SOAH NO. 473-01-2135
PUC DOCKET NO. 23718
APPLICATION OF SOUTHWESTERN
PUBLIC SERVICE COMPANY FOR
AUTHORITY TO: (1) REVISE ITS
FIXED VOLTAGE LEVEL FUEL
FACTORS; (2) SURCHARGE ITS
HISTORICAL FUEL UNDERRECOVERIES; (3) SURCHARGE ITS
ESTIMATED FUEL UNDERRECOVERIES; AND (4) RELATED
GOOD-CAUSE WAIVERS
§
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BEFORE THE STATE OFFICE
OF
ADMINISTRATIVE HEARINGS
CITIES OF AMARILLO AND SPEARMAN
POST-HEARING BRIEF
JUNE 11, 2001
Jim Boyle, Jaime Slaughter, Charmaine Skillman and Rick Guzman
Law Offices of Jim Boyle, PLLC
1005 Congress, Suite 550
Austin, TX 78701
(512) 474-1492
(512) 474-2507
On Behalf of the Cities of Amarillo and Spearman
EXECUTIVE SUMMARY
SHORT TERM FIRM SALES
ARE COORDINATION TRANSACTIONS
Central Issue
The central issue in this proceeding is whether short-term firm wholesale sales are
eligible for margin sharing or revenue credits. The term “short-term firm” is used by Cities in
the same way the term is defined by the FERC in its Form 1, namely, firm sales which are one
year or less in duration.
FERC Categorizes Short-Term Firm Sales as Coordination Sales
Ever since the Public Service of New Mexico decision short-term firm sales have been
categorized as coordination sales. See, Appendix E. In a landmark case involving bulk power
sales, Western System Power Pool, the FERC described in detail the various types of
coordination transactions, including in that classification short-term firm sales of capacity
and energy.1
Case of First Impression
The PUC has never before dealt with the issue of whether SPS’ short-term firm sales
margins should be shared with ratepayers (revenue credits).
Short-term firm contracts are
relatively recent. They are largely in response to FERC’s approval of market based contracts
where a utility may charge what the market will bear.
SPS (Xcel Energy) Does Not Want To Share The Margins With Anyone While Simultaneously
Driving Up The Fuel Factor
There is a horrible mismatch in this proceeding. The increase in the fuel factor is the
result of higher natural gas costs. Most of SPS’ native load is served by the Tolk Station and
1
Western System Power Pool, 55 FERC par. 61,099 at p. 61,032 (Ap. 23, 1991).
ii
Harrington Station coal-fired generation units. There should be no dispute that the off-system
sales in question cause SPS to use more gas-fired generation. While these off-system sales drive
up fuel costs (fuel factor) for retail customers the Company refuses to share any of the margins
resulting from these sales.
The Company has made no offer to adjust the fuel factor to
compensate for the higher gas costs resulting from these sales.
Short-Term Firm Sales Are Uncertain And Non-Recurring
Under any definition of “deceptive and misleading” the SPS presentation meets it on
“Other” or “Additional” Off-System sales. For the first three Errata (Fuel Factor Application)
these sales were listed as : (a) “non-firm/firm” off-system sales and (b) firm off-system sales. As
will be discussed later in the brief none of these projected off-system sales for 2001 took place
even though SPS knew for certain that the sales had not occurred.
This is an excellent
illustration of the fact that short-term off-system sales are highly speculative and “iffy.” Nonrecurring costs are not the sort of costs to be included in rate base or a cost of service. Only the
WAPA contract committed to buying any energy or capacity during 2002 and that was only for
the first two months of the year.
There Is No Merit To The Contention That These Contracts Are Already In Base Rates
The contention that the Short-Term Firm contracts are already in base rates is totally
without merit. The last base rate case, Docket No. 11520, was based upon a September 1992
ending test year. There is no way these contracts could have been taken into consideration
almost a decade prior to their existence.

Docket No. 11520 was a “black box” settlement.

Docket No. 11520 did not adopt SPS’ proposed cost allocation.

Inclusion of short-term sales in base rates would have been inconsistent with
the Commission’s definition of native sales.
iii

No short-term firm contracts were in existence in 1991 or 1992.

Since 1992 Texas wholesale has grown by 130% while Texas retail has grown
by 23% in MWH.

It appears that Texas retail is subsidizing Texas wholesale.
Production Plant Is Not Allocated To Short-Term Transactions
Mr. Hudson points out that production plant is allocated to intermediate term and longterm firm sales.2 The seminal NMPS case points out that capacity is constructed to meet longterm firm sales.3 In other words, short-term firm sales cannot be counted on for the purpose of
constructing generating facilities which take anywhere from five to ten years to become
operational from the time they are first conceived.
If Short-Term Firm Sales Are Handled In Base Rate Cases Then Ratepayers Will Be Harmed
If a short-term firm sale of one year or less is to be included in base rate proceedings,
then, ratepayers will not see the benefits of these market based contracts. It is unlikely that these
sales will line up exactly with either the test year or the rate year, thus, a proper base rate
allocation is not possible. In addition, in order to catch at least some of the short-term sales for
allocation purposes it will be necessary to annually request the Company to file a general rate
case. SPS has not filed a general rate case for almost ten (10) years. There is no indication SPS
is likely to file a general rate case at any time in the near future, thus, Xcel Energy shareholders
will walk away with the margins.
2
SPS Ex. 20, at 33. FERC defines intermediate term firm to be more than 1 year but less than 5, while long-term
firm is five or more years.
3
See Appendix E.
iv
TABLE OF CONTENTS
EXECUTIVE SUMMARY ............................................................................................................ ii
TABLE OF CONTENTS ................................................................................................................ v
I.
INTRODUCTION .............................................................................................................. 1
II.
BACKGROUND ................................................................................................................ 3
A. SPS Admitted the Four Contracts Are Off-System ............................................................ 5
B. SPS’ Failure To Remove “Additional Sales” From Its Schedules Adversely Impacted
Fuel Factor Calculations ..................................................................................................... 5
C. SPS is "Laundering" Power to its Affiliate to Avoid Sharing Off-System Sales Margins
with Texas Ratepayers ........................................................................................................ 7
III.
STANDARD OF REVIEW AND BURDEN OF PROOF ................................................. 8
IV.
TREATMENT OF OFF-SYSTEM SALES REVENUES .................................................. 9
A. Short-Term Firm Sales Are "Off-System" Sales. ............................................................... 9
1. SPS admitted the disputed contracts are off-system and this treatment is supported by
FERC and Commission requirements ............................................................................ 9
2. These contracts were not included in SPS’ last base rate case. .................................... 14
3. There is no merit to SPS witness Hudson’s “Replacement Theory” ............................ 15
4. The contract terms for the four transactions show them to be off-system sales ........... 17
B. The Requirement to Offset Eligible Fuel Expense with Off-System Sales Revenues Is Not
Limited To Non-Firm Off-system Sales Under Commission Rules And Cases .............. 19
1. The history of the fuel factor rulemaking shows no distinction regarding the kinds of
off-system sales for which margin crediting is required. ............................................. 19
2. The Commission’s decision in Docket No. 9945 assumed that the requirement to offset
eligible fuel expenses with off-system sales revenues applies to short-term firm offsystem sales .................................................................................................................. 22
3. Subsequent fuel rulemakings support Cities' position .................................................. 23
4. The criteria for retaining ten-percent margins supports Cities' position ....................... 24
5. SPS fuel cases have not carved out an exception for the margin crediting requirement
...................................................................................................................................... 25
C. The Commission Should Not Ignore the FERC Approach, Which Favors Revenue
Crediting, Not Base Rate Treatment, For Short-term Off-System Sales Margins, Even
When The Sales Are Firm Sales ....................................................................................... 26
D. SPS' Exclusion Of Short-Term Firm Sales Margins Overstates Fuel Costs For Native
System Customers. ............................................................................................................ 29
V.
SPS’ FORECAST OF ADDITIONAL ON-SYSTEM FIRM SALES IS TOO
SPECULATIVE TO BE RECOGNIZED IN THE FUEL FACTOR CALCULATION. 32
VI.
SPS POWER SALES ARE USED TO GENERATE MARGINS FOR ITS AFFILIATE
COMPANY (PSCo) .......................................................................................................... 42
VII. CONCLUSION ................................................................................................................. 45
PRAYER ....................................................................................................................................... 45
CERTIFICATE OF SERVICE ..................................................................................................... 47
v
APPENDICES
SPS Ex. 14, Third Errata, FIRM OFF-SYSTEM SCHEDULES ...................................................A
Cities Ex. 11, WHOLESALE CONTRACTS
(FULL REQUIREMENTS PARTIAL REQUIREMENTS, SHORT TERM FIRM) .............. B
Cities Ex. 8,
SPS RFI RESPONSE (Cities 5-7) OFF-SYSTEM FIRM SALES ........................................... C
EARLEY, WILBUR,
COORDINATION TRANSACTIONS AMONG ELECTRIC UTILITIES,
PUBLIC UTILITIES FORTNIGHTLY (Sept. 13, 1984) .........................................................D
PUBLIC SERVICE COMPANY OF NEW MEXICO,
20 FERC par. 61,290 (Sept. 17, 1982)
SHORT-TERM FIRM TRANSACTIONS ARE COORDINATION SALES ......................... E
PURA § 36.203
FUEL COST RECOVERY ....................................................................................................... F
FUEL RULES
PUC SUBSTANTIVE RULES § 25.235-25.237 .....................................................................G
PRIOR SPS FUEL CASES .............................................................................................................H
vi
SOAH NO. 473-01-2135
PUC DOCKET NO. 23718
APPLICATION OF SOUTHWESTERN
PUBLIC SERVICE COMPANY FOR
AUTHORITY TO: (1) REVISE ITS
FIXED VOLTAGE LEVEL FUEL
FACTORS; (2) SURCHARGE ITS
HISTORICAL FUEL UNDERRECOVERIES; (3) SURCHARGE ITS
ESTIMATED FUEL UNDERRECOVERIES; AND (4) RELATED
GOOD-CAUSE WAIVERS
§
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§
§
§
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§
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§
§
BEFORE THE STATE OFFICE
OF
ADMINISTRATIVE HEARINGS
POST-HEARING BRIEF OF CITIES OF AMARILLO AND SPEARMAN
I.
