases can be
ignored because the amounts were not that much different than the test year
amounts for this particular source of purchased capacity. 97 ETI ignores the fact,
however, that the various sources of purchased capacity are interrelated so that, as
the amount of capacity from one source increases, the amount from other sources
will decrease. ETI’s test-year affiliate-purchased-capacity costs were incurred in a
world without the additional third-party purchased-capacity contracts that ETI
projected for the future period. ETI offered nothing but conclusory assertions for
how its affiliate-purchased-capacity costs would be affected by the new third-party
contracts. 98
ETI’s contract with Entergy Arkansas (the EA WBL contract), which
accounts for more than one-third of ETI’s projected $31 million increase in
purchased-capacity costs over the test year, highlights the problems with ETI’s
95
AR Part IV, Binder 43, Vol. D (Tr. at 634-36, Apr. 26, 2012) (Confidential).
96
AR Part IV, Binder 43, Vol. D (Tr. at 634-36, Apr. 26, 2012).
97
AR Part I, Binder 3, Item 157 (ETI Initial Br. at 39).
98
See, e.g., AR Part IV, Binder 43, Vol. E (Tr. at 607-609, Apr. 26, 2012) (Confidential).
27
projected affiliate-contract expenses. The evidence showed that ETI’s costs under
this contract, which ETI executed only days before the administrative hearing and
months after it initiated the underlying proceeding, were substantially uncertain.
Pricing under the contract was not determined at the time of the PUC proceeding,
but would instead be set based on the MSS-4 schedule in 2013. 99 The quantity of
capacity ETI ultimately purchases under the EA WBL contract was also unknown;
it would be based on a yet-to-be-determined allocation percentage between ETI
and its Entergy affiliates.100 In fact, it was not clear that the contract would ever go
into effect, because it was contingent on ETI receiving regulatory approvals that it
had not yet received at the time of the PUC proceeding. 101 And even if it did go
into effect, it would be subject to two further revisions before ETI ever received
any power.102 The EAI contract is a prime example of why the PUC properly
found that ETI’s affiliate-cost projections were not reasonably certain.
3. ETI’s projected MSS-1 costs were not reasonably certain.
The third component of ETI’s purchased-capacity cost projections was for
MSS-1 payments, also known as reserve-equalization payments. Reserve-
equalization payments are payments among various ETI affiliates relating to each
99
AR Part I, Binder 5, Item 185 (Proposal for Decision at 102) (citing AR Part II, Binder 37, ETI
Ex. 47 (Rebuttal Testimony of Robert R. Cooper at RRC-R-1), and AR Part IV, Binder 43 (Tr. at
628-9, Apr. 26, 2012)).
100
Id.
101
Id.
102
Id.
28
affiliate’s proportionate share of the Entergy System capacity. 103 MSS-1 payments
reflect that some affiliates are “long” on capacity while others are “short” on
capacity. 104 As a utility purchases capacity from third parties or affiliates, its MSS-
1 payments will decrease, all other things equal. Reserve equalization payments
are based on a complex formula in the Entergy System Agreement. 105 In order to
make an estimate of future costs, ETI was required to project not only its own load
growth, but also the load growth of every other Entergy affiliate. 106
ETI acknowledges that if the load of even one Entergy affiliate is less than
predicted, ETI’s projected MSS-1 payments would change. 107 MSS-1 payments
would also change if there was increased load growth for ETI or any affiliate.108
Or if any one of the other Entergy affiliates signed a new purchased-capacity
contract.109 Or if the future book value of the generation assets of any Entergy
affiliate was not identical to projections. 110 ETI admitted at the hearing that there
was “some uncertainty” in its MSS-1 projections.111 In fact, ETI’s projections
were so uncertain that ETI proposed to change them by $4.5 million in a brief after
103
AR Part II, Binder 36, ETI Ex. 39 (Direct Testimony of Patrick J. Cicio at 11-12).
104
Id.
105
AR Part II, Binder 36, ETI Ex. 39 (Direct Testimony of Patrick J. Cicio at Exhibit PJC-1 at
30-37).
