[Federal Register Volume 62, Number 44 (Thursday, March 6, 1997)]
[Rules and Regulations]
[Pages 10204-10219]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-5363]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 284
[Docket Nos. RM91-11-006 and RM87-34-072; Order No. 636-C]
Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation Under Part 284 and
Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol
Issued February 27, 1997.
AGENCY: Federal Energy Regulatory Commission. Energy.
ACTION: Final rule; order on remand.
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SUMMARY: In United Distribution Cos. v. FERC, 88 F.3d 1105 (D.C. Cir.
1996), petitions for cert. filed, 65 U.S.L.W. 3531-32 (U.S. Jan. 27,
1997) (No. 96-1186, et al.) (UDC), the Court of Appeals for the
District of Columbia Circuit affirmed the Commission's restructuring of
the natural gas industry in the Commission's Order No. 636. (Final rule
published at 57 FR 13267, April 16, 1992). In UDC, the Court remanded
six issues to the Commission for further explanation or consideration.
This order complies with the Court's remand.
FOR FURTHER INFORMATION CONTACT:
Richard Howe, Office of the General Counsel, Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, DC 20426, (202) 208-
1274;
Mary Benge, Office of the General Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426 (202) 208-1214.
SUPPLEMENTARY INFORMATION:
In addition to publishing the full text of this document in the
Federal Register, the Commission also provides all interested persons
an opportunity to inspect or copy the contents of this document during
normal business hours in the Public Reference Room, Room 2A, 888 First
Street, N.E., Washington, DC 20426.
The Commission Issuance Posting System (CIPS), an electronic
bulletin board service, provides access to the texts of formal
documents issued by the Commission. CIPS is available at no charge to
the user and may be accessed using a personal computer with a modem by
dialing 202-208-1397 if dialing locally or 1-800-856-3920 if dialing
long distance. To access CIPS, set your communications software to
19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex,
no parity, 8 data bits and 1 stop bit. The full text of this order will
be available on CIPS in ASCII and WordPerfect 5.1 format. CIPS user
assistance is available at 202-208-2474.
CIPS is also available on the Internet through the Fed World
system. Telnet software is required. To access CIPS via the Internet,
point your browser to the URL address: http://www.fedworld.gov and
select the ``Go to the FedWorld Telnet Site'' button. When your Telnet
software connects you, log on to the FedWorld system, scroll down and
select FedWorld by typing: 1 and at the command line and type: /go
FERC. FedWorld may also be accessed by Telnet at the address
fedworld.gov.
Finally, the complete text on diskette in WordPerfect format may be
purchased from the Commission's copy contractor, La Dorn Systems
Corporation. La Dorn Systems Corporation is also located in the Public
Reference Room at 888 First Street, NE., Washington, DC 20426.
Note: Appendix A, containing Tables 1 and 2, and Appendix B,
containing Tables 1 through 5 are not being published in the Federal
Register but are available from the Commission's Public Reference
Room.
Before Commissioners: Elizabeth Anne Moler, Chair; Vicky A.
Bailey, James J. Hoecker, William L. Massey, and Donald F. Santa,
Jr.
Pipeline Service Obligations and Revisions to Regulations to
Regulations Governing Self-Implementing Transportation Under Part
284 of the Commission's Regulations and Regulation of Natural Gas
Pipelines After Partial Wellhead Decontrol (Docket Nos. RM91-11-006
and RM 87-34-072; Order No. 636-C)
Order on Remand
Issued February 27, 1997.
In United Distribution Companies v. FERC (UDC),1 the United
States Court of Appeals for the District of Columbia Circuit upheld the
Commission's Order No. 636 2 ``in its broad contours and in most
of its specifics.'' 3 In so doing, the Court affirmed the
Commission's restructuring of the natural gas industry, but remanded
six issues to the Commission for further explanation or consideration.
This order complies with the Court's remand.
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\1\ United Distrib. Cos. v. FERC, 88 F.3d 1105 (D.C. Cir. 1996),
petitions for cert. filed, 65 U.S.L.W. 3531-32 (U.S. Jan. 27, 1997)
(No. 96-1186, et al.) (UDC).
\2\ Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation; and Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol, [Regs.
Preambles Jan. 1991-June 1996] FERC Stats. & Regs. para. 30,939
(1992), order on reh'g, Order No. 636-A, [Regs. Preambles Jan. 1991-
June 1992] FERC Stats. & Regs. para. 30,950 (1992), order on reh'g,
Order No. 636-B, 61 FERC para. 61,272 (1992), reh'g denied, 62 FERC
para. 61,007 (1993).
\3\ UDC, 88 F.3d at 1191.
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In light of the Court's remand, the Commission has reexamined Order
No. 636, and of necessity, the changes in the natural gas industry that
have occurred since restructuring. Based on reconsideration of the
remanded issues, the Commission reaffirms certain of its previous
rulings and reverses others.
I. Introduction
In Order No. 636 the Commission required interstate pipelines to
restructure their services in order to improve the competitive
structure of the natural gas industry. The regulatory changes were
designed ``to ensure that all shippers have meaningful access to the
pipeline transportation grid so that willing buyers and sellers can
meet in
[[Page 10205]]
a competitive, national market to transact the most efficient deals
possible.'' 4 To achieve this goal, the Commission required
pipelines to restructure their services to separate the transportation
of gas from the sale of gas, and to change the design of their
transportation rates. The Commission also required pipelines to permit
firm shippers to resell their capacity rights, creating national
procedures for trading transmission capacity. The Commission adopted a
new flexible delivery point policy and took various other actions in
order to promote the growth in market centers. In addition, the
Commission adopted policies to govern the pipelines' recovery of
transition costs that would arise from the restructuring.
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\4\ Order No. 636, [Regs. Preambles Jan. 1991--June 1996] FERC
Stats. & Regs. at 30,393.
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In UDC, the Court affirmed the major elements of the restructuring
rule--the unbundling of sales and transportation,5 the use of an
SFV rate design, the capacity release rules, the curtailment
provisions, the right-of-first refusal mechanism, and the recovery of
transition costs. Specifically, the Court affirmed the Commission's
regulation of capacity release including restrictions on non-pipeline
releases,6 its ban on buy/sell transactions,7 and its
adjustments to pipelines' rates, including the authority to increase
those rates under section 5 of the Natural Gas Act (NGA) in the
circumstances presented.8 The Court further held that the
Commission has jurisdiction over the curtailment of third-party
supplies.9
The Court remanded six aspects of the rule for further explanation
or consideration, although the Court permitted the rule to stand as
formulated pending the Commission's final action on remand.10
First, the Court remanded the issue of no-notice transportation
eligibility, particularly the Commission's restriction on the
entitlement to no-notice transportation service to those customers who
received bundled firm-sales service on May 18, 1992.11 The Court
found that the Commission had not adequately explained the
``disadvantaging of former bundled firm-sales customers who converted
under Order No. 436.'' 12 Second, while the Court upheld the basic
right-of-first-refusal mechanism, with its matching conditions of rate
and contract term,13 it remanded as to the Commission's selection
of a twenty-year term-matching cap.14 Specifically, the Court
found that the Commission had not adequately explained how the twenty-
year cap protects against pipelines' market power, and the failure to
explain why it looked at new-construction contracts in arriving at the
twenty-year figure.15
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\5\ The mandatory unbundling remedy itself was not challenged;
however, appellants challenged four peripheral aspects of the remedy
which were addressed by the Court. First, the Court upheld the rule
that customers must retain contractual firm-transportation capacity
for which the pipeline receives no other offer. Second, the Court
deferred to individual proceedings the issue of pipelines' ability
to modify storage contracts without NGA section 7(b) abandonment
proceedings. Third, the Court declared moot the challenge to the
Commission's rule that transportation-only pipelines may not acquire
capacity on other pipelines. Fourth, as discussed further in this
order, the Court remanded for further consideration the Commission's
decision that only those customers who received bundled firm-sales
service on May 18, 1992, are entitled to no-notice transportation
service.
\6\ UDC, 88 F.3d at 1152-54.
\7\ Id. at 1157.
\8\ Id. at 1166.
\9\ Id. at 1148.
\10\ Id. at 1191.
\11\ Id. at 1137.
\12\ Id.
\13\ Id. at 1139-40.
\14\ Id. at 1141.
\15\ Id.
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Third, the Court remanded the issue of SFV rate mitigation for
further explanation of the requirement that initial rate mitigation
measures must be applied on a customer-by-customer basis, and the
phased-in measures must be applied on a customer-class basis.16
The Court found that the Commission had not adequately justified its
preference for customer-by-customer mitigation over customer-class
mitigation.17 The Court was particularly concerned by arguments of
the pipelines that customer-by-customer mitigation would increase the
risks that a pipeline will fail to collect its costs.18 Fourth,
the Court remanded the Commission's deferral to individual
restructuring proceedings the eligibility of small customers on
downstream pipelines for a one-part small-customer rate.19 The
Court found that the Commission made an arbitrary distinction between
former indirect small customers of an upstream pipeline who are now
direct customers, and small customers who have always been direct
customers of the same upstream pipeline.20
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\16\ Id. at 1174.
\17\ Id.
\18\ Id.
\19\ Id. at 1175.
\20\ Id. at 1174-75.
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Fifth, the Court found that the Commission had not adequately
explained the requirement that pipelines allocate ten percent of Gas
Supply Realignment (GSR) costs to interruptible customers.21 The
Court's principal concern was the lack of justification for the
allocation figure of ten percent, as opposed to another percentage or
allocation method.22 Finally, the Court remanded the Commission's
decision to exempt pipelines from sharing in GSR costs.23 The
Court required further explanation of why the Commission used ``cost
spreading'' and ``value of service'' principles to allocate costs to
the pipelines' customers, but reverted to traditional ``cost
causation'' principles to justify exempting pipelines from those
costs.24
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\21\ Id. at 1188.
\22\ Id. at 1187.
\23\ Id. at 1190.
\24\ Id. at 1189.
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Pipelines began implementing the requirements of Order No. 636 in
1993, and restructured services now have been in effect for three
heating seasons. Significant changes have occurred in the natural gas
industry since the development of the record in the Order No. 636
proceeding, many of which are a direct result of restructuring. Thus,
the Commission's actions on remand necessarily will reflect the insight
gained from restructuring.
Since Order No. 636, substantial progress has been made toward
realizing the Commission's goal of opening up the pipeline grid to form
a national gas market for gas sellers and gas purchasers to meet in the
most efficient manner. Today, there are 38 operating market centers as
compared to only six when Order No. 636 issued.25 These market
centers provide a variety of services that increase the flexibility of
the system and facilitate connections between gas sellers and buyers.
These services commonly include wheeling, parking, loaning, and
storage.26 In addition, electronic trading of gas and capacity
rights, which did not exist at the time of Order No. 636, is now
offered at over 20 market centers and other transaction points
throughout North America. Electronic trading systems enable buyers and
sellers to discover the price and availability of gas at transaction
points, submit bids, complete legally binding transactions, and
prearrange capacity release transactions.
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\25\ Energy Info. Agency, DOE, No. DOE-EIA-0560(96), Natural Gas
Issues and Trends (Dec. 1996).
\26\ Wheeling, offered at 33 market centers, is the transfer of
gas from one interconnected pipeline to another. Parking, offered at
29 market centers, is when the market center holds the shipper's gas
for a short time for redelivery within approximately 15 days.
Loaning, offered at 20 market centers, is a short-term advance to a
shipper by the market center operator which is repaid in kind by the
shipper. Storage is offered at 16 market centers.
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In addition to the information provided by electronic trading
services, electronic information services offer capacity release and
tariff information
[[Page 10206]]
aggregated from pipeline electronic bulletin boards, gas futures
pricing information,27 weather information, and determination of
least cost routing. Such information was not widely available
electronically before Order No. 636.
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\27\ Since 1990, futures contracts have provided information
about expected prices each month for the next two years, and these
prices are reported daily.
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Capacity release is also playing an increasingly significant role
in permitting the reallocation of firm pipeline capacity to customers
most desiring it. For example, in October 1996, the Commission
estimates that released capacity held by replacement shippers accounted
for about 23 percent of firm transportation contract demand, for a
group of 30 pipelines for which capacity release data was
obtained.28 Capacity release permits shippers to release the
rights to transportation on the segments of a pipeline they do not
need, and to acquire firm rights in segments that connect to other
supply areas, on a temporary or permanent basis. Because of this
ability to obtain firm transportation access to supply regions
throughout the North American continent, shippers have less need to
renew contracts for firm capacity over the entire length of the
pipelines that have traditionally served them from supply basins in the
south and southwestern parts of the United States.29
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\28\ This estimate is derived from downloaded data posted on
pipelines' electronic bulletin boards as required by 18 CFR
Sec. 284.10(b).
\29\ For example, in Tennessee Gas Pipeline Co., Opinion No.
406, 76 FERC para. 61,022 at 61,127-29 (1996), customers argued they
should not be compelled to pay for or hold firm rights to capacity
in the production area when they only want capacity in the market
area. See also Transcontinental Gas Pipe Line Corp., Opinion No.
405, 76 FERC para. 61,021 at 61,061 (1996) (discussing the
significance of segmenting capacity).