INTRODUCTION
The main issue in this case concerns whether short-term (one year or less) firm sales
should be treated as off-system sales for fuel costs purposes. The Cities of Amarillo and
Spearman (Cities) respectfully submit that such sales should be treated as off-system and that
Southwestern Public Service Company (SPS) has failed to meet its burden of proof on this
issue.4
The Company forecasted revenues (firm and non-firm) from off-system sales in Errata 3
of $268.7 million on 4.8 million MWh for the 2001 rate year. Of that amount SPS proposed to
include only $22.7 million (8.4%)5 of the total projected rate year off-system sales revenues as
an offset to total system eligible fuel expenses.
In violation of the Commission’s rule
4
PUC SUBST. R. § 25.237(c)(1) and (2).
5
On May 8, 2001 the Company filed a revised forecast for firm sales with its fourth errata using a new rate year
(7/01 through 6/02) that was 1.8 million MWh (43%) higher than the forecasted amount presented in Errata 3.
However, the Company later changed its definition of off-system sales when it filed its last errata on the day of
hearing (SPS Ex. 21) to exclude all firm sales. The revised forecast suggests that the percentage of off-system
sales reflected in the calculation of the fixed fuel factor, given the new rate year, will actually be much smaller
than 8.4%.
1
requirements that the entire revenue from off-system sales shall be credited to eligible fuel
expenses, the Company recognized only a portion of the revenue it projects to receive from nonfirm off-system sales in its calculation of the fuel factor. SPS’ fuel factor proposal, therefore,
does not utilize a “reasonable estimate” of off-system sales during the period that the revised fuel
factors are expected to be in effect, because SPS has not recognized revenues from short-term
firm off-system sales in its fuel factor calculations, even though the Company has included the
costs of such sales.6
The issue of whether short-term firm off-system sales margins should be credited has not
been litigated or decided in any previous SPS proceedings. See Appendix H. SPS’ argument
that is has always credited only non-firm sales is unpersuasive. So that the revised fuel factor is
calculated correctly, Cities recommend that the Company’s revenues from four short-term firm
sales offset eligible fuel expenses. In the present case, these sales encompass transactions during
the rate year between SPS and the following companies:




El Paso Electric Company (EPE);
Public Service Company of New Mexico (PMN);
Western Area Power Administration-Colorado River Storage (WAPA);
and
Oklahoma Gas and Electric Company (OGE).
Inclusion of the revenues for the rate year from sales to these companies by SPS will ensure that
a reasonable estimate of off-system sales will be reflected in the revised fuel factor calculation
for SPS consistent with PUC SUBST. R. § 25.237(c)(1)(B) and that the significant increase in
SPS’ system average fuel costs resulting from such sales will be appropriately offset by the
revenues the Company receives from such transactions.
6
PUC SUBST. R. § 25.237(a)(1) & PUC SUBST. R. § 25.236(a)(7)(C).
2
SPS’ and Cities’ proposed fuel factor calculations, given these changes to the estimate of
off-system sales, are as follows:
Voltage Level
Fuel SPS’
Current
Factor7
Proposed Cities’
Fuel Factor
Fuel Factor
Secondary
Distribution $0.022343
Level
Primary Distribution Level $0.022037
$0.029600
$0.024274
$0.029196
$0.023943
Sub-Transmission Level
$0.021094
$0.027945
$0.022917
Transmission $0.020974
$0.027787
$0.022787
Backbone
Level
Proposed
Moreover, Cities recommend that SPS’ forecast for Additional Firm Sales in the rate year
should be removed from the fuel factor calculation (i.e., not treated as on-system sales) because
SPS has failed to meet its burden of proof that these sales are sufficiently certain to be included
in its fuel factor calculation. Removing these unspecified and highly speculative additional offsystem sales will significantly reduce the Company’s average fuel costs in the rate year and
therefore result in a more reasonable fuel factor for Texas retail ratepayers.
Finally, Cities recommend that the Public Utility Commission (Commission) investigate
the SPS buy/resell arrangement with EPE and Public Service of Colorado (an SPS affiliate) at
the time of SPS’ next fuel reconciliation proceeding to ensure that Texas retail customers do not
subsidize SPS’ below-market sales and self-dealing with its affiliates.
II.
BACKGROUND
SPS’ actions tainted the credibility of its case throughout this entire proceeding. For
example, the record evidence demonstrates that SPS:
7
SPS’ current fixed fuel factor was last revised in PUC Docket No.22810 on October 2000. SPS’ proposed fuel
factor is the same as the interim fuel factor approved in April of this year.
3

despite admitting the four contracts at issue in this case are off-system sales,
and after filing four earlier erratas which included firm off-system sales,
remarkably, on the first day of hearing, actually changed its filing such that all
firm off-system sales were removed;

despite knowing the information to be incorrect, and despite numerous
corrections to its off-system sales schedules, failed to timely correct its filing
to remove “Additional Sales” that it knew it did not make during the first four
months of 2001; and

entered an agreement with EPE to deliver energy at below market prices
during off-peak periods to SPS’ affiliate, perhaps for resale into the energy
starved California market, when there is no reason why SPS itself could have
made such sales, and in such manner as to avoid the very PUCT rule that
requires SPS to share those profits with Texas ratepayers.
These actions demonstrate a consistent pattern of withholding margins from Texas retail
ratepayers through deception and bending rules in a manner that is clearly contrary to Texas law
and longstanding ratemaking principles, which needs to be addressed now in this proceeding.
4
A.
SPS Admitted the Four Contracts Are Off-System
Despite admitting in its pleadings that the four contracts at issue in this case are offsystem sales, on the first day of the evidentiary hearing SPS desperately attempted to escape the
ramifications of its admissions by wholly amending its application. In SPS’ third “errata,” on a
schedule entitled “Summary of Off-System Sales (Firm Power Sales)(Net MWh)”, the Company
included each of the disputed contracts. Also, when requested during discovery to “… identify
each of the off-system sales transactions presented on Schedule FF-4.4b that are firm
transactions …”, SPS’ sworn response included each of the disputed contracts.
Under the
semantic guise of an “errata” SPS, for the first time (and contrary to its application and every
previously filed errata in this case), removed all firm off-system sales from its schedules.8 This
was a transparent and desperate last minute attempt to conceal the fact that the Company had not
credited revenues from these sales to eligible fuel expenses charged to retail ratepayers as
required by the Commission’s fuel rule.
B.
SPS’ Failure To Remove “Additional Sales” From Its Schedules Adversely
Impacted Fuel Factor Calculations
Although SPS filed several “errata” affecting its off-system sales schedules, it failed to
timely remove from its filing certain unspecified “Additional Sales” for which no contracts had
been executed and which, therefore, are not sufficiently certain to be included in setting the
8
SPS submitted its fifth “errata” on the first day of the evidentiary hearing and asserted that its contents merely
reflected the company’s rebuttal position in this case. Interestingly, since the company removed the entire
category of firm off-system sales from its fifth “errata”, despite having previously clearly identified specific firm
off-system sales, the company apparently rebutted not only Cities but also itself.
5
Company’s fuel factor.9 By including sales that did not occur, SPS unreasonably increased its
estimated rate year fuel costs and the resulting fuel factor by driving up forecasted system gas
usage and fuel costs. SPS’ own witnesses actually admitted, reluctantly on cross-examination,
that including sales that did not occur adversely impacted the projected fuel costs.10
Further, SPS’ witnesses stated “Additional Sales” are “sales that are expected to be made,
but [for which] no actual contract is in place.”11
SPS’ evidence, as discussed above,
demonstrates that it is impossible to predict from one year to the next, which, if any, “Additional
Sales” will be made. Significantly, the mere fact that these sales are highly unpredictable (i.e.,
not known and measurable), and are projected to have a term of one year or less (i.e., nonrecurring in nature), makes these transactions inappropriate for inclusion either in setting a fuel
factor or in setting this case.
By providing false information on such highly speculative transactions, which serve to
drive up system average fuel costs, SPS demonstrated its credibility with regard to short-term
firm off-system sales is, at best, suspect. Remarkably, in his rebuttal testimony, SPS witness
Hudson even criticized Cities’ witness Norwood for proposing to adjust credit revenues from
“Additional” firm sales to fuel expense, noting in his rebuttal that such sales “are only
anticipated sales at this time.” As admitted on cross-examination, SPS in fact knew that no
“Additional” firm sales had occurred in 2001 when Mr. Hudson filed his rebuttal testimony, but
the Company continued to include these non-existent sales in its fuel factor forecast, thereby
9
SPS submitted its application on February 21, 2001. That application included MW sales for January and February
2001 that SPS knew, at the time it filed its application, did not occur. SPS filed three “errata” to its application
between February 21 and April 9, 2001. In the third “errata”, filed on April 9, SPS included MW sales for
January, February, March, and April that SPS knew did not occur. Between April 9 and May 16, the day the
evidentiary hearing began, SPS filed rebuttal testimony and a fourth “errata”. However, SPS failed to remove
from its schedules the data for MW sales it knew did not occur until it did so in response to an objection raised by
Cities on May 16, 2001 (Tr. pp. 51-64).