106
AR Part IV, Binder 43, Vol. D (Tr. at 651-52, Apr. 26, 2012).
107
AR Part IV, Binder 43, Vol. D (Tr. at 651-52, Apr. 26, 2012).
108
Id.
109
Id.
110
AR Part IV, Binder 43, Vol. L (Tr. at 1915, May 3, 2012).
111
Id. at 1918-19.
29
the administrative hearing on the merits had concluded. 112 It is easy to see why
the PUC did not find ETI’s cost projections to be reasonably certain. As with the
other components of its $276 million purchased capacity projections, the projected
MSS-1 costs were cobbled together from a host of unexplained assumptions and
prognostications. Substantial evidence supported the PUC’s decision to reject
them.
4. ETI’s proposal failed to account for revenues from load
growth.
In addition to ETI’s cost estimates being uncertain, the evidence also
showed that ETI failed to take into account attendant impacts related to its
proposed adjustment and failed to comply with the matching principle. As the
PUC found, ETI based its projections of future capacity costs on the assumption
that it will experience higher sales in that future period. 113 But ETI’s proposal
would set rates by applying its higher projected purchased-capacity costs for the
future period to its sales (i.e., billing determinants) from the past test year. 114
ETI’s proposal ignores the fact that utilities purchase or build capacity in
order to meet their projected demands, and that increased demands bring higher
revenues. Any utility experiencing growth in the amount of electricity it sells will
necessarily have to build or buy additional capacity to meet that growth. For such
112
AR Part I, Binder 3, Item 157 (ETI Initial Br. at 77).
113
AR Part I, Binder 5, Item 185 (Proposal for Decision at 109).
114
Id.
30
a utility, the total cost of capacity in the future will almost always be higher than
the total cost of capacity in a prior period (unless the unit cost of capacity is falling
at a faster rate than the sales are increasing). Critically, however, the revenues that
the utility receives in the future period will also increase as its load grows. Thus,
assuming the per-unit cost of capacity remains constant, any increase in total
capacity costs will be paid for by the increase in total capacity-related revenues.
And even if the per-unit cost of capacity increases, the increase in capacity-related
revenues will still partially offset the increased capacity costs. 115 Accordingly, in
accordance with the matching principle, 116 the PUC sets rates based on a
concurrent review of costs and sales in the same year.
It is undisputed that ETI was experiencing load growth. For the two-year
period preceding the test year, ETI’s retail sales (measured in kW) grew by over
7%. 117 For the two years beyond the test year, ETI projected an overall increase in
ETI’s capacity of about 7.8%.118 In fact, at the time of the administrative hearing,
ETI had already contracted for 6% more load in the rate year. 119 The evidence thus
showed that ETI projected load growth, and the PUC properly found that ETI’s
115
The Proposal for Decision contains a hypothetical illustrating this point. AR Part I, Binder 5,
Item 185 (Proposal for Decision at 105).
116
AR Part II, Binder 41, TIEC Ex. 1 (Direct Testimony of Jeffry Pollock at 18-19).
117
AR Part IV, Binder 43, Vol. B (Tr. at 128-30, Apr. 24, 2012).
118
Id. at 1540.
119
AR Part I, Binder 5, Item 185 (Proposal for Decision at 109) (citing AR Part II, Binder 37,
ETI Ex. 47 (Rebuttal Testimony of Robert R. Cooper at 4); AR Part IV, Binder 43, Vol. D (Tr. at
667-68, Apr. 26, 2012).
