[Federal Register Volume 61, Number 26 (Wednesday, February 7, 1996)]
[Notices]
[Pages 4633-4646]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-2547]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket Nos. RM95-6-000 and RM96-7-000]
Alternatives to Traditional Cost-of-Service Ratemaking for
Natural Gas Pipelines and Regulation of Negotiated Transportation
Services of Natural Gas Pipelines; Statement of Policy and Request for
Comments
Issued January 31, 1996.
I. Introduction
In this docket, the Commission has been exploring the criteria it
should use when evaluating rates established through methods other than
the traditional cost-of-service ratemaking method. In response to a
number of requests from natural gas pipeline companies to approve rates
based on various pricing methods, which may or may not be cost-based,
the Commission has decided to establish a framework for analyzing
certain of such proposals. The Commission solicited comments on the
criteria it should use in evaluating non-cost-of-service based
proposals \1\ and representatives from all segments of the industry
responded. The Commission has reviewed those comments and is now
providing the industry with guidance by stating the criteria it will
consider when evaluating proposals for market-based rates. Moreover,
the Commission will modify its existing policy statement on incentive
ratemaking in light of the comments received.
\1\ Alternatives to Traditional Cost-of-Service Ratemaking for
Natural Gas Pipelines, 70 FERC para. 61,139 (Feb. 8, 1995)
(``Request For Comments'').
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Moreover, the Commission will modify its existing policy statement
on incentive ratemaking in light of the comments received.
The Request for Comments also generated responses from the industry
on other non-cost-of-service based alternatives to the Commission's
traditional ratemaking methodology. In particular, the Commission has
received and reviewed comments on negotiated/recourse rates. Under a
negotiated/recourse program the Commission would dispense with cost-of-
service regulation for an individual shipper when mutually agreed upon
by the pipeline and its shipper and permit negotiated terms and/or
conditions that could vary from the pipeline's otherwise applicable
tariff. A recourse service found in the pipeline's tariff would be
available for those shippers preferring traditional cost-of-service
rates and services.
Based on the comments received, the Commission is prepared to
permit negotiated rates within the guidelines discussed below. The
Commission has determined, however, that in order to make an informed
decision, additional consideration and comment is needed regarding the
legal and policy implications of negotiated terms and conditions of
service. Therefore, the Commission is establishing a separate
proceeding to solicit further comments concerning negotiated terms and
conditions.
II. Background
In 1989, Congress urged the Commission to ``improve [the]
competitive structure [of the natural gas industry] in order to
maximize the benefits of [wellhead] decontrol.'' \2\ The Commission
responded to Congress in part in Order No. 636 \3\ by taking
significant steps to increase competition in the transportation market.
By regulating pipelines in a manner that seeks to ensure all shippers
have meaningful access to the pipeline transportation grid, the
Commission has created a regulatory environment intended to maximize
competition.
\2\ H.R. Rep. No. 29, 101st Cong., 1st Sess., at 6 (1989).
\3\ Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation Under Part 284 of the
Commission's Regulations, and Regulation of Natural Gas After
Partial Wellhead Decontrol, Order No. 636, 57 Fed. Reg. 13267 (April
16, 1992), FERC Stats. and Regs. para. 30,939 (April 8, 1992), order
on reh'g, Order No. 636-A, FERC Stats. & Regs. para. 30,950 (August
2, 1992), order on reh'g, Order No. 636-B, 61 FERC para. 61,272
(November 27, 1992), reh'g denied, Order No. 636-C, 62 FERC para.
61,007 (January 8, 1993), appeal pending sub nom. United
Distribution Companies, et al. v. FERC, Nos. 92-1485, et al.
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The result of Order Nos. 436 and 636, combined with the North
American Free Trade Agreement (NAFTA) and the certification of new
pipelines, is an increased availability of unbundled transportation and
greater integration of upstream and downstream natural gas markets,
both domestic and Canadian. As a result, there has been a shift in
traditional supply sources; many existing pipeline customers no longer
want or need the same amount of firm capacity to their traditional
pipeline's supply regions. In addition, the overall natural gas demand
has been increasing steadily, albeit modestly. Since 1992, national
consumption of natural gas has increased at about 3 percent.\4\ This
increased demand has occurred primarily in the industrial and electric
end-use markets for natural gas.\5\ Natural gas consumers in these
markets often have dual fuel capability,\6\ and for this reason
pipelines have sought ratemaking flexibility to respond to alternative
fuel competition in these markets.
\4\ In 1992, the overall national consumption of natural gas was
19.5 Tcf; in 1994 it reached 20.7 Tcf, a 6 percent increase. Figures
for the first nine months of 1995 suggest an increase of 3 percent
over the first 9 months of 1994. Natural Gas Monthly, December 1995.
\5\ See, e.g., Energy Information Administration, Natural Gas
Annual 1994, at p. 37 (DOE-EIA-0131(94)/1, November 1995) (``Most of
the 476 billion cubic feet increase in consumption was due to
increased reliance on natural gas in the electric utility sector., .
. ., while industrial consumption grew by 196 billion cubic feet or
3 percent.'').
\6\ See, e.g., National Petroleum Council, The Potential for
Natural Gas in the United States, Volume III, Demand and
Distribution, (December 1992) at 72-73 and 96.
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Pipelines contend that greater flexibility is key to attracting new
gas markets and retaining existing markets.
[[Page 4634]]
For example, new electric generators have argued that they require
long-term price certainty for transportation to finance gas-dependent
ventures. In addition, it is asserted that ratemaking flexibility would
permit pipelines to tailor natural gas transportation rates for
electric generators to meet the swings in gas consumption often
experienced by such generators. Pipelines have argued that, because
many LDCs are unwilling to commit to long-term firm contracts, greater
flexibility in rates and services is needed to retain customer load as
old long-term contracts expire. LDCs also want flexibility so they can
swing between pipelines to take advantage of the opportunity to
purchase gas from different supply regions.
The Commission has recognized that additional rate design
flexibility may be needed in a post-restructuring environment. In cases
concerning the appropriate rate treatment for the costs associated with
a pipeline's loss of revenues resulting from the expiration of
contracts, for instance, parties have argued that they need additional
rate design flexibility in order to market excess capacity and recover
costs associated with their turned-back capacity.\7\ In Natural Gas
Pipeline Company of America,\8\ the Commission indicated its
willingness to permit pipelines flexibility in negotiating rates with
its current and prospective customers for unsubscribed capacity,
including rates which depart from SFV rate design. The Commission also
stated that it would entertain, as part of a settlement, a proposal
that allows rate flexibility for the capacity that customers had
already elected.
\7\ See Southern Natural Gas Co., 73 FERC para. 61,322 (1995);
Natural Gas Pipeline Co. of America, 73 FERC para. 61,050 (1995);
Transwestern Pipeline Co., 72 FERC para. 61,085, reh'g denied, 72
FERC para. 61,089 (1995); and El Paso Natural Gas Co., 72 FERC para.
61,083 (1995).
\8\ 72 FERC para. 61,083 (1995).
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In recent filings, pipeline companies also have urged the
Commission to permit greater flexibility in service options and terms
and conditions in order to meet competition. For example, Panhandle
Eastern Pipe Line Corporation (Panhandle) proposed a Limited Firm
Transportation (LFT) Service, under which its customers would be
guaranteed the ability to schedule firm transportation service for only
20 days in any given month.\9\ Trunkline Gas Company proposed a Premium
Alternative Transportation (PAT) Service, consisting of interruptible
transportation with preferential scheduling and curtailment features
for an annual contracting fee.\10\ Trunkline also proposed a Park and
Transfer Service to help shippers manage their supply while reducing
the frequency of cash-outs and scheduling penalties.\11\
\9\ Panhandle Eastern Pipe Line Co., 72 FERC para. 61,185
(1995).
\10\ Trunkline Gas Co., 73 FERC para. 61,107 (1995).
\11\ Id.
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In an attempt to respond to pipelines' requests for added
flexibility, the Commission sought comments on alternative methods for
pricing of services by natural gas pipeline companies. In its Request
for Comments, the Commission stated its interest in developing a
framework for analyzing proposals involving alternative pricing
methods. Recognizing that there are a number of cost-based, as well as
non-cost based alternatives to the Commission's traditional method, the
Commission sought comment on fifteen specific questions related to
possible ratemaking alternatives.
In the Request for Comments, the Commission also sought comment on
a Commission Staff Paper that proposed criteria for evaluating of
proposals for market-based rates. The staff paper applied basic market
power analysis, as used in the past by the Commission as well as in
other contexts, to develop a proposed analytical framework for
evaluating gas pipeline market-based rate proposals.
The Commission also sought comment on whether changes should be
made in its existing policy statement on incentive ratemaking.\12\ The
Commission noted that although it has stated the criteria upon which it
will evaluate cost-based incentive rate proposals, to date no natural
gas company has submitted such a proposal. The Commission raised
several specific questions regarding its policy on incentive rate
proposals and solicited comments on all aspects of its existing policy
statement.
\12\ Policy Statement on Incentive Regulation, 61 FERC para.
61,168 (1992).
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The Commission received 59 comments from parties representing all
segments of the natural gas industry.\13\ The majority of the responses
focused on the staff paper and suggestions for criteria for evaluating
market-based rate proposals. Furthermore, the responses critically
analyzed the Commission's existing incentive rate policy statement and
offered sound suggestions for altering the existing policy to meet the
needs of the public interest in today's natural gas market.
\13\ A list of the commenters is included as an appendix to this
policy statement.
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The comments also proposed other alternatives to traditional cost-
of-service ratemaking. Specifically, INGAA proposed that the Commission
approve negotiated/recourse rate applications. Under such applications,
pipelines would be allowed to negotiate a rate and/or terms and
conditions of service so long as a Commission approved (recourse) rate
remained available. Customers would always retain the right to elect
the recourse rate and forego negotiation. Various commenters filed
responses to INGAA's proposal.\14\ Several of these commenters
generally support INGAA's proposal although they object to INGAA's
proposal to index the recourse rate.\15\ Comments in opposition to
INGAA's proposal focused on issues ranging from cost shifting and
degradation of service to preventing undue discrimination and complying
with the NGA's filing requirement. INGAA further clarified its proposal
on September 25 and November 9, 1995 and commenters filed additional
responses thereafter. A detailed discussion of INGAA's proposal and the
responses thereto is included as part of the Commission's Request for
Comments in Section IV below.