10
Tr. 314/2-10 (Lemmons cross).
6
driving up natural gas consumption and system average fuel costs. The Commission should not
allow the Company to drive up fuel charges to Texas retail customers through such unabashed
deception.
C.
SPS is "Laundering" Power to its Affiliate to Avoid Sharing Off-System
Sales Margins with Texas Ratepayers
On January 1, 2001, SPS entered into a power sale agreement with El Paso Electric
(EPE) to sell 103 MW of Peak and Off-Peak Energy for one year beginning January 1, 2001 and
ending on December 31, 2001.12 Simultaneously EPE entered into an agreement to sell 103 MW
of Off-Peak Firm Power Service to Public Service of Colorado (PSCo) contingent on EPE
receiving the same amount of energy through the Eddy County tie from SPS.13 PSCo pays EPE
what SPS charged for the off-peak energy, plus a small adder.14 The SPS sale to EPE made it
possible for its sister company, PSCo, to make huge margins by selling to energy-starved
California and other markets in the Western United States.15 SPS could have, and has in the past,
sold power directly to customers in the Western market.
However, by the “laundering”
transaction through EPE to its affiliate SPS avoided sharing the margins from those sales with
the ratepayers who paid for the facilities to make these sales possible, saving these margins
instead for the company’s shareholders. This transaction is discussed more extensively infra. It
is another example of SPS actions designed to circumvent its obligation to use off-system sales
revenues to minimize eligible fuel expenses charged to Texas retail ratepayers.
11
Tr. 310/19-20 (Lemmons cross).
12
Cities Ex. 12.
13
Cities Ex. 17.
14
Cities Ex. 23 at 15.
15
Tr. 406/ 15-17 (Norwood response to ALJ).
7
III.
STANDARD OF REVIEW AND BURDEN OF PROOF
PURA § 36.203 authorizes the Commission to adopt rules to adjust an electric utility’s
fixed fuel factor. See Appendix F. The Commission has issued rules that allow an electric utility
to set and revise its fuel factors in a timely manner. See Appendix G. These Commission rules
are clear and unambiguous in their requirement that all off-system sales by SPS be credited
against fuel expense for purposes of calculating a fuel factor. Net eligible fuel factor expenses
are calculated by offsetting eligible fuel expenses by the revenues from off-system sales in their
entirety. Section 25.236(a)(7) provides as follows, in relevant part:
(7) . . . In addition to the expenses designated in paragraphs
(1) - (6) of this subsection, unless otherwise specified by
the commission, eligible fuel expenses shall be offset by:
(c) revenues from off-system sales in their entirety,
except as permitted by paragraph (8) of this subsection.16
The rule could not be plainer: off-system sales margins are required to be off-set against
fuel expenses, without regard to whether they are firm or non-firm off-system sales.
Moreover, the utility has the burden of proof in a fuel factor revision proceeding. PUC
SUBST. R. § 25.237(c)(1). That rule provides:
In a proceeding to revise fuel factors, an electric utility has
the burden of proving that:
(A)
the expenses proposed to be recovered through the
fuel factors are reasonable estimates 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. . . .17
16
This exception is not applicable because SPS presented no proof that an independent system operator or functional
equivalent organization exists in its transmission region or that it has general access tariffs for both firm and nonservice. Therefore, SPS is not entitled to share in any of the margins from off-system sales.
17
PUC SUBST. R. § 25.237(c)(1) (emphasis added).
8
At the beginning of the hearing, the ALJ expressed the opinion that treatment of offsystem sales revenues may not be an appropriate issue for a fuel factor revision proceeding.
However, under PUC SUBST. R. 25.237(c), the issue of whether SPS has properly and accurately
credited off-system sales revenues to eligible fuel expenses is part of the Company's burden to
show it appropriately calculated its estimated fuel expenses in a fuel factor revision proceeding.
In addition, it is the Company’s burden to request and demonstrate that it is eligible to retain
10% of the margins from off-system sales, and SPS has not made such a request in this
proceeding.
IV.
TREATMENT OF OFF-SYSTEM SALES REVENUES
A.
Short-Term Firm Sales Are "Off-System" Sales.
1. SPS admitted the disputed contracts are off-system and this treatment is
supported by FERC and Commission requirements
The four transactions in dispute (EPE, PNM, OGE and WAPA) in this proceeding
represent short-term firm off-system sales. SPS argued at the hearing that the sales associated
with these four contracts are “on-system,” but the Company is wrong. First, SPS has already
admitted that these contracts are for sales that are off-system. Second, consideration of several
key definitions explains why these contracts are “off-system.”
The short-term firm sales at issue in this case are off-system sales and the entire revenue
from such sales should be used to offset SPS’ eligible rate year fuel expenses. In his rebuttal
testimony, Mr. Hudson states:
Q. How does the FERC treat wholesale firm sales in its
ratemaking process?
9
A. … SPS’ long-term firm and intermediate firm sales are
addressed in the base ratemaking process because their
characteristics are known and can be included in the
base rate cost of service allocation.18
Mr. Hudson only described FERC’s treatment of long- and intermediate-term firm sales; he
neglected to explain that short-term firm sales are not addressed in the base ratemaking process.
The explanation for his omission, however, is simple. During cross-examination, he explained
that under the FERC’s definitions, short-term firm sales are for one-year or less.19 Thus, their
“characteristics” cannot be known with any degree of accuracy such that a utility could plan,
construct and operate capacity to serve short-term sales. The fact that these contracts were
executed within a very short time before service was initiated, and that the agreements specify
that neither the buyer nor seller has any obligation to purchase or serve beyond the one-year term
of these transactions, demonstrates that these short-term sales were not, and could not have been,
planned and included in SPS wholesale or retail base rates.
18
SPS Ex. 20 at 33, lines 4-10 (Hudson rebuttal).
19
Tr. 499/4-14.
10
Further, documents provided by SPS, relating specifically to Mr. Hudson’s rebuttal, also
admit that each of the four disputed contracts is a short-term firm off-system transaction. All
sales for resale are either “Requirements” or “Coordination” sales. 20 Requirements services are
either “Full” or “Partial.” An exhibit produced by Mr. Hudson at his deposition lists SPS’ “Full”
and “Partial” requirements contracts.21 That same exhibit also lists several “Firm” contracts,
including the four short-term sales at issue. The duration of SPS’ Requirements contracts is five
years or more, but the duration for each of the “Firm” contracts is for one-year or less, and some
are for less than six-months. The long- and intermediate-term contracts (the Requirements
contracts) are the type for which the utility typically would have an ongoing obligation to plan
and construct new generating facilities in order to ensure service under such agreements. There
is no such ongoing obligation to plan and construct generating capacity to serve short-term firm
or non-firm off-system sales; therefore, it is not appropriate to include such transactions in
setting a utility’s base rates.
Finally, in SPS’ third “errata,” on a schedule entitled “Summary of Off-System Sales
(Firm Power Sales)(Net MWh)”, the company included each of the disputed contracts.22 Also,
when requested during discovery to “… identify each of the off-system sales transactions
presented on Schedule FF-4.4b that are firm transactions …”, SPS’ sworn response included
each of the disputed contracts.23
That response was never supplemented or amended and Mr.
Hudson, in fact, adopted it.24
20
Cities Ex. 3 at 13 (coordination services).
21
Cities Ex. 11 at Bates 319 (produced as DTHDepo_Q1, Page 319); see Appendix B.
22
SPS Ex. 14 at 6 of 41 (Bates stamped 13).
23
Cities Ex. 8.
24
Cities Ex. 9 (SPS list of additional sponsor filed May 16, 2001).
11
Although the Commission rules do not define “short-term” sales, FERC has a longstanding definition of short-term sales as those for one-year or less.25 It is appropriate to
consider FERC definitions in this proceeding since SPS acknowledged that the sales at issue are
FERC jurisdictional sales.26 The duration of each of the disputed contracts is one year or less.27
The Commission defines a “native load customer” as one on whose behalf an electric
utility has an obligation to construct and operate its system to meet in a reliable manner the
electric needs of the customer.28
The Commission’s rules do not define an “off-system
customer,” but, logically, it follows that an off-system customer would be any customer other
than a native customer. This is, in fact consistent with FERC definitions. FERC states that all
sales are either “Requirements” or “Coordination” services; requirements service is service for
which the utility builds capacity and has a continuing obligation to serve, and coordination
service is everything else (including, notably, long-term firm services that are not requirements
services).29 Moreover, it is well settled that:
Capacity is planned and investment costs incurred to serve
a utility’s native load. Capacity costs are placed in rate
base and allocated among native load customer groups
using the cost allocation method. Such costs are incurred
to provide long-term firm service to those groups.
Opportunity sales make use of any capacity excess to the
native load … [such as] firm power transaction in which
the seller is able to commit capacity for a certain time
period.30
25
SPS Ex. 20 at 121-126 (Hudson rebuttal) (“short-term firm service has a duration of each period of commitment
for service of one-year or less”) and Tr. 499/9-19 (Hudson Cross).
26
SPS Ex. 20 at 8, line 18 (Hudson rebuttal).
27
See, e.g. Cities Ex. 11.
28
PUC SUBST. R. 25.5(41).
29
Cities Ex. 3 and SPS Ex. 20 at 121-126 (Hudson rebuttal) (long-term firm service has a duration of five years or
longer and is a distinct category from requirements service).