31
proposal to mix test-year billing determinants and projected future costs was
“logically inconsistent” and a violation of the matching principle. 120
Indeed, ETI does not deny that load growth increases its revenues and can
thus offset increased costs, such as purchased-capacity costs. Instead, ETI argues
that the PUC is simply not allowed to consider load growth when making post-test-
year adjustments.121 Specifically, ETI argues that if it the PUC were supposed to
consider future load growth in setting base rates, the Legislature would have said
so.122 ETI fails to mention, however, that the Legislature has not directed the PUC
to consider projected future expenses in setting base rates either. ETI nonetheless
proposed that future expenses should be considered, but that future revenues
should be ignored. The PUC properly rejected this illogical request.123 Moreover,
while ETI has cited no authority for the proposition that the PUC may not consider
load growth in determining post-test-year adjustments, this Court has come to the
opposite conclusion. In Central Power & Light Co., the Court upheld the PUC’s
decision to deny a post-test-year adjustment that failed to take into account the
attendant impacts of increased electricity sales from load growth. 124 If ETI
120
AR Binder 5, Item 185 (Proposal for Decision at 109).
121
ETI’s appellant’s brief at 32-33.
122
Id.
123
AR Part I, Binder 7, Item 244 (Order on Rehearing at 7).
124
E.g., Cent. Power & Light Co., 36 S.W.3d at 564 (upholding the PUC’s decision to deny a
post-test-year adjustment that failed to take into account the attendant impacts of increased
electricity sales from load growth).
32
believes that the PUC should stop considering load growth when evaluating post-
test-year adjustments, it should take that policy matter up with the Legislature, not
the courts.
ETI also argues that the load growth would not materialize for two years and
complains that the intervenor witnesses failed to quantify the effect of load growth
or, in the case of the Cities’ witness, got it wrong.125 Initially, ETI had the burden
of proof, not intervenors. It was not intervenors’ job to fix ETI’s proposed test-
year adjustment. Further, the evidence showed that ETI would experience load
growth during its proposed rate year, and that this would offset at least some of
ETI’s future expenses. 126 Moreover, multiple intervenor witnesses testified that
when all the proper attendant impacts were taken into account, ETI’s future
purchased-capacity costs would be lower than its test-year costs, not higher.127
ETI did not meet its burden of identifying with reasonable certainty its future
purchased-capacity costs net of increased revenues due to load growth.
In summary, there was substantial evidence to support the PUC’s findings
that ETI’s speculative rate-year projections were not known and measurable, that
ETI failed to identify, quantify, and match all attendant impacts of its proposed
125
ETI Appellant’s Brief at 33.
126
AR Part I, Binder 5, Item 185 (Proposal for Decision at 109), AR Part I, Binder 7, Item 244
(Order on Rehearing at FoF 84).
127
AR Part II, Binder 9, Cities Ex. 6C (Confidential Direct Testimony and Exhibits of Karl J.
Nalepa at 17); AR Part II, Binder 8, Cities Ex. 4 (Direct Testimony of Dr. Dennis W. Goins at
19); AR Part II, Binder 41, TIEC Ex. 1 (Direct Testimony and Exhibits of Jeffry Pollock at 27).
33
adjustment with reasonable certainty, and that its proposal violated the matching
principle.
B. Having failed to meet its burden of proof, ETI is not entitled to its
proposed post-test-year adjustments.
ETI repeatedly argues that the PUC must have erred because it did not allow
ETI to recover at least some of its projected increase to its test-year expenses for
purchased capacity. 128 This contention ignores the fact that ETI had the burden of
proving that its changes to its historical-test-year costs were known and
measurable. 129 ETI could have relied on the test-year costs, which were
established in the record. But instead it elected to seek recovery of its forecasted
expenses for a future year. For the reasons discussed above, the PUC properly
found that ETI did not meet its burden of proving that its projected costs were
known and measurable. Accordingly, ETI’s contention that it was entitled to at
least some of it its proposed $31 million increase over the actual test-year costs
makes little sense. Indeed, it would have been arbitrary and capricious for the
PUC to determine that ETI’s forecast was unreliable because its costs were
substantially uncertain, but to nevertheless award ETI some fraction of its
estimated increase anyway. The PUC’s decision to reject ETI’s speculative
projections was supported by substantial evidence.
128
ETI Appellant’s Brief at 27, 39.
129
PURA § 36.006; Central Power & Light Co., 36 S.W.3d at 564.
