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UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
El Paso Natural Gas Company ) Docket No. RP08-426-000
Brief Of Southern California Edison Company,
Opposing Exceptions To Initial Decision
Douglas Kent Porter J. Patrick Nevins Russell Archer Hogan Lovells USA L.L.P. Southern California Edison Company Columbia Square P.O. Box 800 555 Thirteenth Street, N.W. 2244 Walnut Grove Avenue Washington, D.C. 20004 Rosemead, California 91770 (626) 302-3964 [email protected] [email protected]
(202) 637-6441 [email protected]
Counsel for Southern California Edison Company
March 7, 2011
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TABLE OF CONTENTS
Page
TABLE OF AUTHORITIES...................................................................................................................ii
I. SUMMARY.............................................................................................................................. 1
II. LIST OF EXCEPTIONS OPPOSED........................................................................................ 3
III. ARGUMENT ........................................................................................................................... 3
A. The Initial Decision Correctly Concluded That EPNG’s Short-Term Firm and IT Rate Proposal Is Unjust and Unreasonable............................................. 3
1. EPNG’s Proposal Does Not Qualify as Peak/Off-Peak Rates ........................ 5
2. EPNG’s Proposal Does Not Qualify as Term Differentiated Rates .............................................................................................................. 8
3. Some Similarity To The Types of Rates Allowed By Order No. 637 Does Not Render EPNG’s Proposal Just and Reasonable. ................................................................................................... 9
4. The Market Cannot Be Relied Upon To Limit EPNG’s Rates. ...................... 11
5. EPNG Failed To Justify Its Proposed 250% Rate Differential. ..................... 14
6. EPNG’s Proposal Violates Order No. 712. ................................................... 17
7. EPNG’s Proposal Improperly Increases IT rates. ......................................... 22
8. Revenue Crediting Does Not Save EPNG’s Proposal. ................................. 25
9. Conclusion Regarding Short-Term Rates..................................................... 28
B. EPNG Should Not Be Permitted To Reallocate Costs Not Paid By Article 11.2 Shippers To Other Customers. .............................................................. 29
1. EPNG Did Not Justify A “Discount Adjustment,” Which Would Be The Only Basis For Reallocating Costs Not Recovered As A Result of Article 11.2. ................................................................................ 31
2. Article 11.2 Rates Are Not Vintage Rates..................................................... 38
3. EPNG’s General Theory That It Must Be Allowed To Recover All Its Costs From Someone Must Be Rejected............................................ 40
IV. REBUTTAL OF POLICY CONSIDERATIONS CLAIMED TO WARRANT COMMISSION REVIEW AND DECISION ............................................................................ 42
V. CONCLUSION...................................................................................................................... 43
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TABLE OF AUTHORITIES
Page JUDICIAL CASES:
Ala. Electric Coop., Inc. v. FERC, 684 F.2d 20 (D.C. Cir. 1982)....................................................................................................... 30
Elizabethtown Gas Co. v. FERC, 10 F.3d 866 (D.C. Cir. 1993)....................................................................................................... 22
INGAA v. FERC (“INGAA I”), 285 F.3d 18 (D.C. Cir. 2002)......................................................................................... 5, 9, 13, 19
Interstate Natural Gas Association of America v. FERC (“INGAA II”), Case No. 09-1016 (D.C. Cir., Aug. 13, 2010)...................................................... 12, 18, 19, 20, 21
KN Energy, Inc. v. FERC, 968 F.2d 1295 (D.C. Cir. 1992)................................................................................................... 30
Nat’l Fuel Gas Supply Corp., 468 F.3d 831 (D.C. Cir. 2006)..................................................................................................... 19
S. Cal. Edison Co. v. FERC, 172 F.3d 74 (D.C. Cir. 1999)....................................................................................................... 13
United Distribution Cos. v. FERC, 88 F.3d 1105 (D.C. Cir. 1996)..................................................................................... 9, 13, 20, 30
COMMISSION RULEMAKING AND POLICY STATEMENTS
Order No. 637, “Regulation of Short-Term Natural Gas Transportation Services, and Regulation of Interstate Natural Gas Transportation Services,” FERC Stats. & Regs. ¶ 31,091 at 31,263, reh’g, Order No. 637-A, FERC Stats. & Regs. ¶ 31,099, reh’g, Order No. 637-B, 91 FERC ¶ 61,062 (2000) ....................................................................................................passim
Order No. 712, “Promotion of a More Efficient Capacity Release Market,” FERC Stats. & Regs. ¶ 31,271, reh’g, Order No. 712-A, FERC Stats. & Regs. ¶ 31,284 (2008) ....................................... 12, 17-22
Order No. 636-A, FERC Stats. & Regs. ¶ 30,950 (1992) ....................................................................................... 26
Policy for Selective Discounting for Natural Gas Pipelines, 111 FERC ¶ 61,173, reh’g denied, 113 FERC ¶ 61,173 (2005) ..................................... 31, 34, 35
Policy Statement on Alternatives to Traditional Cost of Service Ratemaking for Natural Gas Pipelines, 74 FERC ¶ 61,076, reh’g denied, 75 FERC ¶ 61,024 (1996) ...................................................... 12
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Policy Statement Providing Guidance with Respect to the Designing of Rates, 47 FERC ¶ 61,295, reh’g, 48 FERC ¶ 61,122 (1989) ................................................................. 33
Statement of Policy: Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC ¶ 61,227 (1999); clarified, 90 FERC ¶ 61,128 (2000), clarified, 92 FERC ¶ 61,094 (2000)............................................................................................................................. 39
COMMISSION DECISIONS
Ameren Energy Marketing Company, 128 FERC ¶ 63,005 (2009) ........................................................................................................... 4
Arkla Energy Resources, 62 FERC ¶ 61,076 (1993) ........................................................................................................... 26
BP Pipelines (Alaska) Inc., 131 FERC ¶ 61,003 (2010) ........................................................................................................... 4
Cimarron River Pipeline, LLC, N. Natural Gas Company, 124 FERC ¶ 61,069 (2008) ......................................................................................................... 26
El Paso Natural Gas Co., 63 FERC ¶ 61,139 (1993) ........................................................................................................... 26
El Paso Natural Gas Co., 112 FERC ¶ 61,150 (2005) ............................................................................................. 16, 23, 24
El Paso Natural Gas Co., 114 FERC ¶ 61,290 (2006) ................................................................................................... 31, 32
El Paso Natural Gas Co., 114 FERC ¶ 61,305 (2006) ......................................................................................................... 42
El Paso Natural Gas Co., 124 FERC ¶ 61,124 (2008) ......................................................................................................... 15
El Paso Natural Gas Co., 131 FERC ¶ 61,077 (2010) ..................................................................................................... 4, 40
El Paso Natural Gas Co., 133 FERC ¶ 61,129 (2010) ................................................................................................... 12, 17
El Paso Natural Gas Co., 134 FERC ¶ 63,002 (2010) ..................................................................................................passim
Enbridge Pipelines (KPC), 103 FERC ¶ 61,305 (2003) ......................................................................................................... 42
High Island Offshore System, LLC, 107 FERC ¶ 63,019 (2004), aff’d, 110 FERC ¶ 61,043 (2005).................................................... 22
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Iroquois Gas Transmission Sys., LP, 86 FERC ¶ 61,261 (1999) ........................................................................................................... 34
Mississippi River Transmission Corp., 95 FERC ¶ 61,460 (2001) ........................................................................................................... 13
Nat’l Fuel Gas Supply Corp., 67 FERC ¶ 61,147 ...................................................................................................................... 30
NEO California Power LLC, 127 FERC ¶ 63,009 (2009) ........................................................................................................... 4
NorAm Gas Transmission Co., 77 FERC ¶ 61,011 (1996) ........................................................................................................... 42
Northwest Pipeline Corp. 84 FERC ¶ 61,109 (1998) .......................................................................................................... 42
Pac. Connector Gas Pipeline, LP, Jordan Cove Energy Project, L.P., 129 FERC ¶ 61,234 (2009) ......................................................................................................... 26
Portland Natural Gas Transmission Sys., 123 FERC ¶ 61,108 (2008); ....................................................................................................... 15
Pub. Utils. Comm’n of the State of Cal. v. EPNG, et al., 97 FERC ¶ 61,380 (2001) ........................................................................................................... 21
Pub. Utils. Comm’n of the State of Cal. v. EPNG, et al., 105 FERC ¶ 61,201 (2003) ......................................................................................................... 21
San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services, 131 FERC ¶ 61,259 (2010) ........................................................................................................... 4
S. Cal. Edison Co. v. S. Cal. Gas Co., 80 FERC ¶ 61,390 (1997) ..................................................................................................... 13, 22
Southern Natural Gas Co., 99 FERC ¶ 61,345 (2002) ..................................................................................................... 22, 23
Stingray Pipeline Co., 68 FERC ¶ 61,372 (1994) ........................................................................................................... 22
Sys. Energy Resources, Inc., 41 FERC ¶ 61,238 (1987) ........................................................................................................... 30
Tenn. Gas Pipeline Co., 80 FERC ¶ 61,070 (1997) ........................................................................................................... 22
Tex. Gas Transmission Corp., 93 FERC ¶ 61,102 (2000) ........................................................................................................... 15
Transok, Inc., 70 FERC ¶ 61,177 ...................................................................................................................... 22
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Trunkline Gas Co., 90 FERC ¶ 61,017 (2000) ..................................................................................................... 35, 38
Wyo. Interstate Company, Ltd., 121 FERC ¶ 61,135 (2007) ......................................................................................................... 26
RULES AND REGULATIONS:
Rule 711 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission, 18 C.F.R. § 385.711 (2010) ......................................... 1
18 C.F.R. § 284.7(b)(1) (2010) ......................................................................................................... 16
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UNITED STATES OF AMERICA BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION El Paso Natural Gas Company ) Docket No. RP08-426-000
Brief Of Southern California Edison Company
Opposing Exceptions To The Initial Decision
Pursuant to Rule 711 of the Rules of Practice and Procedure of the Federal Energy
Regulatory Commission (“Commission”), 1 / Southern California Edison Company (“SCE”)
respectfully submits this brief opposing certain exceptions to the Initial Decision issued in this
proceeding by Presiding Administrative Law Judge Charlotte J. Hardnett on January 14, 2011. 2/
I. SUMMARY
SCE opposes here exceptions to two aspects of the Initial Decision raised in the Brief on
Exceptions filed by El Paso Natural Gas Company (“EPNG”). First, SCE opposes EPNG’s challenge
to the Presiding Judge’s rejection of EPNG’s proposal to charge for short-term firm and interruptible
transportation service as much as 250% of its cost-based maximum rate for long-term firm service.
On this issue, SCE also responds to the “Brief on Exceptions of Southern California Gas Company
and San Diego Gas & Electric Company on Short-term Rates Issue,” which similarly raises
exceptions to the rejection of EPNG’s short-term rate proposal. Second, SCE opposes EPNG’s
exception to the ruling in the Initial Decision that, assuming that Article 11.2 of the 1996 Settlement
applies to provide lower rates for shippers covered by that article, EPNG is not permitted to
reallocate the shortfall in its cost recovery to others.
With respect to the first issue, the Initial Decision correctly concluded in light of evidence
adduced at the hearing that EPNG’s proposed short-term rates are not just and reasonable. The
Commission has never approved as just and reasonable a rate design like EPNG’s proposal here,
and it is contrary to Commission policy. While EPNG attempts to cloak its proposal as “value-based 1/ 18 C.F.R. § 385.711 (2010). 2/ El Paso Natural Gas Co., 134 FERC ¶ 63,002 (2010) (“Initial Decision” or “I.D.”).
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pricing” authorized in Order No. 637, its proposed rates fail to satisfy the revenue and cost
constraints of the traditional regulatory model that the Commission has emphasized must remain in
place. EPNG’s proposal fails to comply with the explicit parameters for peak/off-peak rates and term
differentiated rates set forth in Order No. 637 because EPNG proposes short-term rate premiums at
all times of the year, with no offsetting lower rates at other times of the year or for longer-term
contracts. Moreover, EPNG failed to provide a reasoned basis for its proposed 250% cap on the
rates, or to demonstrate a link between those rates and actual costs. For this reason, EPNG’s
proposal also conflicts with the Commission’s decision in Order No. 712 to maintain a cost-based
recourse rate for pipeline-provided short-term services as an alternative to, and protection against,
market-priced short-term capacity releases.
EPNG claims that “the market” will limit the rates that it can charge. Yet, EPNG did not
provide any market study to counter the presumption that it has market power that would allow it to
maintain prices above competitive levels for a significant period of time, or to analyze the
concentration of the market to determine if EPNG and large firm capacity holders might together
exercise market power. Therefore, there is no support for EPNG’s claim that competitive market
forces would act as an adequate substitute for regulation to ensure that EPNG’s short-term rates are
just and reasonable. Finally, EPNG’s proposed revenue crediting mechanism cannot render the
excessive short-term rates just and reasonable. The proposed revenue crediting suffers from
numerous flaws, including the limitation that it would begin only if EPNG first collects its entire cost of
service. Moreover, even if EPNG proposed to later credit to other shippers all the revenue from its
short-term services, that approach would not justify the imposition of unjust and unreasonable rates
in the first instance.
Turning to Article 11.2, SCE joined with the other “California Parties” in filing a brief on
exceptions arguing, as EPNG does, that the Commission in its order on the Initial Decision should
either: (a) eliminate Article 11.2 as contrary to the public interest or (b) rule that, under the current
circumstances, (i) Article 11.2(a) rates that are lower than the generally applicable settlement rates
would be unjust and unreasonable and (ii) no rate adjustment under Article 11.2(b) is appropriate. If
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the Commission rejects this position and agrees with the Presiding Judge that Article 11.2 should
continue to apply to provide lower rates for covered customers, however, EPNG should not be
permitted to reallocate the resulting shortfall in cost recovery to others. EPNG’s proposal to
reallocate the shortfall to other customers is contrary to the fundamental rate-making principal of
matching cost allocation to cost causation, and would improperly require non-11.2 shippers to
subsidize service to the Article 11.2 shippers. The proposed reallocation is not authorized by the
Commission’s selective discounting policy, which is the relevant test for this issue previously
established by the Commission, because the provision of Article 11.2 rates to all customers was
manifestly not required to meet competition and retain the volumes on the system. EPNG’s other
arguments in support of reallocation of the 11.2 shortfall are equally unavailing. Therefore, if Article
11.2 is not terminated and rates for the 11.2 shippers less than the general system rates are held to
be just and reasonable, EPGN alone must be responsible for the resulting shortfall in its cost
recovery. The proposed reallocation of costs to other shippers would be unjust and unreasonable.