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The construction and development of the pipeline grid that
continues today will increase this flexibility for shippers. In the
Eastern region of the United States, construction has been undertaken
to add pipeline capacity to meet peak day demand along traditional
pipeline paths,30 and to add paths to new supply regions.31
The interstate pipeline grid is undergoing significant expansion in
other regions also to access new supply basins, and to create new paths
from existing supply basins to additional markets.32 As new supply
basins and paths develop, issues associated with shippers'
relinquishment (``turn-back'') of capacity along older pipeline routes
from the traditional supply areas have arisen as firm contracts come up
for renewal. The Commission has addressed such capacity issues on
pipelines serving the Midwest 33 and Southern California,34
and on other pipelines serving traditional production areas.35 It
is possible that as other pipelines' long-term contracts expire,
additional capacity will become unsubscribed because shippers now have
more flexibility to choose different suppliers and pipeline routes than
they had prior to restructuring. The Commission and the industry have
sought creative ways to market excess capacity so that pipelines can
recover their costs.36
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\30\ For example, in Docket No. CP96-153-000, Southern Natural
Gas Co. has applied for authorization to expand its pipeline
facilities by 76,000 Mcf/day of capacity, primarily to serve
existing customers wishing to increase their firm contract
quantities. See Southern Natural Gas Co., 76 FERC para. 61,122
(1996). The Commission recently authorized CNG Transmission Corp. to
construct a pipeline loop between two points in Schenectady Co., New
York, to alleviate potential service interruptions to Niagara Mohawk
Power Corp.'s distribution system. CNG Transmission Corp., 74 FERC
61,073 (1996).
\31\ In Docket Nos. CP96-248-000 and CP96-249-000, Portland
Natural Gas Co. has proposed to construct a new 242-mile pipeline
extending from Troy, Vermont, to Haverhill, Massachussets. In Docket
Nos. CP96-178-000, CP96-809-000 and CP96-810-000, Maritimes &
Northeast Pipeline, LLC also propose to construct new pipeline
facilities in Northern New England.
\32\ For example, Northern Border Pipeline Company, in Docket
No. CP95-194-000 and Natural Gas Pipeline Company of America, in
Docket No. CP96-27-000, have proposed to construct new pipeline
facilities to bring Canadian gas to the Chicago area.
\33\ Natural Gas Pipeline Co. of America, 73 FERC para. 61,050
(1995).
\34\ El Paso Natural Gas Co., 72 FERC para. 61,083 (1995)
(rejecting El Paso's proposed ``exit fee'' to reallocate costs
associated with turned-back capacity); Transwestern Pipeline Co., 72
FERC para. 61,085 (1995) (approving a settlement including a
mechanism to share the costs and burdens associated with capacity
relinquishment).
\35\ Tennessee Gas Pipeline Co., 77 FERC para. 61,083 at 61,358
(1996) (permitting rate design changes in a contested settlement
based, in part, on Tennessee's concern that 70 percent of its firm
contracts would expire by the year 2000); Transcontinental Gas Pipe
Line Corp., Opinion No. 405-A, 77 FERC para. 61,270 (1996)
(deferring potential capacity turn-back issues until closer to the
expiration date of the contracts at issue).
\36\ 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, 74 FERC 61,076 (1996); NorAm Gas Transmission Co., 75
FERC para. 61,091 at 61,310 (1996).
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The Commission continues to refine its policies to reflect current
circumstances. The Commission is considering possible improvements in
the capacity release rules, so that pipeline capacity can be traded
more efficiently.37 The Commission has also adopted uniform
national business standards for interstate pipelines,38 and the
process of standardizing practices for interstate transportation is a
continuing effort.39 Because of all these changes in the industry,
the Commission's views on the issues remanded by the Court, of
necessity, are different from the Commission's views in 1992 when it
issued Order No. 636.
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\37\ Secondary Market Transactions on Interstate Natural Gas
Pipelines, 61 FR 41046 (1996), IV FERC Stats. & Regs. para. 32,520
(to be codified at 18 CFR part 284) (proposed July 31, 1996).
\38\ Standards for Business Practices of Interstate Natural Gas
Pipelines, Order No. 587, 61 FR 39053 (1996), III FERC Stats. &
Regs. para. 31,038 (1996) (to be codified at 18 CFR parts 161, 250,
and 284).
\39\ Standards for Business Practices of Interstate Natural Gas
Pipelines, 61 FR 58790 (1996), IV FERC Stats. & Regs. para. 32,521
(to be codified at 18 CFR part 284) (proposed Nov. 13, 1996).
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In summary, on remand the Commission has decided to modify its no-
notice policy, on a prospective basis, to the extent the prior policy
restricts entitlement to no-notice service to any particular group of
customers. Further, the Commission will reverse its selection of a
twenty-year matching term for the right of first refusal and instead
adopt a five-year matching term. The Commission will reaffirm its
decision to first require customer-by-customer mitigation of the
effects of SFV rate design. In addition, the Commission will reaffirm
its decision to establish the eligibility of customers of downstream
pipelines for the upstream pipeline's one-part small-customer rate on a
case-by-case basis. The Commission will reverse the requirement that
pipelines allocate ten percent of GSR costs to interruptible customers,
and instead will require pipelines to propose the percentage of their
GSR costs their interruptible customers must bear in light of the
individual circumstances present on each pipeline. Finally, the
Commission will reaffirm its decision to exempt pipelines from sharing
in GSR costs.
II. Eligibility Date for No-Notice Transportation
In Order No. 636, in connection with the conclusion that bundled,
city-gate, firm sales service was contrary to section 5 of the NGA, the
Commission required pipelines to provide a ``no-notice'' transportation
service. Under no-notice transportation service, firm shippers could
receive delivery of gas on demand up to their firm entitlements on a
daily basis, without incurring daily scheduling and balancing
penalties. The purpose of no-notice service was to enable firm shippers
to meet unexpected requirements such as sudden changes in temperature.
The Commission required that pipelines offer no-notice service only to
those
[[Page 10207]]
customers eligible for firm sales service at the time of restructuring.
The Court remanded for further explanation of this limitation on
the no-notice service requirement.40 Section 284.8(a)(4) of the
regulations, adopted by Order No. 636, requires pipelines ``that
provided a firm sales service on May 18, 1992 [the effective date of
Order No. 636]'' to offer the no-notice service.41 The eligibility
cut-off for no-notice service was established in Order No. 636-A, in
which the Commission held that pipelines were required to offer no-
notice transportation service ``only to customers that were entitled to
receive a no-notice firm, city gate, sales service on May 18, 1992.''
42 The Commission also strongly encouraged pipelines to make no-
notice service available to their other customers on a non-
discriminatory basis.
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\40\ UDC, 88 F.3d at 1137.
\41\ 18 CFR 284.8(a)(4).
\42\ Order No. 636-A, [Regs. Preambles Jan. 1991-June 1996] FERC
Stats. & Regs. at 30,573.
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On appeal, the Court addressed the issue of whether the Commission
should have required pipelines to offer no-notice transportation
service not only to customers who remained sales customers on May 18,
1992, but also to former bundled firm sales customers who had converted
to open access transportation before Order No. 636 (conversion
customers). The Court found the Commission had not adequately explained
why the conversion customers should not also have a right to receive
no-notice service. The Court held that the Commission's desire to begin
the experiment with no-notice service on a limited basis does not
explain or justify the disadvantaging of former sales customers who
converted before Order No. 636.43 The Court also held that, while
conversion customers had no right to expect to receive no-notice
service, neither did customers who were still receiving bundled sales
service on May 18, 1992.44 Finally, the Court held that the
Commission had not provided substantial evidence to support its
assumption that bundled sales customers relied more heavily on
reliability of transportation service than did conversion
customers.45 The Court accordingly remanded the issue of no-notice
transportation eligibility to the Commission for further
explanation.46
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\43\ UDC, 88 F.3d at 1137.
\44\ Id.
\45\ Id.
\46\ Id.
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At the time of Order No. 636, considerable uncertainty existed
whether pipelines would be able to perform no-notice service on a
widespread basis. Many pipelines had indicated in their comments that
they would not be able to provide no-notice transportation
service.47 However, at a technical conference held on January 22,
1992, pipelines made statements to the contrary. In Order No. 636, the
Commission relied upon those later assertions. Nevertheless, on
rehearing of Order No. 636, rehearing petitions from pipelines such as
Carnegie Natural Gas Company (Carnegie) and CNG Transmission
Corporation (CNG) indicated there was still some uncertainty among
pipelines whether they would be able to provide reliable no-notice
service.\48\ In addition, pipelines asked the Commission to limit no-
notice transportation service to existing sales customers at current
delivery points with the option to extend the service on a
nondiscriminatory basis where the pipeline had adequate capacity and
delivery capacity.\49\ The rehearing requests of bundled sales
customers also reflected a continuing concern that unbundled services
could not replicate the quality of the bundled sales services.\50\
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\47\ For example, the Interstate Natural Gas Association of
America (INGAA) took the position that the bundled, citygate firm
sales service was essential to the providing of no-notice and
instantaneous service. See also Initial Comments of Texas Eastern
Transmission Corp., Panhandle Eastern Pipe Line Co., Trunkline Gas
Co., and Algonquin Gas Transmission Company (PEC Pipeline Group) at
16-17.
\48\ For example, Carnegie and CNG asserted that before
unbundling, the pipeline's system manager could rely on storage,
system supply gas, linepack, and upstream pipeline deliveries. They
argued that unbundling would deprive the system manager of the use
of some or all of these resources and restrict the manager's ability
to operate the system in the most efficient, system-wide manner. CNG
Transmission Corp., Request for Rehearing at 32; Carnegie Natural
Gas Co., Request for Rehearing at 42-3.
\49\ INGAA, United Gas Pipe Line Co., ANR Pipeline Co., and
Colorado Interstate Gas Co.
\50\ The American Public Gas Association argued that firm sales
service could not be replicated without assured access to firm
storage service. Request for Rehearing at 12-20, citing initial
comments of the Distributors Advocating Regulatory Reform at 74.
Similarly, Citizens Gas & Coke Utility complained that Order No. 636
did not discuss no-notice gas supplies, storage capacity allocation,
or the use of flexible receipt points for meeting the needs of high
priority customers. Request for Rehearing at 2-3.
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In light of such uncertainty, the Commission decided to limit the
requirement for pipelines to offer no-notice service to include only
those customers who were then bundled sales customers. It appeared to
the Commission that bundled sales customers relied more heavily on the
reliability of the transportation service embedded within the sales
service they were receiving than the conversion customers relied on the
reliability of their transportation service. This is because no-notice
service was an implicit part of bundled sales, but was not a part of
unbundled transportation. During the period between Order Nos. 436 and
636, sales customers generally converted to transportation only to the
extent that they did not need the higher quality of the transportation
service embedded within bundled sales service.51 In many cases,
sales customers converted some, but not all, of their sales contract
demand. These customers relied on their retained pipeline sales service
to obtain gas during peak periods since sales service was equivalent to
a no-notice service. Customers used their converted transportation
service as a base load service to obtain cheaper gas from non-pipeline
suppliers throughout the year.52 The comments filed in the record
of Order No. 636 also indicated that non-converted, or partially-
converted customers placed more reliance on the reliability of the
transportation service embedded within the bundled sales
service.53
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\51\ Order No. 636, [Regs. Preambles Jan. 1991-June 1996] FERC
Stats. & Regs. at 30,402.
\52\ For example, Order No. 636 found that in 1991, 60 percent
of peak day capacity on the major pipelines that made bundled sales
was still reserved for pipeline sales service. Order No. 636 also
found: While pipeline sales were less than 20 percent of total
throughput on the major pipelines, during the three day period of
peak usage, pipeline sales were approximately 50 percent of total
deliveries. The seasonal nature of the pipeline sales indicates that
customers rely on pipeline sales during periods when capacity is
most likely to be constrained. Order No. 636, [Reg. Preambles Jan.
1991-June 1996] FERC Stats. & Regs. at 30,400.
\53\ Id. at 30,403 n.68 (quoting reply comments of United
Distribution Companies at 7: ``The remaining pipeline sales service
is largely used to provide swing service during the winter months
and therefore cannot be converted absent comparable
transportation.'').
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The post-restructuring experience with no-notice service has been
quite varied, but the early concerns about the ability of pipelines to
provide reliable no-notice service were not realized. Some pipelines
had no bundled sales customers when Order No. 636 took effect, and thus
were not required to offer no-notice service as part of their
restructuring and did not do so. In the one restructuring proceeding
54 where customers who had converted to transportation before
Order No. 636 indicated a desire for no-notice service, the pipeline
offered them the service, but they ultimately refused it because they
found it too expensive.
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\54\ Questar Pipeline Co., 64 FERC para. 61,157 (1993).
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Some pipelines have, post-restructuring, expanded their offering of
no-notice service. While Williams Natural Gas Company (Williams)
[[Page 10208]]
originally refused a group of conversion customers' requests for no-
notice service,55 a number of the conversion customers eventually
obtained no-notice service under new contracts with the
pipeline.56 More recently, Mid Louisiana Gas Company (Mid
Louisiana) faced the loss of its no-notice customers to a lower-priced
competing intrastate bundled service. In an effort to retain the
customers, Mid Louisiana proposed to reconfigure its no-notice service
to reduce costs and make its no-notice service a more attractive
option.57 Mid Louisiana also expanded its offering of no-notice
service to all firm transportation customers, not just those former
sales customers previously eligible for no-notice service.
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\55\ Williams Natural Gas Co., 65 FERC para. 61,221 (1993),
reh'g denied, FERC para. 61,315 (1994).
\56\ Williams Natural Gas Co., 77 FERC para. 61,277 (1996).