\14\ To date, the Commission has received comments on INGAA's
proposal from Brooklyn Union, GRI, IPAA, NGSA, and a group of eight
industrial organizations.
\15\ AGD, Brooklyn Union, and UGI.
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III. Policy on Market-Based Rates
The Commission has determined that where a natural gas company can
establish that it lacks significant market power,\16\ market-based
rates are a viable option for achieving the flexibility and added
efficiency required by the current marketplace. To date, the Commission
has reviewed requests by regulated companies to charge market-based
rates on a case-by-case basis. The Commission intends to continue in
this vein, but is announcing the criteria it will generally use in the
review process to aid companies in preparing their proposals. Below, we
discuss the criteria the Commission will consider in evaluating any
pending or future proposal for market-based rates. Companies may submit
proposals meeting the established criteria for system segments and/or
specific services offered on a system.
\16\ Transwestern Pipeline Company, 43 FERC para. 61,240 (1988);
El Paso Natural Gas Company, 49 FERC para. 61,262 (1989);
Transcontinental Gas Pipe Line Corporation, 55 FERC para. 61,446
(1991); Richfield Gas Storage System, 59 FERC para. 61,316 (1992);
Koch Gateway Pipeline Company, 66 FERC para. 61,385 (1994); Buckeye
Pipe Line Company, 53 FERC para. 61,473 (1990), and Williams Pipe
Line Company, 69 FERC para. 61,136 (1994).
[[Page 4635]]
A. The Comments Received
The majority of the responses to the Request for Comments focused
on the staff paper and suggestions for criteria for evaluating
proposals for market-based rates.
The majority of those commenters supported market-based rates where
a market is fully competitive.17 Many commenters recognized,
however, that it is unlikely that the primary market, i.e., firm
transportation by interstate pipeline companies, will meet the proposed
criteria for market-based rates.18
\17\ AGA, Edison, Con Edison, ANR/CIG, CNG, Cove Point, INGAA,
Koch Gateway, PGT, PEC Pipeline Group, IPAA, Indicated Shippers,
Alberta, Florida, Ohio CC, New York, Mark B. Lively, and Transok.
\18\ Brooklyn Union, Connecticut Natural, IPAMS, Illinois, Ohio
PUC, Tejas, Atlanta Gas, Columbia Distribution, Northern
Distributors, NI-Gas, UDC, Amoco, NGSA, Texaco, PA. OCA, and PaPUC.
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LDCs, producers, marketers, and state commissions, joined by a few
interstate pipeline companies, assert that other markets, for example
those for capacity release and interruptible transportation, already
are, or can become, competitive enough to permit market-based
rates.19 Several parties believe that the markets for short-term
firm transportation,20 storage,21 and hub/market center
services,22 as well as new markets 23 may also be competitive
enough to permit market-based rates. On the other hand, a number of
endusers and LDCs take the position that market-based rates should not
be allowed for certain markets, including firm transportation,24
capacity release,25 short-term firm,26 interruptible
transportation,27 and storage.28
\19\ Edison, AGD, Atlanta Gas, Brooklyn Union, Pacific Northwest
Commenters, CINergy Gas Companies, Columbia Distribution,
Connecticut Natural, Con Edison, Northern Distributors, NI-Gas,
Northern Indiana, PSE&G, UDC, Columbia, INGAA, PGT, WINGS, Illinois,
Ohio CC, Pa. OCA, PaPUC, and the Ohio PUC.
\20\ Connecticut Natural, Northern Distributors, UDC, Columbia,
INGAA, and WINGS.
\21\ Edison, APGA, Pacific Northwest Commenters, NI-Gas, INGAA,
PGT, WINGS, IPAMS, PaPUC, and Tejas.
\22\ Edison, APGA, Pacific Northwest Commenters, NI-Gas, INGAA,
PGT, WINGS, IPAMS, PaPUC, and Tejas.
\23\ NI-Gas, Northern Indiana, Columbia, Cove Point, and INGAA.
New markets include new construction, new services, or new entrants.
\24\ AF&PA, Fertilizer Institute, Energy Associates, NWIGU,
Petrochemical Energy Group, Pacific Northwest Commenters, Northern
Indiana, IOGA, and Ohio CC.
\25\ AF&PA and NWIGU.
\26\ APGA.
\27\ AF&PA, Fertilizer Institute, APGA, and Pacific Northwest
Commenters.
\28\ Energy Associates.
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The staff paper issued with the Request for Comments proposed
criteria for evaluating market-based rate proposals. The Commission
sought comments regarding whether these criteria were appropriate, too
strenuous, or not strenuous enough. The majority of pipeline
commenters, along with a few others, indicated that the criteria were
too strenuous and ignore competitive factors.29 A few pipelines
suggest the Commission should avoid ``one size fits all'' approaches
and instead use evaluation criteria of a more general nature.30
The majority of end-users and regulatory commissions believe the
proposed criteria are either reasonable and strenuous enough or require
only minor modifications. Specifically, AGD contends that competing
products need not be identical. For example, AGD asserts that in the
off-peak season, released FT and IT are virtually identical. Therefore,
AGD suggests that the criteria be modified to allow for consideration
of such differences in product definition.
\29\ Cove Point, INGAA, Tejas, ANR/CIG, Brooklyn Union, KN
Interstate, AGA, Koch Gateway, WINGS, Transok, KN Interstate, NGSA,
PEC Pipeline Group, and Columbia.
\30\ Enron, INGAA, and NorAm.
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AGD also argues that the criteria should be modified so that the
difference in price to be considered will be the difference in the cost
of obtaining delivered gas through the various alternatives. The Pa OCA
contends that the timeliness criterion should be more strenuous. Pa OCA
states that if projected alternative capacity is delayed or is less
than projected, customers should have the option of continuing to pay a
traditional cost-of-service rate until workable competition exists. The
Ohio CC and Pa OCA state that ``ease of exit'' as well as ``ease of
entry'' should be added to the criteria used to define product markets.
Pa OCA also suggests that the financial risk to customers be added to
the criteria used to define product markets.
The LDCs, producers, and marketers are evenly divided on the
question. Those that oppose the criteria assert that they are too
narrow, will lead to overregulation, and that the .18 the summary
measure of market concentration known as the Herfindahl-Hirschman Index
(HHI) screen is too low.31 Several commenters suggested that other
factors, including market competition, market definition, and product
substitution, must be considered in evaluating any proposal for market-
based rates.32
\31\ Cove Point Pipeline, INGAA, Tejas, ANR Pipeline/CIG
Pipeline, Brooklyn Union, KN Interstate Pipeline, AGA, Koch Gateway
Pipeline, WINGS, Transok Pipeline, PEC Pipeline Group, and Columbia
Pipeline.
\32\ SoCalGas, CNG, Enron, INGAA, and NorAm.
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In response to the Commission's inquiry regarding the use of
different standards for different types of service, a number of LDCs
and pipelines argue that the Commission should use different standards
for different services.33 Several commenters assert that the
standards should be tailored to the services offered and/or the market
to be served.34 In contrast, the few state regulatory commissions
who responded on this issue suggest that the same criteria should be
used for all services.35
\33\ Wisconsin Distributors, AF&PA, Edison, AGA, AGD,
Connecticut Natural, Northern Distributors, NI-Gas, Northern
Indiana, UDC, Columbia, INGAA, KN Interstate, WINGS, IPAMS,
Illinois, Ohio PUC, and Tejas.
\34\ SoCalGas, Koch Gateway, and PEC Pipeline Group.
\35\ Industrial Gas Consumers, APGA, CNG, NGSA, Alberta,
Florida, and Ohio CC.
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B. Response to Legal Arguments Opposing Market-Based Rates
A few commenters raised specific arguments regarding the
Commission's legal authority to implement market-based rates on a broad
scale. Only the IPAA made a broad-based attack on the Commission's
legal authority to permit market-based rates. The Commission believes
that IPAA's attack is based largely on mistaken premises.
IPAA asserts that the NGA contemplates ``traditional'' or cost-of-
service ratemaking and therefore adoption of market-based rates on a
wide scale may be contrary to the statutory intent of the NGA. IPAA
argues that the Supreme Court has specifically held that NGA Sections
5(b), 6(a), 9(a), 10(a) and 14(b) suggest that when Congress enacted
the NGA, it contemplated ``traditional'' or cost-of-service ratemaking
36 IPAA narrowly construes the Supreme Court decisions in FPC v.
Hope,37 and the Permian Basin Area Rate Case 38 as applying
solely in cases where the question to be decided is what methods should
be used to establish a rate base, not whether some alternative to cost-
of-service ratemaking would be appropriate.
\36\ Citing, Colorado Interstate Gas Company v. FPC, 324 U.S.
581 at 601-2 (1945) (CIG).
\37\ In Hope, the Court held that the Commission was not bound
to use any single formula or combination of formulae in determining
rates, but that the Commission's rate-making function ``involves the
making of pragmatic adjustments'' and that under the statutory
standard ``it is the end result reached not the method employed
which is controlling.'' 320 U.S. 591 at 602 (1944).
\38\ 390 U.S. 747 (1968).
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This is an extremely narrow reading of the case law. Moreover, IPAA
does not even acknowledge more recent cases
[[Page 4636]]
such as Farmers Union Central Exchange v. FERC,39 which recognized
the possibility of moving to light-handed regulation when justified by
a showing that the goals and purposes of the statute can be
accomplished without traditional regulatory oversight.40 Thus,
IPAA's arguments in this regard are not persuasive.
\39\ 734 F.2d 1486, 1509 (1991) Farmers Union II.
\40\ See also, Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 870
(D.C. Cir. 1993) (Elizabethtown) (Court of Appeals affirmed
Commission approval of market-based rates, under appropriate
circumstances, as meeting the requirements of the NGA.)
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IPAA also maintains that an essential demand in the pipelines'
request for market-based rates is that the Commission ignore the
statutory prohibition against ``undue discrimination.'' IPAA claims
that the pipelines wish to be able to discriminate in rates, terms, and
conditions, which it argues would violate the NGA and possibly of the
antitrust laws. Simply put, IPAA maintains pipelines want to charge
some customers higher rates in order to subsidize lower rates for
affiliates and other favored customers, in violation of the NGA.