II. LIST OF EXCEPTIONS OPPOSED
SCE opposes the exceptions presented in the EPNG Brief on Exceptions numbered 6
through 9 (concerning the short-term rate issue) and 22 through 26 (concerning reallocation of a
shortfall in cost recovery as a result of Article 11.2). In addition, SCE opposes all of the exceptions
(numbered 1 through 7) in the brief on exceptions filed by Southern California Gas Company and
San Diego Gas & Electric Company (“SoCalGas/SDG&E”). 3/
III. ARGUMENT
A. The Initial Decision Correctly Concluded That EPNG’s Short-Term Firm and IT Rate Proposal Is Unjust and Unreasonable.
The Presiding Judge summarizes the testimony and positions of the participants related to
the short-term rate issue at paragraphs 189 to 285 of the Initial Decision. The Presiding Judge then
discussed the issue and explained her conclusions at paragraphs 286 through 293, and set forth the
3/ SoCalGas/SDG&E joined in the Brief on Exceptions filed by the California Parties, which also included the Public Utilities Commission of the State of California and Pacific Gas and Electric Company, as well as SCE. SCE opposes only the exceptions raised in the separate brief, on short-term rate issues, filed by SoCalGas/SDG&E.
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relevant findings of fact and conclusions of law at paragraphs 687 through 713. The Presiding
Judge’s reasoning on this issue is sound and her fundamental conclusion that EPNG’s short-term
rate proposal is not just and reasonable is unassailable.
EPNG proposes to charge up to two-and-a-half times, or 250% of, its daily reservation rate
for long-term firm transportation for firm service with a term of less than one year (excluding its
defined seven and five month “seasonal” services) and for interruptible transportation (“IT”). 4/ This
proposal contravenes Commission policy and would allow EPNG to charge unjust and unreasonable
rates for its short-term transportation services. Approval of EPNG’s proposal would not protect
consumers from EPNG’s market power – as required by the Natural Gas Act (“NGA”) – and would
adversely affect the market. Accordingly, the proposal should be rejected. Instead, EPNG’s short-
term firm and IT rates should be set at the 100% load factor equivalent of the long-term firm rates.
EPNG argues in its Brief on Exceptions, as it has throughout the case, that its “proposal is
based on the evolution of the Commission’s pro-competitive policies over the last twenty years, and
in particular the Commission’s endorsement of short-term value-based rates in Order No. 637.” 5/
EPNG proposes, however, to go beyond what the Commission allowed in Order No. 637 or in any
other order. EPNG has not cited a single case, during the more than a decade since issuance of
Order No. 637, in which the Commission has held to be just and reasonable “value based rates”
similar to those that EPNG proposes here. The best that EPNG could do was to cite four
settlements with provisions allegedly “similar” to its proposed rates. 6/ Settlements, of course, are
not precedent. 7/ Moreover, as explained below, the provisions in the settlements actually are not
4/ Exh. No. EPG-26, at pp. 27-28; Exh. No. EPG-149, at p. 12. 5/ EPNG Brief on Exceptions at 32. 6/ Exh. No. EPG-337 at pp. 11-12 (citing four settlements alleged to contain “similar” provisions). Relevant portions of the four settlements are included in the record as Exh. Nos. SCE-29 (Texas Gas settlement), SCE-30 (Portland Natural settlement), SCE-31 (Gas Transmission Northwest settlement), and SCE-32 (Northern Border settlement). 7/ E.g., San Diego Gas & Elec. Co. v. Sellers of Energy and Ancillary Servs., 131 FERC ¶ 61,259 at P 13 (2010); BP Pipelines (Alaska) Inc., 131 FERC ¶ 61,003 at P 2 (2010); El Paso Natural Gas Co., 131 FERC ¶ 61,077 at P 3 (2010); NEO Cal. Power LLC, 127 FERC ¶ 63,009 at P 6 (2009); Ameren Energy Mktg. Co., 128 FERC ¶ 63,005 at P 5 (2009). Moreover, each of the settlements relied upon by EPNG expressly provides that it does not have precedential effect. See Exh. No. SCE-29, at pp. 20-21, Article
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similar to EPNG’s proposal: EPNG proposes a much more extreme version of “peak” pricing than
any other pipeline has ever implemented even through a settlement.
As the Presiding Judge correctly concluded at P 293 of the I.D., EPNG’s proposal does not
comply with the safeguards and requirements set forth in Order No. 637. The Commission
emphasized there that both peak/off-peak rate or term differentiated rates “still have to satisfy the
revenue and cost constraints of the traditional regulatory model.” 8 / EPNG’s short-term rate
proposal flouts the revenue and cost constraints of the traditional regulatory model and does not
comply with the requirements for peak/off-peak rates or term-differentiated rates set forth in Order
No. 637.
EPNG emphasizes on brief that “both peak/off peak and term differentiated value-based
rates are just and reasonable cost-based rates.” 9/ The fact that rates designed in accordance with
the dictates of Order No. 637 for peak/off peak and term differentiated rates would be cost-based
provides no support for EPNG’s proposal because EPNG ignored those dictates. EPNG cites two
pages of Order No. 637 for the proposition that “value-based rates” are cost-based rates, pages
31,290 and 31,293: 10/ the first citation relates to peak/off-peak rates while the second addresses
term differentiated rates. Yet, EPNG’s proposal fails to meet the Commission’s requirements for
either peak/off-peak or term differentiated rates as set forth in the very portions of Order No. 637
cited by EPNG.
1. EPNG’s Proposal Does Not Qualify as Peak/Off-Peak Rates
At page 31,290 of Order No. 637, the Commission explained the “Parameters for
Establishing Peak/Off-Peak Rates” as follows:
XV Reservations; Exh. No. SCE-30, at p. 6, Article II Scope of Settlement Section F; Exh. No. SCE-31, at p. 36, Article XII Reservations, Section B Settlement Has No Precedential Value; and SCE-32, at p. 32, Article XI Reservations, Section C; see also Hearing Transcript (hereinafter “TR”), p. 756, lines 7-21 (questions and responses by Mr. Sullivan). 8/ Order No. 637, “Regulation of Short-Term Natural Gas Transportation Services, and Regulation of Interstate Natural Gas Transportation Services,” FERC Stats. & Regs. ¶ 31,091 at 31,263, reh’g, Order No. 637-A, FERC Stats. & Regs. ¶ 31,099, reh’g, Order No. 637-B, 91 FERC ¶ 61,062 (2000), aff’d in part and remanded in part sub. Nom., INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002) (hereinafter “INGAA I”). 9/ EPNG Brief on Exceptions at 33 (emphasis in original retained). 10/ Id.
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Value-based peak/off-peak rates are just and reasonable cost-based rates. Like uniform maximum rates, peak/off-peak rates would be established by taking the pipeline's annual revenue requirement and deriving from it a daily or monthly rate. The difference in developing peak/off-peak rates and the current uniform maximum rate is that instead of dividing the annual revenue requirement by 365 to obtain a daily rate, different daily or monthly rates will be developed for peak and off-peak periods using one of several possible methods of measuring the value of capacity at peak and off-peak. The sum of the daily or monthly rates, multiplied by the quantity used or reserved, still must not exceed the pipeline's annual revenue requirement, and thus, any increases in rates at peak must be offset by decreases in off-peak rates. In other words, if a shipper paid the peak and off-peak rate for the same volume of transportation every day of the year, the amount it paid annually for service would be no more than if it had paid the uniform maximum daily rate for the same transportation volume based on the same revenue requirement.
This requirement limits the rate the pipeline may charge. For example, if the pipeline wanted to charge a rate greatly in excess of the current uniform maximum rate in the four month period December through March, it would have to match this increase with a corresponding reduction in rates for the remaining months. This places a check on the ability of the pipelines to propose extraordinarily high rates during peak periods because any rate increase for peak periods must be matched by a rate decrease during the off-peak periods. This is a disincentive for pipelines to raise peak period rates to unrealistically high levels since this would require an off-setting lowering of off-peak rates that could compromise the pipeline's ability to recover maximum off-peak revenues.
Although EPNG originally presented its short-term rate proposal as “peak/off-peak rates,” 11 /
EPNG’s proposal to charge a peak rate of 250% every day of the year unquestionably does not
comply with these parameters. EPNG did not allocate its annual revenue requirement over the
course of the year: instead, it took the daily rate determined by the revenue requirement spread over
365 days and then multiplied it by 250%. The increases in EPNG’s peak rates are not offset by any
decrease in off-peak rates. If a shipper paid EPNG’s proposed rates every day of the year, the rate
paid annually would be 250% of the cost-based daily rate set in the standard way. There is no
regulatory check on EPNG’s ability to propose extraordinary high rates during peak periods because
11/ EPNG first justified its rate proposal in the direct testimony of Mr. Sullivan, and his explanation of the import of Order No. 637 there focused solely on “peak/off-peak” or seasonal rates. See Exh. No. EPG-149 at pp. 8-9. This testimony contains five extended quotations from Order No. 637 related to peak/off-peak rates, at pp. 9-10, 10-11, 23, 25 and 26. In contrast, the direct testimony does not discuss “term differentiated” rates.
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there is no matching rate decrease in off-peak periods. There is no disincentive for EPNG to raise
peak period rates to unrealistically high levels because EPNG does not provide any off-setting
lowering of its off-peak rates – indeed, EPNG does not propose any off-peak rates.
EPNG suggests that it could not propose peak/off-peak rates as contemplated in Order No.
637 because it “does not have a traditional winter and off-peak summer season.” 12/ Yet, two of the
settlements that EPNG claimed are “similar” to its proposal provide for dual summer and winter
peaks, or unpredictable peaks, while still conforming with the requirement of Order No. 637 to offset
higher peak rates with lower off-peak rates. 13/ Obviously it is possible for pipelines lacking
traditional winter/summer seasonal demands to comply with the requirement of Order No. 637 to
offset peak rates with lower off-peak rates: EPNG simply chose not to do so. More fundamentally,
all of the four settlements cited by EPNG include lower off-peak rates to offset the higher peak rates,
as required by the parameters established by the Commission in Order No. 637. In each case, a
shipper paying the peak/off-peak rate year round would pay the equivalent of the cost-based (100%
load factor) rate set in the traditional manner. 14/ Thus, each of the other pipelines fully offset the
increase in rates during certain times of the year with lower rates during other times. EPNG’s
proposal does not. Moreover, none of the settlements that EPNG claims are “similar” to its proposal
allow for anywhere close to a multiple as high as EPNG’s 250% for even a single peak month. 15/
12/ EPNG Brief On Exceptions at 39. SoCalGas/SDG&E echo this claim at page 11 of their Brief on Exceptions. 13/ The Northern Border settlement provides for higher peak rates in both winter and summer months fully offset by lower rates in other months, so that the annual rate equates to the 100% load factor rate. Exh. SCE-32 at pp. 15-16; TR, p. 764, lines 10-24 (questions and responses of Mr. Sullivan). The Gas Transmission Northwest settlement allows the pipeline to designate from 0 to 4 months as peak months each year, with the corresponding rates for non-designated off-peak months set as necessary to offset the peak rates. Exh. SCE-31 at p. 22; TR, p. 765, lines 6-25 (questions and responses of Mr. Sullivan). 14/ See Exh. No. SCE-29, at p. 12, Article IX Short-Term Firm Transportation Service, Section 2; Exh. No. SCE-30, at p. 2, Article II Scope of Settlement, Section A; Exh. No. SCE-31, at p. 22, Article VI Settlement Rates, Section E Seasonal Rates and Appendix B; and Exh. No. SCE-32, at p. 16, Article V Settlement Base Rates, Section E; see also TR, p. 760, lines 14-22 and p. 766, lines 9-15 (questions and responses by Mr. Sullivan). 15/ According to SCE’s calculations, the highest rate allowed in any month under any of the four settlements is a rate of 170% of the long-term rate under the Texas Gas settlement. Exh. No. SCE-29. The other settlements allowed for peak rates in certain limited months as high as 150% for Portland
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2. EPNG’s Proposal Does Not Qualify as Term Differentiated Rates
On the second page of Order No. 637 cited by EPNG for the proposition that “value-based”
rates are cost-based, the Commission held that “[l]ike peak/off-peak rates, term differentiated rates
would be cost-based, just and reasonable rates because the Commission will limit the pipeline in the
aggregate to produce the pipeline’s annual revenue requirement.” 16/ The Commission further
explained that “[t]erm-differentiated rates would raise the maximum rate for some customers, and
there should be a decrease in the maximum tariff rates for long-term customers. The general
reallocation of revenue responsibility among customer classes must be done through rate changes
for all customers simultaneously in the section 4 rate filing in which the pipeline seeks to implement
term-differentiated rates.” 17/ EPNG’s main witness supporting the rate proposal, Mr. Sullivan,
acknowledged that term differentiated rates are a means of reallocating revenue responsibility so
that if rates are increased for contracts of a certain length, there must be an offsetting decrease in
rates for contracts of a different duration. 18/ Yet, EPNG proposes only to increase rates on short-
term rates, without any offsetting decrease in other rates.
