Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-94-01256/USCOURTS-caDC-94-01256-0/pdf.json

Parties Involved:
Federal Energy Regulatory Commission
Respondent
Tennessee Valley Municipal Gas Association
Petitioner

Document Text:

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United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued February 21, 1996 Decided July 16, 1996

No. 92-1485

UNITED DISTRIBUTION COMPANIES,

PETITIONER

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

WINDWARD ENERGY & MARKETING COMPANY, ET AL.,

INTERVENORS

Consolidated with

92-1495, 92-1496, 94-1171, 94-1173, 94-1174, 94-1175,

94-1176, 94-1177, 94-1178, 94-1179, 94-1180, 94-1181,

94-1183, 94-1184, 94-1185, 94-1187, 94-1188, 94-1189,

94-1190, 94-1193, 94-1194, 94-1196, 94-1197, 94-1198,

94-1200, 94-1201, 94-1206, 94-1207, 94-1209, 94-1213,

94-1215, 94-1217, 94-1218, 94-1222, 94-1223, 94-1226,

94-1228, 94-1229, 94-1231, 94-1232, 94-1233, 94-1234,

94-1236, 94-1237, 94-1238, 94-1239, 94-1240, 94-1241,

94-1242, 94-1243, 94-1246, 94-1247, 94-1248, 94-1249,

94-1252, 94-1256, 94-1257, 94-1258, 94-1259, 94-1263,

94-1264, 94-1265, 94-1267, & 94-1270

On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

Frederick Moring, Roy R. Robertson, Jr., Michael W. Hall, O. Julia

Weller, Roberta L. Halladay, Daniel F. Collins, Robert T. Hall,

III, Harvey L. Reiter, Lee A. Alexander, Edward J. Grenier, Jr.,

Charles F. Wheatley, Jr., John P. Gregg, John T. Miller, David W.

D'Alessandro, Denise C. Goulet and Philip M. Marston argued the

causes for petitioners, with whom Dana C. Contratto, John E.

Holtzinger, Jr., Kevin M. Downey, Kenneth T. Maloney, William I.

Harkaway, Donald K. Dankner, Frederick J. Killion, Jeffrey L.

Futter, Stephen L. Huntoon, Douglas M. Canter, Mary E. Baluss,

Kristine L. Delkus, Christopher J. Barr, John K. Keane, Jr.,

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Telemac N. Chryssikos, James K. Mitchell, Paul K. Sandness, Kevin

J. Lipson, Scott Silverstein, Janice A. Alperin, Christine R.

Pembroke, Kenneth M. Simon, Mitchell F. Hertz, Randolph Q. McManus,

William L. Slover, Donald G. Avery, Andrew B. Kolesar, III,

Laurence E. Skinner, William I. Harkaway, Michael W. Hall, William

H. Penniman, Glen S. Howard, Sterling H. Smith, Gail S. Gilman,

Thomas E. Hirsch, III, David K. Schumacher, Frederic G. Berner,

Jr., Nancy Y. Gorman, Debra L. Raggio Bolton, Susan N. Kelly,

William T. Miller, Elisabeth R. Myers-Kerbal, Glenn W. Letham,

Steven M. Sherman, Don C. Uthus, Timothy P. Ingram, Richard A.

Rapp, Jr., Jennifer N. Waters, Kelly A. Daly, Edward W. O'Neill,

Harvey Y. Morris, Theresa V. Czarski, Paula M. Carmody, Diane

Munns, Lawrence F. Barth, Veronica A. Smith, John F. Povilaitis,

Harold L. Stoller, Jr., Penny G. Baker, Helene S. Wallenstein,

Thomas B. Nicholson, Charles D. Gray, Robert S. Tongren, Margaret

Ann Samuels, Jospeh P. Serio, Yvonne Ranft, Deborah Y. VanDervort,

Robert J. Mussallem, Darrell S. Townsley, Ellen M. Averett, Richard

A. Solomon, Robert K. Johnson, William H. Smith, Jr. and Kim M.

Clark were on the briefs. Jack M. Wilhelm, Robin M. Nuschler,

Douglas J. Law, Kathleen L. Mazure, Phillip G. Lookadoo, Toni M.

Fine, John T. Stough, Jr., Robert I. White, Jacolyn A. Simmons,

Kent D. Murphy, Marc Richter, Richard A. Rapp, Jr., Don S. Smith,

Steven A. Weiler, Paul W. Fox, Kevin J. McIntyre, Scott S. Ives,

Donald C. Shepler, Jr., James Howard, Robert S. Hall, Jr., James F.

Bowe, Jr., Steven H. Lasher, Donald G. Avery, David C. Dickey,

Robert F. Shapiro, Jack M. Irion, Philip B. Malter, Harold L.

Talisman, Jeanne M. Bennett and Robert H. Benna entered

appearances.

Jerome M. Feit, Solicitor, Federal Energy Regulatory Commission,

Joseph S. Davies, Deputy Solicitor and Susan J. Court, Special

Counsel, argued the causes for respondent, with whom Timm L.

Abendroth, Eric L. Christensen, Randolph L. Elliott, Edward S.

Geldermann and Janet K. Jones, Attorneys, were on the brief.

Thomas J. Lane and Jill Hall, Attorneys, entered appearances.

Henry S. May, Jr. argued the cause for intervenors, with whom Judy

M. Johnson, Clifton S. Rankin, Richard J. Kruse, Jeffrey D.

Komarow, James W. McTarnaghan, Allan W. Anderson, Jr., David K.

Schumacher, Frederick T. Kolb, Daniel F. Collins, Janice A.

Alperin, Christine R. Pembroke, Michael W. Hall, Michael J.

Manning, Kenneth R. Carretta, James P. White, William T. Miller,

John P. Gregg, Elisabeth R. Myers-Kerbal, Emery J. Biro, III, Norma

J. Rosner, David G. Stevenson, Bruce A. Connell, MaryJane Reynolds,

Leslie J. Lawner, Jane E. Wilson, Joseph R. Hartsoe, R. Brent

Harshman, Richard C. Green, Douglas W. Rasch, John H. Cheatham,

III, Bud J. Becker, O. Julia Weller, Paul F. O'Konski, Marge

O'Connor, Kenneth E. Randolph, Jeffrey G. DiSciullo, Edward J.

Grenier, Jr., William H. Penniman, Glen S. Howard, Sterling H.

Smith, Charles F. Wheatley, Jr., Don C. Uthus, Timothy P. Ingram,

Paul Korman, Paul W. Mallory, Charles L. Pain, Kathleen T. Puckett,

James J. Cleary, R. David Hendrickson, Patrick P. Pope, Ralph J.

Pearson, Jr., Linda L. Geoghegan, Marilyn L. Doria, Blaine Yamagata

and James Denvir were on the brief. Donald C. Shepler, Jr., James

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*PARTS III AND V.A-B, E.3-4 AND F ARE BY JUDGE WALD; PARTS IV AND

V.C-D AND E.1-2 ARE BY JUDGE SENTELLE; AND PARTS I AND II ARE BY JUDGE

ROGERS.

F. Bowe, Jr., Jean E. Sonneman, Kenneth T. Maloney, Gordon Gooch,

J. Stephen Martin, Katherine B. Edwards, Mario M. Garza, Mark R.

Haskell, J. Paul Douglas, Luke A. Mickum, Leslie J. Lawner, Deborah

A. Macdonald, Sherrie N. Rutherford, Clifton D. Harris, Jr.,

Frederick W. Giroux, Mark D. Foss, Marge O'Connor, James K. Morse,

Kevin M. Sweeney, James P. White, Michael J. Manning, Charles J.

McClees, Michael A. Kelly, F. Nan Todd Wagoner, Janice H. Parker,

Andrew N. Greene, Elisabeth Y. Pendley, Emmitt C. House, Georgetta

J. Baker, Paul E. Goldstein, Frank X. Kelly, Maria K. Pavlou, Steve

Stojic, Merlin E. Remmenga, David B. Ward, Robert Baker and G. Mark

Cook entered appearances.

Appearances were also filed by Carl M. Fink, Howard E. Shapiro,

James C. Moffatt, Jennifer B. Corwin, Robert A. Nuernberg, Ronald

D. Eastman, Oleta J. Harden, Barbara K. Heffernan, Cheryl L. Jones,

Tom Rattray, Gearold L. Knowles, Margaret Ann Samuels, David C.

Dickey, Thomas E. Hirsch, III, Britton White, Jr., James D. Senger,

James J. Flood, Joel F. Zipp, Leja D. Courter, Ronald E. Christian,

James C. Moffatt, Shippen Howe, John R. Staffier, Robert A. Nelson,

Timothy C. Bladek, Andrew N. Greene, Edward B. Myers, Carolyn Y.

Thompson, Kenneth D. Brown, Frank R. Lindh, Keith T. Sampson,

Raymond N. Shibley, Cheryl J. Walker, Thomas J. Eastment, Michael

L. Pate, Barbara S. Jost, Michael E. Small, Robin M. Nuschler, John

C. Walley, Gary E. Guy, Stephen J. Small, Susan D. McAndrew,

Timothy N. Black, David W. Anderson, David L. Huard, David J.

Evans, George H. Rothschild, Jr., Charles H. Shoneman, Randall S.

Rich, Joel L. Greene, Joseph M. Oliver, Jr., M. Lisanne Crowley,

Mark C. Darrell, John B. Chapman, John K. McDonald, Richard E.

Powers, Jr., Sylvia P. McCormack, Jeffrey M. Petrash, Phillip G.

Lookadoo, J. Neises, S.D. Holbrook, James D. McKinney, Jr., John J.

Wallbillich, Joshua L. Menter, Jack P. Grimaldi, J.D. Steelman,

Jr., Nicholas W. Fels, Anthony J. Ivancovich, Rebecca S. Haney,

John S. Grube, Stuart W. Conrad, Robert B. Langstaff, Michael J.

Gianunzio, David W. Rubadue, Marilyn A. Specht, Paul W. Fox, Bruce

F. Kiely, Mark K. Lewis, Jack M. Wilhelm, Michael R. Waller, Mark

C. Moench, Paul M. Flynn, Frederick J. Killion, Michael Thompson,

Wade H. Hargrove, Jr., Donald W. McCoy, Bruce Henderson, Kris L.

Terry, Joseph M. Marcoux, Elizabeth A. Ward, Philip F. Cronin, Jr.,

Stephen L. Huntoon, Nancy J. Skancke, Timothy A. Beverick, Kenton

L. Erwin, Scott P. Klurfeld, David B. Robinson, Anita T. Gallucci,

Michael P. May, Daniel J. Guttman, Jr., William Bingham, James H.

Holt, Don P. Garber, Floyd L. Norton, IV, Dennis D. Ahlers, David

I. Bloom, Thomas M. Patrick, John M. Hopper, Jr., Mary A. Walker,

Joseph E. Mixon, Nancy J. Skancke, Cecil W. Talley and Arthur L.

Smith.

Before: WALD, SENTELLE and ROGERS, Circuit Judges.

Opinion for the Court filed PER CURIAM.*

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TABLE OF CONTENTS

I. INTRODUCTION............................................. 9

A. Background: Natural Gas Industry Structure................................................. 9

B. Order No. 436: Open-Access Transportation........... 12

C. Order No. 636: Mandatory Unbundling................. 16

D. Issues on Review and Conclusions.................... 19

II. OPEN-ACCESS FIRM TRANSPORTATION......................... 25

A. Unbundling.......................................... 25

1. Prohibition on unilateral customer release of transportation capacity................ 25

2. Pipeline modification of contract-storage

rights.......................................... 32

3. Capacity retention by transportationonly pipelines.................................. 37

4. Eligibility date for no-notice transportation............................................ 38

B. Right of First Refusal.............................. 39

1. Pre-granted abandonment generally............... 42

2. The twenty-year contract term................... 45

3. Requirement to discount......................... 48

C. Curtailment......................................... 50

1. Supply curtailment of pipeline gas.............. 54

2. Capacity curtailment............................ 57

3. Supply curtailment of third-party gas........... 60

III. CAPACITY RELEASE........................................ 63

A. Introduction........................................ 63

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B. Jurisdictional Challenges........................... 67

1. FERC's jurisdiction to regulate capacity

release......................................... 69

2. Jurisdiction over LDCs' capacity sales

to their own end-users.......................... 71

3. Jurisdiction over municipal capacity release........................................... 72

4. Jurisdiction over "buy/sell" arrangements........................................... 75

a. Introduction to federal preemption.......... 76

b. Analysis.................................... 77

C. Substantive Challenges.............................. 81

1. Exclusion of Part 157 shippers from capacity release.................................. 81

2. The standard for determining the best

bid............................................. 84

3. Interruptible transportation revenue

crediting....................................... 86

D. Conclusion.......................................... 88

IV. RATE DESIGN............................................. 88

A. FERC's Authority to Adopt SFV Rate

Design.............................................. 89

1. MFV rate design's anticompetitive effects........................................... 89

2. SFV rate design and NGA § 5..................... 92

B. SFV Rate Design and Substantial Evidence............ 99

1. MFV rate design's distortions of the

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natural gas market.............................. 99

2. FERC's choice of SFV rate design............... 102

a. LDCs' claim................................ 102

b. PUCs' claim................................ 103

c. Electric Generators' claim................. 104

d. Small Distributors' and Municipalities' claim................................ 105

3. Regulatory Flexibility Act..................... 105

C. FERC's Discretion to Adopt Mitigation

Measures........................................... 106

1. Background..................................... 106

2. Justifications for mitigation measures......... 108

3. Non-permanence of mitigation measures.......... 110

4. Impact on pipeline rate of return.............. 111

5. Individual customer vs. customer class......... 112

6. Discounts for former customers of

downstream pipelines........................... 114

7. Triennial rate review.......................... 115

V. TRANSITION COSTS....................................... 117

A. Background to Transition Costs..................... 117

1. Order No. 436 and its successors............... 117

2. Order No. 636 and petitioners' challenges......................................... 119

B. Stranded Costs and the "Used and Useful"

Doctrine........................................... 121

C. LDC Bypasses....................................... 125

D. Above-Market Recovery for Great Plains

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1 Order No. 636, Pipeline Service Obligations and Revisions

to Regulations Governing Self-Implementing Transportation Under

Part 284 of the Commission's Regulations, and Regulation of

Natural Gas Pipelines After Partial Wellhead Decontrol, [Current]

F.E.R.C. Stats. & Regs. (CCH) ¶ 30,939, order on reh'g, Order No.

636-A, [Current] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,950, order on

reh'g, Order No. 636-B, 61 F.E.R.C. ¶ 61,272 (1992), reh'g

denied, 62 F.E.R.C. ¶ 61,007 (1993). 

Gas................................................ 127

E. GSR Costs.......................................... 128

1. Ripeness of petitioners' challenges to

FERC's treatment of GSR transition

costs........................................... 130

2. Gas producers' exemption from GSR

costs.......................................... 132

3. Allocation of GSR costs among customer

classes........................................ 133

a. "Cost spreading" and "value of service"...................................... 134

b. Petitioners' challenges.................... 135

1.) Limitation to bundled sales customers............................... 135

2.) Interruptible transportation

customers............................. 137

4. Pipelines' exemption from GSR costs............ 140

F. Conclusion......................................... 146

VI. CONCLUSION............................................. 147

PER CURIAM:

I. Introduction

In Order No. 636,1 the Federal Energy Regulatory Commission

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2 In 1954, Congress added the "Hinshaw exemption," which

excludes from the Commission's jurisdiction gas that is received

within a state (or at the state boundary) and is consumed within

that state, provided that the gas is subject to state regulation. 