The Commission does not share IPAA's view. First, the scenario IPAA
fears is possible only if a pipeline exercises market power. A company
cannot make one group of customers subsidize another unless it has
market power over the group that would pay the higher rates. If a
pipeline has market power over a service then the Commission cannot
permit it to charge market-based rates for that service. In addition,
the Commission has carefully scrutinized affiliate relationships and
generally has taken special precautions, imposing special rules, where
affiliates are involved. In those instances the Commission has
recognized that the normal market controls will not work with affiliate
transactions. Finally, the statute does not prohibit all differences in
rates. The prohibition in the NGA is against unduly discriminatory
behavior. Thus, under Part 284 of the Commission's regulations, the
Commission has allowed differences in rates by permitting pipelines to
discount rates for certain types of service and for certain
customers.41 The Commission has maintained that these differences
in rates are justified if the discount is necessary to meet competitive
circumstances and the customers are not in similar competitive
positions.
\41\ 18 CFR 284.7 (1995).
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Hadson asserts that the Commission has failed to explain how
Commission rulings that prohibit restrictions on the resale of electric
power as per se violations of the FPA,42 and prohibit restrictions
on the resale of natural gas as violative of NGA standards,43 are
consistent with its determination that resale restrictions on the sale
of pipeline capacity are required under the NGA.44
\42\ Citing, Gulf States Utilities Co., 5 FERC para. 61,066
(1978) (Gulf States), Central Maine Power Co., 18 FERC para. 61,126
(19982); Louisiana Power & Light Co., 14 FERC para. 61,075 at
61,130-31 (1981); Central Telephone & Utilities Corp., 10 FERC para.
61,213 (1980); and Empire District Electric Co., 5 FERC para. 61,083
(1978).
\43\ Citing, City of Florence v. Tennessee Gas Pipeline, 24 FERC
para. 61,395 (1983) (City of Florence) (the Commission voided a
restriction in a pipeline LDC contract on the resale of natural gas
by the distributor).
\44\ Hadson at 19.
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Hadson's concerns are misplaced. The Commission has determined that
non-dominant sellers of electric power cannot exercise market
power.45 Likewise, it has determined that markets for the sale of
natural gas are sufficiently competitive that the market, subject to
Commission oversight and intervention, serves to ensure that rates for
the sale of these commodities are just and reasonable. To the extent
this is true for primary sales of electric power and natural gas, the
proposition is even more true with respect to resales of the
commodities. Gulf States, City of Florence and their progeny address
sales, not transportation, and the distinction is critical. Congress
recognized the distinction when it deregulated wellhead prices. The
level of competition that exists for the sale of natural gas has not
been demonstrated to exist for the transportation of natural gas. If
the market does not serve to ensure just and reasonable rates for the
primary market one cannot simply assume that it will ensure just and
reasonable rates for the secondary market.
\45\ See, e.g., Louisville Gas and Electric Company, 62 FERC
para. 61,016 at 61,143-4 and cases cited at footnote 16. (Non-
traditional rates may be acceptable if the seller can demonstrate
that it lacks market power over the buyer or has adequately
mitigated its market power. The seller can demonstrate that it lacks
market power (or has adequately mitigated its market power) by
showing, among other things, that neither it nor its affiliates is a
dominant firm in the sale of generation in the relevant market.)
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Hadson also asserts that lifting cost-based caps and/or moving away
from cost-based ratemaking for the transportation of gas by interstate
pipelines will interfere with the goals of the NGA. Hadson's comments
merely reiterate the reasons for using a market analysis as the
starting point for evaluating any market-based rate proposal. Absent a
showing that a particular company lacks market power or that sufficient
regulatory safeguards, e.g., a cost-of-service fallback rate, can be
implemented to eliminate the potential exercise of market power, the
Commission would continue some form of cost-based ratemaking.46
Where a company can show a lack of market power, then competition in
the market would ensure that the company's rates will be just and
reasonable. In either case, the goals and purposes of the NGA are met
in that any rates that would be charged would be just and reasonable,
either under a cost-based or a market-based analysis.
\46\ See the discussion of Negotiated/Recourse Rates below.
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Hadson also asserts that Farmers Union Central Exchange v.
FERC,47 which affirmed the possibility of light-handed regulation
of oil pipelines, recognized that the movement to light-handed
regulation is justified only by a showing that the goals and purposes
of the statute can be accomplished without traditional regulatory
oversight. Hadson asserts that the staff paper does not address the
potential for serious disruption of the industry in the event that a
future Commission (or a reviewing court) decides to apply court rulings
applicable for other regulated industries, such as the
telecommunications industry, and require strict tariffing.48
Hadson states that the Commission should either revisit its assertion
of NGA jurisdiction over shippers (via blanket certificates) or assure
the public that the procedures under which everyday business is
conducted will not be confounded by a subsequent finding that the
structure does not comport with the filed rate doctrine. Hadson is
merely repeating arguments advanced in opposition to the Commission
exercising its NGA jurisdiction over marketers. The Commission
previously addressed these concerns when it reaffirmed that sales by
marketers are resales subject to the Commission's NGA jurisdiction.
These
[[Page 4637]]
issues need not be addressed again in this context.49
\47\ 734 F.2d 1486, 1509 (1991) Farmers Union II.
\48\ Hadson refers to a line of Federal Communications
Commission cases which stand for the proposition that an agency
should be mindful of specific statutory procedural requirements when
it undertakes reform of substantive regulatory policies and
programs. Citing, MCI Telecommunications Corp. v. ATT, ______ U.S.
______, 114 S.Ct. 2223 (1994) (MCI II), Southwestern Bell Corp. v.
FCC, 43 F.3d 1515 (D.C. Cir. 1995) (Southwestern Bell), and Maislin
Industries, U.S. Inc. v. Primary Steel, Inc., 49 U.S. 116 (1990).
Neither MCI II nor Southwestern Bell speak to the substantive
validity of alternative, non-cost based, ratemaking methodologies.
These cases address the methods of implementing statutory
requirements for rate filings that agencies can legitimately employ.
The cases do not speak to the methods of deriving the rates that
ultimately must be filed. With respect to such methods, the doctrine
advanced in Hope still applies.
\49\ See, Removal of Outdated Regulations Pertaining to the
Sales of Natural Gas Production, Docket No. RM94-18-001, 69 FERC
para. 61,055 at 61,217 (1994), appeal docketed sub nom. Hadson Gas
Systems, Inc. v. FERC, No. 95-1111 (D.C. Cir.).
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IPAA asserts that, assuming for the sake of argument alternative
pricing methods could be sustained on appeal, some very specific
statutory requirements with respect to filing and approval of rates and
the prohibition against undue discrimination must be considered. Citing
Environmental Action v. FERC 50 and Transwestern Pipeline Co. v.
FERC,51 IPAA maintains that a formula or rule means that something
must be filed from which an actual rate can be calculated; a rate
dependent solely upon the market does not qualify as a ``formula'' or
``rule.''
\50\ In Environmental Action v. FERC, 996 F.2d 401 (D.C. Cir.
1993) (Environmental Action), the proposed pricing plan was ruled to
have been acceptable because there was a filed rate cap, and any
discrimination was held to be potential.
\51\ In Transwestern v. FERC, 897 F.2d 570 (D.C. Cir. 1990)
(Transwestern), the Court determined that filing a ``rate `formula'
or rate `rule' '' can satisfy the filing requirements of Section 4;
however, given the Court's ruling that the issue of market-based
rates was moot in that case because there had been no customer
nominations under Transwestern's program, the determination with
respect to a rate formula or rule appears to be have been dicta.
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The Commission's implementation of market-based rates for pipelines
and storage companies comports with the filed rate doctrine. The
Commission has not attempted to eliminate tariffs, as was the case in
the telecommunications industry, and does not do so here. Currently,
for the few proposals that have been approved, the Commission has
required the company to file tariff sheets for the service with market-
based rates. The Commission will continue this practice in any future
declaratory orders ruling on market-based rate proposals.
C. The Criteria
The Commission's framework for evaluating requests for market-based
rates addresses two principal purposes: (1) Whether the applicant can
withhold or restrict services and, as a result, increase price by a
significant amount for a significant period of time, and (2) whether
the applicant can discriminate unduly in price or terms and conditions.
Undue discrimination is especially a concern when an applicant for
market-based rates can deal with affiliates.
Before the Commission can conclude that a seller will not withhold
or restrict services, significantly increase price over an extended
period of time, or unduly discriminate, it must either (1) find that
there is a lack of market power because customers have sufficient good
alternatives or (2) mitigate the market power (i.e., permit market-
based pricing only if specified conditions are met that prevent the
exercise of market power). Market power is defined as the ability of a
pipeline to profitably maintain prices above competitive levels for a
significant period of time.52 To date, in all cases where the
Commission has considered market-based rates, the applicant has been
required to show that it lacks significant market power in the relevant
markets. The staff paper set out a general framework for evaluating
requests for market-based rates. The Commission now adopts this general
framework, as discussed below, as its criteria for evaluating the
competitiveness of transportation services.
\52\ Enron Storage Company, 73 FERC para. 61,206 (1995);
Williams Pipeline Company, 68 FERC para. 61,136 (1994); Avoca
Natural Gas Storage, 68 FERC para. 61,045 (1994); Koch Gateway
Pipeline Company, 66 FERC para. 61,385 (1994); Bay Gas Storage
Company, 66 FERC para. 61,354 (1994); Transok, Inc., 64 FERC para.
61,095 1993); and Richfield Gas Storage System, 59 FERC para. 61,316
(1992).
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The Commission's analysis of whether a pipeline has the ability to
exercise market power will include three major steps: (1) Define the
relevant markets; (2) measure a firm's market share and market
concentration; and (3) evaluate other relevant factors. Each of these
steps was articulated in the staff paper. They are discussed, with
certain noted changes, again below.