EPNG failed to comply with the fundamental parameters for term-differentiated rates
because it does not propose any simultaneous decrease in the costs allocated to longer-term
contracts. In addition, term-differentiated rates are intended to reflect differing risks associated with
contracts of different terms. 19/ Yet, EPNG did not present any evidence demonstrating, much less
quantifying, the risks to it of short-term contracts compared to longer-term contracts. Indeed,
EPNG’s proposal does not even consistently provide for lower maximum rates for longer terms:
EPNG would charge the same rate for one-month contracts as for eleven-month contracts, and
would charge lower rates for its preferred “seasonal” contracts of seven and five months duration
Natural (Exh. No. SCE-30), 140% for Gas Transmission Northwest (Exh. No. SCE-31), and 125% for Northern Border (Exh. No. SCE-32). 16/ Order No. 637 at 31,293, cited in EPNG Brief on Exceptions at 33. 17/ Id. at 31,294 (emphasis added). 18/ TR, p. 771, lines 7-14 (question and response of Mr. Sullivan agreeing that this conclusion is implied by the language from Order No. 637). 19/ Order No. 637 at 31,293.
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than for eleven-month contracts. 20/ Furthermore, as detailed in Section III A. 7. below, the concept
of term-differentiated rates in Order No. 637 has no application to IT service.
3. Some Similarity To The Types of Rates Allowed By Order No. 637 Does Not Render EPNG’s Proposal Just and Reasonable.
Apparently recognizing that its proposal does not conform with the requirements established
in Order No. 637 for either peak/off-peak rates or term-differentiated rates, EPNG couches its
proposal as a hybrid: “TD [term-differentiated] rates that incorporate peak/off-peak concepts.” 21/
EPNG also claims that its proposal is “based on the evolution of the Commission’s pro-competitive
policies” and will achieve the Commission’s “policy objectives” in Order No. 637. 22/
Commission policies that allow deviation from traditional cost-based rates subject to
particular parameters and rate-payer protections do not justify rate proposals that fail to comply with
the parameters and eliminate the protections. The theory that Commission policy has been
“evolving” toward increased reliance on competition obviously does not mean that pipelines may
charge “value-based” rates of any kind they may devise. The Commission always must reconcile its
promotion of competitive, efficient markets with continued recognition that “the basic premise of the
NGA is the understanding that natural gas pipeline transportation is generally a natural monopoly, so
that without regulation the rates of pipeline companies would exceed competitive rates, i.e., ones
approximating cost.” 23/
Moreover, the Commission constantly balances a variety of often competing policy objectives
in formulating its decisions and decides how to weigh the competing policies and where to draw the
lines. The Commission did just that in Order No. 637, explaining:
The Commission’s objective in designing rates is to establish a ratesetting framework that increases efficiency in the marketplace, while protecting against the potential exercise of market
20/ See Exh. No. S-12 at p. 18; Exh. No. EGC-6 at pp. 19 and 21. 21/ EPNG Brief on Exceptions at 33. 22/ Id. at 32. SoCalGas/SDG&E also emphasize “the principles and goals stated in Order No. 637” in their effort to support EPNG’s proposal. See SoCalGas/SDG&E Brief on Exceptions at 7. 23/ INGAA I, 285 F.3d at 30 (internal citations omitted); see also, e.g., United Distribution Cos. v. FERC, 88 F.3d 1105, 1122 & n. 4 (D.C. Cir. 1996) (holding that federal regulation of the gas industry is designed to curb pipeline’s potential market power over transportation of gas, which tends to be a natural monopoly).
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power….[P]rice regulation often permits the exercise of market power and involves tradeoffs between pricing efficiency and the regulatory control over market power. On balance, the Commission finds that the changes to regulation made in this rule – removing the price ceiling from capacity release transactions, permitting pipelines to file for peak/off-peak and term differentiated rates, plus the improvements to scheduling, segmentation, penalties, and reporting requirements – will enhance marketplace efficiency and competition, protect captive customers, and set prices for short-term transactions that reflect demand during peak periods while not jeopardizing protections against the exercise of market power. 24/
EPNG proposes rates that it claims will promote efficiency and competition while deviating from the
provisions established by the Commission to protect against the potential exercise of market power.
In an effort to justify its failure to comply with the requirements established in Order No. 637,
EPNG emphasizes the Commission’s recognition that “there may be several reasonable methods of
designing peak/off-peak or TD rates,” so “pipelines are free to adopt whatever methods are best
suited to the characteristics of their system.” 25/ The variety of potentially reasonable methods of
designing these rates, however, all must conform with the basic parameters of cost-based rates
established by the Commission. Indeed, examination of the portions of Order No. 637 cited by
EPNG on this point (pages 31,291 and 31,293-94) only highlights the failings of EPNG’s approach.
In the first reference, at page 31,291, the Commission stated in the last paragraph of the
“Parameters” section quoted in Section III.A.1. above that it will “consider any reasonable method of
implementation that is consistent with the general principles discussed in this section, but the
pipeline will have the burden of proof to show that its proposed method is just and reasonable.” 26/
The obvious meaning is that the Commission will consider any method, shown by a pipeline to be
just and reasonable, that is consistent with the principles or parameters set forth above – but not any
method that does not comply with them. EPNG’s proposal does not comply with the general
principles set forth in that section of Order No. 637 because it proposes peak rates every day of the
year. More generally, EPNG has not borne its burden of proof to show that the proposed rates are 24/ Order No. 637 at 31,269 (internal footnotes omitted). 25/ EPNG Brief on Exceptions at 33. 26/ Order No. 637 at 31,291 (emphasis added). EPNG acknowledges this statement in its Brief Opposing Exceptions at 38, but glosses over the fact that its proposal fails to comply with the referenced “general principles” established in Order No. 637.
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just and reasonable. The Commission’s willingness to consider a variety of methods that comply
with the parameters it established does nothing to save EPNG’s proposal, which does not comply
with those parameters.
Similarly, in EPNG’s other reference to the flexibility allowed in Order No. 637, the
Commission recognized that more than one method of allocating costs is possible for term-
differentiated rates, but then went on to explain:
The Commission recognizes that the use of term-differentiated rates for short-term services may enhance the potential for price discrimination, particularly during off-peak periods, by increasing the rate caps that would apply to short-term service acquired in off-peak periods. Consequently, a pipeline proposing term-differentiated rates for short-term services will need to fully explain the basis and justification for the price differentials.
Term-differentiated rates have a much greater potential for effecting the rates of all customers than peak/off-peak rates. Term-differentiated rates would raise the maximum tariff rates for some customers, and there should be a decrease in the maximum rates for long term customers. The general reallocation of revenue responsibility among customer classes must be done through rate changes for all customers simultaneously in the Section 4 rate filing in which the pipeline seeks to implement term-differentiated rates. 27/
EPNG’s proposal does not reallocate any costs between long and short-term contracts, but instead
simply increases the maximum rates that may be charged to short-term customers. This approach
cannot be viewed as within the variety of types of term-differentiated rates allowed by Order No. 637.
4. The Market Cannot Be Relied Upon To Limit EPNG’s Rates.
EPNG claims that its proposal is “consistent with the Commission’s discussion of
peak/off-peak rates in Order No. 637” because
EPNG expects that it will be able to charge a rate in excess of a 100% load factor rate only during peak demand periods. As Mr. Sullivan emphasized, the fact that EPNG’s maximum short-term rate will be the 250% rate all year round does not mean that it will be able to collect that rate during all times of the year. 28/
27/ Order No. 637 at 31,293. 28/ EPNG Brief on Exceptions at 34.
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Indeed, EPNG’s lead witness Mr. Sullivan repeatedly avowed at the hearing that EPNG is relying on
the market to set prices for its short-term services, up to its 250% cap. 29/ Mr. Sullivan explained,
“What EPNG is relying on is that the market, competitive market for transportation services in El
Paso’s service area is competitive, ... and the competitive market for short-term services are the best
way to establish the value of transportation services.” 30/ He further explained the basis for EPNG’s
position as follows:
I believe short-term transportation markets are competitive enough now that we can let the market determine the value of that transportation capacity….
I believe the value of IT transportation should be determined by the market, by the transportation market, because the Commission has found in Order 637 and 712 we have competitive short-term markets. 31/
The Commission has held that EPNG’s proposal is not the equivalent of market-based
rates; 32/ but, given EPNG’s attempt to rely on the market as a purported limitation on its rates, the
Commission’s market-based rate policies are informative. The Commission will authorize a pipeline
to charge market-based rates -- that is, let the market determine the rates -- only if the pipeline
demonstrates that it lacks significant market power in the relevant market or has adequately
mitigated its market power. 33/ “[T]he basic premise of the NGA is the understanding that natural
gas pipeline transportation is generally a natural monopoly, so that without regulation the rates of
29/ See TR, p. 719, line 22 to p. 720, line 6 and p. 780 at lines 9-11 and 21-24. 30/ TR, p. 719, line 22 to p. 720, line 6 31/ TR, p. 780 at lines 9-11 and 21-24. SCE explains further below the Commission’s actual findings in Order No. 637 and Order No. 712, “Promotion of a More Efficient Capacity Release Market,” FERC Stats. & Regs. ¶ 31,271, reh’g, Order No. 712-A, FERC Stats. & Regs. ¶ 31,284 (2008), aff’d sub nom. Interstate Natural Gas Association of America v. FERC, Case No. 09-1016 (D.C. Cir., Aug. 13, 2010) (hereinafter INGAA II). Properly interpreted, these orders provide no support for EPNG’s proposal. 32/ El Paso Natural Gas Co., 133 FERC ¶ 61,129 at P 19 (2010). 33/ The Policy Statement on Alternatives to Traditional Cost of Service Ratemaking for Natural Gas Pipelines, 74 FERC ¶ 61,076 at 61,230, reh’g denied, 75 FERC ¶ 61,024 (1996)(providing guidance on how the Commission will make market power determinations and explaining the information to be included in applications for market-based rates). “Market power is defined as the ability of a pipeline to profitably maintain prices above competitive levels for a significant period of time.” Id., 74 FERC at 61,230.
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pipeline companies would exceed competitive rates, i.e., ones approximating cost.” 34/ “In order to
approve market-based rates, however, the Commission must first conclude that the goals and
purposes of the NGA can be accomplished in the circumstances of the particular filing without the
traditional costs-based regulatory oversight. The Commission’s statutory obligation is to protect
consumers and captive customers from the exercise of market power, and in order for the
Commission to meet its statutory obligations, it must conduct a thorough market analysis to
determine whether competition will protect shippers.” 35/
EPNG asks the Commission to rely on the market to constrain its short-term rates, but offers
no analysis of likely market results or of its ability to exercise market power and maintain rates above
competitive levels. EPNG has not attempted to satisfy the Commission’s requirement for a pipeline
seeking authority to charge market-based rates – i.e., to rely on the market to constrain its rates
within the zone of reasonableness. EPNG did not submit any study or analysis of its market power
in the short-term transportation markets. 36/ And there is no assurance that EPNG would ever sell
the services for less than the maximum rates: EPNG has no obligation to charge below its
34/ INGAA I, 285 F.3d at 30 (internal citations omitted) (upholding the Commission’s decision in Order No. 637 to lift the cost-based rate ceiling on short-term capacity release, while rejecting pipelines’ arguments that the cost-based ceiling on pipeline-provided short-term services similarly should be eliminated); see also, e.g., UDC v. FERC, 88 F.3d 1105, 1122 & n. 4 (D.C. Cir. 1996) (Federal regulation of the gas industry is designed to curb pipeline’s potential market power over transportation of gas, which tends to be a natural monopoly). 35/ Miss. River Transmission Corp., 95 FERC ¶ 61,460 at 62,654 (2001). The Commission can dispense with cost-based rate ceilings and impose instead more “light-handed” regulation only if it can show that the resulting rates are expected to fall within a “zone of reasonableness.” INGAA I, 285 F.3d at 31. For this reason, “The Policy Statement and the cases where the Commission has addressed specific market-based rate proposals make clear that the Commission requires a pipeline to submit a detailed market analysis to support a finding that it lacks market power in its primary transportation market. This is necessary to ensure that the Commission meets its statutory obligations.” Miss. River Transmission, 95 FERC at 62,654. 36/ TR, p. 736, line 24 to p. 737, line 3; and TR, p. 738, lines 7-9 (questions and responses of Mr. Sullivan). All pipelines are presumed to have market power. E.g., S. Cal. Edison Co. v. S. Cal. Gas Co., 80 FERC ¶ 61,390 at 62,302 (1997) (in assessing a complaint against a large holder of EPNG capacity alleging an abuse of its market power, the Commission reasoned by analogy to pipelines “which are presumed to have market power”). The Commission’s dismissal of the complaint was reversed in S. Cal. Edison Co. v. FERC, 172 F.3d 74 (D.C. Cir. 1999). The Court also noted the Commission’s presumption that pipelines have market power. Id. at 75.
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maximum rate or to provide service to any shipper not willing to pay the maximum rate 37/ and, in
fact, has a general policy of not discounting at least with respect to IT. 38/ Even if EPNG were to
discount its rates to the competitive level, no evidence indicates the extent to which the market might
lead to “offsetting” lower rates during off-peak periods. Most importantly, the Commission in Order
No. 637 required that if the maximum rate is increased in certain peak periods then the maximum
tariff rate must be set lower as a matter of regulation in other periods as an offset – regardless of
whether or not the market would enable the pipeline to charge the maximum rates at any given time.
For all of these reasons, the Commission cannot rely on EPNG’s theory that “the market” will
limit the rates that EPNG will charge, so as to create lower “off-peak” rates sufficient to offset rates in
excess of the cost-based rate that EPNG will charge whenever it can.
5. EPNG Failed To Justify Its Proposed 250% Rate Differential.
Unlike with market-based rates, EPNG’s short-term rates are limited by a proposed
maximum cap, derived by multiplying the cost-based rates by 2.5 times. EPNG’s lead witness on
this issue, Mr. Sullivan, acknowledged that EPNG did not propose cost-based short-term rates, 39/
but termed the proposed rates “cost-based derivative rates.” Notably, in Mr. Sullivan’s view, there
would still be “cost-based derivative rates” – rather than market-based rates – if the cap was equal to
the cost-based rate multiplied by 5, 40/ or by 10, 41/ or even by 100. 42/ Given this theory, the
conclusion that a “derivative cap” equal to some multiple of the cost-based rate setting an upper
bound on the rates transforms a market-based rate proposal into a different kind of proposal that
requires no inquiry into the pipeline’s market power is alarming. The Commission appears to have
recognized this potential when accepting and suspending short-term rate proposals by other
pipelines that were essentially the same as EPNG’s proposal here:
The Commission is concerned that [the pipeline] has not adequately linked its costs and the rates it proposes. [The pipeline] appears to
37/ TR, p. 632, line 5-12 (questions and responses of Mr. Thomas L. Price). 38/ Id. at p. 634, line 23 to p. 635, line 5 (questions and responses of Mr. Price). 39/ TR, p. 710, lines 20-21. 40/ Id. at p. 712, lines 2-22 (question and response of Mr. Sullivan). 41/ Id. at p. 715, lines 7-18 (question and response of Mr. Sullivan). 42/ Id. at p. 717, lines 14-22 (question and response of Mr. Sullivan).