\57\ Mid Louisiana Gas Co., 76 FERC para. 61,212 (1996).
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According to data published by the Interstate Natural Gas
Association of America, no-notice service represented 17 percent of
total pipeline throughput in 1995, an increase from 15 percent the
previous year.58 This increase in the volume of no-notice service
provided is consistent with the pattern the Commission has observed in
the industry. Some pipelines, such as Mid Louisiana, Questar, and
Williams, have been providing no-notice service beyond the minimum
requirements directed by the Commission in Order No. 636-A.
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\58\ Foster Natural Gas Report, No. 2098 (Sept. 9, 1996).
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The Commission cannot retroactively change Order No. 636's
limitation on the pipeline's requirement to offer no-notice service
since it is impossible to change past service. However, given the
varied experience with no-notice service since restructuring, and in
light of the Court's remand, the Commission will no longer continue to
limit the pipeline's no-notice service obligation to the pipeline's
bundled sales customers at the time of restructuring.
The Commission intends no other changes to the pipeline's
obligation to provide no-notice service as provided in section 284.8(4)
of the Commission's regulations. If a pipeline offers no-notice
service, the Commission will require it to offer that service on a non-
discriminatory basis to all customers who request it, under the
nondiscriminatory access provision in Sec. 284.8(b)(1).59 The
Commission is aware that since all pipelines were not required during
restructuring to offer no-notice service, some pipelines may not have
the facilities and the capacity available to do so. The Commission's
open-access policy has always been that interstate pipelines must offer
open-access transportation to all shippers on a nondiscriminatory
basis, to the extent capacity is available.60 The
nondiscriminatory access condition does not obligate pipelines to
expand their capacity or acquire additional facilities to provide
service. Thus, a pipeline offering no-notice transportation service
must do so only to the extent the pipeline has capacity available
(including the storage capacity that may be needed to perform no-notice
service).
---------------------------------------------------------------------------
\59\ 18 CFR 284.8(b)(1).
\60\ Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, Order No. 436, [Regs. Preambles 1982-1985] FERC Stats. &
Regs. para. 30,665 at 31,516-17 (1985).
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The Commission believes that a prospective change in policy based
on current circumstances will satisfy the needs of all shippers who
desire no-notice service. This approach is consistent with the fact
that some pipelines, such as Mid Louisiana, Williams, and Questar, have
already shown a willingness to expand their no-notice service beyond
the Commission's basic requirement. However, to the extent there are
shippers who desire no-notice service and cannot obtain it for any
reason, such cases are appropriately resolved on an individual basis,
rather than in a generic rulemaking proceeding.
III. The Twenty-Year Contract Term
Order No. 636 authorized pregranted abandonment of long-term firm
transportation contracts, subject to a right of first refusal for the
existing shipper. Under the right of first refusal, the existing
shipper can retain service by matching the rate and the term of service
in a competing bid. The rate is capped by the pipeline's maximum tariff
rate, and the Commission capped the term of service at twenty years.
The twenty-year term-matching cap was not set forth in the Order No.
636 regulations themselves, but was explained in the preamble and is
part of each pipeline's tariff. In Order No. 636, the Commission
indicated that pipelines and customers could agree to a different
cap.61 As part of the restructuring obligations, pipelines were
required to include in their tariffs the rules and procedures for
exercising the right of first refusal, including the matching term cap
to apply on that pipeline.
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\61\ In the restructuring proceedings of Alabama-Tennessee
Natural Gas Co., Mississippi River Transmission Corp., Northern
Natural Gas Co., and Trunkline Gas Co., as a consequence, the
pipeline and its customers agreed to 10-year caps.
---------------------------------------------------------------------------
The Court found that the basic right of first refusal structure
protects against pipeline market power,62 and the Court approved
the concept of a contract term-matching limitation ``as a rational
means of emulating a competitive market for allocating firm
transportation capacity.'' 63 The Court, nevertheless, judged
inadequate the Commission's explanations for selecting twenty years as
an outer limit for an existing customer to bid before securing the
continuation of its rights under an expiring contract.64 Based
upon the arguments of LDCs, the Court found inadequate the Commission's
explanation that the twenty-year term balances between preventing
market constraint and encouraging market stability. The Court concluded
that the Commission failed to explain why the twenty-year cap
``adequately protects against pipelines' preexisting market power,
which they enjoy by virtue of natural-monopoly conditions;'' 65
and why the ``twenty-year cap will prevent bidders on capacity-
constrained pipelines from using long contract duration as a price
surrogate to bid beyond the maximum approved rate, to the detriment of
captive customers.'' 66
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\62 \UDC, 88 F.3d at 1140.
\63\ Id.
\64\ Id. at 1140-41.
\65\ Id. at 1140.
\66\ The Court dismissed other arguments against the twenty-year
term. In response to the claim that a contract term-matching
requirement disadvantaged industrial customers because of the
possible short useful life of a particular productive asset, the
Court noted the industrial customers' ready access to alternative
fuels, and greater access than consumers served by LDCs. UDC, 88
F.3d at 1140. The Court also rejected the contention that the
twenty-year cap discriminated against industrial customers in light
of their shorter-term natural gas needs than other customers. The
Court found that although the cap may affect different classes of
customers differently, since all parties have an equal opportunity
to bid for capacity, the cap did not violate NGA section 5. Id. at
1141 and n.47.
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Further, the Court found that the Commission's reliance on the fact
that twenty-year contracts have been traditional in cases involving new
construction did not sufficiently explain the selection of a twenty-
year term for renewal contracts on existing facilities.67
Accordingly, while the Court held that the Commission had justified the
right-of-first-refusal mechanism, with its twin matching conditions of
rate and contract term, it remanded the twenty-year term cap for
further consideration.68
---------------------------------------------------------------------------
\67\ Id. at 1141.
\68\ Id.
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The right-of-first-refusal mechanism was, and is, intended to
protect existing
[[Page 10209]]
customers and provide them with the right of continued service, while
at the same time recognizing the role of market forces in determining
contract price and term. As the Commission held in Order No. 636-A,
when a contract has expired, it is most efficient, within regulatory
restraints, for the capacity to go to the bidder who values it the
most, as evidenced by its willingness to bid the highest price for the
longest term.69 The pipeline's maximum tariff rate is one
regulatory restraint, as the bidding for price cannot go above that
rate. The Commission set a cap on term-matching in order to avoid
shippers on constrained pipelines being forced into contracts with
pipelines for longer terms than they desired.
---------------------------------------------------------------------------
\69\ Order No. 636-A, [Regs. Preambles Jan. 1991-June 1996] FERC
Stats. & Regs. at 30,630.
---------------------------------------------------------------------------
The term-matching cap is relevant mainly on capacity constrained
pipelines. However, term-matching also could become necessary in
situations where the contract path goes through constrained points. As
the Court recognized, where capacity is not constrained, there is no
need for an existing customer to match a competing bid, since the
pipeline will have sufficient capacity to serve both the existing
customer and any new customer that desires service.70 While the
Court approved the concept of a contract term-matching limitation, it
found the basis for the particular cap chosen lacking.71
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\70\ UDC, 88 F.3d at 1140.
\71\ Id.
---------------------------------------------------------------------------
In determining the maximum term that an existing customer should be
required to match in order to retain its capacity after its current
contract expires, the Commission must weigh several factors. On the one
hand, the cap should protect captive customers from having to match
competing bids that offer longer terms than the competing bidder would
have bid ``in a competitive market without pipelines' natural
monopoly.'' 72 On the other hand, the Commission does not wish to
constrain unnecessarily the ability of shippers who value the capacity
the most to obtain it for terms of the desired length. The Court has
recognized that the Commission's task in setting the term-matching cap
involves the selection of a ``necessarily somewhat arbitrary figure.''
73
---------------------------------------------------------------------------
\72\ Id.
\73\ Id. at 1141 n.44.
---------------------------------------------------------------------------
The Commission has reexamined the record of the Order No. 636
proceedings, as well as data concerning contract terms that have become
available since industry restructuring. The Commission can find no
additional record evidence, not previously cited to the Court, that
would support a cap as long as the twenty-year cap chosen in Order No.
636. Due to changes in the Commission's filing requirements instituted
after restructuring,74 pipelines now must file, in an electronic
format, an index of customers, which is updated quarterly and includes
the contract term.75 The data that are now on file have enabled
the Commission to determine average contract terms, both before and
since the issuance of Order No. 636. For pre-Order No. 636 long-term
contracts, the average term was approximately 15 years.76 The data
show that since Order No. 636, pipelines have entered into
substantially shorter contracts than before. Post-Order No. 636 long-
term contracts had an average term of 9.2 years for transportation, and
9.7 years for storage. For all currently effective contracts (both pre-
and post-Order No. 636), the average term is 10.3 years for
transportation and 10 years for storage. Moreover, as shown in Appendix
A, the trend toward shorter contracts is continuing. About one quarter
to one third of contracts with a term of one year or greater, entered
into since Order No. 636, have had terms of one to five years.77
However, nearly one half of such contracts entered into since January
1, 1995, have had terms of one to five years.78
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\74\ Revisions to Uniform System of Accounts, Forms, Statements,
and Reporting Requirements for Natural Gas Cos., Order No. 581,
[Regs. Preambles Jan. 1991-June 1996] FERC Stats. & Regs. para.
31,026 (1995), reh'g, Order No. 581-A, [Regs. Preambles Jan. 1,
1991-June 1996] FERC Stats. & Regs. para. 31,032 (1996).
\75\ 18 CFR 284.106(c).
\76\ Using the October 1, 1996 Index of Customers filings, the
Commission calculated the average lengths of long-term contracts
(contracts with terms of more than one year) entered into before the
April 8, 1992 issuance of Order No. 636, versus those entered into
after that date. For pre-Order No. 636 contracts, the average
contract term for transportation was 14.8 years, and for storage,
the average term was 14.6 years.
\77\ Appendix A, p. 1.
\78\ Appendix A, p. 2.
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This information strongly suggests that since the issuance of Order
No. 636, few, if any, pipeline customers have been willing, or
required, to commit to twenty-year contracts for existing capacity. In
the only case to come before the Commission to resolve a controversy
about the pipeline's right-of-first-refusal process, the customers were
required to commit to five-year terms in order to retain the
capacity.79 The industry trend thus appears to be contract terms
that are much shorter than twenty years.
---------------------------------------------------------------------------
\79\ Williams Natural Gas Co., 69 FERC para. 61,166 (1994),
reh'g, 70 FERC para. 61,100 (1995), reh'g, 70 FERC para. 61,377
(1995), appeal pending sub nom. City of Chanute v. FERC, No. 95-1189
(D.C. Cir.).
---------------------------------------------------------------------------
On remand, the Commission intends to select a cap to be generally
applicable to all pipelines. However, the current data lead us to
conclude that the term must be significantly shorter than the twenty-
year cap approved in Order No. 636. In addition, the Commission
recognizes that the selection of a different cap on remand must be
supported by the record. In the Order No. 636 rulemaking, as the Court
pointed out, ``most of the commentators before the agency had proposed
much shorter-term caps, such as five years.'' 80 For example,
Associated Gas Distributors (AGD) argued on rehearing of Order No. 636-
A that a five-year cap would provide ``the most equitable balance
between the LDC's needs to retain some flexibility in its gas supply
portfolio and the pipeline's concern for financial stability.'' 81
Public Service Electric & Gas Company and New Jersey Natural Gas
Company argued that a five-year cap would avoid unnecessary retention
of capacity by LDCs, which, given their general public utility
obligation to serve, ``will err on the side of retaining capacity they
might not need, rather than risking permanent loss of such capacity.''
82 A number of other parties also argued in favor of a five-year
matching term.83 In addition, five years is approximately the
median length of long term contracts entered into since January 1,
1995.
---------------------------------------------------------------------------
\80\ UDC, 88 F.3d at 1141.
\81\ Sept. 2, 1992 Request for Rehearing and Clarification at
13.
\82\ Sept. 2, 1992 Request for Rehearing at 6.
\83\ E.g., Northern States Power Co. (Minnesota) and Northern
States Power Co. (Wisconsin), Sept. 1, 1992 Request for Rehearing at
4-6; New Jersey Board of Regulatory Commissioners, Sept. 2, 1992
Request for Rehearing at 2; New Jersey Natural Gas Co., May 8, 1992
Request for Rehearing at 6; UGI Utilities, Inc., Sept. 2, 1992
Request for Rehearing at 27; the Industrial Groups, Sept. 2, 1992
Request for Rehearing at 18.
---------------------------------------------------------------------------
Based upon the record developed in the Order No. 636 proceeding,
and the information available in the Commission's files, the Commission
establishes the contract matching term cap at five years. The five-year
cap will avoid customers' being locked into long-term arrangements with
pipelines that they do not really want, and will therefore be
responsive to the Court's concerns. The five-year cap also has the
advantage of being consistent with the current industry trend of short-
term contracts, as indicated by the Commission's newly-available
data.84
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\84\ The American Gas Association (AGA), INGAA, and UDC have
filed pleadings proposing different courses of action regarding the
contract matching term. AGA urges the Commission either to eliminate
the cap or to select a cap of no more than three years. However, AGA
does not provide any basis for its argument that three years, as
opposed to any other term shorter than twenty years, is the
appropriate cap for the Commission to adopt. UDC supports AGA's
proposal and argues that the majority of ``long-term'' contracts now
and in the foreseeable future will average four years or less. INGAA
argues that the right-of-first refusal requirement should only
attach to contracts with terms of at least ten years or longer, and
that the Commission should reduce the matching term to ten years.