30
20 FERC ¶ 61,290, p. 61,547. Appendix E.
12
Clearly, the distinction between “native load” or “on-system” and “off-system” is not dependent
upon a classification as either “firm” or “non-firm.” Further, while the duration of service, the
longer it gets, may suggest the utility may be able to plan for and construct production to serve a
particular load, a prudent utility would not build or otherwise commit to purchase generating
capacity to meet short-term sales commitments of one year or less. Indeed, it would not be
practical or consistent with sound ratemaking principals to include short-term sales in base rates,
since by definition, such short-term sales are non-recurring in nature. Therefore, the distinction
between on-system and off-system is determined by ascertaining whether the particular sale was
made from generating capacity included in the native load’s base rates.
The differences between native system sales and off-system sales are straightforward.
These differences can be summarized from Commission and FERC definitions and practice as
follows:
13
Native System Sales
Off-System Sales
Continuing in nature firm Short-term (one-year or less)
sales.
firm and non-firm sales.
Utility
has
continuing Utility has no continuing
obligation to serve.
obligation to serve.
Characteristics
Utility plans and constructs Driven
by
system to serve.
economics.
short-term
Generally curtailable before
native load.
Retail sales within traditional Opportunity/coordination
service area.
sales.
Types of Transactions
Wholesale full and partial Emergency power.
requirements sales.
Interruptible power.
Short-term firm sales.
Full slice of system allocated Not considered in base rate
in base rates.
setting process.
Market-based
charges.
Ratemaking Treatment
Average system fuel charges.
Marginal
charges.
demand
cost-based
fuel
Revenue crediting/sharing of
margins.
2. These contracts were not included in SPS’ last base rate case.
Although SPS asserts that these four contracts should be treated as on-system sales
(meaning that the Commission should assume that these sales have been allocated a full slice of
the system and that the revenues from these sales have been included in the cost of service), the
transaction contracts for these short-term sales were signed only within the last two years
14
(OG&E had a prior contract that was extended by another 100MW last year).31 When short-term
off-system sales are made by a utility, a risk of subsidization by native customers exists because
only native system sales are assigned a full slice of system cost allocation in base rates. SPS
rebuttal witness David T. Hudson testified that existing Texas retail base rates were set in 1992
as part of SPS’ last base rate case. At that time, the Commission assigned only 20% of
production plant costs to the Texas wholesale jurisdiction, while Texas retail customers were
assigned the remaining 80% of production costs.32 Coming nearly a decade after SPS’ last rate
case, these four contracts represent some of the Company’s most recent additional load. They
could not, therefore, have been assigned a full slice of system cost based on a native system load
profile that existed in 1991 and 1992. In fact, at the time of its 1992 rate case, SPS had no shortterm firm off-system sales; its only two firm off-system sales at that time were long-term (five
years or more) sales to TNP and EPE. The EPE contract expired in 1997 and the TNP contract
expires in 2001.
3. There is no merit to SPS witness Hudson’s “Replacement Theory”
Moreover, it would not be reasonable to assume that sales under these contracts represent
a part of, or a replacement for, the Company’s native load that has left the system. SPS’ current
wholesale firm load comprises over 1473 MW. The wholesale firm load described in SPS’ last
rate case was only 946MW. Even though some customers have left the system, wholesale load
has experienced a significant net increase since 1992.
Cities Ex. 25 (DSN-8 Revised)
demonstrates this point. It shows that while Texas retail sales have increased by 26.1 % since
Docket No. 11520, total wholesale firm sales have increased by 130.7%. Therefore, it would be
31
Cities Ex. Nos. 12-15 (none of the disputed contracts was signed before February 29, 2000).
15
presumptuous and incorrect to conclude, without reviewing the Company’s entire load picture,
that these four contracts in particular have replaced recent losses in wholesale native load. In
fact, after excluding the 383 MW of firm capacity sold under the four transactions at issue in this
case, SPS’ remaining 1,090 MW of wholesale firm load sales (which the Cities are not
contesting) is still substantially higher than the 946 MW of wholesale firm load which apparently
was considered in designing SPS’ current base rates in 1992. Additionally, the 946MW of
wholesale firm load native to the system at the time of SPS’ last rate case comprised full
requirements load (Cooperatives and municipals) and two small long-term firm contracts.33 By
contrast, these four contracts represent short-term wholesale transactions, which are not the same
quality or type of load that would be given base rate treatment.
On the other hand, the Company’s current Unbundled Cost Of Service (UCOS) filing
supports the proposition that this new load, which has been added since the last base rate case,
has not been incorporated into SPS’ base rates. If recent firm sales, such as with these four
contracts, are already included as a part of native system load, and these new short-term
transactions are simply replacing wholesale load losses as SPS contends, then there should not be
the need to make such a substantial change to the existing 20% wholesale production plant
allocation to reflect recent load. SPS, however, indicated in that UCOS filing that the current
production plant allocation to the Texas wholesale jurisdiction should be raised to 33% instead of
the 20% allocation which apparently underlies SPS’ current base rates.34 Since these four
contracts represent some of the Company’s most recent additional load, the Company’s UCOS
32
Tr. 464/19 (Hudson cross).
33
SPS Ex. 20 at DTH-R1 (p. 2) at Bates 47. The TNP contract was for twenty years (December 1981-December
2001). Cities Ex. 8 and 11 (Appendix B and C). The EPE contract was for five years. 60 FERC par 61,210
(August 28, 1992).
34
Tr. 470 /1 & 13.
16
proposal to increase its wholesale allocation suggests that these recent short-term firm contracts
are not included in native system load used for the 1992 production plant allocation.
Accordingly, there is no credible basis in the record for asserting that recent short-term firm sales
are simply part of or replacement for native wholesale load for cost allocation purposes.
In any event, it would not be reasonable to treat these contracts as recurring, native load,
for purposes of the fuel factor calculation or designing base rates. The preponderance of the
evidence indicates that a utility would not construct and plan its system in such a manner as to
recover in base rates one-year contracts, because such sales are clearly non-recurring in nature.35
Even though the new rate year runs from July 2001 to June 2002, three contracts will expire by
the end of 2001 and the WAPA contract will expire in February 2002. The evidence does not
support finding that these contracts would be renewed and those sales would continue throughout
June 2001/July 2002 rate year. Even the Company acknowledged that sales outside of the
contract period should not be recognized for forecasting purposes. While the possibility exists
that SPS and the buyers may agree to renew all four of these contracts for another year, SPS
witness Lemmons indicated that it would be speculative to include sales in a forecast unless
those sales are based on an actual signed contract, and in fact SPS’ rate year forecast does not
reflect these four transactions after 2001.36
4. The contract terms for the four transactions show them to be off-system
sales
The terms of the four disputed contracts demonstrate that they are short-term firm offsystem sales. Each contract is performed according to the terms of a “Master Agreement” and a
35
SPS Ex. 20 at DTH-8, Bates 286 (Norwood Deposition page 28).
36
Tr. 313.
17
specific “Transaction Agreement.”37 The Term of each Transaction Agreement between EPE,
PNM, WAPA, OGE, and SPS is, under industry terminology, exactly one (1) year. Any sales
agreement of one-year or less is, according to FERC, short-term.38 The four disputed contracts
are short-term contracts that were signed nearly a decade after SPS’ last base rate case. The
dates on these contracts are as follows:
Contract
EPE
Amount
103MW
Date Signed
January 1, 2001
Term
1/1/01-12/31/01
Cities Ex. 12
PNM
50MW
October 17, 2000
1/1/01-12/31/01
Cities Ex. 13
WAPA
30MW
February 29, 2000
3/1/00-2/28/01
Cities Ex. 14
OGE
200MW
November 7, 2000
1/1/01-12/31/01
Cities Ex. 15
SPS is under no obligation to serve any of these contracting entities beyond the terms of
the individual Transaction Agreements.39 Pursuant to each Transaction Agreement, service is
subordinate to native load and may be curtailed. Unlike the requirements contracts, which may
only be curtailed for emergencies, or the “Interruptible” contracts, which may be curtailed for all
“system contingencies,” The “Firm” contracts generally may be curtailed for force majeure and
emergencies.40 Further, either party may cancel the Master Agreement by providing a 30-day
written notice.41 Finally, as discussed above, none of the disputed contracts are for either Full or
Partial Requirements service and must, therefore, be off-system.
37
Cities Ex. Nos. 12 through 15 are “Transaction Agreements” and Cities Ex. No. 16 is each of the “Master
Agreements.”
38
P. 121-126 SPS Ex. 20 Hudson rebuttal. See, Fn. 23.
39
Tr. 366/ 14-17 (Lemmons cross).
40
Cities Ex. 11 (Bates 319) Appendix No. B.
18
B.
The Requirement to Offset Eligible Fuel Expense with Off-System Sales
Revenues Is Not Limited To Non-Firm Off-system Sales Under Commission
Rules And Cases
1. The history of the fuel factor rulemaking shows no distinction regarding
the kinds of off-system sales for which margin crediting is required.
SPS and Staff cite isolated comments in the adoption preamble for the fuel factor rule in
support of their position that short-term firm sales are excluded from the scope of the rule. But,
their analysis ignores the plain words of the rule, which contains no limitation regarding the
kinds of off-system sales for which margin crediting is required. Further, the Commission's
comments during adoption of the applicable provisions evidence no intent whatsoever to limit
the rule to non-firm off-system sales. All off-system sales are covered by the rule, including
short-term firm sales.
The language requiring off-system sales margins to be credited was first added to the fuel
rule in 1993, when the Commission overhauled the rules applicable to fuel costs and fuel
proceedings. As the adoption preamble notes, the most contentious issue was the definition of
eligible fuel expense.42
Several parties submitted comments on numerous aspects of fuel
expense. But, the preamble noted only two comments regarding sales margins. First, El Paso
Electric Company (EPEC) commented that economy energy sales should be considered in fuel
reconciliation proceedings but not in the setting of the fuel factor. Texas Industrial Energy
Consumers (TIEC) commented that the rule as proposed did not address the treatment of offsystem sales expenses and revenues and advocated using all margins as an off-set to fuel
expenses.43
In response to TIEC's comments, the Commission amended the rule as proposed to
41
Cities Ex. 16; Tr. at 350, lines 6-16 (Lemmons cross).