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base its rates only upon its perceived value of the service to the customer; however, the Commission in Order No. 637 reasoned that the value based term-differentiated rates would have some link to actual costs. 43/
At the time of the suspension order, the Commission knew that each of the pipelines (like EPNG)
proposed to cap the rates at the 250% level. So, the multiplication of the cost-based rate by 2.5
alone cannot constitute the “link” to cost-based rates referenced here, or the full explanation of “the
basis and justification for the price differentials” required in Order No. 637.
Yet, EPNG offers no reasoned basis for its selection of the 250% “price differential”, and
prepared no studies to justify its selection of the 250% rather than any other multiplier. 44/ Mr.
Sullivan did no analysis of the frequency with which market prices of EPNG’s short-term services
would be expected to be between 100-200%, or 200-250%, or over 250% of the cost-based rate. 45/
EPNG and Mr. Sullivan apparently selected the 250% multiplier simply because other pipelines had
proposed it and the Commission set the filings for hearing. 46/ Although other pipelines have filed
similar proposals, the Commission has never approved as just and reasonable anything close to it.
The fact that a proposal was not summarily rejected by the Commission in an order immediately
following a rate filing in no sense indicates that it is just and reasonable. To the contrary, the
Commission typically sets pipeline filings for hearing precisely because they have not been shown to
be just and reasonable, just as it did with EPNG’s rate filing here. 47/
EPNG’s only other justification for its 250% rate level is that it provides “the necessary and
proper incentives to contract for long-term contracts.” 48/ EPNG argues that setting the rate at
250% of the long-term rate is needed to drive shippers to long-term contracts by making the 5- and
7-month “seasonal” services that EPNG prefers to sell economically preferable to 2 or 3 months of
43/ Portland Natural Gas Transmission Sys., 123 FERC ¶ 61,108 at P 25 (2008); Tex. Gas Transmission Corp., 93 FERC ¶ 61,102 at 61,278 (2000) (same language). 44/ TR at p. 718, lines 2-9 (question and response of Mr. Sullivan). 45/ Id. at p. 719, lines 1-12 (question and response of Mr. Sullivan). 46/ See EPNG Brief on Exceptions at 47; Exh. Nos. EGC-7 and EGC-10 (EPNG data responses stating that the 250% proposal was based on what other pipelines had proposed); TR, p. 708, lines 20-22 (Mr. Sullivan explaining the origin of EPNG’s proposal.) 47/ El Paso Natural Gas Co., 124 FERC ¶ 61,124 at P 30 (2008). 48/ EPNG Brief on Exceptions at 48.
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disfavored short-term services. 49/ EPNG even states “[i]f the short-term rate were much lower, it
may still be economically beneficial to continue to purchase short-term services….” 50 / By
embracing this theory of increasing rates high enough to drive its customers away from short-term
service, EPNG ignores the lessons of the Commission’s holdings in EPNG’s last rate case that:
• “Order No. 637 did not suggest that it was appropriate to price IT service in a manner that would encourage IT shippers to purchase firm service.” 51/
• “There is a role for IT service on the national transportation grid and it is not the Commission’s policy to use pricing for this service as a means of discouraging customers from using IT. Shippers should be able to choose whether to purchase firm or interruptible service based on their needs and proper price signals, not based on a pricing scheme that discourages use of one type of service. It is not the Commission’s policy that IT service should be priced in a manner that discourages its use.” 52/
This Commission’s reasoning applies to EPNG’s proposal for short-term firm transportation service
as much as it does to IT. There is equally a legitimate role for short-term firm service, and shippers
should be able to purchase contracts for an appropriate term based on their needs and proper price
signals, 53/ not on a pricing scheme designed to sell them service for longer terms than they need or
want.
Both EPNG and SoCalGas/SDG&E tout the “success” of EPNG’s rate proposal in “working
as intended” to force customers to contract for longer-term, or at least seasonal, firm service rather
than utilizing IT or short-term firm service. 54/ An example of EPNG’s “success” was provided at the
hearing by Mr. Diemer, the witness for the Electric Generator Coalition (“EGC”). Mr. Diemer
explained that when one EGC generator sought a short-term firm agreement for May through
September, it was told that EPNG would not discount from the 250% load factor maximum rate and
that, therefore, it would be cheaper for them to sign up for the seven month “summer” service – 49/ Id. 50/ Id. 51/ El Paso Natural Gas Co., 112 FERC ¶ 61,150 at P 55. 52/ Id. at P 57. 53/ The Commission’s Part 284 regulations require that pipelines must provide transportation service without undue discrimination or preference with respect to, inter alia, “the duration of service.” 18 C.F.R. § 284.7(b)(1) (2010). 54/ EPNG Brief on Exceptions at 50-51; SoCalGas/SDG&E Brief on Exceptions at 13-14.
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leading the generator to contract for additional months of service that it did not need. 55/ Similarly,
Mr. Cini of SCE explained that, while SCE’s peak demand is in the summer, EPNG’s seven month
“summer” seasonal service is not well-suited for SCE’s needs because April, May and even early
June are low demand months. 56/ Mr. Cini also explained that IT service rather than FT is best
suited to SCE’s needs given its highly variable loads. 57/ EPNG’s only “success” in its rate proposal
is in exercising its market power by pushing customers to contract for services that they do not want
or need.
6. EPNG’s Proposal Violates Order No. 712.
Given EPNG’s lack of a legitimate justification for its 250% price differential, its proposal also
fails to comply with Order No. 712. EPNG claims that, in the recent order on rehearing, the
Commission “rejected the argument that EPNG’s proposal was contrary to Order No. 712.” 58/ In
fact, the Commission merely “did not find the [EPNG] proposal was necessarily inconsistent with
Order No. 712” “[b]ecause the proposed rate may act as a recourse rate to the uncapped capacity
release rate.” 59/ Given the evidence established through the hearing, the Commission should now
conclude that EPNG’s proposal would not comport with Order No. 712 because the 250% rates
would not be just and reasonable recourse rates.
EPNG emphasizes that “the Commission in Order No. 712 expressly acknowledged the
continuing viability of its short-term value-based rate policies, as expressed in Order No. 637.” 60/
EPNG here responds to a straw-man argument: no one claims that Order No. 712 rescinded
anything in Order No. 637. The importance of Order No. 712 in this case is that the Commission
55/ TR, p. 2388, line 11 to p. 2389, line 2; see also Exh. No. EGC-10, an EPNG data response explaining how a “rational shipper” would purchase the five-month winter contract at the 100% load factor rate rather than two months at the 250% short-term rate, and similarly would purchase the seven-month “summer” seasonal contract rather than just 3 months at the inflated 250% rate. Thus, under EPNG’s rate proposal, a “rational shipper” is pushed to purchase capacity for a longer term than it needs or wants. EPNG embraces this fact in its brief. 56/ TR, p. 2551, lines 6-12 (Mr. Cini). 57/ See Exh. No. SCE-1, at p. 15. 58/ EPNG Brief on Exceptions at 36. 59/ El Paso Natural Gas Co., 133 FERC ¶ 61,129 at P 23 (2010) (emphasis added). 60/ EPNG Brief on Exceptions at 36.
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there (just as in Order No. 637) explicitly considered and rejected pipelines’ proposals to lift the rate
cap on pipeline-supplied short-term services. 61/ EPNG’s proposal here would have a similar effect.
The Commission repeatedly emphasized in Order No. 712 that the availability of a cost-
based pipeline rate as a recourse for shippers was an essential part of its determination to remove
the price ceiling only for shipper-released capacity. 62/ The Commission explained:
[W]e cannot relax the recourse rate protection given that the entirety of the market has not been shown to be sufficiently competitive. As we explained in Order No. 712, we need to balance the risks of removing the price ceiling and the benefits of such removal, and we have decided that ensuring sufficient protection against market power must take precedence over potential losses in efficiency. . . . . The pipelines specifically argue that market-based rate filings for pipeline transportation are difficult to make and that the Commission uses stringent criteria in evaluating such filings. But we find that, precisely because pipelines have such enormous economies of scale and enjoy market power, the application of economically correct standards is appropriate in reviewing an application to remove rate regulation entirely. . . . . Because, as discussed above, we have not found the short-term market to be fully competitive, and pipelines are able to recover their cost-of-service, we find that maintaining the recourse rate is necessary to ensure continued protection of customers and does not unduly harm pipelines. 63/
The Court of Appeals for the D.C. Circuit recently affirmed the Commission’s decision in
Order No. 712 that it “could not give identical pricing flexibility to pipelines because of concerns the
pipelines could wield market power.” 64/ The Court acknowledged what it termed the Commission’s
“plausible concern, informed by economic theory” that “[i]f pipelines could charge market-based
rates in the short-term market, they might withhold construction of new capacity to take advantage of
the opportunity to earn scarcity rents in the short-term market.” 65/ The Court recognized that
61/ Order No. 712 at P 82. Mr. Sullivan acknowledged this fact at the hearing. TR, p. 721, lines 5-15. 62/ Order No. 712 at PP 31, 48, 61, 86, 102. Mr. Sullivan conceded this uncontestable facet of the order. TR, p. 726, lines 10-15. 63/ Order No. 712-A at PP 46-49 (emphasis added and footnotes omitted). 64/ INGAA II, slip op. at p. 9. 65/ Id. at p. 10. SoCalGas/SDG&E claim that “the key question in reviewing a pipeline’s short-term rate proposal is whether the proposed rates are so excessive so as to take away the pipeline’s incentive to respond to increased demand by constructing additional capacity.” SoCalGas/SDG&E Brief on Exceptions at 8. While this was part of the Commission’s concern in Order No. 712, it is far from the key
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“[w]ithout the price ceilings in place, pipelines might exercise market power, and FERC might be
unable to remedy the resulting harm to customers.” 66/ Accordingly, the Court held that “FERC
made a reasonable judgment to ‘err on the side of enhanced protection against market power’,”
explaining that this judgment was “consistent with the NGA’s ‘fundamental purpose… to protect
natural gas consumers from the monopoly power of natural gas pipelines’.” 67/ On a similar note,
the Court repeated its pronouncement, made in INGAA I when considering analogous issues on
review of Order No. 637, that “‘the basic premise of the NGA is the understanding that natural gas
pipeline transportation is generally a natural monopoly,’ so FERC face[s] an ‘uphill fight’ to justify
market-based rates under those circumstances.” 68/
If EPNG had fully justified its 250% price differentials and linked that differential to actual
costs, then the rates could provide recourse rates as required by Order No. 712. The evidence
shows, however, that EPNG’s proposed 250% rates are “cost-based” only in the very limited sense
that they are derived as an arbitrary multiple of cost-based rates. Given the lack of support for
EPNG’s proposed rate level, the Commission must again “err on the side of enhanced protection
against market power,” “consistent with the NGA’s ‘fundamental purpose… to protect natural gas
consumers from the monopoly power of natural gas pipelines.” That approach requires rejection of
EPNG’s proposal.
question. The claim by SoCalGas/SDG&E that EPNG’s proposal should be approved based solely on analysis of this issue is untenable. The proposal should be rejected for the myriad reasons detailed in this brief, regardless of whether it would eliminate EPNG’s incentive to construct new capacity. 66/ Id. at p. 11. 67/ Id. at p. 5. The first internal quotation is from Order No. 712 at P 108; the second quotation is from Nat’l Fuel Gas Supply Corp. v. FERC, 468 F.3d 831, 833 (D.C. Cir. 2006). Id. 68/ INGAA II, slip op. at p. 5, quoting INGAA I, 285 F.3d at 30-31 (upholding the Commission’s decision in Order No. 637 to lift the rate-ceiling on short-term capacity releases while rejecting pipelines’ arguments that the cost-based ceiling on pipeline-provided short-term services also should be eliminated). Notably, counsel for SCE questioned EPNG’s witness Mr. Sullivan about this quotation from INGAA I at the hearing. TR, pp. 731-35. Mr. Sullivan responded by contending that this was the premise at the time of enactment of the NGA but that, in his view, the Commission has moved away from the premise more recently with “new policies that allow for the development of competitive transportation services in transportation markets and, in particular, in short-term markets.” Id. at p. 734, lines 8-18. Mr. Sullivan’s theory, which is advanced in EPNG’s brief on exceptions at 32, that the “evolution” of Commission policy warrants letting the market set rates for pipelines’ short-term services cannot be reconciled with Order No. 712, with INGAA I or, now, with INGAA II.
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EPNG, and SoCalGas/SDG&E, also claim support from the Commission’s statement in
Order No. 712 that “short-term customers are not captive.” 69/ The semantic issue of whether short-
term customers are “captive” is simply beside the point. While “captive customers” have been
termed the Commission’s “prime constituency” and are particularly vulnerable to a pipeline’s market
power, 70/ the NGA requires that all rates, charged to all shippers, must be just and reasonable.
The relevant inquiry concerning EPNG’s proposal is not whether “captive customers” might be
charged 250% of the cost-based rate; rather, the question is whether any customers will be charged
any rates above the just and reasonable level. Nothing in Order No. 712 suggests that short-term
customers may be charged unreasonable rates.