NGA § 1(c), 15 U.S.C. § 717(c). 

("Commission" or "FERC") took the latest step in its decade-long

restructuring of the natural gas industry, in which the Commission

has gradually withdrawn from direct regulation of certain industry

sectors in favor of a policy of "light-handed regulation" when

market forces make that possible. We review briefly the regulatory

background for natural gas.

A. Background: Natural Gas Industry Structure

The natural gas industry is functionally separated into

production, transportation, and distribution. Traditionally,

before the move to open-access transportation, a producer extracted

the gas and sold it at the wellhead to a pipeline company. The

pipeline company then transported the gas through high-pressure

pipelines and re-sold it to a local distribution company (LDC).

The LDC in turn distributed the gas through its local mains to

residential and industrial users. See generally EDWARD C. GALLICK,

COMPETITION IN THE NATURAL GAS INDUSTRY 9-12 (1993).

The Natural Gas Act (NGA), ch. 556, 52 Stat. 821 (1938)

(codified as amended at 15 U.S.C. §§ 717-717w (1994)), enacted in

1938, gave the Commission jurisdiction over sales for resale in

interstate commerce and over the interstate transportation of gas,

but left the regulation of local distribution to the states.2 NGA

§ 1(b), 15 U.S.C. § 717(b). The NGA was intended to fill the

regulatory gap left by a series of Supreme Court decisions that

interpreted the dormant Commerce Clause to preclude state

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3 The seminal analysis of pipelines' market power over

transportation can be found in the Federal Trade Commission (FTC)

report that led to the enactment of the NGA. See SEN. DOC. NO.

92, pt. 84A, 70th Cong., 1st Sess. (1935). 

4 A natural monopoly occurs when, because of the high ratio

of fixed costs to variable costs, a single firm has declining

average costs at the level of demand in the industry, such that

the single firm can supply the service more cheaply than two

firms could. RICHARD A. POSNER, ECONOMIC ANALYSIS OF LAW § 12.1, at

343-45 (4th ed. 1992). 

5 We use the term "captive customer" to refer to customers

"who must use gas and can only obtain it from one provider." 

Mississippi Valley Gas Co. v. FERC, 68 F.3d 503, 506 (D.C. Cir.

1995); see also Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1150,

1160 (D.C. Cir. 1985) ("[F]ull requirements [or "captive']

customers purchase their entire natural gas supply from one

pipeline and, because of their geographical location, are unable

to swing off the system to obtain cheaper supplies of gas."). 

6 As of 1985, 10% of gas deliveries were to LDCs served by

four or more pipelines, 39.5% to LDCs served by three pipelines,

28% to LDCs served by two pipelines, and 22.5% to LDCs served by

a single pipeline. STEPHEN F. WILLIAMS, THE NATURAL GAS REVOLUTION OF

regulation of interstate transportation and of wholesale gas sales.

See Arkansas Elec. Coop. Corp. v. Arkansas Pub. Serv. Comm'n, 461

U.S. 375, 377-80 (1983). The overriding purpose of the NGA is "

"to protect consumers against exploitation at the hands of natural

gas companies.' " FPC v. Louisiana Power & Light Co., 406 U.S.

621, 631 (1972) (quoting FPC v. Hope Natural Gas Co., 320 U.S. 591,

610 (1944)). Federal regulation of the natural gas industry is

thus designed to curb pipelines' potential monopoly power over gas

transportation.3 The enormous economies of scale involved in the

construction of natural gas pipelines tend to make the

transportation of gas a natural monopoly.4 Indeed, even with the

expansion of the national pipeline grid, or network, in recent

decades, many "captive" customers5 remain served by a single

pipeline.6 Order No. 436, ¶ 30,665, at 31,473.7

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1985, at 4 (1985). 

7 Order No. 436, Regulation of Natural Gas Pipelines After

Partial Wellhead Decontrol, [Regs. Preambles 1982-85] F.E.R.C.

Stats. & Regs. (CCH) ¶ 30,665, order on reh'g, Order No. 436-A,

[Regs. Preambles 1982-85] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,675

(1985), order on reh'g, Order No. 436-B, [Regs. Preambles 1986-

90] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,688, order on reh'g, Order

No. 436-C, 34 F.E.R.C. ¶ 61,404, order on reh'g, Order No. 436-D,

34 F.E.R.C. ¶ 61,405, order on reh'g, Order No. 436-E, 34

F.E.R.C. ¶ 61,403 (1986), vacated and remanded sub nom.

Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir.

1987) (AGD I), cert. denied, 485 U.S. 1006 (1988). 

Even though the market function potentially subject to

monopoly power is the transportation of gas, for many years the

Commission also regulated the price and terms of sales by producers

to interstate pipelines. See Phillips Petroleum Co. v. Wisconsin,

347 U.S. 672, 677-84 (1954). Producer price regulation was widely

regarded as a failure, introducing severe distortions into what

otherwise would have been a well-functioning producer sales market.

See STEPHEN G. BREYER & PAUL W. MACAVOY, ENERGY REGULATION BY THE FEDERAL POWER

COMMISSION 56-88 (1974). When a severe gas shortage developed in the

1970s, Congress enacted the Natural Gas Policy Act of 1978 (NGPA),

Pub. L. No. 95-621, 92 Stat. 3351 (codified as amended at 15 U.S.C.

§§ 3301-3432 (1994)), which gradually phased out producer price

regulation. Under the NGPA's partially regulated producer-price

system, many pipelines entered into long-term contractual

obligations, in what were known as "take-or-pay" provisions, to

purchase minimum quantities of gas from producers at costs that

proved to be well above current market prices of gas. See Richard

J. Pierce, Jr., Reconstituting the Natural Gas Industry from

Wellhead to Burnertip, 9 ENERGY L.J. 1, 11-16 (1988).

The problem of pipelines' take-or-pay settlement costs has

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8 First, the Commission approved special marketing programs,

under which pipelines agreed to transport third-party gas to

industrial end-users in exchange for the producer's agreement to

credit the transported gas to the pipeline's take-or-pay

liability. See Columbia Gas Transmission Corp., 25 F.E.R.C. ¶

61,220, order on reh'g, 25 F.E.R.C. ¶ 61,401 (1983), order on

reh'g, 26 F.E.R.C. ¶ 61,031 (1984). Second, the Commission

authorized selective transportation programs, under which a

pipeline received a blanket certificate to transport third-party

gas and was allowed to offer this service to its customers on a

selective basis. See Order No. 234-B, Interstate Pipeline

Blanket Certificates for Routine Transactions and Sales and

Transportation by Interstate Pipelines and Distributors, [Regs.

Preambles 1982-85] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,476 (1983); 

Order No. 319, Sales and Transportation by Interstate Pipelines

and Distributors, [Regs. Preambles 1982-85] F.E.R.C. Stats. &

Regs. (CCH) ¶ 30,477, order on reh'g, Order No. 319-A, [Regs.

Preambles 1982-85] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,512 (1983). 

plagued the industry and the Commission over the last fifteen

years. The Commission's initial response to escalating pipeline

take-or-pay liabilities was to authorize pipelines to offer less

expensive sales of third-party (non-pipeline-owned) gas to

non-captive customers while still offering only higher-priced

pipeline gas to captive customers.8 The court struck down these

measures because the Commission "ha[d] not adequately attended to

the agency's prime constituency," captive customers vulnerable to

pipelines' market power. Maryland People's Counsel v. FERC, 761

F.2d 780, 781 (D.C. Cir. 1985) (MPC II); see also Maryland

People's Counsel v. FERC, 761 F.2d 768, 776 (D.C. Cir. 1985) (MPC

I). In response to the court's decisions in MPC I and MPC II, the

Commission embarked on its landmark Order No. 436 rulemaking. See

Order No. 436, ¶ 30,665, at 31,467.

B. Order No. 436: Open-Access Transportation

In Order No. 436, the Commission began the transition toward

removing pipelines from the gas-sales business and confining them

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9 Customers who receive service under a blanket certificate

as authorized in Order No. 436 are known as Part 284 customers. 

Customers who receive individually certificated service, to which

the open-access conditions do not apply, are known as Part 157

customers, or § 7(c) customers. Although the Commission's

current policy is no longer to issue Part 157 certificates, Blue

Lake Gas Storage Co., 59 F.E.R.C. ¶ 61,118, reh'g denied, 61

F.E.R.C. ¶ 61,284 (1992), existing Part 157 certificates remain

in effect. 

10 Pipelines generally offer two forms of transportation

service: firm transportation, for which delivery is guaranteed,

and interruptible transportation, for which delivery can be

delayed if all the capacity on the pipeline is in use. 

to a more limited role as gas transporters. Under a new Part 284

of its regulations,9 the Commission conditioned receipt of a

blanket certificate for firm transportation of third-party gas on

the pipeline's acceptance of non-discrimination requirements

guaranteeing equal access for all customers to the new service.10

Order No. 436, ¶ 30,665, at 31,497-518. In effect, the Commission

for the first time imposed the duties of common carriers upon

interstate pipelines. See Associated Gas Distributors v. FERC, 824

F.2d 981, 997 (D.C. Cir. 1987) (AGD I), cert. denied, 485 U.S. 1006

(1988). By recognizing that anti-competitive conditions in the

industry arose from pipeline control over access to transportation

capacity, the equal-access requirements of Order No. 436 regulated

the natural-monopoly conditions directly. In addition, every

open-access pipeline was required to allow its existing bundled

firm-sales customers to convert to firm-transportation service and,

at the customer's option, to reduce its firm-transportation

entitlement (its "contract demand"). Order No. 436, ¶ 30,665, at

31,518-33. Moreover, the Commission established a flexible rate

structure under which transportation charges were limited to the

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11 The Commission limited itself to re-affirming a previous

policy statement on take-or-pay liabilities that deferred the

issue to individual rate-case filings. Order No. 436, ¶ 30,665,

at 31,560-69; see Regulatory Treatment of Payments Made in Lieu

of Take-or-Pay Obligations, [Regs. Preambles 1982-85] F.E.R.C.

Stats. & Regs. (CCH) ¶ 30,637 (1985); 18 C.F.R. § 2.76. 

12 Order No. 500, Regulation of Natural Gas Pipelines After

Partial Wellhead Decontrol, [Regs. Preambles 1986-90] F.E.R.C.

Stats. & Regs. (CCH) ¶ 30,761, order on reh'g, Order No. 500-A,

[Regs. Preambles 1986-90] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,770,

order on reh'g, Order No. 500-B, [Regs. Preambles 1986-90]

F.E.R.C. Stats. & Regs. (CCH) ¶ 30,772, order on reh'g, Order No.

500-C, [Regs. Preambles 1986-90] F.E.R.C. Stats. & Regs. (CCH) ¶

30,786 (1987), order on reh'g, Order No. 500-D, [Regs. Preambles

1986-90] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,800, order on reh'g,

Order No. 500-E, 43 F.E.R.C. ¶ 61,234, order on reh'g, Order No.

500-F, [Regs. Preambles 1986-90] F.E.R.C. Stats. & Regs. (CCH) ¶

30,841 (1988), order on reh'g, Order No. 500-G, 46 F.E.R.C. ¶

61,148, vacated and remanded sub nom. American Gas Ass'n v. FERC,

888 F.2d 136 (D.C. Cir. 1989) (AGA I). 

maximum approved rate (based on fully allocated costs) but

pipelines could selectively discount down to the minimum approved

rate (based on average variable cost). Id. at 31,533-49.

The court largely approved Order No. 436, but the principal

stumbling-block was the unresolved problem of uneconomical

pipeline-producer contracts in the transition to the unbundled

environment. The Commission had decided not to provide pipelines

with relief from their take-or-pay liabilities, even though the

introduction of open-access transportation in Order No. 436 would

likely exacerbate the problem by reducing pipeline sales.11 AGD I,

824 F.2d at 1021-23. After the court remanded the case on the

ground that the Commission's inaction on take-or-pay did not

exhibit reasoned decision making in light of open access, id. at

1030, the Commission adopted various interim measures in Order No.

500.12 First, it instituted a "crediting mechanism," under which

a pipeline could apply any third-party gas that it transported

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13 The remaining costs "may be recovered either through a

commodity rate surcharge or a volumetric surcharge on total

throughput." 18 C.F.R. § 2.104(a). In K N Energy, Inc. v. FERC,

968 F.2d 1295, 1299-1300 (D.C. Cir. 1992), the court upheld the

Commission's reading of its regulation that a commodity rate

surcharge must also be based on total throughput. 

toward the pipeline's minimum-purchase obligation from that

particular producer. Order No. 500, ¶ 30,761, at 30,779-84.

Second, the Commission adopted two alternative cost-recovery

mechanisms. As customary, a pipeline could recover all of its

prudently incurred costs in its commodity (sales) charges, although

that could prove difficult for pipelines with shrinking

sales-customer bases. In the alternative, under the

equitable-sharing approach, a pipeline offering open-access

transportation could, if it voluntarily absorbed between

twenty-five and fifty percent of the costs, recover an equal share

of the costs through a "fixed charge" and recover the remaining

amount (up to fifty percent) through a volumetric surcharge based

on total throughput (and thus borne by both sales and

transportation customers alike).13 Id. at 30,784-92; 18 C.F.R. §

2.104. Third, the Commission authorized pipelines not recovering

take-or-pay costs in any other manner to impose a "gas inventory

charge" (GIC), a fixed charge for "standing ready" to deliver

gasthe sales analogue to a reservation charge. Order No. 500, ¶

30,761, at 30,792-94; 18 C.F.R. § 2.105.

The Commission's alternative solutions to the problem of

take-or-pay settlement costs in Order No. 500 fared poorly on

judicial review. First, the court remanded the crediting mechanism

for an explanation of whether the Commission had the requisite

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14 Order No. 500-H, [Regs. Preambles 1986-90] F.E.R.C.

Stats. & Regs. (CCH) ¶ 30,867 (1989), order on reh'g, Order No.

500-I, [Regs. Preambles 1986-90] F.E.R.C. Stats. & Regs. ¶

30,880, remanded sub nom. American Gas Ass'n v. FERC, 912 F.2d

1496 (D.C. Cir. 1990) (AGA II). 

15 The Commission terminated the crediting mechanism as of

December 31, 1990. Order No. 500-K, [Current] F.E.R.C. Stats. &

Regs. (CCH) ¶ 30,917, reh'g denied, Order No. 500-L, 55 F.E.R.C.

¶ 61,489 (1991). 