1. Market Definition
The first step is to define the relevant market. Market definition
identifies the specific products or services and the suppliers of those
products or services that provide good alternatives to the applicant's
ability to exercise market power. The term ``good alternatives'' has
been defined as ``an alternative that is available soon enough, has a
price that is low enough, and has a quality high enough to permit
customers to substitute the alternative'' for the applicant's
service.53
\53\ Koch Gateway Pipeline Company, 66 FERC para. 61,385 at
62,299 (1994).
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a. The Product Market. The applicant's service together with other
services that are good alternatives constitute the relevant product
market. The Commission will require the applicant to define the product
market fully and specifically. The applicant must also show how each of
the substitute services in the product market are adequate substitutes
to the applicant's service in terms of quality, price and availability.
For example, the relevant product market may consist of off-peak
interruptible transportation service only. The Commission will consider
any substitutes for the relevant product that can be considered
competitive alternatives, e.g., storage delivery services. Pipelines
might suggest numerous alternatives to FT in their applications: IT,
storage services, residual fuel oil, etc. A narrow definition of the
product market, for example, peak period, firm transportation or off-
peak, interruptible transportation, will better enable the Commission
to critically evaluate the real alternatives that are available to the
proposed service.
i. Timeliness. The definition of the product market may vary
depending on the time period considered. For example, whether a service
is a good alternative to a pipeline's interruptible service will depend
on the time periods chosen for review. The staff paper noted that,
although antitrust authorities have used one year as the time period in
which to test whether a product can become a substitute, a one year
time period was probably not appropriate for long-term firm
transportation because capacity on competitors would typically need to
be available simultaneously to offer a viable alternative to customers.
Because long-term firm contracts typically do not offer customers the
ability to shift between alternatives, the one year time period may not
be appropriate.
A few commenters argue that the Commission should adopt a more
strenuous timeliness criterion.54 They assert that if the
projected alternative capacity is delayed or is less than projected,
customers should have the option of continuing to pay a traditional
cost-of-service rate until workable competition exists.
\54\ Pa OCA and Ohio CC.
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The Commission will not define a specific time period within which
a product must become available in order to be a substitute. The
Commission believes that this determination is dependent upon the type
of product services at issue. As more product services become
available, the duration of service agreements is likely to vary
considerably from the traditional 20-year firm transportation
agreement. Therefore, the ability to establish whether a product is or
can become a good alternative will depend upon the specifics of the
product it is replacing. However, if a pipeline applicant relies on the
existence of capacity that will not be available immediately, it should
also show that its customers will not be committed to long term
contracts on its system within the relevant time period.
[[Page 4638]]
In this regard, customers should be given the option of reducing
service demand levels once the alternative capacity and/or service
becomes available.
ii. Price. Along with showing that alternative capacity will be
available in a reasonable time frame, the Commission will also evaluate
whether the price for the available capacity is low enough to
effectively restrain the applicant from increasing prices. The price
increase threshold is important because with a lower threshold it
becomes ostensibly more difficult for a potential alternative to the
applicant's service to be considered a good alternative. In prior
cases, the Commission has defined such a threshold price level as being
at or below the applicant's approved maximum cost-based rate plus 15
percent.55
\55\ In Buckeye Pipe Line Company, L.P., Opinion No. 360, 53
FERC para. 61,473 at 62,61 (1990), order on reh'g, Opinion No. 360-
A, 55 FERC para. 61,084 (1991), the Commission held that a 15
percent increase was an appropriate level to measure market power.
However, in Williams Pipe Line Co., Opinion No. 391, 68 FERC para.
61,136 at 61,657, the Commission declined to adopt a specific rate
increase as a litmus test for market power. In Koch Gateway Pipeline
Company, 66 FERC para. 61,385, the Commission suggested that
potential alternatives would include services that though presently
not used, would be economic if prevailing prices were to rise by a
modest amount, e.g., five to fifteen percent.
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Several of the commenters suggest that the 15 percent threshold for
price changes is inappropriate.56 They assert that a threshold at
the 5-10 percent level is more consistent with current similar
standards in the Department of Justice's merger guidelines. The
Commission has studied the arguments made on this issue and we agree.
Accordingly, the Commission will adopt a pricing threshold of 10
percent. The Commission believes that if a company can sustain an
increase in its rates in the order of 10 percent or more without losing
significant market share, the company is in a position to exercise
market power to the detriment of the public interest.
\56\ Industrial Gas Consumers, NI-Gas, UDC, Alberta, and
Illinois.
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Although the Commission is adopting 10 percent as its standard
price change threshold, it is not precluding individuals from making an
argument for either a higher or lower threshold in any particular case.
Applicants are free to argue for a higher threshold where they believe
circumstances permit. Similarly, participants in the application
proceeding are free to argue for lower thresholds. The Commission will
consider the arguments presented and make a determination of the
appropriate price change threshold on an individual basis whenever the
issue is raised. In cases where the issue is not raised, the Commission
will use 10 percent as the applicable price increase threshold. In
addition, when applicants propose an appropriate threshold for price
increases, they should also propose the time period over which the
price increase could be sustained.
iii. Quality. A good alternative must provide service in which the
quality is at least as high as that of the service provided by the
applicant. After the Commission has a full and complete description of
the service(s) proposed for market-based rate treatment, it will
evaluate whether any available third party capacity is comparable in
service to the transportation service provided by the applicant.
In the aftermath of Order Nos. 436 and 636, the Commission believes
that all interstate pipelines currently provide operationally
comparable firm transportation service. However, even if a customer can
find available capacity on an alternative pipeline, the overall package
of services available may not be comparable to that it currently
receives from the applicant. For instance, no-notice service may not be
available from other pipelines (though a similar service may be
available from third parties). Under Order No. 636, interstate
pipelines that offered no-notice sales service prior to restructuring
were required to offer no-notice transportation service to their
existing sales customers at the time of unbundling. Pipelines had the
option of making no-notice service available to customers who were not
sales customers. Thus, while many interstate pipelines currently
provide no-notice service, they do not and are not required to offer
such service to new customers. Thus, comparable no-notice service may
not be available on other pipelines.
Also, applicants may wish to demonstrate that intrastate pipelines
offer comparable firm transportation service. Transportation services
offered by intrastate pipelines under Section 311 of the NGPA are also
subject to open-access and non-discriminatory access standards as
interstate pipelines are under Order Nos. 436 and 636. Therefore, to
the extent that intrastate pipelines offer firm transportation service,
the Commission believes that such service could be offered under terms
and conditions that are substantially comparable to the firm
transportation services offered by open-access interstate pipelines.
However, intrastate pipelines are not required to offer firm
transportation services and currently only a few intrastate pipelines
offer such service. Thus, firm transportation may not be available on
intrastate pipelines. Where it is available, pipelines are free to
argue that firm intrastate transportation service is a comparable
alternative to services proposed for market-based rates.
Applicants wishing to make a showing that interruptible
transportation services make good alternatives to the applicant's firm
services should demonstrate that an adequate amount of capacity is
unsubscribed during peak periods so that the quality of the IT service
is comparable to that of the applicant's FT service.
2. The Geographic Market
In addition, in defining the market, the Commission will look to
identify all the sellers of the product or service. The collection of
alternative sellers and the applicant constitutes the relevant
geographic market. Specifying the relevant product and geographic
market tells the Commission what alternatives the customer has if it
attempts to avoid a price increase imposed by an applicant. Geographic
market definition is particularly important in transportation markets.
Gas pipelines can transport gas out of a producing or origin region.
They also deliver gas into a consuming or destination region. The
Commission will identify both the origin and destination markets for
the relevant service. Only in that way can the Commission evaluate
whether there are good alternatives to the pipeline's service.
The Commission expects that typical proposals will adopt a two-step
process of defining the geographic market. First, the applicant will
identify those alternative sellers who offer service between the same
origin and destination markets. Second, the applicant will identify
those competitors that provide service either out of the origin market
or into the destination market.
a. Transportation Between Markets. The first stage of the analysis
identifies sellers offering transportation service over the same route.
Examining different sellers serving the same transportation link
simplifies the analysis. For instance, there is no need to consider
whether different producing areas offer ``good'' alternatives to each
other.
To show that another pipeline provides a good direct alternative,
the applicant must show that customers could purchase the relevant
service from the alternative supplier. Such a demonstration will likely
include showing that capacity would be available on the alternative and
that the customer can obtain any services
[[Page 4639]]
needed to use the competitor's facilities in both origin and
destination markets over the term of the service receiving market-based
rates.
If a customer has a continuing obligation to take gas at a
particular receipt point, or to deliver gas to a specific delivery
point, beyond the term of its FT contract, competition from parallel
pipelines is particularly important in evaluating market power on a
pipeline seeking market-based FT rates. In these circumstances, the
applicant may have market power over the shipper even if both the
origin and destination markets are otherwise competitive. While the
shipper will have good alternatives to the applicant for getting to the
city-gate, it may not have good alternatives for getting gas from the
shipper's particular receipt point to its city-gate. It could of
course, sell its contract gas from that particular point on the spot
market in the production area and buy an equal amount of spot gas in an
area where it had good transportation alternatives. But the spot price
at which it sells might be lower than the spot price at which it buys,
causing extra expense and providing some opportunity for the applicant
pipeline to raise its price. Additionally, the shipper may value the
reliability of the contract gas and be concerned that it might not be
able to buy spot gas when it needs it.
b. Transportation at Origin and Destination Markets. Parallel route
competition is not the only source of market discipline on gas
transporters. A shipper in the production area will typically have
alternative destination markets to which it could send gas. Similarly,
a downstream shipper will typically have a choice of several producing
areas from which to buy gas. Pipelines that provide such alternative
service may offer an additional check on the market power of a shipper.
Natural gas transportation typically originates in the production
area. In the production area (or the mainline receipt point), the
applicant must identify the transportation alternatives available to
customers. Customers could include producers with gas supplies attached
at a receipt point, LDCs, and endusers with firm long-term supply
contracts. To define a particular region as an origin market, the
pipeline must identify all pipelines which compete with it to move gas
out of that area. As a general matter, to demonstrate that these other
pipelines are good alternatives (that is, are in the market) the
applicant must show that its producer/shippers are physically connected
to these other pipeline transporters. Alternatively, the applicant
could include an alternative pipeline in the market if it can connect
to the producer/shipper sufficiently cheaply that the producer/shipper
receives a netback 57 at least as large as it would receive if it
used the applicant's transportation service. The applicant must also
show that these transportation alternatives provide a netback to
producer/shippers roughly the same as they would receive if they used
the applicant's transportation. An alternative is not a good
alternative to a producer seeking to move gas out of the origin market
if the alternative is associated with a much higher cost than the
applicant's cost-based rates, in other words, it must give roughly the
same netback.