The Commission did conclude in Order No. 712 that “[t]he releasing shippers’ ability to
exercise market power in the short-term capacity release market also is limited because short-term
customers are not captive.” 71/ This conclusion, however, was relevant only to the capacity release
market and options available to shippers seeking capacity released by other shippers, including the
alternative of the pipeline’s cost-based service. The Commission most definitely did not conclude
that the short-term customers of a pipeline are not susceptible to the exercise of market power: to
the contrary, the concern with pipelines’ market power drove the Commission’s decision to maintain
the cost-based price caps on pipeline services and the Court’s decision to affirm the Commission’s
approach. 72/
EPNG argues that customers have alternatives to EPNG’s short-term services, 73/ and SCE
does not disagree. 74/ EPNG goes on to claim, however, that the availability of competitive
69/ EPNG Brief on Exceptions at 45-46; SoCalGas/SDG&E Brief on Exceptions at 10, citing Order No. 712 at P 50. 70/ UDC v. FERC, 88 F.3d at 1123. 71/ Order No. 712 at P 50 (emphasis added). 72/ See INGAA II, slip op. at pages 9-12. 73/ EPNG Brief on Exceptions at 46-47. 74/ While EPNG is unable to force SCE to buy long-term firm service, that does not mean that rates for IT and short-term firm service may be established to try to push shippers that way, or that SCE and the California market will not be adversely affected. SCE has financial obligations equivalent to purchasing approximately 285 Bcf of gas per year. Exh. No. SCE-1, at p. 6. SCE buys gas from suppliers that transport gas on EPNG and EPNG’s proposal to increase its maximum IT and short-term
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alternatives, in particular capacity release, will ensure that its short-term rates will be reasonable. 75/
This claim cannot be reconciled with INGAA II, or with Order No. 712 itself for the matter. The
Commission eliminated the rate ceiling on capacity release based, in part, on evidence that release
rates were generally below the cost-based rate, but maintained the cap on pipeline services
precisely because of concerns about pipelines’ market power. 76/ Moreover, “FERC explained it
could not conclude the short-term market would remain competitive if the price ceilings were
removed from pipeline sales.” 77/ As the Commission stated in Order No. 712, “[r]emoving the rate
ceiling for pipeline transactions would therefore remove an important protection both for pipeline
customers and for replacement shippers on capacity release transactions.” 78/
firm rates will affect the prices SCE pays. Id. at pp. 7 and 8; see also TR, p. 2561, lines 1-14 (questions and responses of Mr. Cini). Gas transported on EPNG generally sets the market-price for gas in Southern California, which directly drives electricity prices because gas-fired generation is typically the marginal electric generation source. Exh. No. SCE-1, at p. 6; see also TR, p. 2564, lines 6-17. Thus, the effect of EPNG’s proposal would be higher gas and electricity prices in California, assuming other factors are held constant. Exh. No. SCE-1, at pp. 6 and 8. EPNG’s proposal would have its greatest significance at times of peak demand, when EPNG would have the greatest ability to charge the highest price for transportation, just when gas is most needed and prices are already high. Id. at p. 9. Mr. Cini alluded, both in prepared testimony and on the stand, to the worst case scenario of a possible repeat of the California energy crisis of 2000-01. Id. at pp. 9 and 13; TR, p. 2562, lines 13-15 and p. 2563, lines 13-18. As the Commission knows, during the period from November 2000 through March 2001, gas spot prices in California were elevated to the $20 to $30 per MMBtu level, with prices spikes as high as $60 per MMBtu. Pub. Utils. Comm’n of the State of Cal. v. EPNG, et al., 97 FERC ¶ 61,380 at 62,740 (2001). Allegations by SCE and others that EPNG, and its affiliated marketing company, withheld pipeline capacity to drive up those prices in the periods immediately before and during the energy crisis were the subject of the lengthy and heavily contested proceedings in Docket No. RP00-241. See Pub. Utils. Comm’n of the State of Cal. v. EPNG, et al., 105 FERC ¶ 61,201 (2003) (approving contested settlement resolving the proceedings). As Mr. Cini testified: “We have historical experience with the adverse effects on the California market of limitations on the availability of supply on EPNG, whatever their origin. We do not want to take any risk of repeating that experience.” Exh. No. SCE-1, at p. 13; see also TR, p. 2563, line 19 to p. 2564, line 5 (Mr. Cini explaining the adverse effect of high gas prices on the California electricity market during the energy crisis). 75/ See Exh. Nos. EPG-149 at p. 21; No. EPG-337 at p. 36. 76/ INGAA II, slip op. at p. 9 (“FERC explained it could not give identical pricing flexibility to pipelines because of concerns that pipelines could wield market power.”). 77/ Id. at p. 10. 78/ Order No. 712 at P 83. See also Order No. 637 at 31,382 (“Firm shippers cannot successfully withhold capacity from the market to raise price above the existing maximum just and reasonable rate because, if the firm shippers do not use their capacity, the pipeline has the incentive to sell the capacity as interruptible service. Moreover, the Commission is continuing to protect against the possibility that, in an oligopolistic market structure, the pipeline and the firm shippers will have a mutual interest in withholding capacity to raise price because the Commission is continuing cost-based regulation of
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EPNG attempts to reverse the Commission’s reasoning in Order No. 712 when claiming that
short-term capacity releases, at unlimited market-based rates, will serve as a competitive alternative
that will limit the short-term rates that EPNG itself may charge. EPNG’s proposal would free both
the pipeline and releasing shippers (perhaps working together in an oligopolistic market structure 79/)
to charge whatever the market will bear, limited only by the arbitrary, unsupported and excessive
250% cap. This result would be contrary to the regulatory structure established in Order No. 712
and upheld by the D.C. Circuit in INGAA II under which pipelines’ short-term rates must continue to
be cost-based, and where the availability of that cost-based alternative provides a check on capacity
release prices.
7. EPNG’s Proposal Improperly Increases IT rates.
“The Commission generally will not permit an interruptible rate that is derived from the firm
rate at a load factor that varies from 100 percent.” 80/ Indeed, the Commission has rejected a
proposal to shift costs to IT shippers by increasing the rate by just 3.5% (or stated differently, the use
of a 96.5% rather than the 100% load factor derivative of the FT rate). 81/ And the Commission has
firmly held that arguments based on the Order No. 637 discussion of term differentiated rates cannot
pipeline transportation transactions. The pipelines will be required to sell both short-term and long-term capacity at just and reasonable cost-based rates.”) 79/ “There are two ways in which a seller can exercise market power. It can attempt to raise its price acting alone or it can attempt to raise its price by acting together with other sellers. . . . To evaluate whether a seller can act together with others to exercise market power, the Commission typically examined the market’s concentration.” Policy Statement, 74 FERC at 61,234. EPNG has provided no analysis of the concentration of the relevant market. 80/ Southern Natural Gas Co., 99 FERC ¶ 61,345 at P 87 (2002) (citing Transok, Inc., 70 FERC ¶ 61,177 at 61,564 (1995); Stingray Pipeline Co., 68 FERC ¶ 61,372 at 62,487 (1994); and Algonquin LNG, Inc., 79 FERC ¶ 61,139 (1997)). EPNG’s expert witness Mr. Sullivan stated that he “would not agree at all” with this statement of Commission policy. TR, p. 711, lines 13-17. He did agree, however, that the 100 percent load factor rate is the “normal cost-based rate” for IT service, at least for the past decade. TR, p. 711, lines 4-9; see also Tenn. Gas Pipeline Co., 80 FERC ¶ 61,070 at 61,201-05 (1997) (concluding and explaining that the 100% load factor rate properly balances the Commission’s objectives when setting IT rates of rationing scarce capacity during peak periods, maximizing throughput when capacity is scarce, and recognizing quality of service considerations); Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 871 (D.C. Cir. 1993) (affirming the Commission’s decision that 100% load factor IT rates adequately account for the cost and quality differences between interruptible and firm services). 81/ High Island Offshore System, LLC, 107 FERC ¶ 63,019 at PP 202-211 (2004), aff’d, 110 FERC ¶ 61,043 at PP 198-202 (2005).
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alter the requirement of 100% load factor IT rates. 82/ Indeed, the Commission made this point very
clearly in the suspension order in EPNG’s last general rate case:
[t]he Commission has rejected the view that the rationale behind term-differentiated rates for firm service is a justification for deviation from a 100 percent load factor IT rate and the imposition of a higher IT rate. The discussion in Order No. 637 regarding term-differentiated rates was limited to shippers who were using firm service. 83/
In that case, the Commission summarily rejected EPNG’s proposal of a maximum IT rate
based on a 60% load factor equivalent of the FT-1 rate – a lower IT rate than EPNG’s current
proposal, which is equivalent to a 40% load factor FT-1 rate. 84/ EPNG’s proposed IT rates here are
contrary to Commission policy for all the reasons explained by the Commission when rejecting
EPNG’s similar (albeit less extreme) IT proposal in EPNG’s previous rate case:
• The Commission has consistently endorsed the use of a 100 percent load factor derivative of the FT rate to establish IT rates. EPNG, 112 FERC ¶ 61,150 at P 50 (2005).
• Given that EPNG is not fully subscribed, the relevant rate design objective is to maximize throughput and a higher IT rate would not have that effect. Id. at PP 51-53.
• “The higher IT rate proposed by EPNG would be a disincentive to move IT volumes if there were alternatives to EPNG’s IT service, and where there are no alternatives to EPNG’s IT service, the higher rate appears to be a means of extracting a higher rate than is just and reasonable.” Id. at P 53.
• The Commission has consistently held that IT service should be priced at a lower rate than FT service because it is of a lower quality, and EPNG’s proposal fails to take into account the inferior nature of IT service. Id. at P 56.
• “There is a role for IT service on the national transportation grid and it is not the Commission’s policy to use pricing for this service as a means of discouraging customers from using IT. Shippers should be able to choose whether to purchase firm or interruptible service based on their needs and proper price signals, not based on a pricing scheme that discourages use of one type of service. It is not the Commission’s policy that IT service should be priced in a manner that discourages its use.” Id. at P 57.
82/ See, e.g., S. Natural Gas, 99 FERC at PP 83-87 (2002) (rejecting as “without merit” the argument that the principles of term differentiated rates set forth in Order No. 637 justify IT rates set at anything other than the 100 percent load factor rate). 83/ El Paso Natural Gas Co., 112 FERC ¶ 61,150 at P 55 (2005) (internal citations omitted). 84/ Exh. No. SCE-1 at p. 14; see also TR, p. 783, line 14 to p. 784, line 7 (questions and responses of Mr. Sullivan).
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• “Order No. 637 did not suggest that it was appropriate to price IT service in a manner that would encourage IT shippers to purchase firm service.” Id. at P 55.
As SCE’s witness Mr. Cini explained, the Commission’s reasoning in the previous EPNG rate case
set forth above is fully applicable here. 85/
The last two bullets setting forth the Commission’s reasoning for rejecting an IT rate for
EPNG of more than the 100% load factor equivalent bear particular emphasis because EPNG’s
intent here is to price IT (and short-term firm) service in a way that will discourage their use and push
customers toward contracting for longer term firm service. This intent was explained by EPNG’s
witnesses at the hearing. 86/ Moreover, EPNG embraces the concept in its Brief on Exceptions,
even couching the rate level needed to drive its customers away from the short-term services as the
justification for the 250% differential. 87/
To support its contention that “value-based rates” as envisioned in Order No. 637 may apply
to IT service (contrary to the Commission holding in EPNG’s own last rate case 88/), EPNG notes
that the Commission has approved three settlements approving value-based rates that included IT
service. 89/ These settlements have no precedential value, 90/ and parties may agree to provisions
in a settlement that would not be authorized otherwise. Moreover, as previously explained, all of
these settlements included off-peak rates to offset higher peak rates, as contemplated in Order No.
637.
85/ Exh. No. SCE-1, at p. 15. 86/ In prepared testimony, Mr. Sullivan indicated only that EPNG’s proposal would “encourage” longer term firm contracts and “provide an additional impetus for signing long-term firm contracts.” See Exh. No. EPG-149, at pp. 16-17, 18; Exh. No. EPG-337 at p. 13. On cross-examination, Mr. Sullivan maintained that he does not know if EPNG had the objective of discouraging shippers from relying on IT, noting that he is “not EPNG’s market witness.” See TR, p. 775, line 2 through p. 778, line 12. EPNG’s market witness, Mr. Price, embraced the idea that EPNG’s intent is to move shippers away from IT to seasonal firm service, and even touted its success in doing so. TR, p. 603, lines 5-16. Mr. Price also explained EPNG’s unwillingness to discount IT as part of this same effort to drive customers to longer-term firm service. Id. at p. 634, line 23 through p. 635, line 5. 87/ EPNG Brief on Exceptions at 49. This point is discussed above in Section III.C.5. 88/ El Paso Natural Gas Co., 112 FERC ¶ 61,150 at P 55. 89/ EPNG Brief on Exceptions at 49. 90/ See note 7 supra.
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Nevertheless, EPNG claims that “[r]eliance on the Commission’s policy concerning IT rate
design is misplaced” because it has proposed to design its IT rates using the 100% load factor
equivalent of a firm rate, just the short-term firm rate. 91/ The problem with that theory, of course, is
that the short-term firm rate itself is unreasonably set at 250% of the long-term firm cost-based rate:
the 100% load factor derivative of an inflated, unreasonable rate is equally inflated and
unreasonable. In its last rate case, EPNG proposed to design IT rates using a 60% load factor –
meaning that they would be equal to 166% of the firm rate – but did not distinguish short-term from
long-term firm rates. In this case, EPNG has proposed a much more radical rate design, not only
increasing the proposed maximum IT rates from 166% to 250% of the long-term firm rate but also
extending the concept of inflated rates to short-term firm service. EPNG’s suggestion that this
expansion of its proposal somehow resolves the multitude of problems that led the Commission to
reject EPNG’s IT rate proposal in the last rate case strains credulity, and must be rejected.
8. Revenue Crediting Does Not Save EPNG’s Proposal.
EPNG relies very heavily on its proposed revenue crediting as the cure for various short-
comings of its short-term rate proposal. Indeed, EPNG claims that the Presiding Judge’s rejection of
its short-term rate proposal “rests solely on the notion the EPNG’s proposal must be rejected
because it contains a revenue crediting mechanism in lieu of a cost allocation as a means of
ensuring that the rates be designed to meet EPNG’s annual revenue requirement.” 92 / This
conclusion is inaccurate. In any case, EPNG’s revenue crediting proposal does not resolve all the
many failings of its 250% rate proposal.