INGAA submits that this would correspond to the length of contract
commonly required for new construction, as well as to the needs of
the market.
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[[Page 10210]]
The Commission will require all pipelines whose current tariffs
contain term caps longer than five years to revise their tariffs
consistent with the new maximum cap, regardless of whether this issue
is preserved in the individual restructuring proceedings. The
Commission will consider on a case-by-case basis whether any relief is
necessary in connection with contracts renewed since Order No. 636. The
Commission will entertain on a case-by-case basis requests to shorten a
contract term if a customer renewed a contract under the right-of-
first-refusal process since Order No. 636 and can show that it agreed
to a longer term renewal contract than it otherwise would have because
of the twenty-year cap.
IV. Customer-by-Customer v. Customer-Class Mitigation
In order to mitigate the cost-shifting effects of SFV rate design,
the Commission required pipelines to phase in SFV rates for some
customer classes over a four-year period. However, the Commission
required pipelines to first seek to avoid significant cost shifts to
individual customers (rather than customer classes) by using
alternative ratemaking techniques such as seasonal contract demand.
The Court found that the Commission had not adequately explained
its preference for customer-by-customer mitigation over customer-class
mitigation.85 The Court was especially concerned by the argument
that the ``establishment of rates on a customer-by-customer basis
increases the risks that a pipeline will fail to collect its total
costs during the period in which rates are in effect.'' 86 This
issue was remanded for the Commission to further examine the question
of whether the initial mitigation measures should be implemented on the
basis of customer class.87
---------------------------------------------------------------------------
\85\ UDC, 88 F.3d at 1174.
\86\ Id. (quoting Pipelines' Brief at 27).
\87\ Id.
---------------------------------------------------------------------------
This issue arises because, under MFV, half of the fixed costs in
the reservation charge were allocated among customers on the basis of
peak demand (the ``D-1'' charge), and the other half were allocated on
the basis of annual usage (the ``D-2'' charge). Under the SFV method,
however, a pipeline's fixed costs are allocated among customers based
on contract entitlement alone. As the Court recognized, the adoption of
SFV would shift costs to low load-factor customers, in part by
``measuring usage solely based on peak demand, rather than annual
usage.'' 88 The Commission, while finding that the impact of
placing all of a pipeline's fixed costs in the reservation charge would
facilitate an efficient transportation market and support a competitive
gas commodity market, found it appropriate to minimize significant
cost-shifting to ``maintain the status quo with respect to the relative
distribution of revenue responsibility.'' 89 In explaining how to
minimize cost shifts, the Commission held in Order No. 636-B that a
``significant cost shift'' test was to be applied to each
customer.90 The Commission further explained that its goal was to
maintain the status quo and not to provide the opportunity for some
customers ``to make themselves better off at the expense of other
customers.'' 91 Instead, the Commission intended each individual
customer's revenue responsibility to stay substantially the same.
---------------------------------------------------------------------------
\88\ Id. at 1170.
\89\ Order No. 636-B, 61 FERC at 62,014.
\90\ Id. at 62,016.
\91\ Id.
---------------------------------------------------------------------------
The purpose of mitigation was, in a sense, to replicate the role
the D-2 component played under MFV rate design. Under MFV rate design,
the D-2s operated in essence on a customer-by-customer basis, since
each customer got a different D-2 based on its annual usage. The result
was a lower allocation to low load factor customers within a class than
high load factor customers in the same class. This effect of D-2s was
thus customer-specific.
Pipelines tend to have relatively few customer classes, but those
classes have many members. As a result, customers within a single class
have widely varying load factors and other characteristics. Therefore,
the implementation of SFV, together with the elimination of the D-2
component in MFV rate design, caused substantial cost shifts among
customers within particular customer classes. Mitigation by class does
nothing to minimize those cost shifts. In the proceedings to implement
each pipeline's restructuring, it became clear that the customer-by-
customer approach was preferable because mitigation could be structured
in accordance with the individual circumstances and needs of each
customer. Thus, while Order No. 636 provided for mitigation on the
basis of customer class as well as on a customer-by-customer basis, in
fact, in the individual proceedings, the customer class approach was
never used.
Another reason the Commission preferred customer-by-customer
mitigation was that the risks to the pipeline, that it would
underrecover its cost of service, could be examined and minimized on a
case-by-case basis in the individual restructuring proceedings. As a
general matter, the customer-by-customer mitigation was carried out by
using seasonal contract demands. 92 That method, as implemented by
the Commission, did not make it more likely that the pipeline would
fail to recover its revenue requirement.93 It simply uses seasonal
measures to reallocate costs in order to avoid significant shifts in
revenue responsibility.
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\92\ Northwest Pipeline Corp., 63 FERC para. 61,130 (1993),
order on reh'g 65 FERC para. 61,055 (1994); Mississippi River
Transmission Corp., 64 FERC para. 61,299 (1993).
\93\ The use of seasonal contract demands enables firm customers
to lower their daily reservation quantities for the off peak season
and keep the higher quantity needed for the peak season.
---------------------------------------------------------------------------
Since the Commission directed, in Order No. 636-B, that each
customer's revenue responsibility could not change significantly with
the use of SFV, the rates would provide for the same revenue stream
pre- and post-SFV. In the case of only one pipeline--Williston Basin
Pipeline Company--has there been any problem of the pipeline not
recovering its costs, and that grew out of the unusual circumstances
that developed after restructuring.94 That matter is now at issue
in the pipeline's pending rate case, which is in hearing
[[Page 10211]]
before an administrative law judge, and the issue will be addressed in
that proceeding. In all other cases, the pipelines' concerns about cost
recovery never materialized. Therefore, it appears that this issue has
no continuing vitality today. As a result, we see no need to effect
changes to the previous ruling. The issues presented in Williston's
case can be addressed on a case-specific basis.
---------------------------------------------------------------------------
\94\ In Williston's restructuring proceeding, the Commission
accepted Williston's proposal to allow the one customer on its
system requiring mitigation (Wyoming Gas) to shift to Williston's
one-part rate schedule for small customers. As a consequence,
Wyoming Gas pays Williston only when it transports gas, including
paying any GSR costs. Williston Basin Interstate Pipeline Co., 63
FERC para. 61,184 (1993). In May 1995, Wyoming Gas built a 15-mile
extension and connected its facilities with Colorado Interstate Gas
System, allowing it to bypass Williston. As a result, Wyoming Gas
has reduced its takes from Williston by 35 percent. Williston
recently asked the Commission to allow it to convert its existing
one-part rate to a two-part rate, with a reservation charge, for
Wyoming Gas. Williston has proposed an alternative method of
mitigating the cost shift to Wyoming Gas. Williston's proposal, in
Docket No. RP95-364, went into effect January 1, 1996, and is in
hearing as part of Williston's general rate case. Williston Basin
Pipeline Co., 73 FERC para. 61,344 (1995), order on reh'g, 74 FERC
para. 61,144 (1996); Order on Motion Rates and Request for Stay, 74
FERC para. 61,081 (1996).
---------------------------------------------------------------------------
V. Small-Customer Rates for Customers of Downstream Pipelines
In Order No. 636, the Commission assured small customers that they
could continue to receive firm transportation under a one-part
volumetric rate computed at an imputed load factor, similar to the
manner in which their previous sales rates were determined. The
Commission thus required pipelines to offer a one-part small-customer
transportation rate to those customers that were eligible for a small-
customer sales rate on the effective date of restructuring.95 On
rehearing of Order No. 636-A, the issue arose whether the Commission
should require upstream pipelines to offer their small-customer rate to
the small customers of downstream pipelines, who became direct
customers of the upstream pipeline as a result of unbundling. The
Commission held in Order No. 636-B that this issue should be raised in
the upstream pipeline's restructuring proceeding, to ``enable the
parties to consider the small customers' need for such a service on the
upstream pipeline and the impact of the additional small customers on
the rates charged to the upstream pipeline's current customers under
the small customer schedule and its customers paying a two-part rate.''
96
---------------------------------------------------------------------------
\95\ Section 284.14(b)(3)(iv) of the regulations adopted by
Order No. 636 required pipelines to include in their restructuring
compliance filings tariff provisions offering one-part small-
customer rates for transportation, to the class of customers
eligible for that pipeline's small-customer sales rate on May 18,
1992. Section 284.14 contained provisions governing the
implementation of pipeline restructuring and setting forth the
contents of pipeline compliance filings. In Order No. 581, the
Commission deleted Section 284.14 from the regulations because the
regulation was no longer necessary following the completion of
restructuring. Revisions to the Uniform System of Accounts, Forms,
Statements, and Reporting Requirements for Natural Gas Cos., Order
No. 581, 60 FR 53019 (October 11, 1995), II FERC Stats. & Regs.
para. 20,000 et seq. (regulatory text), III FERC Stats. & Regs para.
31,026 (1995) (preamble).
\96\ Order No. 636-B, 61 FERC at 62,020.
---------------------------------------------------------------------------
The Court found that the Commission made an arbitrary distinction
between former indirect small customers of an upstream pipeline and
small customers who were direct customers of the upstream
pipeline.97 Despite the Commission's indication in Order No. 636-B
that the Commission would consider the need for such discounts on a
case-by-case basis, the Court agreed with appellants' contention, that
it is ``unfair and unreasonable to make them demonstrate * * * a need
[for a small customer rate] in restructuring proceedings when that need
has already been presumed for other small customers.''98 Thus, the
Court remanded the issue to the Commission for further consideration of
``whether or not the small customer benefits should be made available
to the former downstream small customers.'' 99
---------------------------------------------------------------------------
\97\ UDC, 88 F.3d at 1174-75.
\98\ Id. at 1174.
\99\ Id. at 1175.
---------------------------------------------------------------------------
The Commission's ruling, that the issue would be considered on a
pipeline-by-pipeline basis, rather than in a generic rulemaking, did
not represent an unwillingness by the Commission to fully consider the
needs of the former downstream small customers. One of the objectives
of Order No. 636's requirement that pipelines offer a subsidized, one-
part transportation rate to their former small sales customers was to
maintain a status quo for that class of customers, subject to a few
changes in terms and conditions adopted in the Rule.100
---------------------------------------------------------------------------
\100\ Order No. 636-B, 61 FERC at 62,019.
---------------------------------------------------------------------------
Any changes in the size of the subsidized, small customer class on
a pipeline necessarily affect the pipeline's other customers. Under
traditional cost-based ratemaking, rates are generally designed to
recover the pipeline's annual revenue requirement.101 Costs are
allocated to customer classes based on contract capacity entitlements
and projected annual or seasonal volumes. Small customer rates,
however, involve an adjusted cost allocation to permit them to pay less
for their service than they would if their rates were designed based on
actual purchase levels. Small customers have historically been charged
rates derived from a higher-than-actual, imputed load factor because
these customers often ``lack the flexibility to construct storage and
lack industrial load to balance their purchases,'' 102 and because
they serve the distinct function of delivering gas primarily to
residential and light commercial users.103 During the
restructuring process, the Commission intended for pipelines to retain
the same imputed load factor for the small customer transportation rate
that had previously been used to compute the small customer sales
rate.104
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\101\ The Commission's traditional cost-based ratemaking is a
five-step process. The first task is to determine the pipeline's
overall cost of service. The second task is to functionalize the
pipeline's costs by determining to which of the pipeline's
operations or facilities the costs belong. The third task is to
categorize the costs assigned to each function as fixed costs (which
do not vary with the volume of gas transported) or variable, and to
classify those costs to the reservation and usage charges of the
pipeline's rates. The fourth step is to allocate the costs
classified to the reservation and usage charges among the pipeline's
various rate zones and among the pipeline's various classes of
jurisdictional services. The fifth step is to design each service's
rates for billing purposes by computing unit rates for each service.
The fifth step is called rate design. See Order No. 636, [Regs.
Preambles Jan. 1991-June 1996] FERC Stats. & Regs. at 30,431.
\102\ Texas Eastern Transmission Corp., 30 FERC para. 61,144 at
61,288 (1985).
\103\ Tennessee Gas Pipeline Co., 27 FERC para. 63,090 at 65,375
(1984).
\104\ Order No. 636-B, 61 FERC at 62,019.
---------------------------------------------------------------------------
Since a one-part, small-customer rate is a subsidized rate,
eligibility criteria for the small-customer class and the size of that
class is always a contentious issue in a pipeline rate case. Before
restructuring, pipelines and their customers usually arrived at the
small-customer eligibility cutoff through negotiations. The class size
and eligibility criteria therefore differ on each pipeline. Changes to
the eligibility criteria for the small customer rate, particularly
those that enlarge the size of the class, upset the prior cost
allocation among the customer classes. Those customers who are not in
the small customer class experience a cost shift because they must pick
up a greater share of the pipeline's costs. The determination of class
size and eligibility requires consideration of the customer profile of
each pipeline and the individual circumstances present on each system,
and ultimately is the result of pragmatic adjustments.105
---------------------------------------------------------------------------
\105\ See FPC v. Natural Gas Pipeline Co. of America, 315 U.S.
575, 586 (1941) (holding that rate-making bodies are ``free, within
the ambit of their statutory authority, to make the pragmatic
adjustments which may be called for by particular circumstances.'')
See also Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589
(1945) (``Allocation of costs is not a matter for the slide-rule. It
involves judgment on a myriad of facts. It is not an exact
science.'').
