[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.
---------------------------------------------------------------------------

    \58\ Foster Natural Gas Report, No. 2098 (Sept. 9, 1996).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.

---------------------------------------------------------------------------

[[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.
---------------------------------------------------------------------------

    \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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \155\ See Table 1.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \156\ Order No. 528-A, 54 FERC at 61,304.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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'').
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \164\ UDC, 88 F.3d at 1187.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \165\ Id. at 1187-88.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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