16 Order No. 528, Mechanisms for Passthrough of Pipeline

Take-or-Pay Buyout and Buydown Costs, 53 F.E.R.C. ¶ 61,163

(1990), order on reh'g, Order No. 528-A, 54 F.E.R.C. ¶ 61,095,

reh'g denied, Order No. 528-B, 55 F.E.R.C. ¶ 61,372 (1991). 

authority under § 7 of the NGA. American Gas Ass'n v. FERC, 888

F.2d 136, 148-49 (D.C. Cir. 1989) (AGA I). After the Commission

explained its § 7 authority for the crediting mechanism in Order

No. 500-H,14 the court upheld the crediting mechanism.15 American

Gas Ass'n v. FERC, 912 F.2d 1496, 1509-13 (D.C. Cir. 1990) (AGA

II). Second, the court struck down the equitable-sharing

cost-recovery mechanism on the ground that the Commission's

"purchase deficiency" method for calculating the "fixed charge,"

which assigned costs to each customer based on how much its

purchases had declined over the relevant preceding period, violated

the filed-rate doctrine. Associated Gas Distributors v. FERC, 893

F.2d 349, 354-57 (D.C. Cir. 1989) (AGD II), reh'g en banc denied,

898 F.2d 809 (D.C. Cir.), cert. denied, 498 U.S. 907 (1990). The

Commission responded to the invalidation of the "purchase

deficiency" method in AGD II by adopting Order No. 528,16 which

allowed pipelines, in the "fixed charge," to pass through a portion

of costs to customers based on any of several measures of current

(rather than past) demand or usage, with the intent of avoiding the

filed-rate problem. Order No. 528, ¶ 61,163, at 61,597-98.

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17 The committee added that "[t]his legislation does not

deregulate gas pipelines, and the Committee will continue its

oversight of the FERC to ensure that captive residential

consumers are not disadvantaged, and that the current competitive

"open access' pipeline system is maintained." H.R. REP. NO. 29,

supra, at 4. 

Finally, the court struck down the Commission's approval of a GIC

on a particular pipeline because it had given undue weight to the

pipeline's customers' having agreed to the GIC and failed

adequately to consider the interests of end-users. Tejas Power

Corp. v. FERC, 908 F.2d 998, 1003-05 (D.C. Cir. 1990).

Congress completed the process of deregulating the producer

sales market by enacting the Natural Gas Wellhead Decontrol Act of

1989, Pub. L. No. 101-60, 103 Stat. 157 (codified in scattered

sections of 15 U.S.C.). As the House Committee on Energy and

Commerce emphasized, the Commission's creation of open-access

transportation was "essential" to Congress' decision completely to

deregulate wellhead sales. H.R. REP. NO. 29, 101st Cong., 1st Sess.

6 (1989). The committee report declared also that "[b]oth the FERC

and the courts are strongly urged to retain and improve this

competitive structure in order to maximize the benefits of

decontrol."17 Id. The committee expected that, by ensuring that

"[a]ll buyers [are] free to reach the lowest-selling producer,"

id., open-access transportation would allow the more efficient

producers to emerge, leading to lower prices for consumers, id. at

3, 7.

C. Order No. 636: Mandatory Unbundling

In Order No. 636, the Commission declared the open-access

requirements of Order No. 436 a partial success. The Commission

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found that pipeline firm sales, which in 1984 had been over 90

percent of deliveries to market, had declined by 1990 to 21

percent. Order No. 636, ¶ 30,939, at 30,399 tbl. 1. On the other

hand, only 28 percent of deliveries to market in 1990 were firm

transportation, whereas 51 percent of deliveries used interruptible

transportation. Id. at 30,399 & n.61. The Commission concluded

that many customers had not taken advantage of Order No. 436's

option to convert from firm-sales to firm-transportation service

because the firm-transportation component of bundled firm-sales

service was "superior in quality" to stand-alone

firm-transportation service. Id. at 30,402. In particular, the

Commission found that stand-alone firm-transportation service was

often subject to daily scheduling and balancing requirements, as

well as to penalties for variances from projected purchases in

excess of ten percent. Moreover, pipelines usually did not offer

storage capacity on a contractual basis to stand-alone

firm-transportation shippers. Id. The result was that many of the

non-converted customers used the pipelines' firm-sales service

during times of peak demand but in non-peak periods bought

third-party gas and transported it with interruptible

transportation. The Commission found that "[i]t is often cheaper

for pipeline sales customers to buy gas on the spot market, and pay

the pipeline's demand charge plus the interruptible rate, than to

purchase the pipeline's gas." Id. at 30,400. Because of the

distortions in the sales market, these customers often paid twice

for transportation services and still received an inferior form of

transportation (interruptible rather than firm). Id. Because of

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the anti-competitive effect on the industry, the Commission found

that pipelines' bundled firm-sales service violated §§ 4(b) and

5(a) of the NGA. Id. at 30,405.

The Commission's remedy for these anti-competitive conditions,

and the principal innovation of Order No. 636, was mandatory

unbundling of pipelines' sales and transportation services. By

making the separation of the two functions mandatory, the

Commission expects that pipelines' monopoly power over

transportation will no longer distort the sales market. Order No.

636, ¶ 30,939, at 30,406-13; Order No. 636-A, ¶ 30,950, at 30,527-

46; Order No. 636-B, ¶ 61,272, at 61,988-92. To replace the

firm-transportation component of bundled firm-sales service, the

Commission introduced the concept of "no-notice firm

transportation," stand-alone firm transportation without penalties.

Those customers who receive bundled firm-sales service have the

right, during the restructuring process, to switch to no-notice

firm-transportation service. Pipelines that did not offer bundled

firm-sales service are not required to offer no-notice

transportation; but if they do, they must offer no-notice

transportation on a non-discriminatory basis. Order No. 636, ¶

30,939, at 30,421-25; Order No. 636-A, ¶ 30,950, at 30,570-77;

Order No. 636-B, ¶ 61,272, at 62,006-10; see 18 C.F.R. §

284.8(a)(4).

In contrast to the continued regulation of the transportation

market, the Commission essentially deregulated the pipeline sales

market. The Commission issued every Part 284 pipeline a blanket

certificate authorizing gas sales. Although acknowledging that

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"only Congress can "deregulate,' " the Commission "institut[ed]

light-handed regulation, relying upon market forces at the wellhead

or in the field to constrain unbundled pipeline sale for resale gas

prices within the NGA's "just and reasonable' standard." Order No.

636, ¶ 30,939, at 30,440. The Commission reasoned that open-access

transportation, combined with its finding that "adequate divertible

gas supplies exist in all pipeline markets," would ensure that the

free market for gas sales would keep rates within the zone of

reasonableness. Id. at 30,437-43; Order No. 636-A, ¶ 30,950, at

30,609-24; Order No. 636-B, ¶ 61,272, at 62,024-25; see 18 C.F.R.

§§ 284.281-284.288.

The Commission also undertook several measures to ensure that

the pipeline grid, or network, functions as a whole in a more

competitive fashion. First, open-access pipelines may not inhibit

the development of "market centers," which are pipeline

intersections that allow customers to take advantage of many more

transportation routes and choose between sellers from different

natural gas production areas. Similarly, open-access pipelines may

not interfere with the development of "pooling areas," which allow

the aggregation of gas supplies at a production area. Order No.

636, ¶ 30,939, at 30,427-28; Order No. 636-A, ¶ 30,950, at 30,581-

82; Order No. 636-B, ¶ 61,272, at 62,011-12; see 18 C.F.R. §§

284.8(b)(6), 284.9(b)(5). Finally, as part of the move toward

open-access transportation, the Commission required Part 284

pipelines to allow shippers to deliver gas at any delivery point

without penalty and to allow customers to receive gas at any

receipt point without penalty. Order No. 636, ¶ 30,939, at 30,428-

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18 The Commission has modified its Part 284 regulations in

two rulemakings since Order No. 636 that are not on review in

this proceeding. First, the Commission adopted further standards

for the electronic bulletin boards used for capacity release. 

Order No. 563, Standards for Electronic Bulletin Boards Required

Under Part 284 of the Commission's Regulations, [Current]

F.E.R.C. Stats. & Regs. (CCH) ¶ 30,988 (1993) (amending 18 C.F.R.

§§ 284.8(b)(4)-(5), 284.9(b)(4)), order on reh'g, Order No. 563-

A, [Current] F.E.R.C. Stats. & Regs. (CCH) ¶ 30,994, reh'g

denied, 68 F.E.R.C. ¶ 61,002 (1994). Second, the Commission

modified the short-term exception to the capacity-release rules. 

Order No. 577, Release of Firm Capacity on Interstate Natural Gas

Pipelines, [Current] F.E.R.C. Stats. & Regs. (CCH) ¶ 31,017

(amending 18 C.F.R. § 284.243(h)(1)), order on reh'g, Order No.

577-A, [Current] F.E.R.C. Stats. & Regs. ¶ 31,021 (1995). 

29; Order No. 636-A, ¶ 30,950, at 30,582-86; Order No. 636-B, ¶

61,272, at 62,012-13; see 18 C.F.R. § 284.221(g)-(h).

Even though this is the court's first occasion to address

Order No. 636, which was enacted in 1992, we do not write on a

clean slate. Beginning with MPC I and MPC II, the court has

consistently required the Commission to protect consumers against

pipelines' monopoly power. No longer reluctantly engaged in the

unbundling enterprise, the Commission has responded by initiating

sweeping changes with Order No. 636. Accordingly, we review the

Commission's exercise of its authority under the NGA in light of

the principles that the court has already applied in this area.

D. Issues on Review and Conclusions

After two comprehensive rehearing orders, Orders No. 636-A and

No. 636-B, the Commission denied further rehearing.18 62 F.E.R.C.

¶ 61,007 (1993). The Judicial Panel on Multidistrict Litigation

consolidated all the petitions for review of the Order No. 636

series and transferred them to the Eleventh Circuit by random

selection pursuant to 28 U.S.C. § 2112(a)(3). On February 15,

1994, the Eleventh Circuit transferred the petitions for review to

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19 El Paso Natural Gas Co., 59 F.E.R.C. ¶ 61,031, order on

reh'g, 60 F.E.R.C. ¶ 61,117 (1992). 

20 Algonquin Gas Transmission Co., 59 F.E.R.C. ¶ 61,032,

reh'g denied, 60 F.E.R.C. ¶ 61,113 (1992). 

21 The court also received separate petitioners' briefs from

Carnegie Natural Gas Company, an interstate pipeline company; 

Elizabethtown Gas Company, a local distribution company; Hadson

Gas Systems, Inc., a "marketer" that buys and re-sells pipeline

transportation capacity; and Meridian Oil Inc., also a marketer. 

this court. We consolidated with this case petitions for review of

the Commission's decision to prohibit buy/sell agreements,19 and of

the Commission's decision to end capacity-brokering programs.20 We

ordered the petitioners to file briefs in consolidated industry

groups: pipelines; local distribution companies (LDCs); small

distributors and municipalities; industrial end-users; electric

generators; and public utility commissions (PUCs).21

The petitioners do not challenge the mandatory unbundling

remedy itself. At issue on review are numerous other aspects of

Order No. 636 involving changes that the Commission undertook as

part of its comprehensive restructuring of the natural gas

industry. In Part II of our opinion, we discuss the challenges to

the Commission's rules on Part 284 firm transportation. Part III

addresses the challenges to the Commission's new capacity-release

program. Part IV covers the requirement that pipelines use the

straight fixed/variable rate-design methodology. Finally, in Part

V we deal with challenges to the Commission's handling of

transition costs.

As we discuss in Part II.A, the petitioners challenge four

peripheral aspects of the Commission's unbundling remedy. We

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uphold the Commission's rule that customers must retain contractual

firm-transportation capacity for which the pipeline receives no

other offer. See 18 C.F.R. § 284.14(e). Further, insofar as the

Commission may have stated that a § 7(b) abandonment proceeding is

never required for pipeline changes to contract-storage withdrawal

and injection schedules, we grant relief, but we defer review of

possible challenges to specific pipeline changes. The challenge to

the Commission's rule that transportation-only pipelines may not

acquire capacity on other pipelines has been rendered moot by

virtue of an intervening Commission decision. We remand for

further explanation the Commission's decision that only those

customers who received bundled firm-sales service on May 18, 1992,

are entitled to the new no-notice transportation service.

Part II.B concerns the Commission's award of pre-granted

abandonment to long-term firm-transportation service, subject to

the existing shipper's "right of first refusal" (ROFR). Under this

provision of the rules, pipelines are no longer required to go

through § 7 abandonment proceedings when a transportation contract

expires. In return, the existing customer has the right to retain

service if it matches the terms of a competing offer for that

capacity. Such bids are capped at the maximum rate approved by the

Commission for that service, and the contract length may not exceed

twenty years. Order No. 636, ¶ 30,939, at 30,448-52; Order No.

636-A, ¶ 30,950, at 30,627-36; Order No. 636-B, ¶ 61,272, at

62,025-28; see 18 C.F.R. § 284.221(d). While we conclude that in

its basic structure the right-of-first-refusal mechanism complies

with § 7, we remand the right-of-first-refusal mechanism to the

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Commission for further explanation of why it adopted a twenty-year

term-matching cap. We uphold the Commission's decision not to

require pipelines to discount rates in the right-of-first-refusal

process.

The Commission also re-visited its policies for the

curtailment of gas in times of a supply shortage or a capacity

interruption. Gas can be curtailed on an end-use basis, meaning

that high-priority users have priority in times of curtailment, or

on a pro rata basis, meaning that each user's deliveries are

curtailed proportionally. The Commission found that it was

statutorily obligated to require pipelines to adopt an end-use

curtailment plan for shortages in the supply of pipeline gas. On

the other hand, the Commission declined to require pipelines to

adopt end-use curtailment for capacity interruption. Order No.

636, ¶ 30,939, at 30,429-31; Order No. 636-A, ¶ 30,950, at 30,586-

93. In Part II.C, we affirm the Commission's decision that title

IV of the NGPA requires end-use supply curtailment and conclude

that the issue of curtailment compensation is not ripe for review.

We also deny the petitions for review of the Commission's

capacity-curtailment policies, but we do not examine whether pure

pro rata capacity curtailment is always appropriate because the

Commission has examined that issue on a pipeline-specific basis in

the restructuring proceedings. Finally, we uphold the Commission's

policies for supply shortages of third-party gas.

Part III addresses the Commission's adoption of a uniform

capacity-release programa regulated market that allows

capacity-holders to re-sell the rights to pipeline

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22 A buy/sell arrangement is an agreement between an LDC and

one of its local end-users under which (1) the end-user

identifies (and sometimes purchases) gas held by a producer, (2)

the LDC in turn purchases the identified gas and uses its

firm-transportation capacity to transport the gas, and (3) the

LDC sells the gas to the end-user. 

23 The Commission recently issued a policy statement

approving the use of market-based rates for transportation

services, analogous to the market-based rates for pipeline gas

sales, see supra at 15-16, but only if the pipeline can

demonstrate that it lacks significant market power over the

transportation service. Alternatives to Traditional Cost-ofService Ratemaking for Natural Gas Pipelines and Regulation of

Negotiated Transportation Services of Natural Gas Pipelines, 74

F.E.R.C. ¶ 61,076, reh'g denied, 75 F.E.R.C. ¶ 61,024 (1996). 

This policy statement is not on review in this proceeding, and we

firm-transportation capacity. An existing shipper that finds

itself with excess capacity may list that capacity on the

pipeline's electronic bulletin board (EBB), which functions as a

central clearinghouse for the secondary capacity market. Order No.