42
See generally, 18 Tex. Reg. 836 (February 9, 1993).
19
recognize off-system sales, including in setting the fuel factor. Recognizing that in the past
margins sometimes had been split between customers and the utility, the Commission included a
transition provision (Section 23.23(b)(6)) to continue to recognize any previous Commission
orders permitting sharing of margins.44 No rule provision allowing margin sharing was adopted
at this time; instead, the opportunity for a 10 percent retention of margins by utilities satisfying
certain criteria as currently provided for in Commission rules was not adopted until 1999. As
enacted in 1993, the rule unequivocally required "revenues from off system sales in their
entirety" to be included in the calculation of eligible fuel expense.45
The Commission chose to require revenues from all off-system sales to be credited. SPS
and Staff cite to isolated comments in the preamble in an attempt to show the Commission
intended to limit the term "off-system" to the type of sales that SPS had identified in its past
dockets and had included in its calculation of fuel expenses (non-firm only). But, SPS and Staff
wrongly construe the Commission's comments regarding recognition of past rulings. As the
preamble text makes clear, the Commission expressed its intent to continue margin splitting
during a transition period if the Commission had so ordered previously, but otherwise expressed
the clear directive that off-system sales margins be fully credited to customers.
The issue of
firm/non-firm off-system sales was not addressed in the preamble. Previous Commission rulings
in SPS cases, though permitting SPS to share in off-system sales margins at the 25 percent level,
never authorized SPS to exclude short-term firm off-system sales from the total margins to be
shared. In fact, this issue had not been litigated in any SPS case prior to adoption of the 1993
fuel rule since the Company has not reported any short-term firm off-system sales in its rate
43
18 Tex. Reg. 836, *838.
44
18 Tex. Reg. 836, *844.
45
18 Tex. Reg. 836, *841, Section 23.23(b)(2)(B)(vi)(III).
20
filing schedules until this case; therefore, language in the preamble recognizing previous
Commission orders referred to the issue of margin sharing (which had been specifically
addressed in previous orders), not to the issue of what constituted an off-system sale (which had
not been litigated or ruled on in previous orders).
Staff has attempted to construe the EPEC and TIEC comments addressed in the preamble
as evidence that the Commission considered "economy" and "off-system" sales to be the same
and that neither included short-term firm sales. But, this analysis is quite weak because the
Commission simply grouped comments from these two parties for purposes of addressing the
issue of off-system sales margins. There is nothing in the preamble supporting Staff's analysis
that the Commission considered the terms to be synonymous or that by addressing the comments
together, the Commission intended to exclude short-term firm sales from the rule.
21
2. The Commission’s decision in Docket No. 9945 assumed that the
requirement to offset eligible fuel expenses with off-system sales revenues
applies to short-term firm off-system sales
To determine the meaning or scope of the term "off system sales," and the applicability of
the Commission’s fuel rule to such transactions, it is instructive to review a significant case
decided immediately before the 1993 fuel rule amendments. In Docket No. 9945, Application of
El Paso Electric Company for Authority to Change Rates, 18 PUC BULL. 9, September 1992,
the Commission considered the issue of whether margins from EPEC’s five-year firm off-system
sale to CFE should be shared between ratepayers and the utility. Although the Commission's
Examiners proposed equal sharing of the margins, the Commission ultimately permitted the
Company to retain the margins entirely because of its extremely poor financial condition. There
is absolutely no indication that the Commission's decision to permit EPEC to retain the margins
was related to the firm nature of the short-term sales or that the Commission considered the sale
to be anything other than an off-system sale. A review of both the Examiners' Report and the
Commission’s Final Order demonstrates that all parties and the regulators considered short-term
firm sales to be off-system sales.
Docket No. 9945 was litigated in 1991, and the Commission's Order on Rehearing was
issued in February 1992. In February 1993, the Commission adopted the rule amendment
requiring off-system sale margins to be credited against fuel expense in their entirety, with
recognition of a transition period for utilities previously permitted to share in margins under
Commission order. Docket No. 9945, with its extensive policy discussion of how to divide
margins for a short-term firm "off system" sale, demonstrates that in its February 1993
22
rulemaking, the Commission was using the term "off system sale" to include short-term firm
sales.
3.
Subsequent fuel rulemakings support Cities' position
Rulemaking activity subsequent to the February 1993 fuel rules also demonstrates the
Commission has not interpreted the term "off system sales" to exclude short-term firm sales. In
December 1993, the Commission amended the fuel factor rule to require that utilities use a
Commission application when filing fuel factor cases.46
In the application and supporting
testimony, the utilities were required to identify "off-system kilowatt-hour sales, and associated
fuel costs and revenues". The Commission drew no distinction between firm or non-firm offsystem sales.
Next, the Commission re-visited the issue of margin sharing, through rule amendments in
1999. 24 Tex. Reg. 4998 (July 2, 1999).47 At this time, the Commission enacted the provision in
place today, allowing retention of 10 percent of off-system sales margins if the utility meets the
criteria in the rule. Throughout the preamble discussion adopting this change, the Commission
evidenced no intent to limit the meaning of "off system" sales as SPS urges in this proceeding.
During the 1999 amendments, the Commission also determined that it was time to end
the long transition period that had been established by rule in 1993, permitting utilities to
continue to share margins under previous Commission orders though such sharing continued
with the 1993 rule language requiring that off-system sales margins be credited in their entirety.
The Commission noted that the concept of a transition period is one that is temporary in nature.
46
18 Tex. Reg. 9096, *9098 at Section 23.23(b)(2)(C).
47
During these amendments, the Commission also re-organized the rule numbering, moving the fuel rule from
Chapter 23 to Chapter 25.
23
The transition had existed since 1993, and since then the Commission had attempted to move all
utilities under the current fuel rule, regardless of inconsistencies with Commission orders prior to
1993.48 The elimination of the transition period evidenced a desire by the Commission to
consistently require all off-system margins to be credited, unless the utilities could meet the new
criteria for ten-percent retention. Again, SPS has not requested or attempted to show that it
qualifies for the ten-percent off-system sales margin retention in this case.
4. The criteria for retaining ten-percent margins supports Cities' position
Finally, the criteria for 10 percent margin retention show that the Commission intended
off-system sales to include both firm and non-firm sales. As one of the criteria for 10 percent
margin retention the Commission required that there be a generally applicable tariff for firm and
non-firm transmission service offered in the transmission region in which the utility operates. 49
This requirement recognizes that utilities commonly make both types of sales as off-system
sales.
48
24 Tex. Reg. 4998, 5003-5004.
49
24 Tex. Reg. 4998,*5007 (PUC SUBST. R. 25.236(a)(8)(B)).
24
5. SPS fuel cases have not carved out an exception for the margin crediting
requirement
SPS rebuttal witness Hudson cited numerous Commission cases as precedent for its
position, but the cases do not stand for the position SPS asserted.50 Significantly, in none of the
cases was the issue of short-term firm off-system sales margins litigated or decided.
See
Appendix H. Almost all the cases were settled and thus are poor precedent even on the issues
resolved in the cases. The cases involved issues such as whether SPS should share non-firm offsystem sales margins, the proper ratio of margin sharing, and the proper methodology for
flowing through margins to ratepayers. While it is true that these past cases addressed only nonfirm off-system sales, one cannot conclude therefrom that other kinds of off-system sales were
specifically and deliberately excluded from margin crediting. In fact, short-term firm sales were
not at issue in the cases because SPS had no such sales at the time, or it failed to report them,
based on its unfounded theories that these transactions are not actually off-system sales or not
subject to the fuel rule crediting requirements. Regardless, since the cases do not address shortterm firm sales such as the four transactions at issue in this case, these past cases cited by SPS
are not relevant to this issue.
SPS’ citation to a long string of fuel cases in which the issue of short term firm sales was
not litigated or decided obscures the fact that this case is the first one in which SPS has made the
argument that it should not have to follow the Commission rule and credit all off-system sales
margins. SPS’ position is out of step with the common understanding of the term "off system"
sales, and its previous fuel cases do not bolster its position.
50
SPS Ex. 20 at 14. (Hudson rebuttal).
25
C.
The Commission Should Not Ignore the FERC Approach, Which Favors
Revenue Crediting, Not Base Rate Treatment, For Short-term Off-System
Sales Margins, Even When The Sales Are Firm Sales
PURA requires that Commission orders not ignore federal law.
PURA § 11.009
mandates that PURA not be applied in manner conflicting with federal law. That section
provides:
This title shall be construed to apply so as not to conflict
with any authority of the United States.
PURA § 36.001(b) requires that the Commission not issue an order conflicting with federal
regulations, which would include the FERC. That section provides:
A rule or order of the regulatory authority may not conflict
with a ruling of a federal regulatory body.
FERC has significant experience with wholesale off system transactions and the appropriate
regulatory treatment that needs to be considered when deciding this case.
The FERC has categorized short-term transactions or coordination transactions. The
FERC has stated:
The WSPP would continue to provide for coordination
transactions; however, as opposed to the two-year duration
of transactions under the experiment, the permanent Pool
would provide for transactions of one year or less. Services
would be identical to those in the experiment: Service
Schedules A through D would provide, respectively, for
economy energy service, unit commitment service, firm
system capacity/energy sales or exchange service, and
transmission service. (emphasis added).51
Clearly, the FERC has determined that as far as the Western System Power Pool (WSPP),
and in particular SPS, as a member, is concerned, short-term transactions shall be treated as one
51
Western Systems Power Pool, 55 FERC ¶ 61,099 at 61,302(1991).