---------------------------------------------------------------------------
Before Order No. 636, the pipelines had a relatively stable group
of customers. Order No. 636, however, greatly expanded the number of
customers a pipeline would serve, and the cost-shifting effects of a
significant expansion of the class of customers eligible for the rate
were not known. Circumstances vary widely throughout the pipeline
industry. For example, the upstream-most pipelines serving production
areas, such as Texas and the Gulf of Mexico, may serve ten or more
downstream pipelines. Therefore, allowing all the small customers of
all those downstream pipelines automatically to qualify for small
[[Page 10212]]
customer status on the upstream pipeline could shift substantial costs
to the relatively few existing non-pipeline direct customers of the
upstream pipeline. The Commission could not, through a generic ruling,
be certain this would not happen.
The circumstances of Tennessee Gas Pipeline Company (Tennessee) and
its three downstream pipelines illustrate some of the factors to be
taken into account with respect to the issues of small customer class
size and eligibility.106 During restructuring, small customers of
three pipelines downstream from Tennessee (East Tennessee, Alabama-
Tennessee, and Midwestern) became direct customers of Tennessee, as
well as the downstream pipelines. Tennessee originally proposed to
offer a one-part rate only to its direct small customers and those
customers of downstream pipelines that took service directly from
Tennessee prior to restructuring. Tennessee proposed to continue using
its pre-existing eligibility cutoff of 10,000 Dth/day for the one-part
rate. Tennessee added a different, two-part rate schedule for its
former small sales customers and to other small customers of downstream
pipelines. Tennessee requested an eligibility cutoff of 5,300 Dth/day
for the two-part rate schedule because it was the highest criterion
used in the tariffs of Tennessee's downstream pipelines.107
---------------------------------------------------------------------------
\106\ Customers of Tennessee's downstream pipelines include East
Tennessee Customer Group and Tennessee Valley, the petitioners on
this issue in UDC.
\107\ East Tennessee used a volumetric maximum of 4,046 Dth/d;
Midwestern Gas Co. used 5,233 Dth/d; and Alabama-Tennessee Natural
Gas Co. used 2,564 Dth/d. East Tennessee Natural Gas Co., 63 FERC
para. 61,102 (1993); Midwestern Gas Transmission Co., 63 FERC para.
61,099 (1993); and Alabama-Tennessee Natural Gas Co., 63 FERC para.
61,054 (1993).
---------------------------------------------------------------------------
The Commission found that the lack of a one-part rate for small
former sales customers on Tennessee's downstream pipelines would lead
to inequitable results. The Commission thus required Tennessee to offer
the one-part rate to those downstream customers otherwise eligible for
small customer rates on the downstream pipelines, and held that the
eligible level would be set at 5,300 Dth/day or less. The Commission
analyzed the cost shifting effect of enlarging the small-customer class
and found that the particular increase to the eligible class under
consideration would affect only a small percentage of Tennessee's daily
transportation contract demand.108 A generic determination
concerning the class of eligible customers simply would not have
permitted the Commission to fully consider the needs of the small
customers and the impact of expanding class size and eligibility on the
other customers. Therefore, based on further consideration, the
Commission reaffirms its decision to determine, on a case-by-case
basis, the eligibility of customers of downstream pipelines for the
upstream pipeline's small-customer rate.
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\108\ Tennessee Gas Pipeline Co., 65 FERC para. 61,224 at 62,064
(1993), appeal pending sub nom. East Tennessee Group v. FERC, (D.C.
Cir. No. 93-1837 filed Aug. 20, 1993).
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VI. Pipelines' Exemption From GSR Costs
A. Summary of Commission Conclusion on Remand
In UDC, the Court remanded to the Commission the issue of the
pipelines' recovery of prudently incurred GSR costs. While the Court
did not question the basic principle that recovery of such costs is
appropriate, it did take issue with the Commission's decision to
provide pipelines the opportunity to recover their prudently incurred
costs in a manner that differed from the approach taken by the
Commission in the Order Nos. 500/528 series (hereinafter Order Nos.
500/528).
Observing that the petitioners challenging the Order No. 636
recovery mechanism noted ``remarkable similarities'' between Order Nos.
436 and 636, the Court stated that it ``[i]nitially, agreed with
petitioners that the Commission's stated rationale for allocating take-
or-pay costs to pipelines substantially applied in the context of GSR
costs as well.'' 109 The Court found that ``Order No. 636 is based
on principles of cost spreading and value of service that are, in turn,
premised on the notion that all aspects of the natural gas industry
must contribute to the transition to an unbundled marketplace.''
110 Accordingly, the Court remanded the matter to the Commission
for further consideration. In so doing, the Court expressly ``did not
conclude that the Commission necessarily was required to assign the
pipelines responsibility for some portion of their GSR costs,''
111 but rather that the Commission's stated reasons did not rise
to the level of reasoned decisionmaking.
---------------------------------------------------------------------------
\109\ 88 F.3d at 1188.
\110\ Id. at 1190.
\111\ Id. at 1188 (emphasis in original).
---------------------------------------------------------------------------
The Commission readily acknowledges that there are noteworthy
similarities between the take-or-pay problems underlying Order No. 436
and the Order Nos. 500/528 series and the GSR recovery issues addressed
by the Commission in Order No. 636. Those similarities include, as the
Court observed, the fact that the GSR costs to be recovered as
transition costs in Order No. 636 arise from the same provisions in
producer-pipeline contracts that gave rise to the take or pay problem
addressed in Order Nos. 500/528. Another equally important similarity
is that in both Order Nos. 500/528 and in Order No. 636, the Commission
was attempting to fashion a mechanism to provide pipelines a means for
recovering prudently incurred gas supply costs.
There are, however, compelling differences as well. In Order Nos.
500/528 the Commission was attempting to deal with the cost
consequences of a failure in gas markets, resulting in a major
suppression of demand for gas, coupled with mandated monthly increases
in the wellhead ceiling prices for gas. This market failure had its
origins in events that preceded the Commission's open access
initiatives in Order No. 436 and persisted for a number of years
thereafter.112 A number of factors contributed to the
extraordinary circumstance in which pipelines were continuing to incur
huge contractual liabilities that could not be, and were not being,
recovered in rates. As discussed below, Order No. 380 contributed
significantly to the problem by prohibiting the pipelines from
including commodity costs in their minimum bills. Order No. 436
exacerbated that problem, particularly by giving customers the ability
to convert from sales to transportation service without either
providing an appropriate transition cost recovery mechanism so that
departing parties would bear some responsibility for the cost
consequences associated with their departure or relieving the pipelines
of their service obligation. They were still obligated to provide
service to their customers when called upon but they could not depend
upon those customers to purchase gas on an ongoing basis.113
However, the inability of pipelines to recover their huge take-or-pay
liabilities was, at bottom, the direct result of extraordinary market
failures overhanging the pipeline-customer sales relationship that had
traditionally provided the means by which pipelines recovered their
prudently incurred costs.
---------------------------------------------------------------------------
\112\ Regulation of Natural Gas Pipelines after Partial Wellhead
Decontrol, Order No. 500-H, [Regs. Preambles 1986-1990] FERC Stats.
& Regs. para. 30,867 at 31,509-14 (1989), aff'd in relevant part,
American Gas Ass'n v. FERC, 912 F.2d 1496 (D.C. Cir. 1990).
\113\ Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C.
Cir. 1987), cert. denied, 485 U.S. 1006 (1988).
---------------------------------------------------------------------------
In the face of these extraordinary market conditions, the
Commission adopted extraordinary measures. As
[[Page 10213]]
discussed below, in Order Nos. 500/528 the Commission created a
mechanism to facilitate settlement of the take-or-pay liabilities, to
free gas markets of the burdens of a problem that experience
demonstrated would not be resolved through traditional cost recovery
mechanisms, with or without open access transportation requirements. In
that context, (and given the Court's decision in AGD requiring the
Commission to address the take-or-pay problem as a condition to
maintaining open access transportation) the Commission's overriding
concern was to restore order to the markets promptly by encouraging
settlements that could move the industry past economic stalemate. Of
necessity, the Commission's objectives could only be achieved by
foregoing efforts to assign costs and ``responsibility'' among the
various industry participants through conventional means.
In those circumstances, and to facilitate settlement, the
Commission found that because no one segment of the industry could be
held accountable for the complex circumstance leading to the take-or
pay problem, it required all industry participants, including
pipelines, to participate in the solution. In exchange for a pipeline's
agreement to absorb some part of its take-or-pay costs, the pipeline
was granted a rebuttable presumption that its costs were prudently
incurred, significantly reducing its risk that a further portion of its
costs would be disallowed as not prudently incurred.
In stark contrast to the circumstances surrounding Order Nos. 500/
528, Order No. 636 was not issued in the context of market conditions
that precluded pipelines from a meaningful opportunity to seek recovery
of prudently incurred costs. While at the time of Order No. 636 there
were, of course, individual contracts that were priced higher than the
prevailing market prices for gas, this ``market circumstance'' did not
render pipeline gas supply costs unrecoverable. To the contrary,
pipelines had the ability to seek recovery of costs incurred under
those contracts, so long as their sales customers continued to purchase
gas from them.
However, Order No. 636 effected significant regulatory changes,
largely to the benefit of users of the transportation system and
purchasers of gas, that directly resulted in the inability of pipelines
to recover their gas supply costs from their sales customers (who were
allowed to convert to transportation customers by Order No. 636).
After carefully reviewing the Court's concerns in UDC and the
circumstances surrounding the cost recovery issues in both Order Nos.
500/528 and Order No. 636, the Commission believes that it must
reaffirm its conclusion in Order No. 636 that pipelines should be
permitted an opportunity to recover 100 per cent of prudently incurred
GSR costs. As described below, the Commission finds that the
extraordinary market circumstances that gave rise to the requirement
for pipeline absorption of gas supply costs in Order Nos. 500/528 were
not present at the time of Order No. 636. In the absence of the special
circumstances that gave rise to the justification for pipeline
absorption as required in Order Nos. 500/528, and in light of the fact
that the regulatory changes in Order No. 636 directly led to the
incurrence of GSR costs, the Commission reaffirms its conclusion in
Order No. 636 that pipelines should be permitted an opportunity to
recover 100 percent of costs that are determined to be eligible gas
supply realignment costs and are prudently incurred. 114
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\114\ The Court gave several examples of reasons which might
justify not requiring pipelines to absorb a share of their GSR
costs. These were: (1) a finding that ``unbundling under Order No.
636 benefits consumers so much more than it does the pipelines that
the pipelines should bear few or no GSR costs,'' UDC, 88 F.3rd at
1189, (2) a finding that ``the pipelines' contribution to the
industry's transition has already been so disproportionately large
vis-a-vis consumers that they are entitled to be excused from
further responsibility, Id., and (3) a finding that requiring the
pipeline segment of the industry to absorb GSR costs would ``raise
substantial concerns about its financial health,'' Id. at 1189 n.
99. The pipeline industry is not in such precarious financial
condition that absorption would threaten its financial viability.
However, the Commission does not believe that the Court precluded
the Commission from using the rationale discussed below in this
order.
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B. Scope of Commission's Decision
The Commission's disposition of this matter on remand does not
affect the resolution of GSR costs for most pipelines. Since Order No.
636, the Commission has approved settlements between most pipelines and
their customers resolving all issues concerning those pipelines'
recovery of their GSR costs. In addition, in two GSR proceedings, no
party sought rehearing of the Commission's acceptance of the pipeline's
GSR recovery proposal.115 None of the GSR settlements contains a
provision permitting the settlement to be reopened as to the absorption
issue.116 Therefore, the Court's remand of the GSR cost absorption
issue does not affect the settled GSR proceedings. Regardless of the
Commission's decision on remand concerning absorption of GSR costs, the
GSR settlements and the final and non-appealable orders will remain
binding on the subject pipelines and their customers.117 To the
extent that pipelines have voluntarily elected to enter into
settlements that require absorption of some portion of the GRS costs to
avoid protracted litigation of eligibility and prudence challenges, we
do not disturb that result.
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\115\ Trunkline Gas Co., 72 FERC para. 61,265 (1995); Williston
Basin Interstate Pipeline Co., 70 FERC para. 61,009 (1995).
\116\ On November 25, 1996, the Missouri Public Service
Commission (MoPSC) filed, in this rulemaking docket, a motion
asserting that Williams' GSR settlement left open the issue whether
Williams must absorb its GSR costs in excess of $50 million. On
December 10, 1996, Williams filed an answer, arguing that its
settlement provides for it to recover 100 percent of those costs,
without regard to the outcome of appeals of Order No. 636. In a
separate order in the dockets in which Williams is seeking recovery
of GSR costs in excess of $50 million, the Commission has upheld
Williams' interpretation of its settlement. Williams Natural Gas
Co., 78 FERC para. 61,068 (1997).
\117\ /Similarly, after the court's decision in Associated Gas
Distribs. v. FERC, 893 F.2d 348 (D.C. Cir. 1989) (AGD II), that the
Order No. 500 method of allocating fixed take-or-pay charges
violated the filed rate doctrine, the Commission exempted from the
Order No. 528 order on remand all pipelines whose recovery of take-
or-pay costs had been resolved either by settlement or by final and
non-appealable order. Order No. 528, 53 FERC para. 61,163 at 61,594
(1990).