636, ¶ 30,939, at 30,416-21; Order No. 636-A, ¶ 30,950, at 30,550-

65; Order No. 636-B, ¶ 61,272, at 61,994-62,003; see 18 C.F.R. §

284.243. We uphold the Commission's jurisdiction to regulate the

re-sale of interstate-transportation rights in general, as well as

specifically its jurisdiction over LDCs who broker capacity to

local end-users and over municipal LDCs. We also uphold the

Commission's decision that state-authorized "buy/sell

arrangements"22 are pre-empted by the Commission's capacity-release

program. Finally, we uphold the Commission's decision to exclude

Part 157 shippers and conclude that other challenges to the

substance of the capacity-release program are not ripe for review.

Part IV deals with the Commission's requirement that pipelines

adopt a new rate-design methodology known as straight

fixed/variable (SFV).23 Under SFV, pipelines must allocate fixed

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review only the Commission's requirement that pipelines use SFV

rate design. 

24 The reservation, or demand, charge is for reserving

firm-transportation capacity; the usage, or commodity, charge is

for the actual transportation of gas. 

25 Under the previously effective MFV rate design, pipelines

assigned most fixed costs to the reservation charge, but return

on equity and related taxes were assigned along with variable

costs to the usage charge. According to one study, the practical

result was that under MFV about 15% to 20% of fixed costs were

assigned to the usage charge. GENERAL ACCOUNTING OFFICE, NATURAL GAS:

COSTS, BENEFITS AND CONCERNS RELATED TO FERC'S ORDER 636, at 33 n.11

(Nov. 1993). In addition, under MFV rate design the reservation

charge was divided into two equal components: the "D-1 charge"

was based on a customer's daily contract demand, or entitlement,

and the "D-2 charge" was based on a customer's actual annual

usage. 

26 A customer's load factor is the ratio between its average

usage and its peak usage. Customers with seasonal usage

fluctuations, such as LDCs, have low load factors, whereas

customers with constant usage throughout the year, such as

industrial end-users, have high load factors. 

costs to the reservation charge, and variable costs to the usage

charge.24 The Commission mandated SFV so that fixed costs, which

vary greatly between pipelines, would no longer affect the usage

charge and thus distort the national gas-sales market that Order

No. 636 fosters. Because the shift from the previous modified

fixed/variable (MFV) rate design25 would disadvantage

low-load-factor customers,26 the Commission adopted various SFV

mitigation measures to protect those customers. Order No. 636, ¶

30,939, at 30,431-37; Order No. 636-A, ¶ 30,950, at 30,593-609;

Order No. 636-B, ¶ 61,272, at 62,013-24; see 18 C.F.R. § 284.8(d).

We uphold the Commission's authority under § 5 to adopt SFV rate

design and conclude that substantial evidence supports the

Commission's findings that MFV rate design distorted the producer

sales market and that SFV is an appropriate rate-design

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methodology. Although we uphold the Commission's SFV mitigation

measures against most challenges, we conclude that the Commission

failed to explain why it ordered some mitigation measures on an

individual-customer basis and others on a customer-class basis and

why it did not require pipelines to offer small-customer discounts

to former customers of downstream pipelines. Accordingly, we

remand those issues to the Commission.

Finally, as we explain in Part V, the Commission addressed the

transition costs involved with implementing Order No. 636. The

Commission allowed pipelines, whose role as gas merchants was

greatly reduced, to pass through to transportation customers all

the costs of reducing contractual purchase obligations from

producers, known as gas-supply realignment (GSR) costs. Unlike the

Order No. 500 equitable-sharing cost-recovery mechanism for

take-or-pay costs from pipeline-producer contracts, Order No. 636

imposes all the costs of realigning unneeded producer-pipeline

contracts on pipeline customers. The Commission authorized

pipelines to recover 90% of the GSR costs from current

firm-transportation customers (including customers who converted

from being bundled firm-sales customers under Order No. 436) and

10% of the GSR costs from interruptible- transportation customers.

Order No. 636, ¶ 30,939, at 30,457-62; Order No. 636-A, ¶ 30,950,

at 30,641-64; Order No. 636-B, ¶ 61,272, at 62,031-45. We uphold

the Commission's decision to allow pipelines to recover GSR costs

from customers who converted to open-access transportation before

Order No. 636, but remand the decision that pipelines must allocate

10% of GSR costs to interruptible-transportation customers for

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27 The court has docketed the petitions for review of the

restructuring proceedings in UGI Utilities v. FERC, No. 93-1291,

and held them in abeyance until our decision. 

further explanation. We also remand the decision that pipelines

can pass through all their GSR costs to customers for further

consideration by the Commission in light of the equitable-sharing

procedures in Order No. 500 and the general cost-spreading

principles of Order No. 636. We affirm the Commission's treatment

of LDC by-pass, GSR costs for the Great Plains coal gasification

project, and stranded costs.

The Commission resolved issues that it considered generic to

all pipelines in the Order No. 636 rulemaking, but deferred many

issues associated with the implementation of mandatory unbundling

to restructuring proceedings. Every Part 284 pipeline is required

to go through an individual pipeline restructuring proceeding, to

conform its operations to the new regulations and to address

pipeline-specific issues. 18 C.F.R. § 284.14; Order No. 636, ¶

30,939, at 30,462-69; Order No. 636-A, ¶ 30,950, at 30,664-73.

The Commission has by now completed the restructuring proceedings,

and in the proceedings for some pipelines interested parties have

petitioned for review.27 In this decision, we review only the Order

No. 636 rulemaking, although on some issues we have necessarily had

to consider the interaction between the rulemaking and the

subsequent restructuring proceedings.

II. Open-Access Firm Transportation

A. Unbundling

The petitioners challenge four aspects of the Commission's

unbundling remedy: the rule that customers must retain contractual

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firm-transportation capacity for which the pipeline receives no

other offer; the Commission's policy on pipelines' ability to

modify existing storage contracts without abandonment proceedings;

the rule that transportation-only pipelines may not acquire

capacity on other pipelines; and the eligibility date for

no-notice transportation service.

1. Prohibition on unilateral customer release of transportation

capacity

When the Commission concluded that the pipelines' bundled

firm-sales service violated §§ 4(b) and 5(a) of the NGA, Order No.

636, ¶ 30,939, at 30,405, the Commission found also that "the

continued enforcement of a pipeline sales customer's purchase

obligations, agreed to before implementation of unbundling under

this rule, is unjust and unreasonable, and unduly discriminatory."

Id. at 30,453. Accordingly, all existing bundled firm-sales

customers were given the option to reduce or terminate their

contractual purchase obligations during the pipeline's

restructuring proceedings. 18 C.F.R. § 284.14(d)(1). By contrast,

those customers were not relieved of their contractual

transportation obligations unless either an alternative,

creditworthy shipper offered to assume the capacity at the same or

a higher rate (up to the maximum approved rate), or the pipeline

agreed to reduce or terminate the transportation obligation. Id.

§ 284.14(e)(2). If a customer wished to reduce or terminate its

transportation obligation, and either a replacement shipper assumed

the capacity or the pipeline agreed, then the pipeline was

authorized to abandon the service under the prior contract. Id. §

284.14(e)(3). In effect, existing bundled firm-sales customers

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28 The other LDC petitioners are the Atlanta Gas Light

Company and the Chattanooga Gas Company. 

remained contractually bound to receive firm-transportation service

on the pipeline.

On rehearing, Northern Indiana Public Service Company (NIPSCO)

maintained that the Commission's actions entirely abrogated the

existing pipeline-customer bundled firm-sales contracts, and that

the Commission could not require the LDCs to enter into new

transportation contracts. The Commission denied that it had

abrogated the contracts: the pipelines remained contractually

obligated to provide separate sales and transportation services.

"[T]he fact that LDCs have an opportunity to revise their sales

entitlements under existing contracts with their pipeline suppliers

does not mean they should also have an unqualified right to

terminate their obligations for the costs of transportation

capacity under those contracts." Order No. 636-A, ¶ 30,950, at

30,638. The Commission also explained that if it released former

bundled-sales customers from transportation obligations, "these

capacity costs could be shifted from the customer who has

contracted for the capacity to the pipeline or other customers that

have no need for the capacity." Id. at 30,637.

NIPSCO, joined by other LDC petitioners,28 contends that, by

holding pipeline customers to the transportation component of

bundled firm-sales contracts, the Commission essentially imposed a

new contract upon the customers, which is beyond the Commission's

§ 5 authority. Section 5(a) provides that, whenever the Commission

has found that an existing contract is "unjust, unreasonable,

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29Minimum bills were clauses in pipeline-customer contracts

that "require[d] a pipeline customer to pay for a minimum volume

of gas, whether or not the customer purchase[d] that amount of

unduly discriminatory, or preferential," it "shall determine the

just and reasonable contract to be thereafter observed and in

force, and shall fix the same by order." 15 U.S.C. § 717d(a).

NIPSCO contests not the Commission's underlying finding that the

bundled firm-sales contracts violated §§ 4(b) and 5(a), but only

the remedy imposed under § 5. Our review is limited to whether the

Commission's reading of § 5 to authorize it to hold LDCs to the

remaining terms of a modified pipeline-customer contract is a

reasonable construction of its statutory authority. See AGD I, 824

F.2d at 1001.

The bundled firm-sales contracts between pipelines and LDCs

were subject to the Commission's § 5 authority. The regulatory

structure of the Natural Gas Act is contract-based: it "permits

the relations between the parties to be established initially by

contract, the protection of the public interest being afforded by

supervision of the individual contracts." United Gas Co. v. Mobile

Gas Serv. Corp., 350 U.S. 332, 339 (1956). Under § 5, "the

Commission has plenary authority to limit or to proscribe

contractual arrangements that contravene the relevant public

interests." Permian Basin Area Rate Cases, 390 U.S. 747, 784

(1968). For example, in Wisconsin Gas Co. v. FERC, 770 F.2d 1144

(D.C. Cir. 1985), cert. denied, 476 U.S. 1114 (1986), the court

affirmed the Commission's decision in Order No. 380 that "minimum

bill" provisions in existing contracts were "unjust and

unreasonable" under § 5.29 The court upheld the Commission's

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gas." Wisconsin Gas Co., 770 F.2d at 1149. Thus, the minimum

bills were analogous to the take-or-pay provisions in

pipeline-producer contracts. But cf. id. at 1159-60. The

Commission prohibited minimum bills because they allowed

pipelines to collect substantial commodity charges for gas that

was never delivered and because they "ha[d] become a major

obstacle to the transmittal of clear market signals from the

burner tip back to the well-head." Order No. 380, Elimination of

Variable Costs From Certain Natural Gas Pipeline Minimum

Commodity Bill Provisions, [Regs. Preambles 1982-85] F.E.R.C.

Stats. & Regs. (CCH) ¶ 30,571, at 30,962, order on reh'g, Order

No. 380-A, [Regs. Preambles 1982-85] F.E.R.C. Stats. & Regs.

(CCH) ¶ 30,584, order on reh'g, 29 F.E.R.C. ¶ 61,076, order on

reh'g, [Regs. Preambles 1982-85] F.E.R.C. Stats. & Regs. (CCH) ¶

30,607, order on reh'g, 29 F.E.R.C. ¶ 61,332 (1984), affirmed in

part and remanded in part sub nom. Wisconsin Gas Co. v. FERC, 770

F.2d 1144 (D.C. Cir. 1985). 

remedy, eliminating the minimum bill from the contracts, against

the claim that such a remedy "unlawfully alter[ed] the terms of

existing contracts," on the ground that "section 5 gives the

Commission authority to alter terms of any existing contract found

to be "unjust' or "unreasonable.' " Id. at 1153 n.9.

NIPSCO also maintains that the Commission has construed its §

5 authority to extend beyond the limits in § 1(b) on the

Commission's jurisdiction. Regardless of the Commission's

authority to impose modified contractual obligations on pipelines,

NIPSCO contends that the Commission lacks such authority over LDCs

because LDCs are "non-jurisdictional" entities. Under § 1(b), the

Commission's jurisdiction over "the transportation of natural gas

in interstate commerce" does not apply to "the local distribution

of natural gas or to the facilities used for such distribution."

15 U.S.C. § 717(b). But the local-distribution exception applies

only to the movement of gas within an LDC's local mains and not to

the movement of gas in high-pressure interstate pipelines. FPC v.

East Ohio Gas Co., 338 U.S. 464, 470-71 (1950); see also Louisiana

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30 See also infra at 74 n.67. 

Power & Light, 406 U.S. at 636 & n.13. Thus, for the same reasons

that the Commission has jurisdiction over the re-sale of interstate

capacity rights by LDCs to local end-users, see infra Part III.B.2,

it also has jurisdiction over an LDC's ability to reduce or

terminate its contractual interstate-transportation obligation.

The pipeline-LDC contracts for transportation through interstate

pipelines do not fall within the local-distribution exception to

the Commission's jurisdiction.

The Commission cannot use the pipeline-LDC contracts as a

jurisdictional hook for non-jurisdictional measures that do not

relate to the Commission's § 5 remedial authority over the

contracts.30 As the court has held in a different context, the

Commission may not assert its jurisdiction over a party merely

because it is "involved in a contractual relationship with a

jurisdictional pipeline." ARCO Oil & Gas Co. v. FERC, 932 F.2d

1501, 1503 (D.C. Cir. 1991). NIPSCO maintains that the Commission

has done just that by replacing the agreed-upon contractual terms

with entirely new terms of the Commission's own devising, when it

would otherwise be without jurisdiction to compel the LDC to

receive service in the first instance. But we do not agree that

the Commission has overstepped the bounds of its § 5 authority in

the first place. First, an LDC may maintain its original bargain

by choosing not to exercise its unilateral right to terminate the

purchase obligation. The resulting combination of sales service

and no-notice firm-transportation service replicates its prior

contractual entitlement. Thus, it is somewhat difficult to see the

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purported compulsion against LDCs in the Commission's decision not

to grant them the right to terminate their transportation

obligations. Second, the Commission's remedy was appropriately

confined to the underlying violation. Because the Commission found

the sales component of the bundled contracts to be unjust and

unreasonable, Order No. 636, ¶ 30,939, at 30,453, it interfered

with existing contracts only to the extent necessary to remedy the

effects of pipelines' market power. The Commission has the

authority under § 5 to adopt a remedy proportionate to the problem

being addressed. AGD I, 824 F.2d at 1019. Finally, § 5 instructs

that "the Commission shall determine the just and reasonable ...

contract to be thereafter observed and in force, and shall fix the

same by order." 15 U.S.C. § 717d(a). The limits of the

Commission's authority to modify pipeline-LDC contracts under § 5

lie in the requirement that, given the original contract and the

Commission's findings of unlawfulness, the resulting contract be

"just and reasonable." NIPSCO does not contend that the result of

unbundling the firm-sales contracts was unjust or unreasonable. We

therefore uphold the Commission's § 5 authority to hold LDCs to the

transportation component of the modified bundled firm-sales

contracts.

NIPSCO contends in the alternative that, even if the

Commission's action was within its § 5 authority, the Commission

acted arbitrarily and capriciously. In NIPSCO's view, the limited

nature of the remedy allows pipelines to continue to exercise

market power over customers in the transportation contracts, in

contravention of the overall goals of Order No. 636. We reject

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this challenge as well because the Commission has provided a

reasonable basis for its decision not to allow customers

unilaterally to reduce their contractual transportation

obligations. Cf. ARCO, 932 F.2d at 1502.