To begin with, the Commission in Order No. 637 contemplated revenue crediting as a
substitute for offsetting lower rates through cost reallocation only for peak/off-peak rates proposed in
a limited section 4 rate filing, since costs cannot be reallocated outside of a general rate case. 93/
The order does not contemplate revenue crediting for peak/off-peak rates set in a general rate case
like this one, or for term differentiated rates at all. More generally, the Commission sometimes 91/ EPNG Brief on Exceptions at 49. 92/ Id. at 38. 93/ Order No. 637 at 31,291-92.
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authorizes revenue crediting, rather than proper cost allocation, for new services; 94/ yet, none of
the services covered by EPNG’s proposal here are new. 95/
Moreover, even if revenue crediting were an acceptable substitute for allocating costs and
putting their recovery at-risk, EPNG’s crediting proposal is woefully inadequate. EPNG does not
propose any crediting of revenue from the short-term services unless and until it first recovers its
entire cost of service and, even after that, would credit only 90% of the increment of revenue above
the traditional cost-based 100% load factor rate. 96/ In contrast, for IT services coming out of Order
No. 636 restructuring proceedings (which EPNG looks to as an analogy intended to support its
proposal 97/), pipelines generally credited back 90% of all the IT revenues in excess of the costs
allocated to IT 98/ -- a very different proposition from not crediting any revenue until the total cost of
service is recovered and then crediting 90% of only the increment above the cost-based rates.
Another short-coming here is that to the extent that EPNG succeeds in moving shippers from IT and
94/ See e.g., Pac. Connector Gas Pipeline, LP, Jordan Cove Energy Project, L.P., 129 FERC ¶ 61,234 at P 14 (2009); Cimarron River Pipeline, LLC, N. Natural Gas Co., 124 FERC ¶ 61,069 at P 15 (2008); Wyo. Interstate Co., 121 FERC ¶ 61,135 at P 2 (2007). 95/ TR, p. 795, line 17 to p. 796, line 4 (questions and responses of Mr. Sullivan). 96/ Exh. No. EPG-337 at p. 21 and TR, p. 804, line 9 to p. 805, line 8. The precise scope of what services are covered by the revenue crediting has been less than clear. The “Prepared Direct Testimony of Mr. Derryberry,” Exh. No. EPG-153 at p. 49 clearly stated that EPNG would share revenues only from its short-term firm transactions, without covering IT, and the tariff sheets included in the filing followed this approach. Mr. Sullivan’s testimony, on the other hand, appears to state that IT revenues are included in the sharing as well. At the hearing, Mr. Derryberry indicated that his written testimony was erroneous and that EPNG intends to include IT revenues in the sharing mechanism. TR, p. 664, line 6 to p. 666, line 15 (questions and answers of Mr. Derryberry). 97/ Exh. No. EPG-337 at p. 21; TR, p. 820, line 5 to p. 821, line 4, and page 821, line 23 to p. 822, line 4 (questions and responses of Mr. Sullivan on redirect). 98/ In Order No. 636-A, the Commission recognized that the implementation of capacity release could affect the level of IT service, complicating the issue of allocating costs to IT. FERC Stats. & Regs. ¶ 30,950 at 30,563-64 (1992). The Commission held there that the issue should be considered in individual restructuring proceedings while suggesting that parties consider the possibility of revenue crediting. The Commission stated that one possibility would be that revenues from IT service be credited to firm shippers, adding that a full credit of all the IT revenues might not be appropriate if the pipeline has some revenue and cost responsibility (such as restructuring transition costs) allocated to IT service. Id. at 30,564 & n. 164. In individual pipeline restructuring proceedings, pipelines typically agreed to credit to firm shippers 90% of all IT revenues above the costs allocated to IT. EPNG’s own Order 636 restructuring proceeding is a typical example of that approach. EPNG, 63 FERC ¶ 61,139 at 61,938-39 (1993); see also, e.g., Arkla Energy Resources, 62 FERC ¶ 61,076 at 61,461 (1993) (deciding this issue when contested by the parties and requiring the allocation of some costs to IT and the crediting to firm shippers of 90% of all IT revenues above the allocated costs).
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short-term firm to seasonal or long-term firm service – as EPNG says it has successfully been
doing 99/ – the resulting revenues will not be included within the required revenue sharing. 100/
Furthermore, the revenue crediting will do little or nothing for the shippers actually paying the
inflated short-term rates. To the extent that EPNG’s proposal results in crediting, the revenues will
be allocated, some time later, among all shippers pro rata based on the total jurisdictional revenues
received from all shippers. 101/ As a result, the revenues will be allocated almost entirely to long-
term firm shippers – who are those positioned to release capacity as a possible competitive
alternative to short-term service from EPNG. Thus, the crediting mechanism may perversely result
in a greater harmony of interests of the parties who might have the opportunity to coordinate in an
exercise of market power to increase the costs of short-term transportation services. 102/
EPNG maintains that the Commission’s only purpose in Order No. 637 in requiring lower off-
peak rates to offset peak rates (or lower long-term rates to offset higher short-term rates) is to
prevent the over-recovery of total system costs. 103/ If EPNG’s theory were right, it could charge
short-term customers any rate with no limitation as long as it credited the revenues back to long-term
customers. Yet, even a perfectly designed revenue crediting mechanism could not take the place of
offsetting rate decreases off-peak or for longer-term services as required under Order No. 637 (and
EPNG’s proposed mechanism is a long ways from perfect). As the Commission explained in Order
No. 637, lower off-peak rates are necessary to ensure that a customer buying the particular service
year-round would not pay more than the annual revenue requirement allocated to the service. 104/
EPNG’s proposal would not do that: it would charge short-term customers excessive rates year-
99/ TR, p. 633, lines 5-16 (Mr. Price). 100/ Id. at p. 1279 at lines 1-22 (questions and responses of Ms. Palazzari). 101/ Exh. No. EPG-337 at pp. 20-21 (correcting prior testimony that the revenues would flow only to firm long-term shippers, and increasing the proposed sharing percentage once the various criteria for sharing are satisfied from 75% to 90%). 102/ As discussed above, there is no evidence of the extent to which a sufficiently competitive market exists that would prevent EPNG from acting together with large capacity holders (who are free to charge any price for short-term releases under Order No. 712) to raise prices for short-term services. EPNG did not do any analysis of market concentration that would shed light on the issue. 103/ EPNG Brief on Exceptions at 43. 104/ Order No. 637 at 31,290.
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round – regardless of whether it might, potentially, flow some of the excess revenue back to some
other customers. Moreover, the requirement of lower off-peak rates is intended as “a check on the
ability of pipelines to propose extraordinary high rates during peak periods” and “a disincentive for
pipelines to raise peak period rates to unrealistically high levels.” 105/ Freed, by its own decision,
from the required “check” of lower, off-setting off-peak rates, EPNG proposes the extraordinary and
unrealistically high rate of 250% as its peak rate, to be applied every day of the year. Notably, none
of the four settlements that EPNG claims are “similar” to its proposal allow for anywhere close to
such a high multiple for even a single peak month. 106/
The most significant problems with EPNG’s rate proposal have little to nothing to do with the
possibility of EPNG over-collecting its costs. The crucial point is that – under the NGA -- all
customers are entitled to just and reasonable rates on all available services. Collecting inflated and
unreasonable rates from some, short-term customers, and then crediting excess revenues sometime
later to different customers, cannot make the inflated and unreasonable rates reasonable. And
revenue crediting at a later date will do nothing to address the real-time harm on the markets – gas
and electricity – that could result from EPNG’s collection of excessive rates on short-term services.
9. Conclusion Regarding Short-Term Rates.
For all of the reasons explained here, EPNG’s proposed short-term firm and IT rate proposal
is unjust and unreasonable and the holdings of the Initial Decision on this issue should be affirmed.
EPNG’s short-term firm and IT rates should be set at the 100% load factor equivalent of the long-
term firm rates, consistent with Commission policy and precedent. EPNG and SoCalGas/SDG&E
tout the “success” of EPNG’s rate proposal in “working as intended” to force customers to contract
for longer-term, or at least seasonal, firm service rather than utilizing IT or short-term firm
service. 107/ The time has come to put an end to this “success” of EPNG in wielding the stick of
unjust and unreasonable effective short-term rates to force customers to contract for services that
they do not want or need. 105/ Id. 106/ See supra note 15. 107/ EPNG Brief on Exceptions at 50-51; SoCalGas/SDG&E Brief on Exceptions at 13-14.
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B. EPNG Should Not Be Permitted To Reallocate Costs Not Paid By Article 11.2 Shippers To Other Customers.
EPNG proposes that, if Article 11.2 of the 1996 Settlement is not terminated, it should be
permitted to reallocate the shortfall in costs not recovered from the protected contracts or shippers to
other customers. 108 / The Presiding Judge summarizes the testimony and positions of the
participants related the 11.2 cost reallocation issue at paragraphs 520 to 563 of the Initial Decision.
The Presiding Judge then discussed the issue and explained her conclusions at paragraphs 564
through 567, and set forth the relevant findings of fact and conclusions of law at paragraphs 719,
722-23 and 727. The Commission should affirm the Presiding Judge’s conclusion that the Article
11.2 shortfall may not be allocated to any shipper.
EPNG’s proposal to reallocate costs is contrary to the fundamental rate-making principle of
matching cost allocation to cost causation, and would improperly require non-11.2 shippers to
subsidize the 11.2 customers. The proposed reallocation is not authorized by the Commission’s
selective discounting policy, which is the relevant test for this issue as previously established by the
Commission, because the provision of Article 11.2 rates to all customers was manifestly not required
to meet competition and retain the volumes on the system. EPNG’s other arguments in support of
reallocation of the 11.2 shortfall are equally unavailing. Therefore, if Article 11.2 is not terminated
and the rates for the 11.2 shippers less than the general system rates are held to be just and
reasonable, EPGN alone must be responsible for the resulting shortfall. The proposed reallocation
of costs to other shippers would be unjust and unreasonable.
The Brief on Exceptions filed by the California Parties, including SCE, explains that Article
11.2 rates would not be just and reasonable because they would not properly allocate the costs of
post-1995 EPNG projects that are required to serve the Article 11.2 shippers and were not
contemplated at the time of the Settlement. If the Commission rejects this view – which is shared by
the California Parties and EPNG – however, it will have concluded that it is reasonable for the Article
11.2 customers to not bear certain costs that would be allocated to them but for the 1996 Settlement.
108/ See EPNG Brief on Exceptions at 102-26.
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That conclusion could only be based on the view that, in the Presiding Judge’s words, “EPNG
agreed as part of the Settlement to absorb the costs of any underutilized capacity as part of the 1996
Settlement.” 109/ Based on that reasoning, the resulting shortfall in cost recovery must be borne by
EPNG alone.
“Traditional ratemaking principles used to establish just and reasonable rates require that the
rates produce revenues from each class of customers that match, as closely as possible, the costs
of serving each class or individual customer. In other words, rates must reflect to some degree the
costs actually caused by the customers who must pay them.” 110/ “Principles of fairness in
ratemaking support the concept that those who are responsible for the incurrence of costs be the
ones who will bear those cost burdens.” 111/ As the United States Court of Appeals for the D.C.
Circuit has explained:
FERC and the courts have added flesh to these bare statutory bones [of NGA Section 4], establishing what has become known in Commission parlance as the “cost-causation” principle. Simply put, it has been traditionally required that all approved rates reflect to some degree the costs actually caused by the customer who must pay them. 112/
Under this principle, “[p]roperly designed rates should produce revenues from each class of
customers which match, as closely as practicable, the costs to serve each class or individual
customer.” 113/
EPNG’s proposed reallocation of costs from 11.2(a) contracts to other customers
unquestionably would violate this fundamental ratemaking principle. EPNG allocated all its costs
109/ I.D. at P 564. 110/ Nat’l Fuel Gas Supply Corp., 67 FERC ¶ 61,147 at 61,415 (internal footnotes omitted), reh’g, 68 FERC ¶ 61,132 (1994). 111/ Sys. Energy Resources, Inc., 41 FERC ¶ 61,238 at 61,616 (1987). 112/ KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992). In this decision, the Court actually upheld minor variation from the cost-causation principle in the unusual context of resolving take-or-pay issues. The departure from principle was allowed only in that limited circumstance and still required imposition of costs only on entities that bore some responsibility for the costs and derived some benefit from the solution imposed. Id. at 1302-1304; see also UDC v. FERC, 88 F.3d 1105, 1185-87 (D.C. Cir. 2006) (discussing KN Energy and this very limited exception allowed to the cost-causation principle). 113/ Ala. Electric Coop., Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982) (emphasis in original retained).
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among all its customers and, then, to the extent that Article 11.2 prevents it from recovering certain
costs, it seeks to reallocate the unrecovered costs to other customers. The “shortfall” costs at issue
were incurred to provide service to the 11.2 shippers, not to provide service to the other shippers.
EPNG not only admits, it actively argues (as a reason why Article 11.2 should be eliminated) that the
costs that cause the system rates to exceed the rate caps were incurred equally, if not
disproportionately, to provide service to the 11.2 shippers. For instance, EPNG explains on brief:
there can be no reasonable dispute that the Article 11.2 shippers demanded the construction of EPNG’s major post-1995 expansion facilities, whose costs causes EPNG’s recourse rates to exceed the Article 11.2(a) rate cap. Why is that relevant? The answer is found in the fundamental ratemaking principle that cost responsibility should be aligned with cost causation. Having urged EPNG to construct facilities whose costs have caused the Article 11.2 issues in this case, it cannot be in the public interest to allow Article 11.2 to permit the Article 11.2 shippers to avoid a significant portion of those costs. 114/
Reallocation of costs, from the 11.2 shippers that caused them to other shippers that did not, plainly
would violate the principle of cost causation.
1. EPNG Did Not Justify A “Discount Adjustment,” Which Would Be The Only Basis For Reallocating Costs Not Recovered As A Result of Article 11.2.