26
year (the same time period as the contracts at issue in this case) to this or less shall be treated or
coordination sales.
Long-standing FERC policy, therefore, treats short-term sales as "coordination" sales,
whose revenues should be credited against expenses. These kinds of sales stand in contrast to
native load customer sales. Utilities plan and incur costs to construct capacity to meet their
native load obligations, and it is appropriate to reflect these costs in base rates through the cost
allocation process.
Furthermore, FERC discussed the differences between native load customers and
opportunity sales in Public Service Company of New Mexico, Docket No. ER80-313-001,
Opinion No. 146, September 17, 1982 (20 FERC ¶ 61,290) Appendix E. (emphasis added). It is
evident that under the FERC’s interpretation short-term sales, even when firm, require revenue
credit treatment because of their unpredictable nature.
Capacity is planned and investment costs incurred to serve
a utility’s native load. Capacity costs are placed in rate base and
allocated among native load customer groups using the cost
allocation method. Such costs are incurred to provide long term
firm service to those groups. Opportunity sales make use of any
capacity excess to native load. Such sales take many forms, from
interruptible split-the-savings economy sales (the seller’s lowest
dispatch priority) to firm power transactions in which the seller is
able to commit capacity for a certain time period.” (Emphasis
added.). . .
There are good reasons for preferring the revenue credit
method to cost allocation in reflecting opportunity sale transactions
in native load customer rates. Cost allocation is simply not
feasible in many cases. For many interruptible sales it is
impossible to know beforehand, at the time native load rates are
being adjusted, the quantities that will be sold during the test year
or during the period those rates will be in effect. In many sales, it
is not possible to predict from which unit or units a particular
customer will be served….Opportunity sales revenue is difficult to
predict. The volume and rates of opportunity sales are dependent
upon a number of factors, such as availability of capacity and the
27
relative hourly incremental operating costs of prospective buyers
and sellers.52
Transactions involving the sale of power from existing capacity built to serve native load
but temporarily available for sale to others are known as opportunity or coordination
transactions. These transactions do not cause the selling utility to plan or construct new capacity.
See, Southern Company Services, Inc., Docket Nos. ER91-150-006 and ER91-570-005, Order
Denying Rehearing and Directing Further Compliance Filing, December 21, 1992, 61 FERC ¶
61,339 at 62,336.53 By contrast, requirements sales are long-term commitments in which the
seller agrees to provide firm service to meet all or part of a buyer’s load.54
Regardless of whether the sales are called "opportunity", "coordination", "non-native" or
"off-system", the common thread is that such sales are sufficiently short in duration that the
utility does not plan capacity to serve the load. Because additional capacity is not planned or
constructed to meet the load, FERC does not consider it feasible to allocate capacity costs to
wholesale customer classes in a base rate proceeding by attributing short-term sales as part of
their permanent load (and permanent cost allocation). Margin crediting is a more effective
regulatory tool to deal with these short-term sales. If the Commission determines that short-term
sales should be treated the same as long-term native load, then the agency runs the risk of
adopting a ruling inconsistent with, and potentially in conflict with, an order of a federal
regulatory body.55
52
(pp. 61,546-61,547).
53
Coordination sales have been discussed extensively in a leading article, Coordination Transactions among
Electric Utilities, Public Utilities Fortnightly, Sept. 13, 1984, at p. 31. Short-term firm service arrangements fall
within the description of a coordination sale. Id. At 32. See, Appendix D.
54
Id. at 31.
55
PURA § 11.009 and PURA § 36.001(b).
28
D.
SPS' Exclusion Of Short-Term Firm Sales Margins Overstates Fuel Costs
For Native System Customers.
By understating the amount of off-system sales, SPS has overstated the fuel costs for its
native system customers. Offsetting rate year eligible fuel expenses by the revenues from shortterm firm off-system sales to EPE, PNM, OG&E, and WAPA will eliminate any problem in the
rate year caused by SPS’ understatement of costs to serve such off-system sales.
It is reasonable to offset eligible fuel expenses by revenues from these sales for purposes
of calculating the fuel factor, PUC Subst. R. § 25.236(a)(7)(C), because the average fuel cost to
serve these sales will be greater than SPS’ system average cost of fuel. The problem with the
SPS proposal is that the Company has assumed that on all of these contracts, which were for oneyear and shorter periods, the costs to serve these customers will be the same as the costs to serve
the retail customer.56 That assumption is not reasonable. First, as discussed earlier in this Brief,
these off-system customers did not pay for those plants to serve that energy, unlike the long-term
retail customer who has been buying from SPS for many years and who has paid for all these
plants. Second, if SPS did not make those sales, the energy costs for the Company would be
much lower because the marginal fuel in most hours for their system is gas.57
In Section IV.A, supra, Cities demonstrated that because only on-system, native load
customers were allocated a full slice of system costs, off-system customers are subsidized by
native load customers. Accordingly, the margins from off-system sales should be credited to
native load customers to reflect off-system use of plant that off-system customers do not pay for
through cost allocation.
56
SPS Ex. 20 at DTH-8, Bates 291 (Norwood Deposition page 48).
57
SPS Ex. 20 at DTH-8, Bates 291-92 (Norwood Deposition page 48-49).
29
The risk of subsidization is compounded because the off-system sales will cause the
energy costs for the Company to be higher, due to its reliance on gas as the marginal fuel. SPS
was forecasting that its average energy charge for its firm sales, noted as off-system in SPS’
Third Errata (SPS Ex. 14), will be about $30.57/MWh. The average cost for the four contracts in
dispute falls within a range ($29.60 to $31.92) of plus or minus $1.35/mwh of this overall
average cost.58 SPS Ex. 14 at Bates 47 (Errata 3 treats the energy charge component and the fuel
component as the same for firm power sales). The Company originally predicted that its offsystem projection would be lower than the Company’s average annual Texas retail fuel factor for
that same time period (2001), which the Company calculated at about $31.47/MWh.59 With the
rebuttal testimony, however, that picture changes. SPS is now projecting an average annual
Texas retail fuel factor for the new rate year of about $28.91/MWh. The Company also projects
a gas-fired generation total cost of $56.34/net MWh and a coal-fired generation total cost of
$13.70/net MWh.60 However, the Company did not revise its projections for off-system firm
sales costs, even though the Fuel Filing Package requires that those be provided.61 SPS’ failed to
provide this information in its rebuttal schedules; however, the fact remains that by attributing
system average fuel cost to these short-term sales, instead of the higher marginal fuel cost
incurred to serve these transactions, SPS’ proposed treatment of these sales drives up costs to
Texas retail customers. Cities’ Witness Scott Norwood, however, testified that typically the
average fuel cost to serve non-native load should fall near the high end of the range between a
company’s system average cost of fuel and average cost of gas-fired energy.62
58
Cities Ex. 14 at 16.
59
SPS Ex. 5 at Bates 122.
60
SPS Ex. 17 at Bates 17.
61
Cities Ex. 4 at Bates 40.
62
SPS Ex. 20 at DTH-8, Bates 286 (Norwood Deposition page 26).
30
Additionally, Mr. Norwood explained why SPS’ marginal requirements are supplied by
gas-fired generation. He testified that off-system sales are supplied only after SPS has served its
firm native system customers with its most economical power. Cities Ex. 1 supports this fact,
showing that the capacity factors for the year 2000 for the coal-fired plants typically are higher
and in a narrower range than the gas-fired plants.63 Given SPS’ system, gas-fired generation has
a forecasted average cost over double the cost of the company’s system average fuel cost. 64 He
also noted the correlation between the Company having approximately 5.5 million MWh of gasfired generation and also having about 5 million MWh of off-system sales in the same 2001 rate
year. He concluded that if SPS did not make its projected off-system sales, it would “be burning
a tremendously smaller amount of gas.”65 For each additional megawatt hour the company sells
to serve these off-system customers the average fuel cost will increase by the price of gas.66
That SPS’ fuel costs are driven by the costs of providing additional energy from gas-fired
generation is also supported by supported by testimony from SPS witness Karen Roberts. She
testified as follows:
Q: I guess I want to draw a distinction between on-system
and off-system sales. Are you serving your off-system
sales after you dispatch plants to provide service to
your on-system sales?
A: Yes. That’s my understanding.
Q: Okay. The additional energy that’s needed to provide
services to these off-system sales will primarily come
from gas-fired generation?
A: It could come from gas-fired. It could come from coalfired. It could come from purchased power.
63
Cities Ex. 1 at Bates 101-112.
64
Cities Ex. 23 at 17; Cities Ex. 25 at 2. See also, Cities Ex. 6 (demonstrates that the capacity factors for the gasfired plants typically is much lower than that of the coal-fired plants).
65
SPS Ex. 20 at DTH-8, Bates 292 (Norwood Deposition page 50).
66
SPS Ex. 20 at DTH-8, Bates 292 (Norwood Deposition page 49-50).
31
Q: Right. But primarily it would come from gas?
A: I would say, on a general basis that would be true.67
Finally, virtually all energy supplied by SPS above a certain base load level in the
proposed rate year (7/01 to 6/02) will come from gas-fired generation (the chart depicting the
generation mix for 2001 and 2002 reflects that additional energy above an approximate coalfired generation baseline comes from gas-fired generation).68 That fact plus the fact that unrebutted testimony shows that non-native load is dispatched after native load is dispatched and
therefore primarily served from higher cost gas-fired generation, indicates that native system
customers will be subsidizing the fuel costs to serve off-system sales in the proposed rate year.
