10204 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

1United 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).

2Pipeline 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.

¶ 30,939 (1992), order on reh’g, Order No. 636–A,

[Regs. Preambles Jan. 1991–June 1992] FERC Stats.

& Regs. ¶ 30,950 (1992), order on reh’g, Order No.

636–B, 61 FERC ¶ 61,272 (1992), reh’g denied, 62

FERC ¶ 61,007 (1993).

3UDC, 88 F.3d at 1191.

§ 95.8003 VOR Federal Airways Changeover Points Airway Segment V–76 Is Amended to Delete

From To

Changeover points

Distance From

Lubbock, TX VORTAC ...................................................... Big Spring, TX VORTAC ................................................. 71 Lubbock

V–81 is Amended to Delete

Lubbock, TX VORTAC ...................................................... Midland, TX VORTAC ...................................................... 71 Lubbock

[FR Doc. 97–5549 Filed 3–5–97; 8:45 am]

BILLING CODE 4910–13–M

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.

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 SelfImplementing 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.

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
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10205

4Order No. 636, [Regs. Preambles Jan. 1991—June

1996] FERC Stats. & Regs. at 30,393.

5The 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 firmtransportation 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.

6UDC, 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.

16 Id. at 1174.

17 Id.

18 Id.

19 Id. at 1175.

20 Id. at 1174–75.

21 Id. at 1188.

22 Id. at 1187.

23 Id. at 1190.

24 Id. at 1189.

25Energy Info. Agency, DOE, No. DOE–EIA–

0560(96), Natural Gas Issues and Trends (Dec.

1996).

26Wheeling, 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.

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.

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 newconstruction contracts in arriving at the

twenty-year figure.15

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

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

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.

In addition to the information

provided by electronic trading services,

electronic information services offer

capacity release and tariff information
10206 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

27Since 1990, futures contracts have provided

information about expected prices each month for

the next two years, and these prices are reported

daily.

28This estimate is derived from downloaded data

posted on pipelines’ electronic bulletin boards as

required by 18 CFR § 284.10(b).

29For example, in Tennessee Gas Pipeline Co.,

Opinion No. 406, 76 FERC ¶ 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 ¶61,021 at 61,061 (1996) (discussing

the significance of segmenting capacity).

30For 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 ¶ 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.

32For 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.

33Natural Gas Pipeline Co. of America, 73 FERC

¶ 61,050 (1995).

34El Paso Natural Gas Co., 72 FERC ¶ 61,083

(1995) (rejecting El Paso’s proposed ‘‘exit fee’’ to

reallocate costs associated with turned-back

capacity); Transwestern Pipeline Co., 72 FERC

¶ 61,085 (1995) (approving a settlement including a

mechanism to share the costs and burdens

associated with capacity relinquishment).

35Tennessee Gas Pipeline Co., 77 FERC ¶ 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 ¶61,270 (1996) (deferring potential

capacity turn-back issues until closer to the

expiration date of the contracts at issue).

36Alternatives 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 ¶ 61,091 at

61,310 (1996).

37Secondary Market Transactions on Interstate

Natural Gas Pipelines, 61 FR 41046 (1996), IV FERC

Stats. & Regs. ¶32,520 (to be codified at 18 CFR part

284) (proposed July 31, 1996).

38Standards for Business Practices of Interstate

Natural Gas Pipelines, Order No. 587, 61 FR 39053

(1996), III FERC Stats. & Regs. ¶ 31,038 (1996) (to

be codified at 18 CFR parts 161, 250, and 284).

39Standards for Business Practices of Interstate

Natural Gas Pipelines, 61 FR 58790 (1996), IV FERC

Stats. & Regs. ¶32,521 (to be codified at 18 CFR part

284) (proposed Nov. 13, 1996).

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.

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

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

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.

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-bycustomer 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 ‘‘nonotice’’ 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
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10207

40UDC, 88 F.3d at 1137.

41 18 CFR 284.8(a)(4).

42Order No. 636-A, [Regs. Preambles Jan. 1991-

June 1996] FERC Stats. & Regs. at 30,573.

43UDC, 88 F.3d at 1137.

44 Id.

45 Id.

46 Id.

47For 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.

48For 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.

50The 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.

51Order No. 636, [Regs. Preambles Jan. 1991-June

1996] FERC Stats. & Regs. at 30,402.

52For 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.’’).

54Questar Pipeline Co., 64 FERC ¶ 61,157 (1993).

customers eligible for firm sales service

at the time of restructuring.

The Court remanded for further

explanation of this limitation on the nonotice 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 nonotice 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.