In its March 20, 2006 Order in Docket No. RP05-422, the Commission held that “nothing in
the [1996] Settlement prevents EPNG from proposing to price its services so that it could recover its
costs from other shippers to the extent that Article 11.2 rates would not recover its cost of
service.” 115/ The Commission added the general reminder that “El Paso will have the burden of
establishing the justness and reasonableness of its rates” and then added, more specifically:
Further, to the extent that El Paso proposes to include a discount adjustment in its rates, that proposal will be evaluated at the hearing pursuant to the Commission’s selective discount policy. Under that policy, the pipeline has the ultimate burden of showing that any discount for which it seeks an adjustment was necessary to meet competition, and El Paso will have this burden at the hearing. 116/
114/ EPNG Brief on Exceptions at 73 (internal footnote omitted). 115/ Exh. No. EPG-69 at p. 43 (quoting EPNG, 114 FERC ¶ 61,290 at P 92 (2006). 116/ EPNG, 114 FERC at PP 92-93 (internal footnote omitted). In accompanying footnote 69 of the order, the Commission cited its “Policy for Selective Discounting for Natural Gas Pipelines,” 111 FERC ¶ 61,173, reh’g denied, 113 FERC ¶ 61,173 (2005) (hereinafter, the “Discounting Policy Statement” and “Discounting Policy Statement Rehearing” respectively).
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EPNG now attempts to read this statement very narrowly as ruling that the selective discount
policy applies only if it literally proposes a “discount adjustment,” and that it also may advance other
theories for reallocating costs. 117/ Yet, in Docket No. RP05-422, EPNG had argued (just as it has
here) for the proposed reallocation of uncollected 11.2 costs more generally based on the 1996
Settlement itself and the ratemaking principle that pipelines are permitted the opportunity to recover
their costs, adding only as a secondary argument that reallocation also would be consistent with the
Discounting Policy Statement. 118/ Other parties argued that EPNG had no right to reallocate to
other shippers costs that it cannot recover as a result of Article 11.2, under any theory. 119/ In the
context of these arguments in Docket No. RP05-422, and in light of the Commission’s general rate-
making principles, the proper reading of the Commission’s holding quoted above is that a showing of
compliance with the selective discount policy is the only way in which EPNG could show the
proposed reallocation of an 11.2 shortfall to be just and reasonable. To the extent EPNG proposes
to reallocate the cost shortfall, the proposal is to be evaluated pursuant to the selective discounting
policy.
Pipelines are afforded a right to propose rates providing a reasonable opportunity to recover
their cost of service, but they have no general right to reallocate costs so as to require certain
customers to subsidize others. If a pipeline enters into a settlement agreeing not to collect certain
costs from settling customers, it cannot then reallocate those foregone costs to non-settling services
or to new customers. Similarly, if a pipeline agrees to a negotiated rate with customers that do not
recover all the costs of the service, it cannot reallocate the shortfall to other customers. The
117/ See EPNG Brief on Exceptions at 105. 118/ EPNG’s arguments are summarized in EPNG, 114 FERC ¶ 61,290 at PP 87-88, but the point is made clearer by reference to EPNG’s pleadings in Docket No. RP05-422 on the subject that lead to the order (which are available in the Commission’s E-Library). At the technical conference in that proceeding, the participants provided for two rounds of comments regarding issues associated with Article 11.2. In its Initial Comments, filed on October 5, 2005, EPNG’s sole argument in favor of reallocation (included at p. 18 of the comments) was the general principle that pipelines are entitled to a reasonable opportunity to recovery their costs. In Reply Comments filed on October 14, 2005, EPNG (at pp. 29-30) again presented the fundamental argument that it has a right to reallocate costs in order to have the reasonable opportunity to recover them and then added: “Additionally, El Paso has an independent right to reallocate costs as part of a discount-type adjustment.” 119/ See EPNG, 114 FERC at P 89.
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selective discount policy is a limited exception where reallocation of costs is allowed. That policy
provides that reallocating costs not collected from customers receiving a discount is appropriate if
and only if the discount benefited other customers by retaining volumes on the system, thereby
allowing system costs to be spread over a wider base. This is consistent with the cost causation
principle because the customers allocated the costs were benefitted by the discount. 120/
EPNG attempts (while also making other arguments) to justify the cross-subsidization
inherent in its proposed reallocation of costs not collected by reason of the 11.2 rate caps by
analogy to the selective discount policy. 121/ Yet, the rate caps were not structured as discounts
under the 1996 Settlement. They were simply rates agreed upon as part of a complex series of
tradeoffs in the settlement. 122/ The closest analogy may be negotiated rates, as the Presiding
Judge and the Staff’s witness concluded. 123/ Even if the Article 11.2(a) rate caps are treated as
discounts, the Commission’s policies clearly do not allow a discount adjustment in these
circumstances.
In the 1989 Rate Design Policy Statement, the Commission provided that if a pipeline grants
a discount in order to meet competition, it need not design its rates based on the assumption that the
discounted volumes flow at the maximum rates. 124/ The Commission explained that, if a pipeline
must assume that previously discounted service will be priced at the maximum rate, there may be a
disincentive for pipelines to discount services “to capture marginal firm and interruptible
120/ EPNG’s key witness on this issue, Ms. Palazzari, explained this issue at the hearing: “the theory of the discount policy, Mr. Nevins, is that the customers of the pipeline, as well as the pipeline itself, are benefitted by keeping the shipper on the system at a discount, than losing the shipper all together. So it’s a benefit analysis.” TR, p. 942, lines 17-21; see also id. at p. 944, line 17 to p. 945, line 6 (Ms. Palazzari agreeing that other customers are only better off if the customer would have otherwise left the system or reduced its billing determinants but for the discount, and that the Commission imposes the requirement that the discount be motivated by competition because, absent competition, the discount was not needed to retain the volumes.) 121/ EPNG Brief on Exceptions at 117-26. 122/ See Exh. No. SCE-2 at pp. 44-46. 123/ I.D. at P 565; Exh. No. S-12 at p. 47. EPNG makes that point in its brief on exceptions at 117 that the Article 11.2 rates are not actually, literally, negotiated rates, as established in more recent Commission policy. The rates certainly are more akin to negotiated rates than they are to discounts however. 124/ Policy Statement Providing Guidance with Respect to the Designing of Rates, 47 FERC ¶ 61,295, reh’g, 48 FERC ¶ 61,122 (1989).
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business.” 125/ The policy is designed to serve dual goals of preventing cross-subsidization in the
design of rates and maximizing throughput by attracting new “marginal business.” 126/
As the Commission has implemented this policy, “[i]n order to obtain such a discount
adjustment in a rate case, the pipeline has the ultimate burden of showing that its discounts were
required to meet competition.” 127/ “The Commission does not routinely grant pipelines a discount
adjustment, but grants such an adjustment only to the extent that the discount was required to meet
competition. The Commission has denied pipelines the adjustment where the pipeline has failed to
meet its burden of showing that the discount was required to meet competition.” 128/ “Once
evidence has been introduced raising reasonable questions concerning whether competition in fact
required the discounts given in particular transactions, the pipeline must provide sufficient evidence
concerning why it granted the specific discounts in question in order to show that competition
required it to give those discounts in order to obtain the customers in question.” 129/
Here, essentially every active customer entitled to the Article 11.2 rates has taken the
position that the rates were not required by competition. 130/ Importantly, every witness in the
proceeding that was actually present at the time of negotiation of the 1996 Settlement maintains that
Article 11.2 was not motivated by competition. Rather, Article 11.2 was simply a negotiated part of
the entire, complicated settlement. This evidence alone seems sufficient to resolve the issue against
125/ Id., 47 FERC at 62,056. 126/ Id.; 48 FERC at 61,448-49. 127/ Discounting Policy Statement, 111 FERC at P 4; see also Exh. No. SCE-2 at pp. 42-43 (explaining the selective discount policy). 128/ Discounting Policy Statement Rehearing, 113 FERC at P 24. The Commission explained this point, for apparent emphasis, in the March 20 EPNG order, supra., 114 FERC at note 71. 129/ Iroquois Gas Transmission Sys., LP, 86 FERC ¶ 61,261 at 61,957 (1999). 130/ See “Prepared Direct And Answering Testimony of James A. Doering On Behalf of The Texas-New Mexico Shipper Group,” Exh. No. TNM-1; “Prepared Answering Testimony of John A. Cogan on behalf of UNS Gas, Inc. and El Paso Municipal Customer Group,” Exh. No. UNS-1; “Prepared Direct Testimony of Glen D. Reeves,” Exh. No. SRP-1; “Prepared Direct Testimony of Thomas A. Carlson,” Exh. No. APS-1; “Prefiled Written Testimony of Robert A. Hewlett,” Exh. No. AEP-1; “Prepared Direct And Answering Testimony of Robert A. Jordan on Behalf of Southwest Gas Corporation,” Exh. No. SWG-18; “Prepared Direct and Answering Testimony of Jack N. Jones on Behalf of Southern California Gas Company and San Diego Gas & Electric Company,” Exhibit No. SCG-13.
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EPNG; certainly, at an absolute minimum, it presents “reasonable questions” that shift the burden of
proof back to EPNG.
Importantly, the Article 11.2 rates were offered to customers for a very long term, indeed an
apparently endless term according to the 11.2 shippers. “Before a pipeline gives a long-term
discount… for competitive reasons, the Commission would generally expect the pipeline to make a
thorough analysis as to whether such a discount was in fact required. This would include reviewing
expected market conditions over the term of discount, the customer’s competitive alternatives, such
as its access to other pipelines or ability to use alternate fuels, and the cost of those
alternatives.” 131/ And “in the case of a long-term discount, the pipeline must present a thorough
analysis of whether competition required such a long term-discount.” 132/
EPNG could not possibly maintain that it was required to offer the rate caps in order to meet
competition and obtain customers, or capture incremental business. The rate caps by definition
were offered only to existing customers that agreed to the settlement of significant issues on the
system. As the Commission has held, “There is no apparent reason for giving discounts in the
middle of a long-term contract, since the pipeline already has the load and the revenues under the
contract.” 133/ It is also very difficult to envision the 11.2 rates as required to keep volumes on the
system since they were provided predominantly to customers then receiving full requirements
service.
EPNG does claim that some portion of its EOC load was susceptible to competition at the
time of the 1996 Settlement, originally suggesting that “[n]early 50 percent of EPNG’s EOC billing
determinants could potentially be lost to another existing pipeline at that time.” 134/ Detailed cross-
examination concerning this issue at the hearing revealed that this claim was very significantly
overstated. 135/ There was a continuing dialogue at the hearing with attorneys for EPNG seeking
131/ Trunkline Gas Co., 90 FERC ¶ 61,017 at 61,094 (2000). 132/ Discounting Policy Statement, 111 FERC at P 66. 133/ Trunkline, 90 FERC at 61,093. 134/ Exh. No. EPG-374 at p. 100. 135/ See TR, p. 907, line 8 to p. 925, line 16 (cross-examination of Ms. Palazzari evaluating this claim on a customer-by-customer basis).
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agreement by customer witnesses that some particular volumes, on some discrete portions of the
system, might have been served by another pipeline at some time; the limited fruits of that
questioning are presented by EPNG on brief. 136/ The details of the debate about what particular
contracts might have been subject to competition are immaterial however, for two key reasons:
First, the Article 11.2 rate caps were made available to all the existing shippers at the time.
So to show that the rate caps were required to meet competition, EPNG would need to demonstrate
that a discount was required to meet a competitive threat and keep the volumes on the system for
every single shipper on the system. EPNG also would need to demonstrate that competitive
conditions required that it provide the same pricing to all the 11.2 customers, including even very
small full requirements customers. 137/ EPNG does not even attempt to make such an impossible
showing.
Second, no evidence has been presented that shows that EPNG actually evaluated at the
time of the 1996 Settlement the level of competition for its customers. On the stand, Ms. Palazzari
testified that she had not seen any economic analyses that were considered by EPNG around the
time of the Settlement that demonstrated that the EOC load was at-risk. 138/ Similarly, Ms.
Palazzari was not familiar with any analyses that EPNG considered at the time evaluating how much
any competing alternatives would have cost the customers. 139/ Nor was there any evidence
produced from the time of the Settlement negotiations evaluating how long of a term for a discount
would be needed. Absent such evidence, EPNG cannot possibly satisfy the burden of proof
required under the selective discount policy. As SCE’s witness Mr. O’Loughlin testified:
Due to the complete lack of contemporaneous evidence regarding any type of analysis by EPNG of competitive conditions in developing the Article 11.2(a) pricing, the Commission should reject EPNG’s attempt to classify the cost shift as a discount. 140/
136/ See EPNG Brief on Exceptions at 119-21. 137/ See Exh. No. SCE-2 at pp. 43-44. 138/ TR, p. 975, lines 7-25. 139/ Id. at p. 976, line 1 to p. 978, line 9; see also Exh. No. EGC-45 (EPNG data response stating that Ms. Palazzari did not review any analyses prepared or reviewed by EPNG in considering whether to enter into the Settlement that demonstrated how much any competing alternatives would have cost). 140/ Exh. No. SCE-2 at p. 44.
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Similarly, the Presiding Judge rightly concluded that “EPNG offered no contemporaneous evidence
of competitive concerns forcing the Section 11.2 rate caps at the time of the Settlement which would
be used to prove its discount rate theory.” 141/
For these same two key reasons, there is no importance to EPNG’s alternative theory that it
is the level of competition in 2006, rather than in 1995-96, that matters for the inquiry. 142/ Although
some larger amount of volume likely was subject to competition a decade after the Settlement, it still
was not enough to explain why an across-the-board rate cut for all customers could be motivated by
concern with competition. Moreover, convincing evidence would need to be presented that EPNG
analyzed at the time of the 1996 Settlement the complex uncertainties of how much competition
would exist a decade out, and what rates and discount term would be needed to compete with the
future competition. There is absolutely no record evidence suggesting that EPNG did such analysis
at the time.
EPNG did no competitive analysis – either of conditions in 1995-96 or, even more unlikely,
for 2006 -- prior to agreeing to Article 11.2 for the simple reason that the rate caps were not
motivated by competition. Had it done so, of course, it would have readily concluded that there was
absolutely no competitive reason to offer lower rates to the vast majority of its customers. Most of
the contracts providing rate cap protection were with the former full requirements customers who,
almost by definition, had no competitive alternatives to service to EPNG and generally were
contractually barred from taking service from a competing pipeline. Even putting aside the key fact
that the customers already had long-term contracts, EPNG could not conceivably maintain that it
needed to offer rate relief to those customers in order to prevent them from taking service from a
competitive alternative.