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However, there has as yet been no settlement of the proceedings
initiated by Tennessee to recover its GSR costs.118 There has also
been no settlement of a recent filing by NorAm Gas Transmission Company
(NorAm) and two recent filings by ANR Pipeline Company (ANR) to recover
their GSR costs.119 Also, while the Commission has approved a
settlement concerning Southern Natural Gas Company's (Southern)
recovery of GSR costs, several of Southern's customers were severed
from that settlement.120 In addition, the settlement approved by
the
[[Page 10214]]
Commission concerning the recovery of GSR costs by Panhandle Eastern
Pipe Line Company (Panhandle) does not resolve how it will recover any
GSR costs which it may file in the future.121 Therefore, since the
recovery of GSR costs does remain an issue in some cases, the
Commission must address the issue remanded by the Court. The following
describes in greater detail the basis for the Commission's decision to
reaffirm it's decision in Order No. 636 with respect to recovery of GSR
costs.
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\118\ On January 28, 1997, the Administrative Law Judge in
Tennessee's GSR proceedings (Docket Nos. RP93-151-000 et al.)
required the participants to file a joint status report concerning
their settlement negotiations by February 7, 1997. The status report
indicated that almost all parties have agreed to a settlement in
principle. On February 21, Tennessee reported to the ALJ that the
parties expect to file a settlement by February 28, or shortly
thereafter.
\119\ /NorAm made its first filing to recover GSR costs on
August 1, 1996, following the UDC decision. The Commission accepted
and suspended the filing, subject to this order on remand. NorAm Gas
Transmission Co., 76 FERC para. 61,221 (1996). The Commission has
approved settlements of ANR's first three GSR proceedings. ANR
Pipeline Co., 72 FERC para. 61,130 (1995); 74 FERC para. 61,267
(1996). However, those settlements did not address ANR's recovery of
any subsequent GSR costs. On October 31, 1996, ANR filed to recover
additional GSR costs in Docket No. RP97-47-000. ANR Pipeline Co., 77
FERC para. 61,130 (1996). That proceeding has not yet been settled.
In addition, on January 31, 1997, ANR made another GSR filing in
Docket No. RP97-246-000.
\120\ /Southern Natural Gas Co., 72 FERC para. 61,322 at 62,329-
30, 62,355-6 (1995), reh'g denied, 75 FERC para. 61,046 (1996).
\121\ /Panhandle Eastern Pipe Line Co., 72 FERC para. 61,108
(1995).
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C. The Regulatory Framework
The Commission's task in both Order Nos. 500/528 and Order No. 636
was to determine a method for pipelines to recover their prudently
incurred costs arising from the non-market responsive take-or-pay
contracts entered into during the late 1970s and early 1980s. Take-or-
pay costs are part of a pipeline's expenses. As the Court of Appeals
held in Mississippi Power Fuel Corp. v. FPC,122 pipelines must be
allowed an opportunity to recover their prudently incurred expenses:
---------------------------------------------------------------------------
\122\ 163 F.2d 433, 437 (D.C. Cir. 1947).
---------------------------------------------------------------------------
Expenses * * * are facts. They are to be ascertained, not
created, by the regulatory authorities. If properly incurred, they
must be allowed as part of the composition of rates. Otherwise, the
so-called allowance of a return upon investment, being an amount
over and above expenses, would be a farce.
The Court of Appeals has recently reiterated that holding, and
emphasized the Supreme Court's longstanding admonition that regulatory
agencies must recognize prudently incurred expenses in establishing
just and reasonable rates:
More than a half century ago, the Supreme Court admonished
regulatory agencies to ``give heed to all legitimate expenses that
will be charges upon income during the term of regulation.''
Mountain States Telephone & Telegraph Co. v. FCC, 939 F.2d 1021,
1029 (D.C. Cir. 1991) (citing West Ohio Gas Co. v. Public Utilities
Comm'n of Ohio 294 U.S. 63, 74 (1935)). Of course, recovery may be
denied if particular costs (1) are not used and useful in performing
the regulated service 123 or (2) have been imprudently incurred.
---------------------------------------------------------------------------
\123\ Tennessee Gas Pipeline Co. v. FERC, 606 F.2d 1094, 1109
(D.C. Cir. 1979), cert denied, 445 U.S. 920, cert. denied, 447 U.S.
922 (1980) (``current ratepayers should bear only legitimate costs
of providing service to them'').
---------------------------------------------------------------------------
Consistent with the Supreme Court's admonishment that regulatory
agencies recognize prudently incurred expenses, the Commission has a
particular obligation not to ignore or disallow expenses incurred by
pipelines as a result of the Commission's own regulatory actions. For
that reason, as the Court of Appeals pointed out in Public Utilities
Comm'n of Cal. v. FERC, 988 F.2d 154, 166 (1993), the Commission,
With the backing of this court, has been at pains to permit
pipelines to recover * * * [Order Nos. 500/528 take-or-pay costs]
which have accumulated less through mismanagement or miscalculation
by the pipelines than through an otherwise beneficial transition to
competitive gas markets.
As more fully discussed below, the Order No. 636 GSR costs are the
direct result of the transition to unbundled transportation service
required by Order No. 636. In Order No. 636, the Commission prohibited
pipelines from continuing their practice of bundling sales of natural
gas with transportation rights and required pipelines making unbundled
sales to do so through a separate arm of the company. Order No. 636
gave pipeline sales customers an immediate right to terminate gas
purchases from the pipeline.124 In light of the substantial
improvement in the quality of stand-alone transportation service
required by Order No. 636, almost all sales customers immediately
terminated their sales service during restructuring, leading to the
termination of the pipelines' merchant business. The Commission has
developed standards for eligibility for GSR cost recovery designed to
limit GSR costs solely to those costs caused by Order No. 636.125
For that reason, the Commission has given pipelines an opportunity to
recover the full amount of their GSR costs.
---------------------------------------------------------------------------
\124\ The Commission's only requirement for pipelines to
continue to offer to sell gas at cost-based rates was a requirement
that they offer small customers such sales service for a one-year
transition period. Order No. 636-A, [Regs. Preambles Jan. 1991-June
1992] FERC Stats. & Regs. at 30,615.
\125\ See Texas Eastern Transmission Co., 65 FERC para. 61,363
(1993).
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However, as discussed below, the massive take-or-pay settlement
costs addressed by Order Nos. 500/528--unlike GSR costs--were not the
direct result of the Commission's regulatory actions. Rather, they
arose from market conditions beginning in the early 1980s which would
have rendered a portion of the costs unrecoverable, regardless of the
Commission's initiation of open access transportation in Order No. 436.
In those unique circumstances, while the Commission created a special
recovery mechanism to permit the pipelines to recover their take-or-pay
settlement costs, the Commission also required pipelines using that
mechanism to absorb a share of the costs.
D. The Treatment of Costs in Order Nos. 500/528
In order to understand the basis for the Commission's different
treatment of Order No. 636 GSR costs and Order Nos. 500/528 take-or-pay
costs, it is necessary first to review the circumstances which led to
the Order Nos. 500/528 absorption requirement and the Commission's
reasons for that requirement.
1. The Factual Context of Order Nos. 500/528
The industry's take-or-pay crisis developed before the Commission
initiated open access transportation in Order No. 436. The Commission
made this finding in Order No. 500-H.126 The severe gas shortages
of the 1970's led to enactment of the NGPA, which initiated a phased
decontrol of most new gas prices and established ceiling prices for
controlled gas, including incentive prices for price-controlled new gas
higher than the ceiling prices previously established by the Commission
under the NGA.127 To avoid future shortages, pipelines then
entered into long-term take-or-pay contracts at the high prices made
possible by the NGPA, and those high prices stimulated producers to
greatly increase exploration and drilling.128 All participants in
the natural gas industry expected both demand and prices to continue
increasing indefinitely.
---------------------------------------------------------------------------
\126\ Regulation of Natural Gas Pipelines after Partial Wellhead
Decontrol, Order No. 500-H, [Regs. Preambles 1986-1990] FERC Stats.
& Regs. para. 30,867 (1989), aff'd in relevant part, American Gas
Ass'n v. FERC, 912 F.2d 1496 (D.C. Cir. 1990).
\127\ Id. at 31,509.
\128\ Id. at 31,509-10.
---------------------------------------------------------------------------
However, by 1982 demand was falling, due to a number of factors
including unexpectedly strong competition from alternative fuels, the
recession of the early 1980s, and warmer than normal weather. By 1983,
demand for natural gas was 17 percent below its 1979 level. As a
result, the supply of natural gas (i.e., current deliverability from
the nation's gas wells) exceeded demand for natural gas by 4 Tcf, or
nearly 20 percent of total deliverability.129 This deliverability
[[Page 10215]]
surplus persisted for the remainder of the 1980s.
---------------------------------------------------------------------------
\129\ As the Commission found in Order No. 500-H:
By 1982, demand for gas was falling. High natural gas prices,
combined with decreasing oil prices, led to increased fuel
switching, particularly as customers who did not already have the
necessary equipment to burn alternative fuels installed it. The
recession of the early 1980's and warmer than normal weather further
decreased demand. These factors combined to create an excess of the
supply of natural gas (i.e., current deliverability from the
nation's gas wells) over the demand for natural gas. The
deliverability surplus persisted for the remainder of the 1980's. In
1982 the deliverability surplus was about 1.5 Tcf, or 8.3 percent of
total deliverability. By 1983, with the demand for natural gas 17
percent below its 1979 level, the deliverability surplus was about 4
Tcf, or nearly 20 percent of total deliverability.
Id. at 31,510.
---------------------------------------------------------------------------
This unexpected change in market conditions caused pipelines, as
early as 1982, to start incurring significant take-or-pay liabilities
under the take-or-pay contracts entered into with the expectation of
continued high demand. By year-end 1983, nearly two years before Order
No. 436 issued, pipeline take-or-pay exposure was $5.15
billion.130 However, despite the deliverability surplus, both
wellhead gas prices and the gas costs reflected in the pipelines' rates
continued to increase. Similarly, the average residential cost of gas
continued to rise.131 These price increases at a time of
oversupply were primarily the result of the inflexible supply
arrangements between producers, pipelines, LDCs, and consumers, under
which most gas users could obtain gas only through purchases from the
pipeline. The Commission's first major action to address those supply
arrangements was the issuance of Order No. 380 132 on May 25,
1984, requiring pipelines to eliminate commodity costs from their
minimum bills.
---------------------------------------------------------------------------
\130\ Id.
\131\ The residential cost of gas rose from $5.17 in 1982 to
$6.12 in 1984. Id.
\132\ Elimination of Variable Costs from Certain Natural Gas
Pipeline Minimum Bill Provisions, Order No. 380, [Regs. Preambles
1982-1985] FERC Stats. Regs. para. 30,571 (1984).
---------------------------------------------------------------------------
Take-or-pay exposure increased to $6.04 billion by year-end
1984.133 By the end of 1985, just two months after Order No. 436
issued and before any pipeline had accepted a blanket certificate under
Order No. 436, pipelines had outstanding take-or-pay liabilities of
$9.34 billion.134 In 1986, as pipelines were just beginning to
implement open access transportation under Order No. 436, the
pipelines' outstanding unresolved take-or-pay liabilities peaked at
$10.7 billion.135
---------------------------------------------------------------------------
\133\ Id.
\134\ Id. at 31,513.
\135\ Id.
---------------------------------------------------------------------------
In short, although Order No. 436 exacerbated pipelines' existing
take-or-pay problems by making it easier for the pipelines' traditional
sales customers to purchase from alternative suppliers, Order No. 436
did not cause those problems. Rather, the pipelines' take-or-pay
problems were caused by an excess of supply over demand in the natural
gas market which arose in the early 1980s due to the convergence of a
number of factors, many entirely unrelated to the Commission's exercise
of its regulatory responsibilities. As a result, even before Order No.
436 issued, the natural gas industry already faced a massive problem in
which pipelines were contractually bound to take or pay for high-priced
gas which market conditions suppressed demand and prevented them from
reselling at prices which would recover their costs. Simply put, at the
time of Order No. 436, the market was requiring substantial cost
absorption entirely apart from any regulatory action of the Commission.
The Commission and the industry had never previously faced a take-
or-pay problem of this nature. In earlier times, pipelines had made
take-or-pay payments to particular producers, and the Commission had a
policy of permitting such payments to be included in rate base and then
recovered as a gas cost when the pipeline later took the gas under
make-up provisions in the contract.136 By 1983, however, with
their total take-or-pay exposure over $5 billion, the pipelines could
not manage their take-or-pay problems, and stopped honoring the bulk of
their take-or-pay liabilities.137 They then sought settlements
with the producers to reform or terminate the uneconomic take-or-pay
contracts and to resolve outstanding take-or-pay liabilities.
---------------------------------------------------------------------------
\136\ Regulatory Treatment of Payments Made in Lieu of Take-or-
Pay Obligations, Regulations Preambles 1982-85 para. 30,637 at
31,301 (1985).
\137\ In Order No. 500-H, the Commission found that, although
pipelines incurred total take-or-pay exposure over the period
January 1, 1983 through June 30, 1987 of over $24 billion, they only
made take-or-pay payments totalling $.7 billion. Order No. 500-H,
Regulations Preambles 1986-1990 para. 30,867 at 31,514.
---------------------------------------------------------------------------
Because pipelines had never previously incurred significant take-
or-pay settlement costs, the Commission had no policy concerning
whether and how pipelines were to recover those costs. The Commission
commenced establishing such a policy in an April 1985 policy
statement,138 just six months before Order No. 436. When Order No.
500 issued in August 1987, few take-or-pay settlement costs had yet
been included in pipelines' rates. However, since the pipelines'
outstanding take-or-pay liabilities were in the neighborhood of $10
billion, it was clear that pipelines would incur massive costs in their
settlements with producers.