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 nonotice 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 nonotice transportation eligibility to the

Commission for further explanation.46

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

In light of such uncertainty, the

Commission decided to limit the

requirement for pipelines to offer nonotice 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 nonpipeline 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

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.

Some pipelines have, postrestructuring, expanded their offering of

no-notice service. While Williams

Natural Gas Company (Williams)
10208 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

55Williams Natural Gas Co., 65 FERC ¶ 61,221

(1993), reh’g denied, FERC ¶ 61,315 (1994).

56Williams Natural Gas Co., 77 FERC ¶ 61,277

(1996).

57Mid Louisiana Gas Co., 76 FERC ¶ 61,212

(1996).

58Foster Natural Gas Report, No. 2098 (Sept. 9,

1996).

59 18 CFR 284.8(b)(1).

60Regulation of Natural Gas Pipelines After

Partial Wellhead Decontrol, Order No. 436, [Regs.

Preambles 1982–1985] FERC Stats. & Regs. ¶ 30,665

at 31,516–17 (1985).

61 In the restructuring proceedings of AlabamaTennessee 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.

62 UDC, 88 F.3d at 1140.

63 Id.

64 Id. at 1140–41.

65 Id. at 1140.

66The 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.

67 Id. at 1141.

68 Id.

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 nonotice 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.

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.

The Commission cannot retroactively

change Order No. 636’s limitation on

the pipeline’s requirement to offer nonotice 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 nondiscriminatory basis to all customers

who request it, under the

nondiscriminatory access provision in

§ 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 openaccess 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).

The Commission believes that a

prospective change in policy based on

current circumstances will satisfy the

needs of all shippers who desire nonotice 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 nonotice service beyond the Commission’s

basic requirement. However, to the

extent there are shippers who desire nonotice 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.

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 termmatching 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

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

The right-of-first-refusal mechanism

was, and is, intended to protect existing
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10209

69Order No. 636–A, [Regs. Preambles Jan. 1991–

June 1996] FERC Stats. & Regs. at 30,630.

70UDC, 88 F.3d at 1140.

71 Id.

72 Id.

73 Id. at 1141 n.44.

74Revisions 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. ¶ 31,026

(1995), reh’g, Order No. 581–A, [Regs. Preambles

Jan. 1, 1991–June 1996] FERC Stats. & Regs. ¶

31,032 (1996).

75 18 CFR 284.106(c).

76Using 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.

77Appendix A, p. 1.

78Appendix A, p. 2.

79Williams Natural Gas Co., 69 FERC ¶ 61,166

(1994), reh’g, 70 FERC ¶ 61,100 (1995), reh’g, 70

FERC ¶ 61,377 (1995), appeal pending sub nom.

City of Chanute v. FERC, No. 95–1189 (D.C. Cir.).

80UDC, 88 F.3d at 1141.

81Sept. 2, 1992 Request for Rehearing and

Clarification at 13.

82Sept. 2, 1992 Request for Rehearing at 6.

83E.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.

84The 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

Continued

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.

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

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

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 longterm 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

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.

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 fiveyear 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.

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 longterm 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
10210 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

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.

85UDC, 88 F.3d at 1174.

86 Id. (quoting Pipelines’ Brief at 27).

87 Id.

88 Id. at 1170.

89Order No. 636–B, 61 FERC at 62,014.

90 Id. at 62,016.

91 Id.

92Northwest Pipeline Corp., 63 FERC ¶ 61,130

(1993), order on reh’g 65 FERC ¶ 61,055 (1994);

Mississippi River Transmission Corp., 64 FERC

¶ 61,299 (1993).

93The 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.

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

¶ 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 ¶ 61,344 (1995), order on

reh’g, 74 FERC ¶ 61,144 (1996); Order on Motion

Rates and Request for Stay, 74 FERC ¶ 61,081

(1996).

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-bycase 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. CustomerClass 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 customerby-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

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.

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 customerby-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-bycustomer 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.

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
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10211

95Section 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. ¶ 20,000

et seq. (regulatory text), III FERC Stats. & Regs

¶ 31,026 (1995) (preamble).

96Order No. 636–B, 61 FERC at 62,020.

97UDC, 88 F.3d at 1174–75.

98 Id. at 1174.

99 Id. at 1175.

100Order No. 636-B, 61 FERC at 62,019.

101The 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.

102Texas Eastern Transmission Corp., 30 FERC

¶ 61,144 at 61,288 (1985).

103Tennessee Gas Pipeline Co., 27 FERC ¶ 63,090

at 65,375 (1984).

104Order No. 636–B, 61 FERC at 62,019.

105See 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 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.