Again, EPNG simply did not offer the rate caps in order to meet competition; rather it
negotiated the caps as part of a complex series of trade-offs embodied in the 1996 Settlement. 143/
141/ I.D. at P 565. 142/ See EPNG Brief on Exceptions at 123-24. 143/ See Exh. No. SCE-2 at pp. 44-46.
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Similar facts were present in a rate case of Trunkline Gas Company. 144/ There, Commission Staff
and certain other parties challenged Trunkline’s request for a discount adjustment by arguing that
the discounts were given to settle a rate case. Trunkline denied that conclusion, maintaining that the
discounts were offered to meet competition and not as part of a rate case settlement. The
Commission held that Trunkline failed to meet its burden of proof and rejected the proposed discount
adjustment. More importantly for present purposes, the Commission as well as the pipeline and all
participants in the case implicitly recognized that a discount offered for the purpose of an
inducement to settle a rate case is not motivated by competition and, thus, cannot give rise to a
discount adjustment. The same is true of the rate caps included in the 1996 Settlement.
2. Article 11.2 Rates Are Not Vintage Rates.
Perhaps recognizing that it cannot justify its proposed reallocation of costs not collected
because of Article 11.2 under the selective discount policy, EPNG also presented another theory:
that the result would be analogous to “vintage rates.” 145/ Yet, EPNG’s proposed reallocation of
costs from 11.2 customers to other shippers bears no resemblance to vintage rates and cannot be
justified in that way. As the Presiding Judge concluded, “no [ ] ‘new facility vintage’ scenario exists
here. EPNG appears [with its vintage rate theory] to be grasping at straws to obtain the unjust and
unreasonable, and therefore an unlawful revenue increase from the non-Section 11.2 Shippers on its
system.” 146/
The general concept of vintage rates is that different customers are charged different rates
associated with capacity that was constructed at different times. 147/ EPNG’s theory here (in the
event Article 11.2 continues to exist) is that Article 11.2 shippers should pay rates based on the 1995
cost of service escalated under the settlement (per 11.2(a)) and that other shippers would
disproportionately bear the cost of more recent projects or expenditures through the reallocation, so
144/ Trunkline, 90 FERC ¶ 61,017 at 61,084-095 (2000). 145/ EPNG Brief on Exceptions at 114-16; see also Exh. No. EPG-69 at p. 45. 146/ I.D. at P 566. 147/ TR, p. 947 at lines 17-23 (Ms. Palazzari confirming this concept).
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that the different customers would be charged different rates associated with capacity constructed at
different times. 148/
Under the Certificate Policy Statement, “[t]he threshold requirement in establishing the public
convenience and necessity for existing pipelines proposing an expansion project is that the pipeline
must be prepared to financially support the project without relying on subsidization from its existing
customers.” 149/ This no-subsidies requirement often means that new projects are incrementally
priced, with costs covered only by customers using new facilities to avoid having other customers
subsidize the project. 150/ Rolled-in pricing is appropriate in the case of cheap expansibility made
possible because of earlier, more costly construction. 151/ Furthermore, “[t]he Commission’s no-
subsidy policy recognizes that existing customers should pay the costs of projects designed to
improve their service by replacing existing capacity, improving reliability or providing additional
flexibility.” 152/ Where a project combines an expansion with improvements to existing services, the
existing customers’ rates may be increased in relation to the service improvements, resulting in
costs being shared by new shippers and pre-existing customers. 153/ The unifying principle in
determining how to price new facilities is the need to avoid subsidies – in accordance with the
general principle of cost causation discussed earlier.
This vintage rate theory bears no relation to the actual facts of EPNG’s system. If EPNG’s
post-1995 facilities had been incrementally priced, new customers would bear the costs of the new
facilities and the older, 11.2 shippers would not bear those costs. Or if the post-1995 facilities
served new expansion customers while also improving service for pre-existing customers, the costs
could have been divided to reflect benefits to various shippers. Had this happened, EPNG would
have vintage rates.
148/ See EPNG Brief on Exceptions at 114-116; TR at p. 951, line 22 to p. 952, line 7 (Ms. Palazzari confirming this theory). 149/ Statement of Policy: Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC ¶ 61,227 at 61,746 (1999); clarified, 90 FERC ¶ 61,128 (2000), clarified, 92 FERC ¶ 61,094 (2000). 150/ Id., 88 FERC at 61,745. 151/ Id., 88 FERC at 61,746. 152/ Id., 90 FERC at 61,393 (Order on Rehearing). 153/ See id., 90 FERC at 61,392-94.
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EPNG’s theory of vintage rates is entirely counter-factual however. EPNG does not have
separate facilities to serve non-11.2 customers distinct from older facilities used to serve 11.2
customers: “it’s an integrated system, and its existing facilities use rolled-in pricing.” 154/ All the
post-Settlement shippers and the 11.2 customers share in the costs of the 1995 facilities. 155/ And
both sets of shippers also share in the costs of newer, post-1995 facilities 156/ (although the Article
11.2 rate cap, assuming it is applied, would result in the 11.2 customers bearing less than their fair
share of those costs)
EPNG has not received any orders in any certificate proceedings in which the Commission
held that the costs of any new facilities constructed after the 1996 Settlement should be born entirely
or disproportionately by non-11.2 customers. 157/ When it suits the purpose of arguing for the
termination of Article 11.2, EPNG emphasizes that its post-1995 construction projects meet the
criteria for rolled-in pricing, and that the 11.2 customers benefitted from the projects. 158/ In the
uncontested settlement in this very case, the parties agreed to roll into the mainline cost of service in
this and future rate proceedings the cost of the following host of post-1995 projects: the
Samalayuca Lateral, Havasu Crossover, Hobbs Lateral, Picacho Compressor Station, East Valley
Lateral, Eunice Compressor Station, Line 2000, Line 2000 Power-up, and Line 1903. 159/
There has been no incremental pricing established on EPNG and, thus, no vintage rates
exist. Because EPNG does not have vintage rates, its appeal to the concept in no way justifies the
proposed reallocation of the 11.2 cost shortfall to other customers.
3. EPNG’s General Theory That It Must Be Allowed To Recover All Its Costs From Someone Must Be Rejected.
EPNG’s last remaining theory to support the proposed cost reallocation is the most general
one: the simple idea that pipelines must be given the opportunity to recover their costs. EPNG
154/ TR, p. 952, lines 8-11 (question and response of Ms. Palazzari). 155/ Id. at lines 13-16 (question and response of Ms. Palazzari). 156/ Id. at lines 17-20 (question and response of Ms. Palazzari). 157/ TR, p. 952, line 21 to p. 953, line 16 (question and response of Ms. Palazzari). 158/ See EPNG Brief on Exceptions at 70-73; Exh. No. EPG-374, at pp. 49-65. 159/ Section 3.3 of the Stipulation and Agreement in this proceeding, approved in EPNG, 131 FERC ¶ 61,077 (2010).
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reasons from this basic principle to conclude that if it cannot recover costs from 11.2 shippers, it
must be given the right to collect the costs from others. The flaw in the theory is that EPNG had the
opportunity to collect the costs from the 11.2 customers, but it traded that right away in the 1996
Settlement. 160/ If Article 11.2 remains in place, the basis for that conclusion must be that EPNG
must honor the deal it made. As the Presiding Judge correctly held, “[t]he 199[6] Settlement did not
provide for any reallocation of shortfalls. Moreover, the extrinsic contemporaneous evidence here
demonstrates that there was no intent of reallocation.” 161/
EPNG counters that it did not expressly waive its right to reallocate the cost short-fall to other
customers in the settlement and, therefore, it should be allowed to recover its costs. 162/ Yet,
EPNG agrees that the costs at issue are properly allocated to the Article 11.2 shippers. Assuming
Article 11.2 is upheld, it is because EPNG agreed to insulate those customers from the excess costs.
A pipeline that agrees not to collect costs properly allocated to certain customers has no general
right to then reallocate those costs to other customers.
The implications of EPNG’s theory are wide-ranging and deleterious. Under its theory, any
pipeline potentially could agree to settle a rate case at rates less than the filed levels, and then
propose to treat the cost differential between the settled level of costs and its original filing as
analogous to a discount. Under this theory, that cost differential would be reallocated to non-settling
services or new customers, who would pay higher rates. The principle that pipelines are entitled to
an opportunity to recover their costs cannot be stretched so far as to encompass this sort of
reallocation of costs.
In the 1996 Settlement, EPNG agreed that it would not recover from the covered contract
costs that were incurred to serve them to the extent that the costs would exceed the agreed-upon
rate caps. As explained above, if a pipeline provides a discount to a customer that was not required
to meet competition, it cannot reallocate the resulting shortfall to other customers. Similarly, if a
pipeline enters into a negotiated rate agreement with a customer that fails to cover the allocated 160/ See Exh. No. SCE-2 at pp. 44-46. 161/ I.D. at P 567. 162/ EPNG Brief on Exceptions at 109-113.
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costs, it generally is not permitted to reallocate the costs to other customers. 163/ EPNG’s decision
to provide Article 11.2(a) rates to customers is equivalent to a decision to offer discounts that were
not needed to meet competition to retain volumes on the system. Alternatively, EPNG’s decision
may be seen as equivalent to a negotiated rate agreement, as the Presiding Judge concluded. In
neither scenario are pipelines permitted to reallocate to other customers the costs not collected as a
result of the pipeline’s contracting decision.
In the event that the Commission determines that Article 11.2 continues to apply, it follows
that EPNG agreed that it would not collect from certain customers some of its costs properly
allocated to them. Thus, EPNG had its right to a reasonable opportunity to recover its costs, but
relinquished the right to the extent that costs exceed the rates provided for under the rate caps that it
negotiated. On the other hand, EPNG’s other customers emphatically did not agree to absorb those
costs, subsidize the favored customers, and make the pipeline whole. That result was never
contemplated by the parties to the 1996 Settlement: if it had been, the 1996 Settlement would have
so provided explicitly. Moreover, this result would be contrary to fundamental principles of cost
causation and the Commission’s policy of not requiring any customers to subsidize projects for
others.
For all the reasons set forth herein, EPNG has no legal basis to shift to other customers any
costs that it cannot recover by reason of the application of the Article 11.2 rate caps. Therefore, to
the extent that the Commission rules that the rate caps continue to apply, it should rule at the same
time that EPNG alone must bear any resulting revenue shortfall.
IV. REBUTTAL OF POLICY CONSIDERATIONS CLAIMED TO WARRANT COMMISSION REVIEW AND DECISION
Both EPNG and SoCalGas/SDG&E state that EPNG’s short-term rate proposal is the first
such proposal to be litigated. 164/ EPNG states that the Commission’s decision on the issue will
have significant implications for the industry, and urges the Commission to promote the “policy 163/ EPNG, 114 FERC ¶ 61,305 at P 302 (2006). For more regarding this Commission policy, see e.g., NorAm Gas Transmission Co., 77 FERC ¶ 61,011 (1996); Northwest Pipeline Corp., 84 FERC ¶ 61,109 (1998); Enbridge Pipelines (KPC), 103 FERC ¶ 61,305 (2003). 164/ EPNG Brief on Exceptions at 10; SoCalGas/SDG&E Brief on Exceptions at 14.
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objectives” of Order No. 637. 165 / SoCalGas/SDG&E claim that the Commission’s ruling on
EPNG’s proposal will determine whether “the ratesetting policy goals expressed in Order No. 637
can be implemented on the EPNG system.” 166/
SCE agrees that the Commission’s decision on EPNG’s proposed short-term rates will have
important implications. The Commission should review EPNG’s proposal, and should reject it. The
Commission should leave no doubt that Order No. 637 cannot be used to justify any “value-based”
rates that purportedly would advance some of the goals in that order. The Commission was careful
in Order No. 637 to proscribe limitations and requirements for the implementation of “value based”
rates that are needed to protect against the exercise of market power and to ensure that the rates
are just and reasonable. EPNG’s proposal fails to comport with the Commission’s policies.
EPNG did not explain in the “policy considerations” portion of its Brief Opposing Exceptions
the need for the Commission to review the Initial Decision’s determination regarding the Article 11.2
cost reallocation issue. SCE certainly agrees, however, that other aspects of the Initial Decision
concerning Article 11.2 warrant Commission review, as explaining in the Brief On Exceptions that it
filed along with the other California Parties. Review of EPNG’s argument for reallocation of costs
associated with any continued application of Article 11.2 presumably should be part of that
Commission decision.
V. CONCLUSION
For all the reasons set forth herein, SCE urges the Commission to affirm the Presiding
Judge’s conclusions in the Initial Decision to (1) reject EPNG’s short-term rate proposal and
165/ EPNG Brief on Exceptions at 10. 166/ SoCalGas/SDG&E Brief on Exceptions at 14.
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(2) prohibit EPNG from reallocating to other customers any shortfall in its cost recovery resulting
from application of Article 11.2 of the 1996 Settlement.
Respectfully submitted, /s/ J. Patrick Nevins
Douglas Kent Porter Russell Archer Southern California Edison Company P.O. Box 800 2244 Walnut Grove Avenue Rosemead, California 91770 (626) 302-3964
[email protected] [email protected]
March 7, 2011
J. Patrick Nevins Hogan Lovells US LLP Columbia Square 555 Thirteenth Street, N.W. Washington, D.C. 20004 (202) 637-6441 [email protected] Counsel for Southern California Edison Company
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CERTIFICATE OF SERVICE I hereby certify that I have this 7th day of March, 2011, caused to be served a copy of the forgoing pleading upon all parties listed on the official service list compiled by the Secretary of the Federal Energy Regulatory Commission in this proceeding.
/s/ J. Patrick Nevins J. Patrick Nevins Hogan Lovells USA L.L.P 555 13th Street, N.W. Washington, D.C. 20004 (202) 637-6441 (tel) [email protected]