The Commission found in Order No. 636 that "the amount of

capacity reserved for pipeline firm sales still far exceeds the

pipelines' actual sales so that capacity is not available for firm

transportation and, as a result, interruptible transportation

maintains a significant share of peak period transportation."

Order No. 636, ¶ 30,939, at 30,406. In other words, because many

firm-sales customers decided to purchase third-party gas and

transport it using interruptible service, those customers ended up

holding excess reserved capacity. NIPSCO asserts that the effect of

the Commission's decision not to allow LDCs unilaterally to reduce

their contractual transportation obligations is to perpetuate

customers' excessive capacity holdings. NIPSCO is correct insofar

as the effect of any contract is to lock in current conditions, and

the existence of a long-term contract necessarily slows the

transition of a market to a new equilibrium when some underlying

condition changes. Moreover, the capacity-release mechanism is an

imperfect solution for the LDCs because the existing pipeline

customer is unlikely to receive full compensation for released

capacity in an excess-capacity market situation. Yet the problem

of capacity excess that the Commission identified was that

customers held more capacity in bundled-sales contracts than they

purchased gas from the pipeline, not that customers held more

firm-transportation capacity than needed for their peak demand.

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31 The Commission also announced that the customer could

negotiate an "exit fee" to induce the pipeline to release the

customer from its contractual obligations. Order No. 636, ¶

30,939, at 30,454. Whether the customer retains excess

contractual capacity or negotiates a one-time exit fee, however,

there is no reason why the cost to the customer should not be the

same, discounted over time. 

Contrary to NIPSCO's contention, there is no contradiction between

the general goal in Order No. 636 of encouraging more efficient use

of reserved capacity and the challenged rule that customers may not

unilaterally release contractual transportation obligations: the

Commission never found that the natural gas industry after

mandatory unbundling would be characterized by excess reserved

capacity.

Moreover, the Commission provided in Order No. 636-A a

coherent rationale for its decision. Because a pipeline's rate

structure is predicated upon levels of reserved capacity, providing

customers with the unilateral option to reduce those levels would

either reduce the pipeline's cost recovery or force the pipeline to

increase rates for the remaining customers.31 Order No. 636-A, ¶

30,950, at 30,637. Because someone has to bear the costs of

unfavorable contractual capacity obligations, the Commission

reasoned that the customer who voluntarily assumed those

obligations by entering into the contract should bear those costs

rather than spreading them over all of the pipeline's customers.

The Commission decided to modify the set of contracts that

forms the structure of the natural gas industry only as much as

necessary to alleviate the anti-competitive sales component of the

bundled contracts. The Commission is not required to exercise its

§ 5 authority beyond the limits of the problem it has identified,

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see AGD I, 824 F.2d at 1019, and its cost-shifting rationale was a

well-reasoned justification for its decision not to go further. We

therefore uphold this portion of the rules.

2. Pipeline modification of contract-storage rights

Because the Commission found that "pipelines' superior rights

with respect to access and control provide them with several

advantages over other gas merchants with no access to storage for

their gas," it required pipelines to offer access to their storage

capacity on an open-access basis. Order No. 636, ¶ 30,939, at

30,425-26. By defining "transportation" to include "storage," 18

C.F.R. § 284.1(a), the Commission made storage subject to the same

non-discrimination requirements as capacity rights. Id. §§

284.8(b), 284.9(b). Although pipelines were allowed to retain

storage capacity for system management and in order to ensure the

delivery of no-notice service, they were required to offer

remaining storage capacity on an open-access contractual basis for

customer-owned gas. Order No. 636, ¶ 30,939, at 30,426-27. The

Commission granted former bundled firm-sales customers a priority

right to that storage capacity. Order No. 636-A, ¶ 30,950, at

30,578.

In its request for rehearing of Order No. 636, CNG

Transmission Corporation, a pipeline company, explained that the

changes involving open-access storage would create difficulties for

it in providing the contractual levels of service to its existing

contract-storage customers. Because "current contract storage

injection and withdrawal schedules, and other related operational

protocols, are based upon current levels of contract storage

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32 The LDC petitioners are the Associated Gas Distributors,

the Atlanta Gas Light Company, the Chattanooga Gas Company, the

Brooklyn Union Gas Company, Elizabethtown Gas Company, and Long

Island Lighting Company. 

service," CNG requested the ability to modify existing storage

customers' contractual rights to inject or withdraw gas. The

Commission responded that its

intent was that current contract storage customers retain

their full right to capacity as specified in their

contracts. The Commission did not mean to infer [sic]

that the terms and conditions associated with their

rights could not be changed if they proved unreasonable

in light of Order No. 636's requirements of no-notice

transportation and open access contract storage. This,

of course, is a pipeline specific matter and must be

addressed in the restructuring proceeding.

Order No. 636-A, ¶ 30,950, at 30,579. Upon further rehearing,

however, the Commission went further, stating that,

while it has authorized pipelines to propose to change

existing storage arrangements, if necessary, to provide

no-notice transportation service, the pipeline must still

show that the changes are necessary and reasonable. This

includes an impact of a change on current contract

storage customers. The Commission has not authorized any

reduction in contract storage capacity. The Commission

views changes to injection and withdrawal schedules as

changes to terms and conditions, rather than to the level

of certificated service. Hence, the Commission concludes

that changes to existing contract storage terms and

conditions will not need action under NGA section 7(b).

Order No. 636-B, ¶ 61,272, at 62,011.

A group of LDC petitioners32 challenges the Commission's

statement that changes to contract-storage withdrawal and injection

schedules do not require a § 7(b) abandonment proceeding. We agree

with the petitioners that it is difficult to discern exactly what

the Commission's position is on this issue, and we grant the

petitioners relief insofar as the Commission stated in Order No.

636-B that any change to injection and withdrawal schedules can be

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33The Commission has defined these terms as follows:

[I]n contracting for storage, a customer reserves a

effected without a § 7(b) abandonment proceeding.

If the Commission has permitted the pipelines to "abandon" a

"service rendered by means of ... facilities" certificated by the

Commission, then it has failed to comply with § 7(b), which

requires a "due hearing" and a Commission finding that "the present

or future public convenience or necessity permit such abandonment."

15 U.S.C. § 717f(b). In general, the test for § 7 abandonment is

whether the certificate-holder "permanently reduces a significant

portion of a particular service." Reynolds Metal Co. v. FPC, 534

F.2d 379, 384 (D.C. Cir. 1976); see also Kansas Power & Light Co.

v. FERC, 851 F.2d 1479, 1481 (D.C. Cir. 1988). By comparison, the

withholding of gas delivery to an interruptible-transportation

customer is not an "abandonment," because the customer has no right

to guaranteed delivery under its contract or the certificate of

service. Cerro Wire & Cable Co. v. FERC, 677 F.2d 124, 129-30

(D.C. Cir. 1982). Although the court has reserved the issue

whether a § 7(b) abandonment occurs when only the identity of the

customer changes, an abandonment does take place "when there is a

reduction or alteration in overall service." Tennessee Gas

Pipeline Co. v. FERC, 972 F.2d 376, 384 (D.C. Cir. 1992).

According to the submissions by the Associated Gas

Distributors in the administrative record, a customer who contracts

for storage is concerned with two elements: capacity (how much gas

can be stored) and deliverability (how much gas can be withdrawn on

a given day).33 The AGD attached affidavits from six member LDCs

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specific level of deliverability, capacity, and

injection/withdrawal services. Deliverability reflects

the right of the storage customer to call on the

delivery capacity of the storage facilities every day

for a specified level of daily contract deliverability. 

Injection/ withdrawal is the injection and withdrawal

of gas from storage.

Consolidated Gas Transmission Corp., 47 F.E.R.C. ¶ 61,171, at

61,563, order on reh'g, 49 F.E.R.C. ¶ 61,041 (1989). 

who stated that changes to injection and withdrawal schedules could

reduce deliverability, with adverse consequences on their ability

to meet residential customers' demands. Elizabethtown Gas Company,

in its opposition to CNG's compliance filing in its restructuring

proceeding, objected to CNG's specific proposals to reduce

withdrawal amounts when contract-storage customers had low gas

inventories in storage, to maintain elevated minimum inventory

levels during the early winter months, to limit monthly withdrawal

amounts to less than the total of the daily amounts, to reduce firm

withdrawal rights to best-efforts rights, and to impose minimum

inventory turnovers.

It is impossible, on the current record, to determine on a

generic basis what changes to injection and withdrawal schedules

would "permanently reduce[ ] a significant portion" of

contract-storage service. Reynolds Metal, 534 F.2d at 384.

Because contractual deliverability entitlements are an integral

part of the customer's contract-storage rights, modifications that

affect those rights could in some instances constitute a § 7

abandonment. On the other hand, under other circumstances an

adjustment to an injection or withdrawal schedule could be

sufficiently minor or temporary that no abandonment would occur.

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34 See, e.g., Equitrans, Inc., 63 F.E.R.C. ¶ 61,009, at

61,064, order on reh'g, 64 F.E.R.C. ¶ 61,155, at 62,238, order on

reh'g, 65 F.E.R.C. ¶ 61,132 (1993), order on reh'g, 66 F.E.R.C. ¶

61,235 (1994), petitions for review pending sub nom. UGI Utils.

v. FERC, No. 93-1291 (D.C. Cir.); ANR Pipeline Co., 62 F.E.R.C.

¶ 61,079, at 61,527-28, order on reh'g, 64 F.E.R.C. ¶ 61,140, at

62,006, order on reh'g, 65 F.E.R.C. ¶ 61,162 (1993), order on

reh'g, 66 F.E.R.C. ¶ 61,340, order on reh'g, 68 F.E.R.C. ¶ 61,009

(1994), order on reh'g, 71 F.E.R.C. ¶ 61,033 (1995), petitions

for review pending sub nom. UGI Utils. v. FERC, No. 93-1291

(D.C. Cir.). 

Whether an abandonment proceeding is necessary depends on the

individual customer's storage contract and on the pipeline's

proposed modifications, none of which are before us now.

To the extent that the Commission issued in Order No. 636-B a

sweeping statement that no modifications to injection and

withdrawal schedules for a contract-storage customer require an

abandonment proceeding, such a statement is inconsistent with § 7.

In its brief, however, the Commission denies that it has taken any

such steps to degrade contract-storage rights. Instead, the

Commission maintains that it has merely allowed pipelines to

propose "necessary and reasonable" changes in the restructuring

proceedings, Order No. 636-B, ¶ 61,272, at 62,011, for which the

Commission has authority under § 5. In the restructuring

proceedings, the Commission has followed this approach, approving

proposed modifications to withdrawal and injection schedules if the

pipeline can prove that the changes are "necessary and

reasonable."34

The Commission's theory that it has the authority to proceed

in the restructuring proceedings under § 5 rather than in

abandonment proceedings under § 7(b) is explained nowhere in the

Order No. 636 series. See Order No. 636-A, ¶ 30,950, at 30,579;

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35 The LDC petitioners object that the Commission lacked

substantial evidence to support the required showing under § 5

that existing contract-storage service was not "just and

reasonable." We similarly defer any review of this claim until

applied in a concrete situation in a restructuring proceeding. 

Order No. 636-B, ¶ 61,272, at 62,011. Under § 7(b), the Commission

must hold a "due hearing" and must make a finding that "the present

or future public convenience or necessity permit such abandonment."

15 U.S.C. § 717f(b). By contrast, under § 5 the Commission need

hold only a "hearing" and must find that an existing contract is

"unjust, unreasonable, unduly discriminatory, or preferential."

Id. § 717d(a). We need not decide whether compliance with the

procedures in § 5 could in certain circumstances satisfy the

applicable statutory requirement in § 7(b). The Commission has

assured us in its brief that its approach under § 5 will be

"consistent" with the § 7 requirements. But without any

explanation in the Order No. 636 decisions for why the Commission's

procedures satisfy § 7(b), we cannot accept the Commission's

suggestion that its exercise of its § 5 authority in the

restructuring proceeding would obviate the need for abandonment

hearings.

On the other hand, any claim that a particular pipeline's

modification to contract-storage withdrawal and injection schedules

requires a § 7(b) abandonment proceeding is premature and should be

raised, if at all, in the review of individual restructuring

proceedings.35

3. Capacity retention by transportation-only pipelines

A central part of the Commission's unbundling program is the

requirement that all pipelines assign to their firm-transportation

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36 An "upstream" pipeline is located closer to the wellhead,

or production area. A "downstream" pipeline is located closer to

the burner-tip, or the end-user. 

customers the firm-transportation capacity that the pipelines held

on upstream pipelines. 18 C.F.R. § 284.242. Now that customers

can buy gas directly from the producers, they may bear the

responsibility of reserving capacity both on "upstream" and

"downstream" pipelines.36 If the downstream pipeline were allowed

to retain the capacity on the upstream pipeline, the Commission

reasoned, it would inhibit the formation of a competitive gas-sales

market by preventing downstream customers from gaining access to

the new opportunity to purchase gas directly from the producers.

Order No. 636, ¶ 30,939, at 30,417-18.

Two pipeline petitioners, ANR Pipeline Company and Colorado

Interstate Pipeline Company, urge the Commission to carve out an

exception for "transportation-only pipelines"pipelines that do not

offer any gas sales. For example, a downstream pipeline may wish

to offer a customer a package of firm-transportation capacity on

its pipeline as well as on a connecting upstream pipeline; the

customer may well prefer not to have to contract separately with

the upstream pipeline.

This petition for review has been rendered moot by an

intervening declaratory order. In Texas Eastern Transmission

Corp., 74 F.E.R.C. ¶ 61,074, at 61,220 (1996), reh'g pending,

Docket No. CP 95-218, the Commission declared that the successful

completion of unbundling under Order No. 636, with the separation

of pipelines' merchant and transportation functions, had alleviated

the Commission's former concerns that pipelines would obstruct

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access to production areas to favor their merchant functions.

Accordingly, the Commission announced that it would "decide whether

to allow pipelines to acquire upstream or downstream capacity on a

case-by-case basis." Id. The Commission's intervening action

appears to have provided the pipeline petitioners with the relief

that they had sought; any further relief is available in review of

the declaratory-order proceeding.

4. Eligibility date for no-notice transportation

In its new regulation, the Commission requires interstate

pipelines "that provided a firm sales service on May 18, 1992" to

offer no-notice transportation service. 18 C.F.R. § 284.8(a)(4).

In Order No. 636-A, the Commission clarified that "[t]he pipelines

are 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." Order No. 636-A, ¶

30,950, at 30,573. Although several commentators requested the

Commission to require pipelines to extend no-notice transportation

service to customers who had already converted from bundled

firm-sales service under Order No. 436 and consequently no longer

received such service on May 18, 1992, the Commission denied

rehearing. The Commission offered three reasons: first, that it

was prudent to begin the experiment with no-notice transportation

on a limited basis; second, that customers who were not receiving

bundled firm-sales service on May 18, 1992, "were not relying on

that service"; and third, that such customers "could not

reasonably expect to receive no-notice transportation in the

future" because neither Order No. 436 nor the Notice of Proposed

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37 NAGC frames its argument in terms of "small" customers

and confuses in its brief the distinct issues of small-customer

rates (one-part rates at an imputed load factor) and no-notice

transportation service. In fact, the availability of no-notice

transportation service does not depend on a customer's size. 