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 smallcustomer transportation rate to those

customers that were eligible for a smallcustomer 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

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

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

Any changes in the size of the

subsidized, small customer class on a

pipeline necessarily affect the pipeline’s

other customers. Under traditional costbased 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 higherthan-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

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 smallcustomer 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

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
10212 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

106Customers of Tennessee’s downstream

pipelines include East Tennessee Customer Group

and Tennessee Valley, the petitioners on this issue

in UDC.

107East 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 ¶ 61,102 (1993); Midwestern Gas

Transmission Co., 63 FERC ¶ 61,099 (1993); and

Alabama-Tennessee Natural Gas Co., 63 FERC

¶ 61,054 (1993).

108Tennessee Gas Pipeline Co., 65 FERC ¶ 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).

109 88 F.3d at 1188.

110 Id. at 1190.

111 Id. at 1188 (emphasis in original).

112Regulation of Natural Gas Pipelines after

Partial Wellhead Decontrol, Order No. 500–H,

[Regs. Preambles 1986–1990] FERC Stats. & Regs. ¶

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).

113Associated Gas Distributors v. FERC, 824 F.2d

981 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006

(1988).

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 preexisting 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

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-bycase basis, the eligibility of customers of

downstream pipelines for the upstream

pipeline’s small-customer rate.

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.

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.

In the face of these extraordinary

market conditions, the Commission

adopted extraordinary measures. As
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10213

114The 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.

115Trunkline Gas Co., 72 FERC ¶ 61,265 (1995);

Williston Basin Interstate Pipeline Co., 70 FERC

¶ 61,009 (1995).

116On 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 ¶ 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

¶ 61,163 at 61,594 (1990).

118On 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 ¶ 61,221 (1996).

The Commission has approved settlements of

ANR’s first three GSR proceedings. ANR Pipeline

Co., 72 FERC ¶ 61,130 (1995); 74 FERC ¶ 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 ¶ 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 ¶ 61,322

at 62,329–30, 62,355–6 (1995), reh’g denied, 75

FERC ¶ 61,046 (1996).

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

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.

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
10214 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

121 /Panhandle Eastern Pipe Line Co., 72 FERC

¶ 61,108 (1995).

122 163 F.2d 433, 437 (D.C. Cir. 1947).

123Tennessee 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’’).

124The Commission’s only requirement for

pipelines to continue to offer to sell gas at costbased 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.

125See Texas Eastern Transmission Co., 65 FERC

¶ 61,363 (1993).

126Regulation of Natural Gas Pipelines after

Partial Wellhead Decontrol, Order No. 500–H,

[Regs. Preambles 1986–1990] FERC Stats. & Regs.

¶ 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.

129As 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

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.

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:

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.

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.

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.

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
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10215

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.

130 Id.

131The residential cost of gas rose from $5.17 in

1982 to $6.12 in 1984. Id.

132Elimination of Variable Costs from Certain

Natural Gas Pipeline Minimum Bill Provisions,

Order No. 380, [Regs. Preambles 1982–1985] FERC

Stats. Regs. ¶ 30,571 (1984).

133 Id.

134 Id. at 31,513.

135 Id.

136Regulatory Treatment of Payments Made in

Lieu of Take-or-Pay Obligations, Regulations

Preambles 1982–85 ¶ 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

¶ 30,867 at 31,514.

138Regulatory Treatment of Payments Made in

Lieu of Take-or-Pay Obligations, [Regs. Preambles

1982–85] Stats & Regs. ¶ 30,637 (1985).

139 968 F.2d 1295, 1301 (D.C. Cir. 1992).

140Order No. 500 also increased the pipelines’

bargaining power to negotiate settlements with

producers through the take-or-pay crediting

program.

141The 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).

142UDC, 88 F.3d at 1188.

143Order No. 528–A, 54 FERC ¶ 61,095 (1991).

144The 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

Continued

surplus persisted for the remainder of

the 1980s.

This unexpected change in market

conditions caused pipelines, as early as

1982, to start incurring significant takeor-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.

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

In short, although Order No. 436

exacerbated pipelines’ existing take-orpay 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-orpay 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 makeup provisions in the contract.136 By

1983, however, with their total take-orpay exposure over $5 billion, the

pipelines could not manage their takeor-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.

Because pipelines had never

previously incurred significant take-orpay 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.

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

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,
10216 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

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.

145Order No. 500–H, [Regs. Preambles 1986–

1990] FERC Stats. & Regs. at 31,575.

146Order No. 528A, 54 FERC at 61,303–5 (1991).

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.

148Similarly, 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. ¶ 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.

149See Id. at 31,522–3 and 31,536.

150See Appendix B, Table 1.

151Southern Natural Gas Co., 72 FERC ¶ 61,322 at

62,358 (1995).

152However, 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.