\57\ The netback is the delivered price of gas less the
transportation costs paid by the producers. That is, the netback is
the net price received by the producer.
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Koch Gateway argues that a good alternative does not necessarily
have to be physically connected to a pipeline. The Commission agrees.
Although typically an applicant will have to demonstrate that its
customers are physically connected to alternative gas transportation
facilities that move gas into the area, the Commission will allow
flexibility and permit applicants to argue that even if the customer is
not physically connected to the alternative, it can serve as good
alternatives to the proposed service.
Applicants for market-based rates might allege that liquified
petroleum gas (LPG) and liquified natural gas (LNG) can be good
alternatives to the use of an applicant's transportation service. If
so, the applicant must show that there are sufficient quantities of
these available, and that LPG and LNG can be transported into the
destination market (e.g., by truck) at an overall delivered price that
is equal to or less than the overall delivered price the applicant
pipeline would charge to deliver natural gas. The prices considered
here must be within the pipeline's price increase threshold.
Thus, in order to specify a gas transportation market, the
applicant must first identify all products and services available as
good alternatives to the applicant's customers. Next, the applicant
must identify the origin and destination of that transportation. The
relevant geographic market will be defined in two steps: first, those
alternative sellers that offer service between the same origin and
destination markets and second, all economically substitutable
transportation sold by pipelines (or other good alternative products
and services) serving either the origin market or the destination
market.
Pipelines might be able to exercise market power if customers have
few good alternatives to the pipeline's service either, in the first
instance over a given route or, in a second analysis, separately in
origin and/or destination markets. The applicant might have market
power in the origin market if producer/shippers have few good
alternatives to transport their product out of the origin area. In the
destination market, pipelines might be able to exercise market power if
downstream customers have few good transportation alternatives that
reach their city-gates. If customers have long term supply contracts,
it will be particularly important for the pipeline to demonstrate that
it has no market power over customers on a given route.
3. Firm Size and Market Concentration
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.
a. Acting Alone. One of the indicators that has been examined to
determine whether a seller could exercise market power acting alone is
the seller's market share. A large market share is generally a
necessary condition for the exercise of market power. If the seller has
a small market share it is unlikely that it can exercise market power.
But, a company with a large market share may not be able to exert
market power if entry into the market is easy 58 or there are
other competitive forces at work.
\58\ Given the nature of the interstate pipeline industry, ease
of entry would be difficult to show except in cases involving minor
facilities. For major facilities, the cost of construction and the
time needed for environmental analysis and certification would
suggest that entry may not be easy.
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The applicant must submit calculations (and supporting data) of its
market share in all relevant path or origin and destination areas.
b. Acting Together with Other Sellers. A second way in which a
seller can exercise market power is to act together with other sellers
to raise prices. To evaluate whether a seller can act together with
others to exercise market power, the Commission typically has examined
the market's concentration.
To measure market concentration, one generally considers the
summary measure of market concentration known as the Herfindahl-
Hirschman Index (HHI). If the HHI is small then one can generally
conclude that sellers cannot exercise market power in this market. A
small HHI indicates that customers have sufficiently diverse sources of
supply in
[[Page 4640]]
this market that no one firm or group of firms acting together could
profitably raise market price. If the HHI is higher then additional
analysis may be needed to determine if the seller can exercise market
power.
The Commission will analysize the HHI calculation for the relevant
markets. The HHI will be evaluated for each relevant path and/or origin
market and each destination market utilizing the relevant data for each
mainline receipt point (origin market) and each delivery point
(destination market). If an applicant wishes to argue for either a
broader or narrower market definition, it should also include
calculations for its market definitions. Only sales or capacity figures
associated with good alternatives should be used in calculating the
HHI. In addition, applicants should aggregate the capacity of
affiliated companies into one estimate for those affiliates as a single
seller.59
\59\ The capacity on pipeline systems owned or controlled by the
applicant's affiliates should not be considered among the customer's
alternatives. Rather, the capacity of an applicant's affiliates
offering the same product are to be included in the market share
calculated for the applicant. Similarly, alternative pipelines must
be aggregated with their respective affiliates in order to identify
meaningful alternatives to customers.
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In the gas inventory charge (GIC) cases, the Commission established
a threshold level for the HHI at .18.60 An HHI at this level
indicates that there are four to five good alternatives to the
applicant's service in each of the relevant markets. In an oil pipeline
case, the Commission used a slightly higher HHI of .25 as an initial
screen.61
\60\ El Paso Natural Gas Company, 49 FERC para. 61,262 (1989).
See also Buckeye, 53 FERC at 62,667.
\61\ See Williams Pipe Line Co., Opinion No. 391, 68 FERC para.
61,136 (1994).
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Several commenters suggested that the HHI should be raised.
Suggestions ranged from 0.25 to 0.35.62 Others argued that the
Commission should not adopt an arbitrary numerical threshold of
concentration but should do a thorough review of actual market
conditions on particular pipeline systems instead.63
\62\ AGD, Cove Point, INGAA, Tejas, ANR/CIG, and Brooklyn Union.
\63\ Brooklyn Union and KN Interstate.
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The Commission will not adopt a rigid brightline threshold level
for the HHI, below which an applicant would automatically qualify for
market-based rates, or above which an applicant would be excluded from
market-based rates. Rather, the Commission will use 0.18 HHI as an
indicator of the level of scrutiny to be given to the applicant. If the
HHI is above 0.18, the Commission will give the applicant closer
scrutiny because the index indicates that the market is more
concentrated and the applicant may have significant market power. An
HHI below 0.18 would result in less scrutiny of the applicant's
potential to exercise significant market power because it would
indicate that the market is less concentrated.
The Commission is primarily concerned about whether an individual
applicant seller (including affiliates) can exercise market power. The
HHI will be one of the factors that the Commission will evaluate.
However, market shares and HHIs alone do not give a comprehensive view
of all important factors. The impact of other competitive factors on
the Commission's analysis of market-based rate proposals is discussed
below.
4. Entry and Other Competitive Factors
Even if the applicant's market share were large in a concentrated
(and properly identified) market, one still might not conclude that the
applicant would be able to exercise market power. For example, if the
applicant increased its price, entry into the market might be so easy
that sellers attracted by the profit opportunity created by the higher
price would quickly take customers away from the applicant by offering
a lower price. This would make the applicant's price increase
unprofitable. Thus, the applicant would not be able to exercise market
power, despite its large market share and despite the high market
concentration.64 Ease of entry is one of several competitive
factors that might lead to the conclusion that an applicant lacks
market power. It is most likely to apply to circumstances that do not
require the large sunk costs of major construction--for instance,
perhaps in offering short-haul market center services.
\64\ As stated before, entry would probably only be relevant for
gas pipelines in the case of minor facilities such as facilities
that could be constructed under a blanket certificate.
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Another competitive factor that might be established by an
applicant would be the presence of buyer power. An applicant might
argue that if a single buyer is a large customer of the pipeline, is
knowledgeable and sophisticated in its buying, and has been in business
for a lengthy period of time, the buyer may have the knowledge and
large-scale purchasing power to negotiate reasonable rates even in a
concentrated market. However, just because buyers develop sophisticated
purchasing systems and market knowledge as the result of dealing with
various suppliers in numerous markets, there still is reason to have
some skepticism that a buyer in a single destination area served by one
or a few pipelines will have such capabilities.
The Commission will evaluate whether sufficient quantities of good
alternatives are available to the applicant's customers to make a price
increase unprofitable. In other words, are customers able to replace a
significant proportion of their throughput with other transportation
alternatives if the applicant were to raise its price?
There may be cases where an applicant has completed its own
analysis of its market-based rate proposal using the criteria stated
above and concludes that it cannot, under existing circumstances,
establish that it lacks market power with respect to its proposed
service. Yet, the company may be able to identify certain conditions or
changes that it could implement to mitigate the effects of market power
and make market-based rates a viable option. In such cases, the
Commission would be willing to evaluate proposals for any conditions or
changes that the applicant would propose as mitigation for its
potential exercise of market power.
For example, a pipeline might suggest that the Commission permit
market-based rates for pipeline segments, such as for new laterals for
new service. In order to mitigate its market power and thereby make
itself eligible for market-based rates for service provided on that
lateral, the applicant might propose to refrain voluntarily from
allocating costs attributtable to the lateral to its other, cost-of-
service based services. The applicant might also voluntarily agree to
an open tap policy for services provided on the lateral. Under such a
policy the applicant (in return for getting permission from the
Commission to charge market-based rates) would agree to allow any
entity to interconnect with its facilities. Such an open tap policy
would help protect against withholding capacity by undersizing or
overpricing the new lateral. The interconnection would be for the
purpose of producing potential competitive suppliers to the services
for which the applicant seeks market-based rates. Thus, the
interconnection could be (depending on what the applicant is proposing)
for a lateral, a loop, an extension, or any other facilities that could
compete with the applicant's market-based services.
Applicants proposing such conditions or changes should state so
specifically in their proposals.
D. Filing Procedures
The Request for Comments asked whether the Commission should
continue its current policy of using declaratory orders for ruling on
market-
[[Page 4641]]
based rate proposals, or if some other procedural avenue was more
appropriate. Several commenters support continuing the current practice
of issuing declaratory orders.65 Others suggest that full
evidentiary hearings are required in at least some, if not all,
cases.66 However, the majority support a case-by-case review of
proposals with the Commission issuing an order on the proposal as
appropriate.67
\65\ NI-Gas, SoCalGas, Columbia, KN Interstate, Koch Gateway,
PEC Pipeline Group, Florida, and Transok.
\66\ Petrochemical Energy Group, APGA, Northern Distributors,
Wisconsin Distributors, Indicated Shippers, NGSA, Illinois, and Ohio
CC.
\67\ Fuel Managers, Industrial Gas Consumers, CINergy Gas
Companies, Columbia Distribution, Northern Distributors, Northern
Indiana, SoCalGas, UDC, ANR/CIG, CNG, Koch Gateway, NorAm, PEC
Pipeline Group, Williston Basin, Texaco, and Ohio CC.