34
Further, ETI’s complaint that a “wholesale disallowance” 130 of its projected
purchased-capacity increases was unwarranted is belied by the evidence. During
the course of the PUC proceeding, three intervenor witnesses produced their own
analyses of what ETI’s purchased-capacity costs would look like if the test-year
data were adjusted. Notably, all three concluded that ETI’s costs would be lower
than what it actually incurred in the test year by estimates ranging from $3 million
to $8 million.131 Thus, even if the PUC had decided to descend into the rabbit hole
and engage in ratemaking by prognostication, it had evidence before it that ETI
was not entitled to any increase over test-year costs whatsoever. ETI’s contention
that it proved entitlement to at least some increase over its test-year costs is
without merit.
For all of the foregoing reasons, a reasonable basis exists in the record for
the PUC’s decision that ETI did not meet its burden of proving that its projected
future purchased-capacity costs were known and measurable changes to the test
year. 132
130
ETI’s appellant’s brief at 27.
131
AR Part I, Binder 5, Item 185 (Proposal for Decision at 106-7); AR Part II, Binder 9, Cities
Ex. 6C (Confidential Direct Testimony and Exhibits of Karl J. Nalepa at 17); AR Part II, Binder
8, Cities Ex. 4 (Direct Testimony of Dr. Dennis W. Goins at 19); AR Part II, Binder 41, TIEC
Ex. 1 (Direct Testimony and Exhibits of Jeffry Pollock at 27).
132
City of El Paso, 883 S.W.2d at 185; PURA § 36.006.
35
III. The PUC properly rejected ETI’s proposal to base transmission
equalization expense on projections of future costs.
The analysis is the same for the PUC’s rejection of ETI’s proposed post-test-
year adjustment to its transmission-equalization expense. During the test year, ETI
incurred $1.754 million of actual transmission-equalization expense. 133 Instead of
relying on this number, ETI proposed that its rates be set based upon a future
projection of $10.697 million in transmission equalization expense, which ETI
asserted was a forecast of its rate-year (i.e., June 2012 through May 2013)
expense.134 The evidence showed that ETI’s projection was speculative and
unreliable. ETI’s rate-year expense would be driven by uncertain future costs and
loads of each of the Entergy Operating Companies (“EOCs”). 135 Moreover, ETI’s
$8.9 million upward adjustment was premised on costs for transmission projects
that were in varying stages of design and construction and would not actually
impact its equalization costs until they were completed and in service. Based on
the evidence, the PUC made the following findings of fact:
87. ETI incurred $1,753,797 of transmission equalization expense
during the test-year.
133
AR Part II, Binder 9, Cities Ex. 28 (ETI Response to Cities 3-3(g)).
134
AR Part II, Binders 21-30, ETI Ex. 3 (Schedule P Workpapers at AJ23).
135
At the time of the hearing, the EOCs were Entergy Arkansas, Inc. (“EAI”), Entergy Gulf
States Louisiana, LLC (“EGSL”), Entergy Louisiana, LLC (“ELL”), Entergy Mississippi, Inc.
(“EMI”), Entergy New Orleans, Inc. (“ENOI”), and Entergy Texas, Inc. (“ETI”). AR Part IV,
Binder 43, Vol. F (Tr. at 734-37, Apr. 27, 2012).
36
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.
37
As set forth below, the record is replete with evidence to support these
findings and the PUC’s holding that “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.” 136
A. Substantial evidence supports the PUC’s decision.
The Entergy System Agreement (“ESA”) requires that the various EOCs
equalize the ownership and operating costs of certain transmission investment
across the system. 137 Transmission-equalization expense accordingly relates to
monthly payments that ETI makes (or receives) based upon the obligation to share
the costs of transmission capacity on the Entergy System. In some years, ETI
makes transmission equalization payments; in other years, it is a recipient of
payments. As explained below, there are a host of variables that drive an EOC’s
monthly transmission equalization obligation, including the loads of the various
operating companies vis-à-vis the Entergy System and the in-service dates of
transmission investment.
136
AR Part I, Binder 7, Item 244 (Order on Rehearing at 21).