NAGC's argument about small-customer rates fails because

eligibility for small-customer rates is determined by customer

class, so any pipeline that offered small-customer rates on May

18, 1992, must continue to offer such rates "on the same basis"

to all customers. Order No. 636-A, ¶ 30,950, at 30,600. 

Rulemaking for Order No. 636 had contemplated it. Order No. 636-B,

¶ 61,272, at 62,007.

The National Association of Gas Consumers (NAGC) contends that

the ineligibility of former bundled firm-sales customers who

converted to open-access transportation under Order No. 436 to

receive no-notice transportation is unduly discriminatory.37 NAGC

relies on the Commission's own regulation, promulgated by Order No.

436, which requires an open-access pipeline to offer service

"without undue discrimination." 18 C.F.R. § 284.8(b)(1). And as

NAGC points out, the Commission found in Order No. 636 that the

pipelines' open-access firm-transportation service under Order No.

436 was unlawfully discriminatory because it did not provide the

same quality of transportation service as was available with

bundled firm-sales service. Order No. 636, ¶ 30,939, at 30,402.

Now, customers who converted under Order No. 436 remain limited to

stand-alone firm-transportation service subject to scheduling and

balancing requirements and other penalties. Thus, NAGC maintains

that the Commission must extend eligibility for no-notice

transportation service to customers who converted before Order No.

636 in reliance on the non-discrimination provisions.

We find the Commission's justifications in Order No. 636-B

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38 A natural gas company that receives "pre-granted

abandonment" of a certificated service need not undergo the

customary § 7 abandonment proceedings because the Commission has

made ex ante generic findings of public convenience and

necessity. 

unconvincing. The Commission's desire to proceed cautiously with

no-notice transportation, rather than require pipelines to offer it

to all customers, cannot explain the disadvantaging of former

bundled firm-sales customers who converted under Order No. 436.

Although those customers had no right to expect to receive

no-notice transportation service under Order No. 636, neither did

customers who did receive bundled firm-sales service on May 18,

1992. Finally, the Commission has not provided substantial

evidence to support its assumption that bundled firm-sales

customers who retained bundled service relied more heavily on

reliability of transportation service than did customers who

switched to open-access transportation. We therefore remand this

issue to the Commission for further explanation of which customers

should be eligible for no-notice transportation service.

B. Right of First Refusal

Section 7(b) of the Natural Gas Act prohibits pipelines from

abandoning certificated firm-transportation service until the

Commission makes a finding that "the present or future public

convenience or necessity permit such abandonment." 15 U.S.C. §

717f(d). In its original adoption of open-access transportation in

Order No. 436, the Commission provided automatic "pre-granted

abandonment"38 for all firm-transportation service provided under

a Part 284 blanket certificate. 18 C.F.R. § 284.221(d) (1989).

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39 Order No. 436 was vacated by AGD I in 1987. Then Order

No. 500 was vacated by AGA I in 1989. See supra Part I.B. 

After the order was twice vacated on other grounds,39 the Commission

re-promulgated the automatic pre-granted abandonment rule in Order

No. 500-H, ¶ 30,867, at 31,583-85. In its review of Order No. 500-

H, the court remanded automatic pre-granted abandonment because

"the Commission has not yet adequately explained how pregranted

abandonment trumps another basic precept of natural gas

regulationprotection of gas customers from pipeline exercise of

monopoly power through refusal of service at the end of a contract

period." AGA II, 912 F.2d at 1518. In AGA II, the court concluded

that the Commission's reliance on various market alternatives

available to LDCsnamely interruptible transportation, stand-by gas

service and gas from alternative suppliersprovided inadequate

protection for LDCs. Id. at 1517. The court similarly rejected

the Commission's contention that it was furthering purposes other

than the protection of existing customers because "the Commission's

response seems to entail an enormous qualification of its basic

purpose." Id. On remand from AGA II, the Commission decided to

hold the issue of pre-granted abandonment in abeyance until Order

No. 636. See Order No. 500-J, [Current] F.E.R.C. Stats. & Regs.

(CCH) ¶ 30,915 (1991).

In Order No. 636, the Commission responded to AGA II by

amending its regulations to provide that an existing customer of

long-term firm-transportation service could avoid pre-granted

abandonment if it abided by a new right-of-first-refusal (ROFR)

mechanism. 18 C.F.R. § 284.221(d). No petitioner challenges the

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Commission's rule that interruptible transportation, and firm

transportation with a contract term of less than one year, are

subject to automatic pre-granted abandonment even without the right

of first refusal. Order No. 636, ¶ 30,939, at 30,446; Order No.

636-A, ¶ 30,950, at 30,625-26. But the petitioners do challenge

pre-granted abandonment for long-term firm transportation. In

essence, the issue is whether the right-of-first-refusal mechanism

provides the protection for pipeline customers that AGA II

requires.

The right-of-first-refusal mechanism consists principally of

two matching requirements: rate and contract term. See 18 C.F.R.

§ 284.221(d)(ii). Near the end of a long-term firm-transportation

contract, the existing customer may notify the pipeline that it

intends to exercise its right of first refusal. The pipeline must

post the availability of that capacity on its electronic bulletin

board and, in accordance with the criteria set forth in its tariff,

identify the "best bid" offered by any competing shippers. Order

No. 636, ¶ 30,939, at 30,451; Order No. 636-A, ¶ 30,950, at

30,634. The customer then has the right to match the competing

bid's rate, up to the maximum "just and reasonable" rate that the

Commission has approved for that service, and the competing bid's

contract term. Competing shippers may choose to bid for only a

portion of the capacity in the expiring contract. Order No. 636,

¶ 30,939, at 30,451-52; Order No. 636-A, ¶ 30,950, at 30,634-35.

The Commission promised that it would scrutinize competing bids

from pipelines' marketing affiliates to ensure that they did not

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40 The Commission exempted from pre-granted abandonment the

firm-transportation capacity of any customer who converted from

bundled firm-sales service between February 13, 1991 (the

effective date of Order No. 500-J) and May 18, 1992 (the

effective date of Order No. 636). 18 C.F.R. § 284.221(d)(3); 

see Order No. 636, ¶ 30,939, at 30,452; Order No. 636-A, ¶

30,950, at 30,635-36. 

collude to increase the bidding level.40 Order No. 636, ¶ 30,939,

at 30,451; Order No. 636-A, ¶ 30,950, at 30,634.

Originally, the Commission contemplated that competing bids

could be for any contract length. According to the Commission,

"[o]ther things being equal, the satisfaction of long-term

transportation needs should have priority over the satisfaction of

shorter-term needs." Order No. 636, ¶ 30,939, at 30,450. In Order

No. 636-A, the Commission reconsidered that decision and found

that capping the contract term that must be matched by a

customer exercising its right of first refusal at a

period of 20 years strikes an appropriate balance between

the pipeline's need for stability, the customer's need

for flexibility, and the Commission's overall goal in

Order No. 636 to foster long-term, market driven

arrangements in the gas industry. This cap, in the

Commission's judgement, ensures that the customer

obtaining the service values the service sufficiently to

commit to using it for a reasonable period and provides

the pipeline with a reasonable level of stability.

Twenty years has been the traditional length of long-term

contracts in the natural gas industry and a number of

recent contracts for new capacity are for a twenty year

term.

Order No. 636-A, ¶ 30,950, at 30,631. Commissioner Moler,

dissenting in part, characterized the twenty-year period as "a

blatantly anti-LDC rule," given that LDCs typically have existing

contractual relationships jeopardized by pre-granted abandonment,

and urged the adoption of a shorter contract-term cap. Id. at

30,678-79.

1. Pre-granted abandonment generally

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41 The petitioners on this issue include the Industrial EndUser petitioners (the Process Gas Consumers Group, the American

Iron and Steel Institute, the Georgia Industrial Group, the

American Forest and Paper Association, Arcadian Fertilizer, and

the Virginia Electric and Power Company), the American Public Gas

Association, the National Association of Gas Consumers, and three

LDC petitioners (Atlanta Gas Light Company, Chattanooga Gas

Company, and NIPSCO). 

Many of the petitioners41 contend that the Commission's

pre-granted abandonment of firm-transportation service violates §

7. The petitioners maintain that the right-of-first-refusal

mechanism provides inadequate protection to existing pipeline

customers from the pipelines' market power.

The Commission may satisfy its § 7 obligations by making

generic findings of public convenience and necessity. In Mobil Oil

Exploration & Producing Southeast Inc. v. United Distribution Cos.,

498 U.S. 211, 227 (1991), the Supreme Court upheld a pre-granted

abandonment scheme under the Commission's Order No. 451, even

though the Commission's "approval is not specific to any single

abandonment but is instead general, prospective, and conditional."

See also FPC v. Moss, 424 U.S. 494, 499-502 (1976). The Court

approved the Commission's findings that, under its good-faith

negotiation procedures for the pre-granted abandonment of

producers' sale of "old gas" under the NGPA to pipelines, pipelines

would be protected "by allowing them to buy at market rates

elsewhere if contracting producers insisted on the new ceiling

price." Mobil Oil, 498 U.S. at 227. In AGA II, by contrast, the

court held that the Commission had not adequately explained why

pre-granted abandonment of firm-transportation in Order No. 500-H

would not "allow pipelines indirectly to extract monopoly profits

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42 The Commission also provided that its

complaint procedure is always available to remedy an

from their customers." 912 F.2d at 1516. Most important, the

Commission's proposed alternatives to existing firm-transportation

service, such as interruptible transportation and stand-by service,

failed to provide the existing customer with an adequate level of

protection. Id. at 1517. From Mobil Oil and AGA II, we conclude

that, for a finding of public convenience and necessity for

pre-granted abandonment under § 7, the Commission must make

appropriate findings that existing market conditions and regulatory

structures protect customers from pipeline market power.

The Commission's initial protective measurescontractual

"evergreen" or "roll-over" clausesare by themselves inadequate.

The Commission allows the pipeline and the customer to negotiate

such a contractual provision allowing the parties to extend the

contract before termination and thereby avoid the abandonment

issue. Moreover, the Commission requires pipelines that offer

evergreen or roll-over clauses to do so on a non-discriminatory

basis. Order No. 636-A, ¶ 30,950, at 30,628. Yet the Commission

declined to mandate the inclusion of contract-extension clauses.

Id. As the petitioners note, the voluntary nature of evergreen and

roll-over clauses means that those pipelines that do enjoy market

power will likely refuse to offer such clauses to their customers.

Thus, voluntary contract-extension clauses alone do not provide

sufficient protection to existing pipeline customers.

The mandatory right-of-first-refusal mechanism, however,

provides substantially more protection to existing customers.42

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unjustified loss of service. A hearing is necessary,

however, only when there are material facts in dispute. 

As the Commission has explained, the right of first

refusal is an adequate protection for LDCs serving core

customers.

Order No. 636-A, ¶ 30,950, at 30,633. Although the petitioners

object that the complaint process, 18 C.F.R. § 385.206, provides

inadequate protection, it is evident that the Commission intended

the complaint process to serve only as a back-up to the

right-of-first-refusal mechanism. We do not address the

petitioners' contention, made for the first time at oral

argument, that the Commission should have adopted a complaint

procedure modeled after 18 C.F.R. § 157.106, which allows

customers to contest the pre-granted abandonment of optional

expedited certificates (an innovation of Order No. 436 in which

the Commission presumes that an application for a "new service"

meets the public convenience and necessity if the pipeline agrees

to bear the full economic risk, see AGD I, 824 F.2d at 1030-31). 

43 The Commission decided not to specify on a generic basis

the appropriate method for pipelines to use in determining the

"best bid." See Order No. 636, ¶ 30,939, at 30,451; Order No.

636-A, ¶ 30,950, at 30,634. Rather, as the Commission stated, it

can guard against such pipeline influence in its review of the

individual restructuring proceedings and pipeline tariff filings. 

First, shippers bid against one another for capacity, which in the

Commission's view will prevent the pipeline from using the

right-of-first-refusal mechanism to push the rate above the

competitive market price.43 Second, under the

right-of-first-refusal mechanism the competing bid is capped at the

maximum "just and reasonable" rate, which protects the existing

shipper from having to match a bid higher than the

Commission-approved rate. If the existing customer is willing to

pay the maximum approved rate, then the right-of-first-refusal

mechanism ensures that the pipeline may not abandon the

certificated service. In this way, even a captive customer served

by a single pipeline can exercise its right of first refusal and

retain its long-term firm-transportation service against rival

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bidders. Hence, the basic structure of the right-of-first-refusal

mechanism provides the protections from pipeline market power

required for pre-granted abandonment under § 7.

2. The twenty-year contract term

The petitioners also contend that the contract term-matching

condition allows pipelines to exercise market power inconsonant

with pre-granted abandonment. Thus, on capacity-constrained

pipelines existing customers may be forced to match competing bids

for twenty years' duration, which would not be the outcome in a

competitive market without pipelines' natural monopoly. Competing

bidders who come up against the rate ceiling for this scarce

resourcecapacity on constrained pipelinesmay bid up the length of

the contract term to try to win the auction. In effect, bidding

for a longer contract term becomes a surrogate for bidding beyond

the maximum rate level. Especially with the new capacity-release

mechanism, a competing bidder could bid for a longer contract term

than it would contract for in a competitive market, release the

excess capacity at a discount, and absorb the loss just as though

it had bid an above-maximum rate for a shorter term.

The Commission acknowledged the reality that contract duration

is a measure of value when it declared that its policy was "for the

capacity to go to the person who values it the most, as evidenced

by its willingness to bid the highest price for the longest

reasonable time." Order No. 636-A, ¶ 30,950, at 30,630. As a

general matter, in a perfectly competitive market, a long-term

contract incorporates a premium for stability, and a pipeline

naturally values a longer-term transportation contract more highly,

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ceteris paribus. Order No. 636, ¶ 30,939, at 30,450. Thus, the

contract term-matching condition is a rational means of emulating

a competitive market for allocating firm-transportation capacity.

There are obvious drawbacksthe industrial petitioners provide the

example of a factory owner with a productive asset that has only a

short useful life. Order No. 636-A, ¶ 30,950, at 30,629-30. But

industrial end-users are also far more likely to have ready access

to alternative fuels than do the residential consumers served by

LDCs. See AGD I, 824 F.2d at 995.

For purposes of pre-granted abandonment, however, the issue is

whether the Commission has shown that its choice of a twenty-year

term-matching cap protects consumers against the exercise of

pipeline market power. The petitioners note that longer-term

contracts lock in customers and serve as a barrier to entry into

the pipeline market by potential competitors. Rival pipelines will

not build extensions to their system if the market for additional

capacity has been foreclosed by long-term contracts with the

existing pipeline. The Commission responds only that the pipeline

plays no role in the competitive bidding process and thus cannot

exercise market power. In the Commission's view, its choice of a

twenty-year period reflects a reasonable weighing of the relative

interests in preventing market constraint and encouraging market

stability. None of these explanations, however, supports a finding

that the twenty-year term-matching cap adequately protects against

pipelines' pre-existing market power, which they enjoy by virtue of

natural-monopoly conditions. The Commission has not explained why

the twenty-year cap will prevent bidders on capacity-constrained

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44 The LDC petitioners also contend that the Commission

failed to consider that, following Order No. 636, LDCs are placed

in a more vulnerable market situation, in which their traditional

customers can purchase gas from marketers. The Commission

reasonably responded that LDCs are no different from other

industry participants in that they will have to evaluate future

risks in determining how much capacity to reserve. Order No.