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The Commission will continue its current policy of using
declaratory orders to rule on requests for market-based rates on a
case-by-case basis. In cases where a certificate of public convenience
and necessity is required, the review will occur as part of the
certificate process.
Applying the criteria stated in the sections above, applications
for market-based rates should contain the following information: (1) A
detailed description of the service(s) proposed for market-based rate
treatment; (2) a statement defining the relevant product and geographic
markets necessary for establishing that the applicant lacks market
power with respect to the particular service(s) at issue. Such
statement should state the relevant time period for comparing services
within the product and geographic markets; an analysis describing how
the prices for relevant alternative services compare to the relevant
price increase threshold; and a detailed description of good
alternatives to the proposed service(s); (3) market share and HHI
calculations; and (4) discussion of other relevant competitive factors
and their import. In addition, pipelines should include in each
application a proposal for accounting for the costs and revenues
resulting from the proposed service. An application should be
sufficient to establish on its own, without further inquiry or support,
that the proposed service or services meet the criteria for market-
based rates presented in this policy statement.
Applications for market-based rates will be noticed in the Federal
Register. Interested parties will have an opportunity to intervene in
the proceeding and to present a response to the proposal. The
Commission will consider the information provided in the application,
any information provided by intervenors in response thereto, and will
take any intermediate steps, including issuing data requests or
convening a technical conference, that may be necessary to complete its
evaluation of the proposal. The Commission will either conduct a paper
hearing, based upon the initial filing and responses thereto, or set
the matter for a formal evidentiary hearing before an administrative
law judge, as appropriate. Upon completing its evaluation, the
Commission will issue a declaratory order ruling whether the service
meets the requirements of market-based rates. If the service meets the
standards then the applicant can make the appropriate tariff filing
necessary to set its market-based rates into effect. Commission
approval of market-based rate proposals will be prospective only, thus
eliminating concerns regarding refund liability. The Commission's
determinations in these circumstances will be based upon the facts
presented in the proposal. Accordingly, the Commission may reconsider
its ruling should the circumstances on the pipeline change such that
market-based rates are no longer appropriate.
IV. Policy on Incentive Rates
In circumstances where market-based rates are not appropriate, the
Commission will continue cost-based rate regulation. In October 1992,
the Commission issued a Policy Statement on Incentive Regulation to
allow companies that have market power nevertheless to receive some of
the benefits of greater flexibility and efficiency that are associated
with market-based rates.68 Incentive rate proposals, while cost-
based, are intended to result in better service options at lower rates
for consumers while providing regulated companies with the opportunity
to earn higher returns. Incentive regulation is not intended for
competitive markets. It is intended for markets where the continued
existence of market power prevents the Commission from implementing
light-handed regulation without harm to consumers. The Commission
continues to believe that incentive rate mechanisms have potential to
benefit both natural gas companies and consumers by fostering an
environment where regulated companies that retain market power can
achieve greater efficiency and cost-effectiveness.
\68\ Policy Statement on Incentive Regulation, 61 FERC para.
61,168 (1992).
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In the Policy Statement, the Commission explained that incentive
regulation differs from traditional regulation in that it fosters long-
term efficiency. It accomplishes this by: (1) divorcing rates from the
underlying cost-of-service, (2) lengthening the period between rate
cases; and (3) sharing the benefits of cost savings between consumers
and stockholders on a current basis. The Commission set out five
criteria that incentive rate proposals must meet to gain Commission
approval. Under the policy adopted in 1992, proposals for incentive
rate programs must: (1) Be prospective; (2) be voluntary; (3) contain
incentive mechanisms that are understandable to all parties; (4) result
in quantified benefits to consumers; and (5) demonstrate how they
maintain or enhance incentives to improve the quality of service. Each
of these criteria were discussed at length in the Policy Statement.
After articulating the criteria to be utilized in evaluating proposals
for incentive rate proposals, the Commission invited companies to
submit such proposals for consideration.
Since the issuance of the Policy Statement, the Commission has not
received any requests for approval of incentive rate proposals. For
this reason, and in light of the changes in the natural gas market that
have occurred as a result of the implementation of Order No. 636, the
Commission decided to revisit the issue of incentive rates for pipeline
services. Therefore, in the Request for Comments, the Commission sought
responses to specific questions regarding its incentive rate Policy
Statement. These questions included: (a) why there have not been any
incentive proposals under the policy established in Docket No. PL92-1-
000; (b) whether the Commission should change its existing standards
for incentive rate proposals; (c) if so, what specific criteria the
Commission should employ when evaluating incentive rates; (d) whether
there are models for incentive regulation that the Commission should
consider, such as the California performance-based program; (e) what
the benefits and drawbacks of incentive rates are, and what policy
objectives the Commission should pursue with an incentive rate method;
and (f) whether incentive ratemaking is appropriate for the natural gas
companies regulated by the Commission.
Many of those responding to questions regarding the Commission's
current standards for evaluating incentive rate proposals favor
changing the current standards. Specifically, the majority of those
pipelines that
[[Page 4642]]
responded encourage a change in the standards away from ``quantifying''
benefits to customers and eliminating the cost-of-service cap on
incentive rates.69 Commenters also encourage elimination of the
requirement that rates under incentive programs could be no higher than
they would have been under traditional cost-of-service
regulation.70
\69\ WINGS, NorAm, Williston Basin, Alberta, ANR/CIG, Columbia,
Enron and INGAA.
\70\ INGAA, WINGS, Enron, and NorAm.
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The Commission has reviewed the comments and re-evaluated its
existing policy in light of current conditions in the natural gas
industry. Based on these comments, the Commission recognizes that it is
problematic to compare incentive-based rates with existing cost-of-
service rates or with what rates would have been under cost-of-service
pricing after incentive-based regulation is implemented. Comparisons of
incentive-based rates with previous cost-based rates compare service
and rates in different time periods.
Moreover, the ability of pipelines to profit from cost reductions
remains a key ingredient of most incentive-based options. Imbedded in
the typical incentive-based proposal is the expectation that, over
time, this ability to profit will drive industry costs down and
therefore lead to rates that are lower than they would have been under
traditional cost-based regulation. In consideration of all of these
points, the Commission believes it is appropriate to modify its
existing policy.
In reply to the Request for Comments, INGAA, six pipelines, and the
Alberta Regulatory Commission suggested elimination of the requirement
to quantify benefits. Also, five pipelines specifically recommended
that the Commission eliminate the requirement that rates under
incentive regulation be no higher than they would have been under
traditional cost-of-service regulation. The Commission agrees with
these recommendations. Although both quantifiable benefits and
comparisons shall remain two of the goals of any incentive rate
program, these requirements are eliminated from the Commission's stated
criteria for evaluating incentive rate proposals. Instead of requiring
firms to quantify the benefits of any performance-based proposal, the
Commission will require pipelines proposing such programs to share with
their ratepayers the efficiency gains of the program. Any pipeline
proposal must explicitly specify the performance standards it defines,
the mechanism for sharing benefits with customers, and a method for
evaluating the proposal. Pipeline companies are invited to submit
proposals that fulfill these requirements as well as the three other
criteria articulated in our prior Policy Statement.
Commenters also encouraged the Commission to require participation
in any proposed incentive rate program continue for a prescribed period
of time, such as four or five years. Commenters argue that this will
prevent individual pipelines from moving in and out of incentive rate
programs in an attempt to game the system.
The current policy states that the fact that incentive regulation
is voluntary,
does not mean that utilities should be completely free to abandon
their programs should their profits decline. Such a policy could
encourage inefficient investments in risky cost-cutting innovations,
and it would be unfair to consumers. Instead, programs may include
conditions under which utilities could opt out after an initial
commitment.71
\71\ Policy Statement, 61 FERC at 61,589.
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The Commission later stated that the exact period of time between
rate reviews under incentive rate programs would be decided on a case-
by-case basis.72
\72\ Id., at 61,603.
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The Commission is not inclined to prescribe in this policy
statement a length of time during which performance-based rate
proposals must be operative. The particulars of any one program are
likely to be so company specific as to make such a requirement
impractical. Nevertheless, the Commission is no less committed to the
requirement that pipelines agree to operate under such programs for a
specified period than it was at the time of the original policy
statement. Therefore, the Commission clarifies that approval of an
incentive rate program proposal will require a commitment by the
pipeline that it will continue in the program for a specified length of
time as appropriate for the particular pipeline system at issue.
Proponents of such proposals should suggest a desired duration for
operation under any proposed incentive plan along with arguments
supporting the proposal.
The Commission will consider on a timely basis incentive rate
proposals filed under the revised criteria. Such proposals may take a
variety of forms.73 The considerable state regulatory activity in
developing performance and incentive-based ratemaking mechanisms
attests to the vitality of such approaches. Incentive rates may be
usefully developed by pipelines and their customers as a means of
reaching long-term accord on some of the difficult issues now
confronting the industry. Alternative dispute resolution may also play
an important role in achieving agreement on system-wide incentive
rates, and the Commission supports such efforts.
\73\ Incentive Regulation for Natural Gas Pipelines: A Specific
Proposal with Options, OEP Technical Report 89-1, September 1989;
Incentive Regulation: A Research Report, OEP Technical Report 89-3,
November 1989.
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The Commission is setting forth a policy for market-based rates
today. The incentive rates policy is still emerging. The Commission
encourages pipelines to file new incentive or performance-based rate
proposals and concepts for Commission consideration.
V. Negotiated/Recourse Rates and Terms of Service
A. The Proposals
Where pipelines do not attempt to establish a lack of market power
and do not want to undertake an incentive rate program, there are yet
other alternatives to traditional cost-of-service regulation that could
be used. In the Request for Comments, the Commission sought comment on
other ratemaking methods that would better serve the goal of flexible,
efficient pricing in today's environment. Included in the Commission's
request were ``backstop proposals, where pipelines would be free to
negotiate rates and terms of service, so long as customers could always
choose service under traditional cost-of-service rates and terms of
service.''74
\74\ 70 FERC at 61,394.