137
Inter-transmission investment is defined in Service Schedule MSS-2 of the ESA and generally
includes transmission line investment at 230 kV and above, as well as certain investment in
transmission substations and certain lines 115 kV and higher from an owning company’s last
substations to the connecting point of another company. See AR Part II, Binder 36, ETI Ex. 39
(Direct Testimony of Patrick J. Cicio at Exhibit PJC-1 at 38).
38
1. ETI’s transmission-equalization costs are variable and
uncertain.
Entergy performs “transmission equalization” based upon a complex six-
page formula set out in Service Schedule MSS-2 (“MSS-2”) of the ESA.138 At the
hearing, ETI witness Patrick Cicio testified that ETI’s forecast of transmission
equalization expense was based upon a number of variables from each of the six
EOCs that are inter-dependent and that would affect ETI’s ultimate transmission
equalization expense during the rate year. These variables include:
• Future transmission investment for each EOC; 139
• Future deferred taxes for each EOC; 140
• Future depreciation reserves for each EOC; 141
• Future costs of capital for each EOC (including capital structure and
cost of debt and preferred and common equity); 142
• Future tax rates for each EOC; 143
• Future operating expenses for each EOC (including depreciation
factors, insurance expense, property tax, franchise tax, and operations
and maintenance expense); and 144
138
AR Part II, Binder 36, ETI Ex. 39 (Direct Testimony of Patrick J. Cicio at Exhibit PJC-1 at
38-43).
139
AR Part IV, Binder 43, Vol. F (Tr. at 738, Apr. 27, 2012).
140
Id. at 740.
141
Id. at 741.
142
Id.
143
Id. at 742.
144
Id. at 742-43.
39
• Future responsibility ratios for each EOC, which are based upon a
rolling 12-month average of each EOC’s peak usage coincident with
the Entergy System peak usage.145
The steps of the complicated calculation that Entergy performs each month
to calculate transmission expense are in the record in this case. 146 The calculation
shows that ETI’s transmission-equalization expense will change should there be a
change in any one of the EOC’s forecasted amounts of transmission investment,
sales, or operating costs, or a change to the cost of capital. ETI’s post-test-year
adjustment was therefore predicated on a calculation that required numerous
predictions about uncertain future capital costs, expenses, and load for each of the
EOCs. The assertion that ETI would incur $10.7 million in MSS-2 expense in its
rate year was therefore dubious and did not meet the known and measurable
standard set forth by 16 Tex. Admin. Code § 25.231(a).
2. ETI’s projections were based on projects that were not yet
in-service.
ETI’s projected transmission-equalization expenses are particularly
speculative because they are premised on investment related to transmission
projects that were not yet in-service and were in varying stages of design and
145
Id. at 746-48.
146
AR Part II, Binder 9, Cities Ex. 39 (“Attachment 3, Summary of Monthly MSS-2
Calculation”) and AR Part II, Binder 41, TIEC Ex. 1 (Direct Testimony and Exhibits of Jeffry
Pollock at JP-3).
40
construction.147 ETI witness Mark McCulla explained that the primary driver of
the $10.697 million forecasted increase over test-year costs was based on an
anticipated $184.9 million of additional transmission investment on the Entergy
System for the period June 2012 through May 2013. 148 However, at the
administrative hearing, he conceded that the majority of the projects driving the
investments were still in the design and construction phase and had not yet been
completed.149 Indeed, some of the projects had projected completion dates as far
out as December 2012, six months after the new rates in the case were to go into
effect on June 30, 2012.150 It was therefore unclear when these projects would
actually go into service. As ETI witness Mr. Cicio admitted: “In-service dates can
change. They could go forward. They could go backward. I’ve seen it both
ways.” 151
Investment is not counted for MSS-2 calculation purposes until the
transmission is actually in service and providing electric service to customers.152
147
See AR Part II, Binder 36, ETI Ex. 39 (Direct Testimony of Patrick J. Cicio at Ex. PJC-1 at
39). See also AR Part IV, Binder 43, Vol. F (Tr. at 770, Apr. 27, 2012).