If the Commission does not require SPS to offset eligible fuel expenses with the entire revenue
from off-system sales, or at the very least require that these sales be allocated their true marginal
cost based on gas-fired generation, Texas retail ratepayers will end up subsidizing the costs of
SPS’ short-term firm sales as well as the profits the Company makes from such sales.
V.
SPS’ FORECAST OF ADDITIONAL ON-SYSTEM FIRM SALES IS TOO
SPECULATIVE TO BE RECOGNIZED IN THE FUEL FACTOR
CALCULATION.
In its Application, SPS set forth detailed information regarding “Other” Off-System Sales
for the year 2001. SPS did not distinguish between Non-Firm and Firm Off-System Sales in its
Application, and even after it corrected this deficiency, the amounts and types of short-term firm
sales were changed by SPS thereafter in several Errata filings.
Furthermore, short-term firm sales are too speculative to reliably include as (i.e.,
“Additional Sales” (i.e., native system, on-system load) for fuel factor calculation purposes. In
67
Tr. 233-34.
32
this regard, the evidence demonstrates it was difficult even for the Company to reliably predict
firm sales through the end of the year. In its Application, the Company included “Firm and Nonfirm Off-system Other Sales” for 2001 of 1,340,280MWh.69 In its Third Errata, the Company
stopped reporting “Other Sales” but added an “Additional” category to firm off-system sales. No
additional or other sales were now included for non-firm. In the Third Errata SPS estimated
additional Firm Off-system Sales of approximately 610,396 MWh.70 This estimate would also
ultimately prove unreliable. In this its last errata, the Company zeroed out all the additional sales
for July 2001 through December 2001 that it had included only a month earlier in the Third
Errata. During cross-examination, SPS witness David Lemmons testified that no additional sales
had taken place for January through April of 2001.71 More importantly, he admitted that the
Company’s forecast for additional firm sales was completely wrong and that there “should be
zeroes for the entire year of 2001.”72
This last errata is especially significant because it shows that the Company is projecting
sales for the four contracts (EPE, PNM, OG&E and WAPA) to be non-recurring in nature.73 The
chart shows that the four contracts will not be renewed and as a result no KWh sales are reported
under the revised rate year after December 2001 (or February 2002 for WAPA).
SPS Forecast for 2002 (kWHs)
(EPE, WAPA, PNM, OGE)74
68
Cities Ex. 7.
69
SPS Ex. 2 at Bates 315.
70
SPS Ex. 14 at Bates 13.
71
Tr. 311.
72
Id.
73
SPS Ex. 21 at handwritten page 36 (FF-4.4f, Page 4 of 4).
74
Id.
33
PNM Firm
EPE Firm
OGE Firm
WAPA Firm
Jan
0
0
0
22,320,000
Feb
0
0
0
20,160,000
Mar.
0
0
0
0
Apr.
0
0
0
0
May
0
0
0
0
June
0
0
0
0
SPS has provided dramatic evidence as to why the four contracts should be
excluded from “Additional Sales.” As the foregoing chart illustrates, the four contracts are nonrecurring in nature and they are not the sort of transactions upon which system planners could
count on in order to construct generation facilities.
34
APPLICATION
OFF-SYSTEM SALES
FIRM AND NON-FIRM
OTHER
MWH75
OTHER
Energy Charge76
OTHER
Fuel Cost77
Jan – 01
113,832
5,244,000
3,182,200
Feb – 01
102,816
4,944,000
2,874,245
Mar – 01
113,832
5,244,000
3,182,200
Apr – 01
110,160
5,094,000
3,079,548
May – 01
113,832
5,244,000
3,182,200
Jun – 01
110,160
5,019,000
3,079,548
Jul – 01
113,832
5,294,000
3,182,200
Aug – 01
113,832
5,144,000
3,182,200
Sep – 01
110,160
5,044,000
3,079,548
Oct – 01
113,832
4,844,000
3,182,200
Nov – 01
110,160
4,844,000
3,079,548
Dec - 01
113,832
4,844,000
3,182,200
1,340,280
$60,803,000
$37,467,838
Errata No. 1 made corrections due to “invoice inaccuracies” for off-system sales. Errata
No. 1 was not filed until March 16, 2001. At that time SPS knew that the Other Off-System
Firm and Non-Firm sales information provided in the Application was terribly wrong for the
first three months of 2001 yet SPS made no effort to correct the errors. Errata No. 2 was filed
on March 23, 2001, yet no corrections or changes were made to the Other Off-System Firm and
Non-Firm sales Information.
75
SPS Ex. 2, Sch. FF-4.4b at Bates No. 315.
76
SPS Ex. 2, Sch. FF-4.4c at Bates No. 320.
77
SPS Ex. 2, Sch. FF-4.4c1 at Bates No. 324.
35
Errata No. 3 was filed on April 9, 2001. For the first time, Off System Firm and NonFirm sales were separately identified. The fundamental reason for the new filing was stated as
follows78:
SPS has reviewed Schedule FF-4.4 filed in its original
filing package following discussions with the City of
Amarillo concerning SPS’ treatment of off-system sales
margins.
First, clarity was sought regarding the
classification of certain sales as either firm or non-firm
sales. A review of the schedules found that this distinction
was not made as instructed by the fuel factor filing
package. SPS has revised Schedule FF-4.4 to clarify and
separate the firm and non-firm sales for both historical and
rate year.
The “other” off-system sales category disappeared in Errata No. 3 and in its place
“additional” was substituted. The additional category only appeared with regard to the Rate
Year off-system firm power sales. No off-system non-firm power sales were included in any of
the schedules under either additional or other.
78
SPS Ex. 14 at 4. See Appendix A.
36
ERRATA NO. 3
OFF-SYSTEM
FIRM SALES
ADDITIONAL
MWH79
ADDITIONAL
Energy Charge80
ADDITIONAL
Fuel Component81
Jan – 01
51,842
1,924,239
1,924,239
Feb – 01
46,825
1,886,819
1,886,819
Mar – 01
51,842
1,858,613
1,858,613
Apr – 01
50,170
1,587,725
1,587,725
May – 01
51,842
1,457,278
1,457,278
Jun – 01
50,170
1,467,749
1,467,749
Jul – 01
51,842
1,527,559
1,527,559
Aug – 01
51,842
1,489,900
1,489,900
Sep – 01
50,170
1,283,634
1,283,634
Oct – 01
51,842
1,257,502
1,257,502
Nov – 01
50,170
1,232,346
1,232,346
Dec – 01
51,842
1,291,598
1,291,598
610,396
$18,264,959.80
$18,264,960
Under Errata No. 3, SPS was using a 2001 Rate Year when clearly the Rate Year was
going to have to include a substantial portion of 2002. Even if all issues had been stipulated into
this proceeding, the Rate Year would have gone past the first quarter of 2002. Yet, it was not
until Judge Pomerleau on May 16, 2001, requested SPS to update its Application, consistent with
the new Rate Year, that the Company amended its Application to provide information for the last
six months of the Rate Year.
79
SPS Ex. 14 at p. 6 of 41, Bates No. 13.
80
SPS Ex. 14 at p. 15 of 41, Bates No. 22.
37
The evening of May 16, 2001, SPS delivered to the Cities Errata No. 5 to the Filing
Package, SPS Exhibit 21. The new Filing Package was based on a Rate Year of June 30, 2001 to
July 1, 2002. For the first time, SPS admitted it had no ADDITIONAL firm sales. On the last
page of Errata No. 582, SPS had zeros for each month from July 2001 through December 2001.
This was the first time SPS stepped forward and gave any inkling that the additional firm sales
for 2001 had not occurred. When asked about this situation, SPS witness, David Lemmons
admitted that none of these sales took place or were expected to take place for 200183.
Q. Well, but for each - - month of January, February,
March, April, there should be zeros, should there not?
A. Yes, sir, that would be correct.
Q. Now, is what you’re telling me with regards to SPS 21
– can you show me where those zeros appear?
A. In the megawatt hour information on Schedule FF-4.4f,
Page 36 - - Bates stamped or handwritten, however you
want to call it - - you’ll see that the additional firm
megawatt hours are zero.
Q. Okay. So that zero for the entire year of 2001. Is that
correct?
A. Yes, sir.
After further cross-examination, Mr. Lemmons admitted that incorrect data was included in the
Application and Errata No. 3 that SPS knew was wrong84.
Q. In the earlier - - the original filing, which was in
February, you had 706,180 for the fixed charge
component for January, did you not?
81
SPS Ex. 14 at p. 23 of 41, Bates No. 30.
82
SPS Ex. 21, Sch. FF-4.4f, page 4 of 4, handwritten page 36.
83
Tr. 311/6-20.
84
Tr. 311/21-312/20.
38
A. Yes, sir.
Q. And for February?
A. Yes, sir.
Q. And for all the months of 2001, did you not?
A. Yes, sir.
Q. And that was wrong, wasn’t it?
A. It was a forecast, sir. Everything is wrong there.
Q. Well, but January and February had already happened.
A. Okay.
Q. Now, when you got to Errata No. 3 - - that is, SPS
Exhibit 14 - - you went ahead anyway, in spite of - knowing at that point - - and it was filed on or about
April 8th of this year knowing that nothing had
happened for January, February, or March, and you
didn’t put zeros in there. You put these numbers, didn’t
you?
A. Yes, sir.
In spite of the fact that the second quarter of 2001 was well underway, Mr. Lemmons tried to
excuse SPS’ false and misleading information with regards to OTHER or ADDITIONAL firm
sales. According to Mr. Lemmons, who cares if the data is wrong, it is just a forecast 85. This is
an incredible position for the Company or any of its witnesses to take because not only was SPS
seeking to include 750,269 MWh of “Other Sales” in its fuel factor calculation, but in its original
filing it also sought to recover projected under-recoveries for February, March and April 2001
based on over-stated fuel costs projections which included these Additional firm sales which
never occurred. First, SPS had actual information – not forecasted information – for January,
85
Tr. 313/2-3.