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In its initial comments INGAA proposes negotiated rates and terms
for service as an option. Under INGAA's plan, the Commission would
dispense with cost-of-service regulation for an individual shipper when
mutually agreed upon by the pipeline and a shipper and permit
negotiated rates and terms and conditions of service that could vary
from the pipeline's otherwise applicable tariff. A recourse service
that is on file in the pipeline's tariff would always be available for
those shippers preferring traditional cost-of-service rates and
services.
As originally proposed by INGAA, the recourse rate would escalate
the recourse rate based on a pipeline industry index, less a one
percent productivity factor. INGAA proposed that the Commission modify
its current incentive policy statement to eliminate the cost-of-service
cap and the quantifiable benefits test. Subsequently, INGAA changed its
proposal to make the index component voluntary and optional. INGAA
claims the recourse rate, which would be established
[[Page 4643]]
initially through a Section 4 rate case, would be lower than a cost-
based rate, over time, through the workings of the productivity
adjustment. While INGAA provided a detailed discussion of its indexing
proposal, initially few details were provided on the scope of
negotiated rates and terms and conditions.
Brooklyn Union and PSE&G also endorsed negotiated rates backstopped
by a recourse rate in their initial comments. Both parties emphasized
the recourse rate would be for traditional tariff service priced on a
cost-of-service basis and protected from adverse rate or operational
impact from the individually customized services.
B. Comments on INGAA's Proposal
In response to INGAA's proposal, AGD, Brooklyn Union, and UGI,
while generally supporting negotiated/recourse rates, object to INGAA's
proposal to index the recourse rate. These parties ask the Commission
to allow negotiated/recourse rates as soon as possible without
complicating matters by tying the negotiated/recourse rate concept to
incentive rates. AGD and UGI also express concerns that recourse rate
payers should be protected from cost shifting or degradation of their
service resulting from negotiated rates.
NGSA and IPAA oppose INGAA's negotiated rate proposal contending it
would allow the pipeline to use its market power to discriminate among
its customers by providing additional service benefits to some
customers and denying them to others. Further, they argue that, if the
negotiated service agreements were not filed with the Commission, it
would be difficult to obtain the necessary facts to support a
discrimination complaint.
AGD, Brooklyn Union, and NGSA/IPAA object that INGAA's incentive
rate proposal does not provide for a sharing of efficiency gains. NGSA
and IPAA support the Commission's current incentive rate policy
statement requiring quantification of consumer benefits.
In a September 25, 1995 filing, INGAA clarified its proposal to
emphasize that it would be voluntary, there would be no cost shifting,
and it would be up to individual pipelines whether to propose indexing
of the recourse rate. INGAA also suggested that pipelines would file a
form of notice for negotiated rates, similar to transportation discount
reports, identifying the customer, the negotiated rate or formula, the
recourse rate, and contract quantity and duration. According to INGAA,
the Commission would resolve complaints about discrimination, undue
affiliate preference, or deleterious effects on other services. In a
November 7, 1995 filing, INGAA further clarified its proposal stating
that SFV is not affected because its proposal leaves any existing SFV
rate design in place.75 INGAA adds that the Commission's scrutiny
of costs and allocation plans during the rate cases that will establish
recourse rates will assure that these rates do not contain unapproved
cross subsidies. INGAA asserts that competition will provide the
necessary quality assurance and that the recourse rate will be on file
with the Commission and will thereby meet the NGA's filing requirement.
INGAA contends that its proposal calls for filing information on the
negotiated transactions, similar to the data required by Order No. 581
for discount rates and that required for the index of customers, after
the negotiations are concluded. In this way INGAA asserts that the
negotiated/recourse rates can comply with the requirements of the NGA
while meeting the need of certain customers to keep key data in the
negotiated rate proprietary to protect their competitive positions.
\75\ A just and reasonable recourse rate would be derived using
traditional cost-of-service rate methodologies including SFV.
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In response to INGAA's November 7 filing, NGSA argues that it would
be inappropriate for any action to be taken on ``recourse rates'' by
the Commission in this docket without providing other parties an
opportunity to examine and comment fully on INGAA's new proposal. NGSA
states that INGAA's proposals raise serious questions as to whether
they would achieve the essential goals of bringing greater efficiency
and competition to the interstate natural gas transportation industry
while protecting all customers from the exercise of market power, undue
discrimination, and cross subsidization. NGSA states that INGAA's
proposal is lacking in critical details and therefore requires
additional study and comment.76
\76\ On January 23, 1996, NGSA further supplemented its response
and clarified the goals it believes alternative rate proposals must
meet to be successful.
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A group of industrial end-user trade associations77 also
responded to INGAA's November 7 filing. The Industrials urge the
Commission to reject INGAA's negotiated/recourse rate proposal. The
Industrials criticize INGAA's proposal suggesting it would lead to
market-based rates in a market lacking workable competition, and would
result in ``severe damage to the objectives of Order No. 636 and the
overall policy of developing an integrated transportation grid''. The
Industrials strongly support SFV rates as key to a robust secondary
market and fear that negotiation of non-SFV rates will lead to a hodge-
podge of individual rates and services, encourage LDC's to hoard
capacity, and ultimately impede producers and end-users from accessing
interstate capacity.
\77\ The Petrochemical Energy Group, Process Gas Consumers and
the Georgia Industrial Group, Chemical Manufacturers Association,
American Iron and Steel Institute, American Forest & Paper
Association, Council of Industrial Boiler Owners, Praxair Inc., and
the California Manufacturers Association (``The Industrials'').
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C. Discussion of Negotiated/Recourse Rates and Services
The Commission believes that negotiated/recourse service programs
could be a viable way of achieving flexible, efficient pricing when
market-based rates are not appropriate. Negotiating different rates and
service terms for individual shippers could result in wide flexibility
in service offerings including individually tailored seasonal service
and rates, short-term services, or special rates for more flexible
terms and conditions. Greater rate flexibility has previously been tied
to a showing that a pipeline lacks market power. Under this method,
however, the availability of a recourse service would prevent pipelines
from exercising market power by assuring that the customer can fall
back to cost-based, traditional service if the pipeline unilaterally
demands excessive prices or withholds service. Thus, the recourse rate
mitigates market power. At a minimum, negotiated/recourse services
offer the potential for increased market responsiveness in pipeline
services without protracted disputes regarding market power.
Although the proposal as presented by INGAA and others has many
attractive features, it raised a number of concerns as well. The first
issue of concern involves associating negotiated/recourse proposals
with incentive/performance-based programs. As stated previously,
INGAA's original proposal called for recourse rates to be indexed. The
Commission is concerned that choosing an appropriate index will be
extremely problematic. Questions regarding whether it is appropriate to
index recourse rates and what, if anything, would be an appropriate
index to use must be addressed prior to a pipeline implementing such a
proposal.
Another concern involves situations where the availability of the
recourse service alone is not sufficient to mitigate a pipeline's
exercise of market power. In its response to INGAA's initial proposal,
NGSA expressed its concern that the
[[Page 4644]]
availability of customized terms and conditions would be at the sole
discretion of the pipeline. The pipeline would thus be in a position to
discriminate among its customers in providing enhanced service
flexibility, argues NGSA, favoring affiliates or customers who, for
whatever reason, were able to obtain a negotiated deal with the
pipeline. NGSA's concerns will be further considered in the separate
proceeding discussed below. The Commission is also concerned about the
extent to which the concept of negotiated terms and conditions of
service is compatible with the requirements, goals and objectives of
Order No. 636. Specifically, what effect, if any, negotiated terms of
service are likely to have on: capacity release; flexible receipt and
delivery points; the use of secondary receipt and delivery points; and
no-notice transportation service. For example, if a pipeline agrees to
provide a shipper priority of service at certain points, or additional
flexibility in exchange for a higher rate, what effect would this have
on other shippers served under the recourse service?
The Commission is particularly concerned about maintaining the
integrity of the recourse service. In order to be successful, the
recourse service must remain a viable alternative to negotiated
service. Otherwise, if the recourse service remains stagnant, in time,
the recourse service will become outmoded and will cease to be a viable
alternative to negotiated service. Since the purpose of the recourse
service is to act as a check against pipeline market power, such a
result is impermissible. Therefore, some means may be needed to ensure
the continued viability of the recourse service. The Commission is
concerned about how this would be accomplished and whether any specific
conditions concerning recourse services are needed.
Since open access transportation began, the Commission has required
flexibility in terms and conditions to be offered on a non-
discriminatory basis uniformly to all shippers under a given rate
schedule. When competitive pressure forces a pipeline to liberalize its
tariff to satisfy a few shippers, the tariff is amended and all
shippers enjoy the benefits. To date the Commission has not permitted
narrow classification of customer groups. If the Commission permitted
the negotiation of terms of service pipelines would be able to offer
special flexibility to selected customers. In that case, what
standards, if any, would the Commission use to determine what
constitutes undue discrimination? Likewise, are explicit new
restrictions needed to prevent pipelines from tying access to a
negotiated premium service to the use of the pipeline's other services
as well as new restrictions from granting affiliate preferences
necessary?
Finally, the Commission is concerned that negotiated/recourse
proposals meet the requirements of Section 4 of the NGA. To satisfy the
requirement in the NGA that rates, terms and conditions of service must
be on file with the Commission, some form of filing the negotiated rate
and terms of service will be necessary.
D. Proposals for Negotiated/Recourse Services
As stated previously, negotiated/recourse programs may serve to add
flexibility and efficiency to pipeline services in cases where a
company does not apply for market-based rates for its services and does
not wish to pursue incentive rate programs. For this reason, the
Commission is willing to entertain, on a shipper-by-shipper basis,
requests to implement negotiated rates where customers retain the
ability to choose a cost-of-service based tariff rate. The Commission
already permits individualized rates under its rate discount policies.
In allowing the further negotiation of rates, the Commission is
confident that there are a number of mechanisms available to permit
this added flexibility while ensuring that inappropriate cost shifting
does not take place.
Requests to implement negotiated rates may be made for new or
existing contracts. Companies making such requests must use their
existing Commission approved tariff rates applicable to the service as
their recourse rate unless they are filing a new rate case
simultaneously. The recourse rate will be available for existing
capacity holders that do not negotiate a rate with the pipeline,
thereby ensuring that existing customers will always have a cost-of-
service based rate available for capacity they have under contract.