---------------------------------------------------------------------------
\138\ Regulatory Treatment of Payments Made in Lieu of Take-or-
Pay Obligations, [Regs. Preambles 1982-85] Stats & Regs. para.
30,637 (1985).
---------------------------------------------------------------------------
2. The Policies of Order Nos. 500/528
When the Commission first addressed the issue of how pipelines
should recover their take-or-pay settlement costs in Order No. 500, it
did so under the shadow of the pipelines' vast outstanding take-or-pay
exposure. As a result, the fundamental premise of Order No. 500 was, as
the Court expressed it in KN Energy v. FERC, that ``the extraordinary
nature of this problem requires the aid of the entire industry to solve
it.''139 In order to accomplish this result, Order No. 500
established an equitable sharing mechanism for pipelines to use in
recovering their take-or-pay settlement costs, as an alternative to
recovery through their commodity sales rates.140 Relying on ``cost
spreading'' and ``value of service'' principles, the Commission
permitted pipelines using the equitable sharing mechanism to allocate
their take-or-pay settlement costs among all their customers. The
Commission also required the pipelines to absorb a portion of their
costs.141
---------------------------------------------------------------------------
\139\ 968 F.2d 1295, 1301 (D.C. Cir. 1992).
\140\ Order No. 500 also increased the pipelines' bargaining
power to negotiate settlements with producers through the take-or-
pay crediting program.
\141\ The Court in KN Energy upheld the Commission's use of cost
spreading in connection with the allocation of take-or-pay costs
among a pipeline's open access customers. However, the Court never
reviewed the Order Nos. 500/528 requirement that pipelines absorb a
share of the take-or-pay costs. AGA v. FERC, 888 F.2d 136, 152 (D.C.
Cir. 1989), holding the absorption requirement not ripe for review.
Accord: AGA v. FERC, 912 F.2d 1496 (D.C. Cir. 1990).
---------------------------------------------------------------------------
The Court was of the view that Order Nos. 500/528 based the
absorption requirement on the ``cost spreading'' and ``value of
service'' principles.142 However, Order No. 528-A,143 where
the Commission gave its fullest justification for that absorption
requirement, did not rely on either of those principles to support the
absorption requirement. 144 Rather,
[[Page 10216]]
Order Nos. 500/528 consistently recognized the Commission's traditional
obligation to ``provide a pipeline a reasonable opportunity to recover
its prudently incurred costs.'' 145 However, Order No. 528-A
reasoned that, because the take-or-pay problem was caused more by
general market conditions than by any regulatory action of the
Commission and the underlying take-or-pay contracts were no longer used
and useful, it was appropriate to require the pipelines to share in the
losses arising from those market conditions.146
---------------------------------------------------------------------------
\142\ UDC, 88 F.3d at 1188.
\143\ Order No. 528-A, 54 FERC para. 61,095 (1991).
\144\ The Commission's use of cost spreading and value of
service principles to allocate take-or-pay costs among all the
pipeline's open access customers was, as the Court suggested in KN
Energy, 968 F.2d at 1302, ``only a minor departure'' from the
traditional ratemaking principle that costs should be allocated
among customers based on cost causation. Ordinarily, the cost
causation principle is used to assign the pipeline's cost-of-service
among customers. Its underlying premise is that each customer should
be responsible for the costs its service causes the pipeline to
incur. A necessary corollary is that the pipeline may, if the market
permits, recover 100 percent of the costs it prudently incurs to
serve its customers. Otherwise, the customers would not be
responsible for all the costs their service causes the pipeline to
incur. For this reason the cost causation principle is not used to
assign costs to the pipeline. Order Nos. 500/528 used cost spreading
and value of service principles simply to extend the chain of
causation to assign costs to a broader group of customers. KN
Energy, 968 F.2d at 1302.
\145\ Order No. 500-H, [Regs. Preambles 1986-1990] FERC Stats. &
Regs. at 31,575.
\146\ Order No. 528A, 54 FERC at 61,303-5 (1991).
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E. The Treatment of Costs in Order No. 636
The nature of the take-or-pay problem had changed dramatically by
the time of Order No. 636. That difference in circumstances accounts
for the different policies applied by the Commission in Order No. 636.
1. The Factual Context of Order No. 636
By 1992, when Order No. 636 issued, the world had changed, and the
unique circumstances out of which the Order Nos. 500/528 absorption
requirement arose no longer existed. Pipelines were no longer incurring
substantial costs in connection with their take-or-pay contracts which
they were unable to recover in sales rates, as they had been when Order
No. 436 issued. While some of the uneconomic take-or-pay contracts of
the late '70s and early '80s remained in effect and some pipelines were
still working to resolve some past take-or-pay liabilities, there was
no longer an industry-wide take-or-pay problem.147
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\147\ In late 1989, the Commission found in Order No. 500-H that
pipelines' settlements with producers ``have substantially resolved
the existing take-or-pay liabilities of most pipelines, and all the
pipelines have made significant progress in resolving their
problems.'' Order No. 500-H, [Regs. Preambles 1986-90] FERC Stats. &
Regs. at 31,523. The Commission also terminated the take-or-pay
crediting program effective December 31, 1990, on the ground that
such a program no longer would be necessary. Id. at 31,529.
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In contrast to the situation when Order No. 436 issued, at the time
of Order No. 636 most pipelines were no longer incurring new take-or-
pay liabilities, even under their few remaining old, unresolved
contracts.148 Following Order No. 500, pipelines made a massive
effort to reform their supply contracts by negotiating with producers
settlements of thousands of take-or-pay contracts which either
eliminated the uneconomic take-or-pay provisions or terminated the
contracts altogether.149 By the time Order No. 636 issued,
pipelines had succeeded in reforming nearly all their supply contracts
at a total cost, in settlement payments to producers, of nearly $10
billion.150 For example, at the hearing in Docket No. RP92-134-000
concerning Southern's Mississippi Canyon construction costs, Southern
provided testimony that by 1987 it had succeeded in renegotiating its
supply arrangements such that it was no longer incurring additional
take-or-pay liabilities.151
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\148\ Similarly, when the Commission initiated open access
transmission in the electric industry in Order No. 888, most
electric utilities were recovering their electric generating costs
in the rates charged their customers. Therefore, the Commission
concluded that it would not be reasonable to require electric
utilities to bear losses that, unlike the Order Nos. 500/528 take-
or-pay costs, arise as a direct result of Congress' and the
Commission's change in regulatory regime through FPA section 211 and
Order No. 888. See Recovery of Stranded Costs by Public Utilities
and Transmitting Utilities, III FERC Stats. & Regs. para. 30,----at
31,----(Order No. 888-A) (1997). The Commission's approach to Order
No. 636 GSR costs is similar to its approach in Order No. 888 to
stranded electric generation costs.
\149\See Id. at 31,522-3 and 31,536.
\150\See Appendix B, Table 1.
\151\ Southern Natural Gas Co., 72 FERC para. 61,322 at 62,358
(1995).
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Another reason that pipelines were not incurring new take-or-pay
liabilities when Order No. 636 issued is that, after Order No. 436,
unlike after Order No. 636, pipelines continued to perform a
significant sales service. This was at least in part because, as the
Commission found in Order No. 636, open access transportation service
under Order No. 436 was not comparable to the transportation component
of bundled sales service. As a result, through such strategies as
purchasing gas in the summer, storing it in their storage fields, and
then reselling it during periods of peak demand and prices in the
winter, at the time of Order No. 636 the pipelines could meet most of
their minimum take requirements even in their remaining high-priced
contracts. Many pipelines expected to continue providing such a sales
service indefinitely into the future. For example, on the day before
the June 30, 1991 issuance of the Notice of Proposed Rulemaking which
led to Order No. 636, Southern and some of its sales customers filed a
comprehensive settlement that would have assured a continued sales
service by Southern.152 Similarly, on March 10, 1992, less than a
month before issuance of Order No. 636, ANR filed a settlement under
which it would have continued a bundled sales service.153
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\152\However, during Southern's Order No. 636 restructuring
proceeding, all its sales customers decided to take transportation
only service and Southern terminated its merchant function. Id. at
62,362-3.
\153\ ANR Pipeline Co., 59 FERC para. 61,347, reh'g, 60 FERC
para. 61,145 (1992).
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Order No. 636 upset this relatively stable situation and created a
new jeopardy for the recovery of pipeline gas supply costs. Order No.
636 prohibited pipelines from continuing their bundled sales service
and resulted in the termination of the pipelines' merchant business.
While Order No. 436 had only required pipelines to permit their
customers to convert from sales to transportation service over a phased
five-year schedule,154 Order No. 636 gave pipeline sales customers
an immediate right to terminate their entire sales service. Order No.
636 also required pipelines to substantially improve the quality of
their stand-alone transportation service. As a result, the pipelines'
remaining sales customers switched to transportation-only service, with
almost all of them immediately terminating their sales service during
restructuring.
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\154\ 18 CFR 284.11(d)(3).
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Order No. 636 also made it more difficult for pipelines to manage
their take-or-pay contracts in several other ways. Unlike Order No.
436, Order No. 636 required pipelines to give up most of their storage
capacity so that they were less able to pursue such strategies as
storing gas purchased in the summer, when sales were too low to meet
minimum purchase obligations, for subsequent resale in the winter, when
sales levels were higher. In addition, before Order No. 636, many of
the pipelines that had the take-or-pay contracts with producers had
downstream pipeline customers who were continuing to purchase some gas.
However, Order No. 636 required the downstream pipelines also to
unbundle, resulting in the loss of the downstream pipelines as sales
customers.
The pattern of pipeline filings with the Commission to recover
take-or-pay related costs is consistent with the conclusion that Order
No. 636 reopened a take-or-pay problem that had been largely resolved.
As shown in Table 1 of Appendix B to this order, since Order No. 436,
pipelines have filed to recover a total of approximately $12.1 billion
in take-or-pay related costs, including about $10.4 billion filed
pursuant to Order Nos. 500/528 and $1.7 billion filed as Order No. 636
GSR costs. Fully 81.7 percent of the total $12.1 billion amount was
filed, pursuant to Order
[[Page 10217]]
Nos. 500/528, before Order No. 636 issued in April 1992. See Table 2.
Since Order No. 636, pipelines have continued to make some filings
to recover take-or-pay related costs under Order Nos. 500/528. This is
because the only costs eligible for recovery as Order No. 636 GSR costs
are costs that are tied to the restructuring required by Order No. 636.
However, as shown by Table 2, post-Order No. 636 filings to recover
take-or-pay related costs pursuant to Order Nos. 500/528 represent only
4.2 percent of the total take-or-pay related costs filed with the
Commission since Order No. 436. Table 3, showing costs filed for
recovery under Order Nos. 500/528, by quarter, demonstrates graphically
the dramatic decline in such costs before Order No. 636, and the
relative insignificance of such costs thereafter.
That take-or-pay was no longer an industry-wide problem at the time
of Order No. 636 is also suggested by the fact that just two
pipelines--Southern and Tennessee--account for approximately 65 percent
of all take-or-pay related costs filed with the Commission as Order No.
636 GSR costs.155 Moreover, the sudden spike in GSR costs filed
with the Commission in late 1993, continuing to an extent in 1994, as
pipelines were just implementing their Order No. 636 restructuring is
consistent with a conclusion that Order No. 636 reopened a take-or-pay
problem that had been largely resolved. See Tables 4 and 5.
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\155\ See Table 1.
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2. The Policies of Order No. 636
Based on the changing nature of the take-or-pay problem reviewed
above, the Commission holds that the rationale supporting the Order
Nos. 500/528 absorption requirement is not valid for the GSR costs
caused by Order No. 636. The rationale used in Order Nos. 500/528 does
not support a requirement that pipelines absorb a share of their Order
No. 636 GSR costs. In the factual context faced by the Commission at
the time of Order No. 636, the bedrock ratemaking principle, that
pipelines must be given an opportunity to recover the full amount of
their prudently incurred costs, required the Commission to establish a
different mechanism for pipelines to recover their Order No. 636 GSR
costs. This is particularly so, because these costs were caused by the
Commission's regulatory actions.
When Order No. 636 issued, pipelines were generally taking gas
under their remaining take-or-pay contracts and no longer accumulating
significant additional take-or-pay obligations. Thus, those contracts
could no longer reasonably be analogized to a failed gas supply
project, the analogy used to support the Order Nos. 500/528 absorption
requirement.156 As a result, the Commission's section 5 action in
Order No. 636 reopened a take-or-pay problem that had been largely
resolved. The termination of the pipelines' merchant business as a
result of Order No. 636 created a situation in which the pipelines
simply lacked an ability to manage and sell the natural gas supply
portfolio they had under contract. In these circumstances, where the
Commission's own regulatory action in Order No. 636 rendered the
pipelines' supply contracts no longer used and useful, the Commission
believes that pipelines should be allowed full recovery of transition
costs caused by Commission action.
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\156\ Order No. 528-A, 54 FERC at 61,304.