636-B, ¶ 61,272, at 62,026. 

45 The petitioners contend in part that the twenty-year cap

cannot stand because the Commission failed to explain why it

rejected the commentators' proposals for a shorter period. When,

as here, the Commission must select some, necessarily somewhat

arbitrary figure, we will defer to the Commission's expertise if

it provides substantial evidence to support its choice and

responds to substantial criticisms of that figure. 

pipelines from using long contract duration as a price surrogate to

bid beyond the maximum approved rate, to the detriment of captive

customers. If the maximum approved rate artificially limits a

rival shipper's ability to outbid the existing shipper, the rival

shipper may offer a higher-value contract by bidding up the

contract duration instead.44

A further concern with the Commission's choice of a

twenty-year cap is the Commission's reasoning in selecting twenty

years. Most of the commentators before the agency had proposed

much shorter contract-term caps, such as five years.45 The

Commission relied on the fact that twenty-year contracts have been

"traditional" in the natural-gas industry. Order No. 636-A, ¶

30,950, at 30,631 n.437. However, numerous commentators on

rehearing of Order No. 636-A, as well as Commissioner Moler, id. at

30,679, pointed out that twenty-year contracts have been

traditional only for contracts involving the construction of new

facilities, where the pipeline requires a long-term contract to

secure financing for the project, but not for contracts for the

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46 See Pacific Gas Transmission Co., 56 F.E.R.C. ¶ 61,192,

at 61,727-28, order on reh'g, 57 F.E.R.C. ¶ 61,097 (1991), order

on reh'g, 62 F.E.R.C. ¶ 61,243 (1993), petitions for review

pending sub nom. Altamont Gas Transmission Co. v. FERC, No. 91-

1369 (D.C. Cir. argued Nov. 14, 1995); Iroquois Gas Transmission

Sys., L.P., 53 F.E.R.C. ¶ 61,194, at 61,779-82 (1990), order on

reh'g, 54 F.E.R.C. ¶ 61,103 (1991). 

47 The industrial petitioners also contend that the

twenty-year cap is unduly discriminatory under § 5 of the NGA

because industrial end-users are more likely to have shorter-term

natural gas needs than other customers, such as LDCs who can

count on still having residential customers twenty years in the

continuation of service after contract expiration. Indeed, both of

the decisions that the Commission cited for the proposition that

twenty-year contracts are customary were for new facilities.46

Also, renewal contracts appear more similar to the situation in the

right-of-first-refusal mechanism. The Commission in its brief

responds that the term-matching cap was designed "not to determine

the length of typical gas contracts, but to establish a reasonable

outer boundary for contract length, within which the ROFR might

reasonably function." The petitioners' claim, however, is that

because the Commission looked to the wrong type of contract to

determine the typical contract length it may have selected an outer

boundary that is longer than it would have been if the Commission

had examined the duration of renewal contracts. The Commission

failed to respond to this objection in the Order No. 636 series.

Both of these reasonsthe Commission's failure to explain why

the twenty-year cap will protect against pipelines' market power,

and the failure to explain why it looked at new-construction

contracts in arriving at the twenty-year figurepersuade us to

remand the length of the contract term-matching condition to the

Commission for further consideration.47 The right-of-first-refusal

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future. The Commission responded that "[t]he requirement is not

unduly discriminatory" because "[a]ll parties have an equal

opportunity to bid for the capacity." Order No. 636-A, ¶ 30,950,

at 30,632. Although the twenty-year cap may affect different

classes of customers differently, under these circumstances it

does not violate § 5. 

mechanism, incorporating the twin matching conditions of rate and

contract term, is sufficiently justified. We remand only as to the

Commission's reasons for adopting a twenty-year cap.

3. Requirement to discount

Petitioner Meridian Oil Inc., joined by the American Public

Gas Association, challenges a different aspect of the

right-of-first-refusal mechanism. The Commission declared that a

pipeline need not accept a competing bid for a rate less than the

maximum approved rate; in other words, "pipelines are not required

to discount under the rule." Order No. 636-A, ¶ 30,950, at 30,629.

The result is that a pipeline can choose between providing service

to the highest bidder at a discounted rate and not providing

service at all unless a shipper is willing to pay the maximum

approved rate. In its comments to the Commission, Meridian urged

that pipelines be required to accept the "best bid," which on

pipelines on which capacity was not constrained would likely be

less than the maximum approved rate. The Commission responded that

it would

not require pipelines to discount transportation rates.

However, if a pipeline fails to attempt to maximize

throughput, there is no guarantee that it will be able to

recover all the costs of its underutilized capacity from

its firm customers when it files its next rate case.

Evidence that a pipeline refused to accept the highest

valued bid for capacity below the maximum rate will be

given significant weight during its next rate case.

Order No. 636-B, ¶ 61,272, at 62,028 (footnote omitted).

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Meridian contends first that the Commission violated § 7(b) by

authorizing pre-granted abandonment without requiring the pipeline

to discount. In Meridian's view, by forcing the existing customer

to pay the maximum approved rate to ensure continuity of service,

even if the competitive outcome as determined by the bidding

process is a below-maximum rate, the Commission has failed to

protect customers against pipelines' market power. See Mobil Oil,

498 U.S. at 227; AGA II, 912 F.2d at 1517. However, as we held

above, the Commission has already protected against pipelines'

market power by removing the pipeline's ability to influence the

bidding and by limiting the maximum rate that the pipeline may

charge. See supra at 43-44. The Commission first authorized

selective discounting by pipelines providing transportation under

a Part 284 blanket certificate in Order No. 436, ¶ 30,665, at

31,540-48. See 18 C.F.R. § 284.7(d)(5); AGD I, 824 F.2d at 1007-

13; see also Mississippi Valley Gas Co., 68 F.3d at 507. Given

that the purpose of selective discounting is to increase throughput

by allowing pipelines to engage in price discrimination in favor of

demand-elastic customers, AGD I, 824 F.2d at 1011, Meridian's

proposal that pipelines be required to discount in favor of

demand-inelastic, captive customers would render meaningless

pipelines' ability to charge up to the maximum approved rate. The

§ 7(b) abandonment provisions protect customers against loss of

service only if the customer is willing to pay the maximum rate

approved in a rate proceeding.

Meridian's second contention is that the Commission acted in

an arbitrary and capricious manner by not responding to Meridian's

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48 Because we are satisfied by the Commission's assurance

that it will examine pipelines' failure to discount in rate

proceedings, we need not address the Commission's alternative

contention in its brief that requiring pipelines to discount

would violate the Commission's duty to ensure adequate

capitalization to pipelines. 

comments that the lack of a requirement to discount would prevent

the right-of-first-refusal mechanism from reflecting competitive

market forces on pipelines with excess capacity. The Commission

responded to Meridian's objection by assuring that a pipeline is

not entitled to full cost recovery in its next rate proceeding when

it forgoes the opportunity to recover some of its fixed costs from

a bid rate between the minimum and maximum filed rates.48 Order No.

636-B, ¶ 61,272, at 62,028. Meridian has offered no reason why the

Commission's rate scrutiny will not provide sufficient incentives

for pipelines to discount in appropriate circumstances.

Accordingly, we affirm the Commission's decision not to require

pipelines to discount in the right-of-first-refusal process.

C. Curtailment

When supply shortages arose in the natural gas industry during

the 1970s, the Commission adopted end-use curtailment plans to

protect high-priority customers from an interruption of supply.

See generally Consolidated Edison Co. v. FERC, 676 F.2d 763, 765-67

(D.C. Cir. 1982); North Carolina v. FERC, 584 F.2d 1003, 1006-08

(D.C. Cir. 1978). In 1973, the Commission found itself " "impelled

to direct curtailment on the basis of end use rather than on the

basis of contract simply because contracts do not necessarily serve

the public interest requirement of efficient allocation of this

wasting resource.' " Order No. 467, 49 F.P.C. 85, 86 (quoting

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49 Section 401(a) provides that:

[T]he Secretary of Energy shall prescribe and make

effective a rule, ... which provides that, ... to the

maximum extent practicable, no curtailment plan of an

interstate pipeline may provide for curtailment of

deliveries of natural gas for any essential

agricultural use, unless such curtailment ... (2) is

necessary in order to meet the requirements of high

priority users."

15 U.S.C. § 3391(a); see also id. § 401(f)(2), 15 U.S.C. §

3391(f)(2) (defining "high-priority user"). 

Arkansas Louisiana Gas Co., 49 F.P.C. 53, 66 (1973)), order on

reh'g, 49 F.P.C. 217, order on reh'g, 49 F.P.C. 583 (1973),

petitions for review dismissed sub nom. Pacific Gas & Elec. Co. v.

FPC, 506 F.2d 33 (D.C. Cir. 1974). The Commission's end-use

curtailment schemes were essentially enacted into law by title IV

of the Natural Gas Policy Act of 1978 (NGPA),49 which establishes

the following priority system:

Whenever there is an insufficient supply, under the Act

first in line to receive gas are schools, small business,

residences, hospitals, and all others for whom a

curtailment of natural gas could endanger life, health,

or the maintenance of physical property. After these

"high-priority" users have been satisfied, next in line

are those who will put the gas to "essential agricultural

uses," followed by those who will use the gas for

"essential industrial process or feedstock uses,"

followed by everyone else.

Process Gas Consumers Group v. United States Dep't of Agric., 657

F.2d 459, 460 (D.C. Cir. 1981) (Process Gas I); see also 18 C.F.R.

§§ 281.201-281.215 (the Commission's regulations implementing NGPA

§ 401).

With the introduction of stand-alone firm-transportation

service in Order No. 436, the Commission distinguished for the

first time between supply curtailment and capacity curtailment.

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Transportation service can suffer from a capacity interruption

(such as a force majeure loss of capacity due to pipeline system

failure or a pipeline's overbooking of capacity), whereas sales

service can suffer from a shortage in the supply of gas. See Order

No. 436, ¶ 30,665, at 31,515; Order No. 436-A, ¶ 30,675, at

31,652. The Commission's subsequent approach was to allow

pipelines to adopt pro rata capacity curtailment (allocation

proportional to the amount reserved, without regard to end use),

see, e.g., Texas Eastern Transmission Corp., 37 F.E.R.C. ¶ 61,260,

at 61,692-93 (1986), order on reh'g, 41 F.E.R.C. ¶ 61,015 (1987),

aff'd sub nom. Texaco, Inc. v. FERC, 886 F.2d 749 (5th Cir. 1989),

unless the parties agreed to end-use capacity curtailment on a

particular pipeline, see, e.g., Florida Gas Transmission Co., 51

F.E.R.C. ¶ 61,309, at 62,010-11, order on reh'g, 53 F.E.R.C. ¶

61,396 (1990).

In City of Mesa v. FERC, 993 F.2d 888 (D.C. Cir. 1993), the

court reviewed a proceeding in which the Commission had approved

end-use curtailment for supply shortages but pro rata curtailment

for capacity interruption. El Paso Natural Gas Co., 54 F.E.R.C. ¶

61,316, at 61,928-29, order on reh'g, 56 F.E.R.C. ¶ 61,290, at

62,153-54 (1991). First, the court upheld the Commission's

interpretation of the word "deliveries" in § 401(a) of the NGPA to

refer only to pipelines' sale of gas, so that the statutory end-use

curtailment scheme in title IV applied only to supply curtailment.

993 F.2d at 892-94; see also Atlanta Gas Light Co. v. FERC, 756

F.2d 191, 196-97 (D.C. Cir. 1985). The court found that different

treatment of supply and capacity curtailment was reasonable because

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high-priority users can "generally "fend for themselves' " to

protect against capacity interruption:

Supply shortages usually lead to prolonged periods in

which there is simply too little gas to serve the needs

of all users. In contrast, capacity constraints occur

when there is enough gas in the market but an unexpected

event has caused a brief interruption in the movement of

the gas to consumers. Additionally, capacity

constraints, unlike supply shortages, may only affect the

movement of gas on part of a pipeline, thereby allowing

customers to receive their quota of gas by using

alternate routes that skirt the pipeline bottleneck.

These differences mean that pipeline customers can more

easily adopt self-help measures to protect their

high-priority end-users against the harmful effects of

capacity curtailments than supply shortages.

City of Mesa, 993 F.2d at 894-95.

Although City of Mesa upheld the limitation of title IV of the

NGPA to supply shortages, the court acknowledged that the NGA

provided protections for capacity shortages. The court stated that

"implicit in th[e] consumer protection mandate [of NGA §§ 4 and

7(e)] is a duty to assure that consumers, especially high-priority

consumers, have continuous access to needed supplies of natural

gas." 993 F.2d at 895. This duty arises because " "[n]o single

factor in the Commission's duty to protect the public can be more

important to the public than the continuity of service provided.'

" Id. (quoting Sunray Mid-Continent Oil Co. v. FPC, 239 F.2d 97,

101 (10th Cir. 1956), rev'd on other grounds, 353 U.S. 944 (1957)).

The court emphasized that "since the NGA gives the FERC no specific

guidance as to how to apply its broad mandates in a particular

case, our review of the FERC's actions here is, again, quite

limited." Id. In City of Mesa, the court concluded that the

Commission had failed to engage in reasoned decision making when it

approved a curtailment plan that protected "most" high-priority

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users rather than all such users. Id. at 896-97. The court noted

that in Order No. 636-A the Commission had held that "self-help

strategies were generally sufficient to assure protection of

end-users and thus to meet NGA mandates" but did not further

examine whether self-help measures were adequate to protect against

capacity curtailment. Id. at 897.

In Order No. 636, which was issued before the court's decision

in City of Mesa, the Commission continued without change its

curtailment policies since Order No. 436. First, the Commission

acknowledged that, as a policy matter, it chafed at the title IV

end-use curtailment scheme for supply shortages but stated that it

was bound by the statute. Order No. 636, ¶ 30,939, at 30,430; see

also Transcontinental Gas Pipe Line Corp., 57 F.E.R.C. ¶ 61,345, at

62,117 (1991). The Commission reiterated its reading of § 401(a)

that limited its scope to pipelines' sale of gas. Order No. 636-A,

¶ 30,950, at 30,586-89. Second, the Commission maintained that

self-help measures would allow the consumer-protection mandate of

the NGA to be satisfied by pro rata capacity curtailment:

The Commission believes that with deregulated wellhead

sales and a growing menu of options for unbundled

pipeline service, customers should rely on prudent

planning, private contracts, and the marketplace to the

maximum extent practicable to secure both their capacity

and supply needs. In today's environment, LDC's [sic]

and end-users no longer need to rely exclusively on their

traditional pipeline supplier. Rather, to an

ever-increasing degree they rely on private contracts

with gas sellers, storage providers, and others; a more

diverse portfolio of pipeline suppliers, where possible;

local self-help measures (e.g., local production, peak

shaving and storage); and their own gas supply planning

through choosing between an increasing array of unbundled

service options.

Id. at 30,590.

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The Commission's curtailment policies are challenged from both

sides. Elizabethtown Gas Company contends that the Commission

should have adopted pro rata curtailment for shortages in the

supply of pipeline gas, and a group of small distributors contends

that the Commission should have adopted end-use curtailment for

capacity interruption and for shortages in the supply of

third-party gas.