Specifically, this policy statement does not change the right of first
refusal requirements in section 284.221(d)(2)(ii) that the highest rate
that an existing shipper must match if it wishes to continue its
transportation arrangement is the maximum recourse rate established in
the pipeline's tariff.
A question arises when capacity is constrained. The predicate for
permitting a pipeline to charge a negotiated rate is that capacity is
available at the recourse rate. For purposes of allocating capacity,
shippers willing to pay more than the maximum recourse rate would be
considered to have paid the maximum recourse rate. Therefore, a shipper
willing to pay only the recourse rate cannot lose access to capacity
merely because someone else is willing to pay a negotiated rate. When
there are more requests for capacity than there is capacity available,
then the pipeline must allocate capacity among those shippers willing
to pay either the negotiated rate or the maximum recourse rate, for
example on a pro rata basis if required by its tariff.78 This pro
rata allocation would also apply to situations where the pipeline must
allocate limited capacity for such services as interruptible
transportation.
\78\ If a pipeline has 100 dth of available capacity and there
are two shippers who request that capacity, one is willing to pay no
more than the recourse rate of $5.00/dth and another a negotiated
rate of $6.00/dth, then each would be allocated 50 dth on a pro rata
basis.
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Because pipeline tariffs state that the pipeline will charge a rate
between the maximums and minimums stated on the rate sheets, pipelines
will need to file conforming tariff sheets indicating that the rate for
the service will be either the rates stated on its existing rate
schedule or a rate mutually agreed upon by the pipeline and its
customer. When a rate is negotiated, the pipeline will need to file a
numbered tariff rate sheet stating the exact legal name of the customer
and the negotiated rate for the service. A pipeline may make the
conforming change to its tariff to indicate that the rate may be a
negotiated rate, either at the time it requests to put a particular
negotiated rate into effect or at some earlier time. In addition,
pipelines should also include along with the conforming tariff change,
a proposal for accounting for the costs and revenues resulting from the
proposed service.
A pipeline may file the numbered tariff sheet implementing the
negotiated rate at the time it intends the rate to go into effect. The
Commission does not intend to suspend the effectiveness of negotiated
rate filings or impose a refund obligation for those rates. For these
reasons, the Commission will readily grant requests to waive the 30 day
notice requirement. Issues regarding the appropriate allocation of
costs between recourse rate shippers and negotiated rate shippers will
be addressed fully in the pipeline's Section 4 rate cases.79 At
that time, the Commission will consider issues
[[Page 4645]]
relating to cross-subsidization and interested parties will be able to
raise any concerns they may have regarding the proper allocation of
costs. Therefore, the Commission does not intend to review a pipeline's
negotiated rates at the time filed. However, customers that wish to
argue that they are similarly situated with a customer receiving a
negotiated rate and that a pipeline has been unduly discriminatory may
file a complaint with the Commission at any time. The Commission will
use its authority under Section 5 to investigate the complaint and, if
a remedy is appropriate, will order a prospective rate change.
\79\ The Commission recognizes that not all pipelines currently
have a requirement to file a Section 4 rate case. For those
pipelines that elect to charge negotiated rates and are not required
to file a Section 4 rate case, the Commission may consider, on its
own motion or on complaint by a recourse shipper, using its Section
5 authority to investigate whether the pipeline's recourse rates
remain a viable cost-based alternative to negotiated rates.
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Pipelines are reminded that, pursuant to Sections 284.8(b) and
284.9(b), they are expected to negotiate rates with their customers in
a manner that is not unduly discriminatory and that treats similarly
situated shippers similarly. In addition, customers electing the
recourse rate should be no worse off as a result of the use of
negotiated rates than they would be absent the use of negotiated rates.
Pipelines offering negotiated rates will have the burden of justifying
revenue projections from negotiated services if the pipeline's method
of achieving such projections deviate from traditional methods. In
other words, recourse rate shippers should not bear the responsibility
of unsubscribed capacity alone and pipelines should continue to market
all unsubscribed capacity.
The Commission believes that a pipeline's negotiation of individual
rates with shippers should not affect the way a pipeline accounts for
the recovery of transition costs. For example, the Commission specified
in Natural Gas Pipeline Company of America80 that pipelines treat
transition costs as the last item discounted. One of the main purposes
of this policy was to ensure that transition costs are spread as evenly
as possible among all the pipeline's customers and to reduce the
shifting of costs to the pipeline's captive customers. Consistent with
this policy, if a pipeline negotiates a rate with a customer that does
not include transition costs, the pipeline will be at risk for the
collection of those costs and cannot reallocate them to its recourse
rate shippers.
\80\ 69 FERC para. 61,029 (1994), order on reh'g, 70 FERC para.
61,317 (1995).
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Currently, pipelines' maximum tariff rates are subject to a variety
of surcharges, in addition to those that relate to transition costs,
e.g., ACA, operational Account No. 858, and GRI.81 The Commission
expects that pipelines' recovery and treatment of these costs will not
change for shippers under negotiated rate contracts. As is currently
the case, pipelines who negotiate to provide services at less than the
maximum tariff rate will be subject to the same Commission policies,
such as the Natural policy on the attribution of discounting. The
Commission expects that, to the extent pipelines wish to deviate from
these existing policies, they will be willing to accept the risk of
underrecovery of these costs.
\81\ GRI's funding mechanism for 1996 and 1997 is designed to
collect 50 percent of GRI's Commission-approved budget through
reservation surcharges and 50 percent through the volumetric
surcharge. 71 FERC para. 61,130 (1995). Negotiated rates could
change the mix of reservation/usage billing units. GRI has expressed
concerns that pipelines may not recover full GRI revenue levels or
pipelines may leave GRI if market-based or negotiated rates are
implemented.
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Because of the number of issues remaining concerning whether
negotiation of terms and conditions of service is appropriate, the
Commission is not willing to permit the negotiation of individual
shipper customized terms of service at this time. Commission
willingness to entertain requests for negotiated rates expands on the
flexibility in rates already permitted by the Commission with
discounting. In allowing further negotiation of rates, the Commission
is confident that there are a number of mechanisms to ensure that
inappropriate cost shifting does not take place. However, further
discussion with the industry of all the ramifications of negotiated
terms of service is needed.
Therefore, the Commission is establishing a separate proceeding in
which it will consider this issue and is inviting interested
participants to file comments on the issues raised above, as well as
any other issue that should be considered before permitting pipelines
to negotiate terms of service with individual shippers. Participants
interested in commenting on these issues should submit their written
comments in Docket No. RM96-7-000 within 60 days of the date of this
order.
By the Commission.
Lois D. Cashell,
Secretary.
Appendix
Commenters
Alberta Department of Energy (Alberta)
American Gas Association (AGA)
American Forest and Paper Association (AF&PA)
American Public Gas Association (APGA)
Amoco Energy Trading Corporation and Amoco Production Company (Amoco)
ANR Pipeline Company and Colorado Interstate Gas Company (ANR/CIG)
Associated Gas Distributors (AGD)
Atlanta Gas Light Company and Chattanooga Gas Company (Atlanta Gas
Light)
Brooklyn Union Gas Company (Brooklyn Union)
Cascade Natural Gas Corporation, Northwest Natural Gas Company,
Washington Natural Gas Company and Washington Water Power Company
(Pacific Northwest Commenters)
Cincinnati Gas & Electric Company, Union Light, Heat and Power Company
and Lawrenceburg Gas Company (CINergy Gas Companies)
Cities of Lenox, et al. (Lenox)
Columbia Gas Transmission Corporation and Columbia Gulf Transmission
Company (Columbia)
Columbia Gas Distribution Companies (Columbia Distribution)
Connecticut Natural Gas Corporation (Connecticut Natural)
Consolidated Edison Company of New York, Inc. (Con Edison)
Consolidated Natural Gas Company (CNG)
Cove Point LNG Limited Partnership (Cove Point)
Enron Interstate Pipelines (Enron)
Fertilizer Institute
Florida Public Service Commission (Florida)
Fuel Managers Association (Fuel Managers)
Gas Research Institute (GRI)
Hadson Gas Systems, Inc. (Hadson)
Illinois Commerce Commission (Illinois)
Independent Oil & Gas Association of West Virginia (IOGA)
Independent Petroleum Association of Mountain States (IPAMS)
Indicated Shippers
Industrial Gas Consumers (IGC)
Interstate Natural Gas Association of America (INGAA)
KN Interstate Natural Gas Transmission Company (KN Interstate)
Koch Gateway Pipeline Company (Koch Gateway)
Natural Gas Supply Association (NGSA)
NorAm Gas Transmission Company (NorAm)
Northeast Energy Associates and North Jersey Energy Associates (Energy
Associates)
Northern Distributor Group (Northern Distributors)
Northern Illinois Gas Company (NI-Gas)
Northern Indiana Public Service Company (Northern Indiana)
Northwest Industrial Gas Users (NWIGU)
Office of the Ohio Consumers' Counsel (Ohio CC)
Pacific Gas and Electric Company1
\1\ Filed but had no comments.
[[Page 4646]]
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Pacific Gas Transmission Company (PGT)
Pennsylvania Office of Consumer Advocate (Pa OCA)
Pennsylvania Public Utility Commission (PaPUC)
Petrochemical Energy Group (PEG)
Public Service Commission of the State of New York (New York)
Public Service Electric and Gas Company (PSE&G)
Public Utilities Commission of Ohio (Ohio PUC)
Public Utilities Commission of the State of California\1\
Southern California Edison Company (SoCal Edison)
Southern California Gas Company (SoCalGas)
Tejas Power Corporation (Tejas)
Texaco Natural Gas Inc. (Texaco)
Texas Eastern Transmission Corporation, Panhandle Eastern Pipe Line
Company, Trunkline Gas Company and Algonquin Gas Transmission Company
(PEC Pipeline Group)
Transok, Inc. (Transok)
UGI Utilities, Inc.
United Distribution Companies (UDC)
Williams Interstate Natural Gas System (WINGS)
Williston Basin Interstate Pipeline Company (Williston Basin)
Wisconsin Distributor Group (Wisconsin Distributors)
[FR Doc. 96-2547 Filed 2-6-96; 8:45 am]
BILLING CODE 6717-01-P