39
February, March, and April, and second, the forecasted data is used to set the fuel factor for the
rate year, as acknowledged by Mr. Lemmons86.
Q. And what are we doing in this case, we’re setting a rate
year fuel factor, are we not?
A. Yes, sir.
Q. And that’s in the future, isn’t it?
A. Yes, sir.
Q. And this would have impacted that, would it not?
A. Yes, sir.
What is so bad about providing false information? It is highly relevant to the credibility to be
given SPS with regard to its ability to forecast “additional sales” with reasonable accuracy. The
failure to come clean – until the last minute – dramatically illustrates the highly speculative
nature of these unspecified Additional short-term firm sales. In fact, in his rebuttal testimony
SPS witness Hudson criticized Cities’ witness Norwood for his proposed adjustment to credit
revenues from “additional” firm sales to fuel expense, noting that such sales “are only
anticipated sales at this time.” Yet, at the time of this rebuttal testimony, SPS knew that no
additional firm sales had occurred in 2001 and yet the Company continued to include these nonexistent sales in its fuel factor forecast, thereby driving up natural gas consumption and system
average fuel costs. Furthermore, the fact that the projected additional short-term firm sales did
not occur underscores Cities contention that the cost and revenues from short-term sales of this
sort are appropriately dealt with in setting both interim and permanent fuel factors — which are
subject to final reconciliation at a later date — instead of in base rate proceedings. Short-term
86
Tr. 314/2-10.
40
firm sales, like the four at issue in this proceeding, are not the sort of transactions, which drive
the planning, and construction of power plants.
Beyond a twelve-month period of these
contracts, there is no assurance or obligation on the part of the buyer or seller, that such
transactions will be continued. As Mr. Lemmons pointed out, it would be a fool’s errand to rely
upon short-term firm contracts repeating themselves87.
Q. But until you have a contract on the dotted line, you’ve
got kind of an iffy situation, do you not?
A. Yes, sir.
Given the “iffy” and speculative nature of the Additional Sales, Cities recommend that
the Additional Firm Sales be removed from the calculation of the fuel factor by removing an
equivalent amount of gas-fired generation from the Company’s rate year forecast. SPS treated
these sales as off-system throughout this proceeding up to the filing of SPS Ex. 21, only
changing its position on this issue on the day of the hearing at which time it began treating them
as “on-system” for purposes of calculating the fuel factor. SPS has failed to meet its burden of
proof that these additional sales are sufficiently firm to be included in the calculation of the fuel
factor. SPS witness Jannell Marks admitted during cross-examination concerning these sales
that SPS does not have signed contracts for those sales and those sales have not been identified
by name or by magnitude.88
That concession is significant, because under SPS’ own theory unless they have a signed
contract on firm load, the Company does not have an obligation to serve.89 SPS readily concedes
that it has no obligation to serve non-firm load.90 Further complicating this picture is the fact
87
Tr. 313/10-13.
88
Tr. 384/14-21.
89
See Tr. 154/11-15; Tr. 238/21, Tr. 239/7-9; Tr. 366/14-17.
90
Tr. 438.
41
that SPS has no idea about the characteristics of the individual transactions that are included in
Additional Sales. Given the lack of evidence on this point, SPS cannot reasonably be said to
have proven that these Additional Sales will represent firm on-system sales.
VI.
SPS POWER SALES ARE USED TO GENERATE MARGINS FOR ITS
AFFILIATE COMPANY (PSCo)
On January 1, 2001, SPS entered into a power sale agreement with El Paso Electric
(EPE) to sell 103 MW of Peak and Off-Peak Energy for one year beginning January 1, 2001 and
ending on December 31, 2001.91 Simultaneously El Paso Electric entered into an agreement to
sell 103 MW of Off-Peak Firm Power Service to Public Service of Colorado (PSCo) contingent
on EPE receiving the same amount of energy through the Eddy County tie from SPS.92 The
same individual, Kelly Kratenmaker, acted on behalf of both SPS and its affiliate, PSCo, in these
transactions. EPE described the transaction as follows:
EPE entered into an off-peak purchase of 103 MW from
SPS with a simultaneous sale of 103 MW to PSCo at EPE’s
western delivery points.93
PSCo pays EPE what SPS charged for the off-peak energy plus a small adder.94 The SPS sale to
EPE made it possible for its sister company, PSCo, to make huge margins by selling to energy
starved California and other markets in the Western United States. Since SPS is not sharing the
margins from this transaction, from the ratepayers’ perspective it was anything but an armslength deal; Xcel Energy shareholders will be the beneficiaries of the PSCo sales of the 103
MW of off-peak power. The following chart illustrates this transaction:
91
Cities Ex. 12.
92
Cities Ex. 17.
93
Cities Ex 23 (Norwood Direct Testimony) at Exhibit DSN-9.
94
Cities Ex 23 at 15.
42
SPS-EPE-PSCo Off-Peak Exchange Transaction
PSCo Sells Energy
to Western Market
$$
SPS
PSCo
for
Affiliate
Western
Market
SPS sells 103
MW to EPE at
Eddy County
Tie
EPE
EPE Sells 103
MW Off-Peak
to PSCo at
PV
Switchyard
Moreover, prior to the merger of Southwestern Public Service Company and Public
Service of Colorado, SPS sold power into the Western Market. SPS witness, David Hudson,
provided a portion of the FERC Form 1 for SPS for 1992, which shows the sales being made by
SPS to the following customers located in the Western Market:95









Public Service of Arizona
Southern California Edison
Pacific Gas & Electric
Salt River Project
San Diego Gas & Electric
Pacific Power & Light
Los Angeles Department of Water & Power
Tucson Electric Power Company
Bonneville Power Administration
However, instead of SPS marketing the 103 MW of off-peak power into the Western
Market, its affiliate PSCo was able to market the power to the Western Market at huge margins.
Mr. Norwood estimated that off-peak economy sales could realize between $200-$300 per
95
SPS Ex 21, Exhibit DTH-R2 at 76-77, Bates Nos. 124-125.
43
megawatt hour in the Western Market.96
Had SPS made these sales directly into the western
market, there would have been no question under the Commission’s fuel rules that it would be
required to credit the revenue from such sales to its Texas retail customers. The margins from
theses sales could have helped reduce the eligible fuel cost for this proceeding, and eliminated
past under-recoveries and the need for the significant fuel factor increase proposed by SPS. But
instead, SPS provided this off-peak power to its affiliate PSCo at below-market prices, thereby
directing the significant margins earned from these opportunity sales that were generated by SPS
power plants into the pockets of Xcel Energy shareholders.97
Xcel Energy has embarked on a course of conduct, which used 103 MW of SPS off-peak
energy in order to transfer an equivalent amount of power to PSCo so that it could realize huge
margins through sales into the Western Market. Worse yet, SPS’ proposal to assign the system
average fuel cost to the energy sold under this sham off-system transaction — rather than the
higher marginal gas-filed cost it incurred to supply this sale – serves to drive up fuel charges to
its Texas native system retail customers while at the same time diverting margins to Excel
shareholders. The reasonableness and prudence of such a scheme should be investigated in SPS’
next fuel reconciliation proceeding. Undoubtedly these sales to the Western Market were very
short-term opportunity transactions, which could only appropriately be examined in a fuel
reconciliation proceeding.
96
Tr. 405/5-8.
97
Xcel Energy reported a 36% increase in earning for the first quarter of 2001.
Electric utility margins increased by $55.9 million for the first quarter and by
$206.2 million for the 12 months ended March 31, 2001. The increase reflects
more favorable temperatures retail sales growth, and an expansion of Xcel
Energy’s wholesale operations and favorable marketing conditions.
<http://www.corporate-ir.net/ireye/ir_site.zhtml?ticker=XEL&script=-6&item_id=169956> at p. 9 of 24 (portrait
style).
44
VII.
CONCLUSION
There is no credible basis in the record for SPS keeping short-term firm sales revenues. If
the Commission does not correct this error, fuel charges to Texas retail customers will continue
to be driven higher by the higher marginal costs of these voluntary short-term opportunity sales
by SPS. The Company plans to make additional sales in the future, as suggested in Cities Ex. 5
(excess capacity for off-system sales continues until 2008). These sales will result in higher fuel
factors and higher surcharges for under-recovered fuel expense.
In exchange, Texas retail
customers receive no offsetting benefit. In fact, if SPS simply sold this energy in the economy
market, fuel factor charges would go down and all margins would be credited to ratepayers.
PRAYER
WHEREFORE, PREMISES CONSIDERED, the Cities of Amarillo and Spearman
respectfully request that its recommendations be granted and that the Cities be granted any
further relief to which they are justly entitled.
Respectfully submitted,
LAW OFFICE OF JIM BOYLE, PLLC
1005 Congress Avenue, Suite 550
Austin, Texas 78701
(512) 474-1492
(512) 474-2507 (fax)
By:___________________________
Jim Boyle
State Bar No. 02795000
Jaime Slaughter
State Bar No. 00794647
Charmaine Skillman
State Bar No. 16812500
Rick Guzman
State Bar No. 08654670
45
Attorneys for Cities
46
CERTIFICATE OF SERVICE
I certify that I have served a copy of Cities of Amarillo and Spearman Post-Hearing Brief
upon all known parties of record by fax and/or first class mail on this the 11th day of June, 2001.
___________________________________
Jaime Slaughter
47