153ANR Pipeline Co., 59 FERC ¶ 61,347, reh’g, 60

FERC ¶ 61,145 (1992).

154 18 CFR 284.11(d)(3).

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-orpay 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

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-orpay liabilities, there was no longer an

industry-wide take-or-pay problem.147

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

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

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.

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
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10217

155See Table 1.

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

157Order No. 636, [Regs. Preambles Jan. 1991-June

1996] FERC Stats. & Regs. at 30,662.

158See Equitrans, Inc. 64 FERC ¶ 61,374 at 63,601

(1993).

159UDC, 88 F.3d at 1178–80.

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-orpay 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.

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.

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

¶ 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.

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.
10218 Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations

160See UDC, 88 F.3d at 1189.

161West 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.

162Public 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’’).

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 ¶61,305 at 62,196 (1995); 75 FERC

¶ 61,039 at 61,125–6 (1996); 76 FERC ¶ 61,096 at

61,506 (1996).

164UDC, 88 F.3d at 1187.

165 Id. at 1187–88.

166Williams Natural Gas Co., 75 FERC ¶ 61,022 at

61,071, reh’g denied, 76 FERC ¶ 61,092 (1996).

167The 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 ¶ 61,174

(1994), and 68 FERC ¶ 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.

168UDC, 88 F.3d at 1187.

169 Id.

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

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

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

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

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

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,

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

These benefits received by

interruptible customers clearly justify
Federal Register / Vol. 62, No. 44 / Thursday, March 6, 1997 / Rules and Regulations 10219

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.

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).

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-offirst-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

DEPARTMENT OF HEALTH AND

HUMAN SERVICES

Food and Drug Administration

21 CFR Part 522

Implantation or Injectable Dosage

Form New Animal Drugs; Sarafloxacin

Hydrochloride

AGENCY: Food and Drug Administration,

HHS.

ACTION: Final rule.

SUMMARY: The Food and Drug

Administration (FDA) is amending the

animal drug regulations to reflect

approval of a supplemental new animal

drug application (NADA) filed by

Abbott Laboratories. The supplement

provides for use of sarafloxacin

hydrochloride solution for injection in

18-day embryonated broiler eggs for

control of early chick mortality

associated with Escherichia coli

organisms susceptible to sarafloxacin.

EFFECTIVE DATE: March 6, 1997.

FOR FURTHER INFORMATION CONTACT:

George K. Haibel, Center For Veterinary

Medicine (HFV–133), Food and Drug

Administration, 7500 Standish Pl.,

Rockville, MD 20855, 301–594–1644.

SUPPLEMENTARY INFORMATION: Abbott

Laboratories, 1401 Sheridan Rd., North

Chicago, IL 60064–4000, filed a

supplement to NADA 141–018 that

provides for use of sarafloxacin

hydrochloride solution for injection

(SaraFlox Injection) in 18-day

embryonated broiler eggs in addition to

approved use in day-old broiler

chickens for control of early chick

mortality associated with E. coli

organisms susceptible to sarafloxacin.

The supplement is approved as of

January 21, 1997, and the regulations

are amended by revising 21 CFR

522.2095(d) to reflect the approval. The

basis of approval is discussed in the

freedom of information summary.

In accordance with the freedom of

information provisions of 21 CFR part

20 and 514.11(e)(2)(ii), a summary of

safety and effectiveness data and

information submitted to support

approval of this application may be seen

in the Dockets Management Branch

(HFA–305), Food and Drug

Administration, 12420 Parklawn Dr.,

rm. 1–23, Rockville, MD 20857, between

9 a.m. and 4 p.m., Monday through

Friday.

Under section 512(c)(2)(F)(iii) of the

Federal Food, Drug, and Cosmetic Act

(21 U.S.C. 360b(c)(2)(F)(iii)), this

approval qualifies for 3 years of

marketing exclusivity beginning January

21, 1997, because this supplement

contains substantial evidence of the

effectiveness of the drug involved,

studies of animal safety, or human food

safety studies (other than

bioequivalence or residue studies),

required for approval and conducted or

sponsored by the applicant. Marketing

exclusivity applies only to use in 18-day

embryonated broiler eggs.

The agency has carefully considered

the potential environmental effects of

this action. FDA has concluded that the

action will not have a significant impact

on the human environment, and that an

environmental impact statement is not

required. The agency’s finding of no

significant impact and the evidence

supporting that finding, contained in an

environmental assessment, may be seen

in the Dockets Management Branch

(address above) between 9 a.m. and 4

p.m., Monday through Friday.

List of Subjects in 21 CFR Part 522

Animal drugs.

Therefore, under the Federal Food,

Drug, and Cosmetic Act and under

authority delegated to the Commissioner