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Moreover, the Commission only permits 100 percent recovery of GSR
costs arising in connection with supply contracts which were part of an
overall gas supply portfolio that was commensurate with the pipeline's
merchant obligation--in other words contracts which were used and
useful when Order No. 636 issued. See Texas Eastern Transmission Co.,
65 FERC para. 61,363 (1993). Where the pipeline cannot show that its
costs satisfy the eligibility standards developed in Texas Eastern, the
costs are only eligible for Order Nos. 500/528 recovery and a portion
must be absorbed. Indeed, since Order No. 636, pipelines have filed to
recover, pursuant to Order Nos. 500/528, over $500 million in costs
which they recognized were not caused by Order No. 636. Moreover, when
parties have questioned whether claimed GSR costs meet the Texas
Eastern standards, the Commission has required pipelines to demonstrate
their eligibility at a hearing. Thus, through its GSR eligibility
standards, the Commission ensures that the costs for which 100 percent
recovery is permitted are in fact caused by the Commission's regulatory
actions in Order No. 636.
Eligible GSR costs are similar to other stranded pipeline merchant
costs which Order No. 636 rendered no longer used and useful and whose
recovery the Court approved in UDC, 88 F.3d at 1178-80. Order No. 636
permitted pipelines to file under NGA section 4 to recover 100 percent
of costs ``incurred by pipelines in connection with their bundled sales
services that cannot be directly allocated to customers of the
unbundled services.'' 157 Those costs included costs incurred in
connection with upstream pipeline capacity and storage capacity that a
pipeline no longer needs because its sales service terminated due to
restructuring. In the section 4 cases where recovery of these costs has
been sought, the Commission has recognized that its action in Order No.
636 rendered the costs no longer used and useful, and the Commission
has accordingly permitted the full amount of the eligible and prudently
incurred costs to be amortized as part of the pipeline's cost-of-
service, although not included in rate base.158 In UDC, the Court
approved this approach.159 The GSR costs have become stranded in
an identical manner, and therefore pipelines should be afforded the
same opportunity for full recovery of their prudently incurred GSR
costs.
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\157\ Order No. 636, [Regs. Preambles Jan. 1991-June 1996] FERC
Stats. & Regs. at 30,662.
\158\ See Equitrans, Inc. 64 FERC para. 61,374 at 63,601 (1993).
\159\ UDC, 88 F.3d at 1178-80.
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Moreover, the fact that Order No. 636 led to the complete
termination of most pipelines' merchant function, unlike the situation
after Order No. 436, means that the Commission cannot now take the
Order Nos. 500/528 approach of offering the pipelines the alternative
of seeking 100 percent recovery through their sales commodity rates.
Rather, the recovery mechanism provided by Order No. 636 is the only
available mechanism for recovering GSR costs. Therefore, if the
Commission did not permit pipelines to seek recovery of the full amount
of their GSR costs through the mechanism provided by Order No. 636, the
Commission would be denying recovery by regulatory decree, not simply
allowing market forces to prevent full recovery.
As the Commission has previously found, Order No. 636 substantially
benefits all gas consumers. It is for that reason that the Commission
required that GSR costs be allocated among all the pipelines'
customers. In an October 22, 1996 petition for further proceedings on
remand, the Pennsylvania Office of Consumer Advocate (POCA) suggested
that Order No. 636 also benefitted pipelines by (1) allowing them to
terminate their relatively risky merchant functions, while (2)
retaining the relatively stable transportation operations bolstered by
the guarantee of substantial fixed cost recovery under SFV rates. POCA
asserts that in return for these benefits pipelines should be required
to absorb a portion of their transition costs. However, as discussed
above, most pipelines were not incurring current financial losses in
connection with their merchant functions at the time of Order No. 636.
[[Page 10218]]
Yet the termination of those merchant functions caused a number of
pipelines to incur significant expenses, including the costs of
shedding the gas supplies they had contracted for to serve their sales
customers. Therefore, the Commission does not see the pipelines'
termination of their merchant functions as a ``benefit'' justifying the
Commission to require the pipelines to absorb a portion of the
resulting expenses.160 This is particularly so, in light of the
Supreme Court's admonishment that regulatory agencies must recognize
prudently incurred costs.161 That is an obligation the Commission
takes especially seriously when, as here, its own regulatory actions
have caused the costs.162
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\160\ See UDC, 88 F.3d at 1189.
\161\ West Ohio Gas Co. v. Public Utilities Comm'n of Ohio, 294
U.S. at 74. Mountain States Telephone & Telegraph Co. v. FCC, 939
F.2d at 1029.
\162\ Public Utilities Comm'n of Cal. v. FERC, 988 F.2d 154, 166
(1993) (The Commission ``with the backing of this court, has been at
pains to permit pipelines to recover [take-or-pay costs] . . . which
have accumulated . . . through an otherwise beneficial transition to
competitive gas markets'').
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The Commission also does not believe that the shift to an SFV rate
design, for the recovery of the pipelines' transmission costs, is
relevant to the issue of the pipelines' recovery of the costs of
realigning their gas supplies which supported their merchant function.
To the extent SFV alters the risks a pipeline faces in connection with
its performance of transportation service, the appropriate place to
make an adjustment is in the allowed return on equity embodied in the
pipelines' transportation rates.163
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\163\ In determining the returns on equity allowed in individual
rate cases after the shift to SFV, the Commission has refused to
make any special downward adjustments based on the pipeline's shift
to SFV. However, that has been because the Commission has found that
the equity markets have already taken the Commission's shift to SFV
into account. Therefore, the DCF analysis used by the Commission to
establish return on equity reflects the shift to SFV without the
need for any special adjustment. See Transcontinental Gas Pipe Line
Corp., 71 FERC para. 61,305 at 62,196 (1995); 75 FERC para. 61,039
at 61,125-6 (1996); 76 FERC para. 61,096 at 61,506 (1996).
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In conclusion, the Commission has consistently applied traditional
ratemaking principles to the issue of the pipelines' recovery of
transition costs. However, the different factual contexts addressed by
Order Nos. 500/528 and Order No. 636 led the Commission to approve
different recovery mechanisms in those orders. Even before the
Commission initiated open access transportation in Order No. 436, the
market was preventing pipelines from recovering costs incurred under
their take-or-pay contracts. The Order Nos. 500/528 absorption
requirement reflected the preexisting effect of the market, which would
have required absorption even without open access transportation under
Order No. 436.
However, the Commission's regulatory actions in Order No. 636 have
caused the pipelines to incur the GSR costs and rendered the underlying
gas supply contracts no longer used and useful. In these circumstances,
traditional ratemaking principles require the Commission to allow the
pipelines an opportunity to recover the full amount of the expenses
caused by its actions. And the Commission has been careful, through the
eligibility standards developed in Texas Eastern, to limit Order No.
636 GSR recovery to the costs actually caused by the Commission's
actions in Order No. 636. Accordingly, the Commission reaffirms Order
No. 636's holding that pipelines may recover 100 percent of their GSR
costs.
VII. Recovery of GSR Costs From IT Customers
In Order No. 636-A, the Commission required pipelines to allocate
10 percent of GSR costs to interruptible transportation customers. The
Industrial End-Users challenged this decision on appeal and contended
that unbundling confers no real benefit on that class of customers, who
therefore should not be responsible for paying GSR costs. The Small
Distributors and Municipalities took the opposite view and asserted
that the Commission should have allocated more GSR costs to
interruptible transportation customers. The Court agreed with the
Commission that interruptible transportation customers benefitted from
Order No. 636, through, inter alia, access to low cost transportation
that is available through the capacity release mechanism.164
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\164\ UDC, 88 F.3d at 1187.
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The Court faulted the Commission, however, for failing to explain
why it selected the figure of ``10%''. The Court could not discern how
the Commission got from allocating some GSR costs to allocating 10% of
those costs to interruptible transportation customers, emphasizing that
the law ``requires more than simple guess-work,'' and remanded the
issue to the Commission for further consideration.165
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\165\ Id. at 1187-88.
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As discussed above, the Commission has approved settlements between
most pipelines and their customers concerning those pipelines' recovery
of their GSR costs. Therefore, the Court's remand of the interruptible
allocation issue does not affect the settled GSR proceedings. However,
the issue of how much GSR costs should be allocated to interruptible
service remains open on several pipeline systems. As discussed above,
there has been no settlement resolving the recovery of GSR costs by
Tennessee and NorAm. Also, the settlements which the Commission has
approved in the GSR proceedings of several other pipelines do not
resolve the interruptible allocation issue as to all of those
pipelines' GSR costs. The Commission has interpreted the settlement of
Williams' recovery of GSR costs as leaving open the issue of what
portion of Williams' GSR costs in excess of $50 million should be
allocated to interruptible service.166 The interruptible
allocation issue is also unresolved to the extent it affects the GSR
costs which Southern may recover from the customers which the
Commission severed from the settlement of Southern's GSR proceedings.
Finally, the issue is unresolved as to any GSR costs which ANR and
Panhandle may seek to recover in the future.167
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\166\ Williams Natural Gas Co., 75 FERC para. 61,022 at 61,071,
reh'g denied, 76 FERC para. 61,092 (1996).
\167\ The Commission has approved four settlements concerning
Natural's recovery of GSR costs from various groups of customers.
Natural Gas Pipeline Company of America, 67 FERC para. 61,174
(1994), and 68 FERC para. 61,388 (1994). Those settlements are
generally binding on the parties notwithstanding the outcome of the
judicial review of Order No. 636, with certain limited exceptions as
to particular settlement provisions. Any party to Natural's GSR
proceedings believing that those settlements permit a change in the
allocation of costs to interruptible service as a result of the
Court's remand of that issue may file in the relevant Natural GSR
proceedings a statement explaining why it so interprets the
settlements. Otherwise, the Commission will presume that the issue
has been settled as to all of Natural's GSR costs.
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The Commission continues to believe that pipelines should allocate
some portion of their GSR costs to interruptible service. The Court
upheld the Commission's holding that interruptible transportation
customers benefit from unbundling under Order No. 636.168 As the
Court stated,
\168\ UDC, 88 F.3d at 1187.
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An active market for firm transportation would seem likely to
drive down the cost of less desirable interruptible transportation,
and while the additional use of firm transportation under Order No.
636 may crowd out some interruptible transportation, that results at
least in part from customers converting from interruptible to firm
service * * *. Further still, interruptible transportation customers
do clearly benefit from Order No. 636 through access to low cost
transportation that is available through the Commission's capacity
release mechanism.169
\169\ Id.
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These benefits received by interruptible customers clearly justify
[[Page 10219]]
the allocation of at least some GSR costs to interruptible service.
However, on remand, the Commission has determined not to require
that the percentage of GSR costs so allocated must be 10 percent for
all pipelines. As the Court recognized, different pipelines perform
different levels of interruptible service. Among the pipelines that
potentially could be affected by a departure from the generic 10
percent allocation, interruptible transportation comprises a widely
varying percentage of the pipelines' total throughput for the first
nine months of 1996--from 2.87 percent (Panhandle) to 21.68 percent
(ANR).170 Given this fact, it is not appropriate to require all
pipelines to allocate the same percentage of their GSR costs to
interruptible service. If the same percentage of GSR costs were
allocated to interruptible service no matter how much interruptible
service a pipeline performs, interruptible customers on pipelines
performing little interruptible service could bear a disproportionate
share of the pipeline's GSR costs (absent discounts).
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\170\ Interruptible transportation comprises less than ten
percent of total throughput on Panhandle, NorAm (5.89 percent), and
Tennessee (9.81 percent). Pipelines for which interruptible
transportation comprises greater than 10 percent of total throughput
are Williams (17.72 percent), Natural (13.11 percent), Southern
(11.17 percent), and ANR. The weighted average percentage of
interruptible transportation throughput among all pipelines that
report such data is approximately 18 percent. The Commission has
determined all of the above percentages based on the pipelines'
reports, pursuant to FERC Form No. 11, of the total volumes they
transported during the first nine months of 1996 and their
interruptible volumes during the same period.
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Therefore, the Commission will, instead, require each individual
pipeline, whose GSR proceedings have not been resolved, to propose the
percentage of its GSR costs its interruptible customers should bear in
light of the circumstances on its system. Pipelines which have filed to
recover GSR costs before the date of this order, and whose GSR recovery
proceedings have not been resolved by settlement or final and non-
appealable Commission order, must file such proposals in their
individual GSR proceedings within 180 days of the date of this order.
Interested parties will be given an opportunity to comment on each
pipeline's proposal. If the pipeline's proposal is protested, the
Commission will set the proposal for hearing in the GSR cost recovery
proceeding in which the proposal is made. Those hearings will permit
the interested parties to develop a record on which the Commission can
base its ultimate decision in each case.
This approach will allow the Commission and the parties to develop
an allocation of GSR costs to interruptible service that is tailored to
the specific circumstances of the few pipelines where the issue is
still alive. The Commission also expects that such hearings will
provide the parties a forum to discuss settlement of this issue. The
Commission encourages the parties to seek to settle this and all other
outstanding issues related to GSR recovery.
The Commission Orders
(A) Order No. 636 is reaffirmed, in part, and reversed, in part, as
discussed in the body of this order.
(B) Within 180 days of the issuance of this order, any pipeline
with a right-of-first-refusal tariff provision containing a contract
term cap longer than five years must revise its tariff consistent with
the new cap adopted herein.
(C) Within 180 days of the issuance of this order, pipelines which
have filed to recover GSR costs before the date of this order, and
whose GSR recovery proceedings have not been resolved by settlement or
final and non-appealable Commission order, must file, in their
individual GSR proceedings, a proposed allocation of GSR costs to its
interruptible customers as discussed in the body of this order.
By the Commission.
Lois D. Cashell,
Secretary.
[FR Doc. 97-5363 Filed 3-5-97; 8:45 am]
BILLING CODE 6717-01-P