148
AR Part II, Binder 37, ETI Ex. 59 (Rebuttal Testimony of Mark F. McCulla at 2 and Exhibit
MFM-R-1).
149
AR Part II, Binder 37, ETI Ex. 59 (Rebuttal Testimony of Mark F. McCulla at 2 and Exhibit
MFM-R-1); AR Part IV, Binder 43, Vol. C (Tr. at 457-58, Apr. 25, 2012).
150
See AR Part II, Binder 37, ETI Ex. 59 (Rebuttal Testimony of Mark F. McCulla at Exhibit
MFM-R-1).
151
AR Part IV, Binder 43, Vol. F (Tr. at 773, Apr. 26, 2012).
152
AR Part IV, Binder 43, Vol. F (Tr. at 769, Apr. 27, 2012). See also AR Part II, Binder 36, ETI
Ex. 39 (Direct Testimony of Patrick J. Cicio at Exhibit PJC-1 at 39).
41
Thus, there is no impact to ETI’s transmission-equalization expense until these
projects actually go into service. For this reason alone, ETI’s future transmission-
equalization expense was not reasonably certain.
Given the lack of certainty regarding ETI’s estimates of its transmission
investment in-service dates, as well as the numerous other variables that affect the
MSS-2 calculation, the PUC had considerable evidence upon which to base its
determination that ETI has not met its burden of proving its post-test-year
adjustment was known and measurable.153 The PUC’s decision on transmission-
equalization expense should be upheld.
CONCLUSION AND PRAYER
For the foregoing reasons, TIEC prays that the Court affirm the district
court’s judgment upholding the PUC’s determination of the amount of ETI’s
purchased-capacity and transmission-equalization expenses that should be included
in rates and grant TIEC any and all other relief to which it is entitled.
153
AR Part I, Binder 7, Item 244 (Order on Rehearing at 21).
42
Respectfully submitted,
/s/ Rex D. VanMiddlesworth
Rex D. VanMiddlesworth
rex.vanmiddlesworth@tklaw.com
State Bar No. 20449400
Benjamin Hallmark
benjamin.hallmark@tklaw.com
State Bar No. 24069865
THOMPSON & KNIGHT LLP
98 San Jacinto Blvd., Suite 1900
Austin, TX 78701
Telephone: (512) 469-6100
Facsimile: (512) 469-6180
ATTORNEYS FOR APPELLEE TEXAS
INDUSTRIAL ENERGY CONSUMERS
CERTIFICATE OF COMPLIANCE
I certify that this document contains 10,486 words in the portions of the
document that are subject to the word limits of Texas Rule of Appellate Procedure
9.4(i), including the Glossary of Abbreviations, as measured by the undersigned’s
word-processing software.
/s/ Benjamin Hallmark
43
CERTIFICATE OF SERVICE
As required by Texas Rule of Appellate Procedure 9.5, I certify that on the
30th day of April, 2015, the foregoing document was electronically filed with the
Clerk of the Court using the electronic case filing system of the Court, and that a
true and correct copy was served on the following lead counsel for all parties listed
below via electronic service:
Counsel for Entergy Texas, Inc. Marnie A. McCormick
Patrick J. Pearsall
Duggins Wren Mann & Romero, LLP
600 Congress Ave., Ste. 1900
Austin, Texas 78701
512.744.9300
512.744.9399 (fax)
mmccormick@dwmrlaw.com
ppearsall@dwmrlaw.com
Counsel for the Public Utility Elizabeth R. B. Sterling
Commission of Texas Megan M. Neal
Environmental Protection Division
Office of the Attorney General
P.O. Box 12548
Austin, Texas 78711-2548
512.463.2012
512.457.4616 (fax)
elizabeth.sterling@texasattorneygeneral.gov
Counsel for Office of Public Utility Sara J. Ferris
Counsel Office of Public Utility Counsel
1701 N. Congress Ave., Ste. 9-180
P.O. Box 12397
Austin, Texas 78711-2397
512.936.7500
512.936.7520 (fax)
44
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 Cities 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
/s/ Benjamin Hallmark
45
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