1. Supply curtailment of pipeline gas

Elizabethtown contends that because § 401(a) of the NGPA

requires end-use curtailment only "to the maximum extent

practicable," 15 U.S.C. § 3392(a), the declining role of pipelines

as gas merchants renders end-use curtailment for shortages of

pipeline gas no longer "practicable." The court recently rejected

this argument, made by the same petitioner, in Elizabethtown Gas

Co. v. FERC, 10 F.3d 866 (D.C. Cir. 1993) (Elizabethtown III):

This argument makes no sense to us. Even if [the

pipeline] supplies a smaller share of the gas bought by

each of the LDCs, the gas it does deliver to them could

still in times of shortage go first to "high-priority

users." Accordingly, it seems entirely "practicable" to

increase the level of protection for high priority users

above that provided by the pro rata plan.

Id. at 874; see also Process Gas Consumers Group v. United States,

694 F.2d 778, 787-92 (D.C. Cir. 1982) (en banc) (Process Gas II)

(holding that the phrase "to the maximum extent practicable" gives

the Commission broad powers). Although Elizabethtown contends that

the near-elimination of pipelines as gas merchants following Order

No. 636 requires us to reconsider our holding in Elizabethtown III,

this change in the industry does not affect our reasoning that

end-use curtailment remains "practicable" no matter how small the

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pipelines' share of the gas-sales market. The Commission

recognized that the limitation of title IV of the NGPA to

pipelines' sale of gas means that pipelines are disadvantaged

vis-à-vis other gas merchants, but explained that it remained bound

by the statute. Order No. 636, ¶ 30,929, at 30,430. Because we

have already decided this question in Elizabethtown III, we affirm

the Commission's decision that title IV of the NGPA mandates

end-use curtailment for shortages in the supply of pipeline gas.

Elizabethtown also maintains that the Commission acted

arbitrarily in not requiring high-priority users to compensate

pipeline customers who lose gas supply under end-use curtailment.

In Elizabethtown III, the court "held that a compensation provision

is not necessarily inconsistent with § 401(a)." 10 F.3d at 875.

Indeed, this court has long held that the Commission retains the

authority under title IV of the NGPA to adopt a compensation

scheme. See Consolidated Edison Co. v. FERC, 676 F.2d 763, 767

(D.C. Cir. 1982); cf. Elizabethtown Gas Co. v. FERC, 575 F.2d 885,

887-89 (D.C. Cir. 1978) (Elizabethtown I) (holding that the

Commission has authority under the NGA to adopt a curtailment

compensation plan). In Elizabethtown III, the court remanded with

instructions for the Commission to consider Elizabethtown's

"request for a curtailment compensation scheme." Id. In the Order

No. 636 series, decided before the court's decision in

Elizabethtown III, the Commission stated that its

position on curtailment compensation plans is that the

parties in the individual restructuring proceedings must

explore the development of such schemes ... in the

context of developing their individual curtailment plans

and in the development of voluntary emergency contractual

arrangements between shippers. However, the Commission

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believes that it would be contrary to the concept of the

restructuring proceeding process and the negotiation and

development of individually tailored curtailment

allocation procedures and emergency mechanisms for it to

mandate a generic compensation scheme.

Order No. 636-A, ¶ 30,950, at 30,592; see also Order No. 636, ¶

30,929, at 30,430. The comments by the Commission in the Order No.

636 series continue the Commission's pattern of avoiding the

question of curtailment compensation and do not exhibit the

reasoned consideration of curtailment compensation that the court

subsequently requested in Elizabethtown III.

The Commission has reconsidered the issue of curtailment

compensation, however, on remand from Elizabethtown III. See

Transcontinental Pipe Line Corp., 72 F.E.R.C. ¶ 61,037, reh'g

denied, 73 F.E.R.C. ¶ 61,357 (1995). In those proceedings, the

Commission

conclude[d] that compensation is needed to render

Transco's gas supply curtailment plan just and

reasonable. The priority curtailment plan affects the

contractual rights of Transco's customers by altering the

pro rata allocation of curtailed supplies so that higher

priority customers can obtain gas that would otherwise go

to lower priority customers.

72 F.E.R.C. ¶ 61,037, at 61,235. The Commission rejected

Elizabethtown's proposed compensation scheme, however, in favor of

requiring the higher-priority customer to pay: (1) 150% of the

spot market price for gas if the lower-priority customer was unable

to cover (locate replacement gas on the spot market), or (2) the

difference between the cover price and the original contract price

if the lower-priority customer was able to cover. Id. at 61,237-

38.

In light of the Commission's Transcontinental decision, the

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issue of curtailment compensation is not ripe for review. The

Commission enjoys broad discretion whether to adopt a compensation

scheme on a generic basis or in pipeline-specific proceedings. See

Mobil Oil, 498 U.S. at 230. If Elizabethtown remains aggrieved by

the Commission's decision to accept its general argument but

fashion a different compensation mechanism, then it may seek relief

in review of the Transcontinental decision. We therefore express

no opinion on the appropriateness of any particular curtailment

compensation plan.

2. Capacity curtailment

The small distributor petitioner group, on the other hand,

contends that pro rata capacity curtailment violates the

consumer-protection mandate of the NGA. We review the Commission's

policy on pro rata curtailment to determine whether it is "just and

reasonable" under § 4 and whether it serves the "present or future

public convenience and necessity" under § 7(e). See City of Mesa,

993 F.2d at 895. The Commission decided that the

consumer-protection mandate of the NGA did not require it to adopt

end-use capacity curtailment across the board and promised to

address the issue in each pipeline restructuring proceeding. Order

No. 636-A, ¶ 30,950, at 30,591-92. Indeed, the Commission has

broad latitude on whether to effectuate its policies in generic

rulemakings or in individual-pipeline adjudications. Mobil Oil,

498 U.S. at 230. The issue presented to us, then, is whether the

Commission's decision that the NGA does not require end-use

curtailment in all circumstances is " "reasoned, principled, and

based upon the record.' " Great Lakes Gas Transmission Ltd.

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Partnership v. FERC, 984 F.2d 426, 432 (D.C. Cir. 1993) (quoting

Columbia Gas Transmission Corp. v. FERC, 628 F.2d 578, 593 (D.C.

Cir. 1979)).

The Commission explained that Order No. 636 had allowed the

development of market structures that would enable customers to

take independent, market-based steps to avoid the need for

Commission-mandated end-use curtailment. Order No. 636-A, ¶

30,950, at 30,590. Moreover, the Commission found that since the

enactment of the NGPA in 1978 "the industry has not experienced

shortages beyond isolated, short-lived dislocation," id. at 30,591,

and "gas has always flowed according to the dictate of the market,

i.e., to the heat sensitive users who need it most and who are thus

willing to pay the prevailing market price for it." Id. at 30,592.

This experience with the industry provides substantial evidence for

the Commission's conclusion that end-use curtailment is not

required in all circumstances.

We are unpersuaded, particularly in light of the Commission's

own actions in the restructuring proceedings, that pro rata

capacity curtailment would adequately protect all high- priority

customers on all pipelines. Cf. City of Mesa, 993 F.2d at 896-97.

The Commission's market-based alternatives for customers to avoid

curtailment fall into the following categories: (1) arrangements

with other pipelines; (2) arrangements with other gas sellers;

(3) arrangements for gas storage; (4) arrangements with other

customers (including the capacity-release mechanism); and (5)

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50 Peak shaving is "the practice of adding propane air

mixtures to augment supplies of natural gas during periods of

peak demand." Atlanta Gas Light, 756 F.2d at 195 n.5. 

"peak shaving."50 First, arrangements with other pipelines are more

widely available after Order No. 636, such as by using different

pipelines that connect to one "market center," but a capacity

constraint on a pipeline will still cut off delivery to any

"captive customers," no matter how many transportation options some

other customers may have. Second, arrangements with other gas

sellers are by definition relevant only to supply curtailment, not

to capacity curtailment. Third, arrangements for gas storage are

unhelpful if the capacity interruption occurs at a point between

the contract-storage area and the customer's receipt point.

Fourth, obtaining gas from other customers, whether through the

capacity-release mechanism or otherwise, depends upon the

willingness of lower-priority customers to forgo deliveries.

Fifth, practices such as "peak shaving" (letting a little gas go a

longer way) can temporarily help to alleviate curtailment problems

but cannot ensure continuous service if the interruption lasts too

long. None of these market-based solutions, therefore, can

guarantee continuous service to all high-priority customers in

cases of capacity interruptions. Many of the market-based

solutions fail to acknowledge that many customers have far less

control over access to pipeline capacity than they do over gas

supply. In addition, some of the self-help mechanisms will be more

readily available to larger pipeline customers. City of Mesa, 993

F.2d at 897 n.7.

Yet the Commission has not applied Order No. 636 in the

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restructuring proceedings to preclude the development of

curtailment plans that provide more protection to higher-priority

users. For example, on remand from City of Mesa, the Commission

reiterated its general policy that "customers can, and should,

avail themselves of self-help methods to obtain their needed

supplies" but, in light of the decision in City of Mesa, ordered El

Paso to "includ[e] provisions giving relief to any high priority

shipper when that shipper has exercised all other self-help

remedies in times of bona fide emergencies." El Paso Natural Gas

Co., 69 F.E.R.C. ¶ 61,164, at 61,624 (1994), order on reh'g, 72

F.E.R.C. ¶ 61,042, reh'g denied, 73 F.E.R.C. ¶ 61,074 (1995). In

another restructuring proceeding, the Commission approved a

settlement and found its curtailment plan consistent with City of

Mesa because it "provides an exemption from pro rata curtailment

whenever necessary to avoid irreparable injury to life or

property." Florida Gas Transmission Co., 70 F.E.R.C. ¶ 61,017, at

61,061 (1995). On occasions, the Commission has suggested that

"there may be extraordinary circumstances when reasonable self-help

efforts are insufficient, even for large customers," such that some

emergency protections may always be required for certain force

majeure capacity interruptions. El Paso, 69 F.E.R.C. ¶ 61,164, at

61,624; see also United Gas Pipe Line Co., 65 F.E.R.C. ¶ 61,006,

at 61,092, reh'g denied sub nom. Koch Gateway Pipeline Co., 65

F.E.R.C. ¶ 61,338, at 62,630-31 (1993).

We need not reach the issue whether the adoption of a pure pro

rata capacity-curtailment scheme on a generic basis would comply

with the Commission's duty under the NGA to ensure that

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"high-priority consumers[ ] have continuous access to needed

supplies of natural gas." City of Mesa, 993 F.2d at 895. All the

Commission did in Order No. 636 was to decide not to require

end-use capacity curtailment for all pipelines. Because the

Commission expressly declared that it would re-examine the

suitability of pure pro rata capacity curtailment for customers on

each pipeline, Order No. 636-A, ¶ 30,950, at 30,591-92, we construe

any indications that pro rata curtailment will be the default as

unreviewable policy statements under § 4(b)(A) of the

Administrative Procedure Act, 5 U.S.C. § 553(b)(A). See Pacific

Gas & Elec. Co. v. FPC, 506 F.2d 33, 39 (D.C. Cir. 1974). The

manner in which the Commission has applied its curtailment policy

in the restructuring proceedings supports our conclusion that any

preference for pro rata schemes is not suitable for review. See

Public Citizen, Inc. v. NRC, 940 F.2d 679, 682-83 (D.C. Cir. 1991).

Accordingly, the compliance of specific curtailment plans with the

NGA's consumer-protection mandate remains open on review of the

restructuring proceedings.

We uphold the Commission's decision not to require end-use

curtailment on a generic basis for capacity curtailment but to

proceed instead on a case-by-case basis.

3. Supply curtailment of third-party gas

Finally, the small distributor petitioners contend that the

consumer-protection mandate of the NGA requires the Commission to

adopt end-use curtailment for shortages in the supply of

third-party gas. The petitioners concede that title IV of the NGPA

applies only to pipelines' sale of gas, but urge that §§ 4 and 7(e)

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51 Our reasons for holding that the Commission may apply a

curtailment plan to shortages in the supply of gas owned by

someone not a "natural-gas company" are the same as our reasons,

for holding that the Commission may apply a capacity-release plan

to capacity rights held by a municipal LDC, which is not a

of the NGA require some form of end-use curtailment for the sale of

gas by producers and other third parties. The Commission declined

to "impos[e] ... the industry-wide, end-use supply curtailment

scheme envisioned by the petitioners" because "the best protection

against, and remedy for, supply shortages [i]s to allow the market

to establish the price for gas." Order No. 636-A, ¶ 30,950, at

30,591.

As an initial matter, a group of intervenors in support of the

Commission maintains that the Commission lacks jurisdiction under

§ 1(b) to enact a curtailment plan for third-party gas. But the

Supreme Court has held expressly that "curtailment plans are

aspects of [the Commission's] "transportation' and not its "sales'

jurisdiction." Louisiana Power & Light, 406 U.S. at 641 (citing

Panhandle Eastern Pipe Line Co. v. Public Serv. Comm'n, 332 U.S.

495, 523 (1947)). The intervenors rely on a Fifth Circuit case,

Sebring Utilities Commission v. FERC, 591 F.2d 1003 (5th Cir.),

cert. denied, 444 U.S. 879 (1979), in which the court indicated

that the Commission would not have jurisdiction to order

curtailment of gas not owned by a statutory "natural-gas company."

Id. at 1016-19. However, the ownership of the gas is not relevant

to the Commission's transportation jurisdiction because in adopting

a curtailment scheme the Commission exercises its jurisdiction over

the pipeline, which incorporates any curtailment plan into its

tariff.51 If we were to follow Sebring, then the Commission would

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"natural-gas company." See infra Part III.B.3. 

52 The intervenors also rely on American Public Gas

Association v. FERC, 587 F.2d 1089 (D.C. Cir. 1978) (per curiam),

in which the court approved the Commission's policy at that time

of excluding "direct sales" gas (gas sold directly from producers

to LDCs or certain high-priority end-users) from pipelines'

end-use curtailment plans, so as to alleviate the shortage of gas

in the interstate market. Id. at 1097-98. Nothing in that

opinion, however, limits the Commission's § 1(b) transportation

jurisdiction to pipeline-owned gas or precludes the Commission

from adopting a different policy for the curtailment of

third-party gas, given the changed circumstances in the end of

the gas shortage and the unbundling of sales and transportation. 

See Order No. 636-A, ¶ 30,950, at 30,589-90. 

also lack jurisdiction to regulate capacity curtailment of

third-party gasa proposition implicitly rejected by the City of

Mesa court, which in remanding on the capacity-curtailment issue

assumed that the Commission had jurisdiction over curtailment plans

for third-party gas. 993 F.2d at 895-98. Moreover, Sebring was

decided before the unbundling of sales from transportation, at a

time when virtually all gas was pipeline-owned.52 Under the

principles of Louisiana Power & Light, the Commission's

transportation jurisdiction extends to supply curtailment of

third-party gas.

The Commission decided that an end-use supply curtailment plan

for third-party gas was not required to ensure high-priority

customers "continuous access to needed supplies of natural gas."

City of Mesa, 993 F.2d at 895. As discussed with respect to

capacity curtailment, see supra at 58-59, the Commission provided

a list of market-based alternatives to secure the continuous supply

of gas that is convincing in the context of supply curtailment.

Although the petitioners posit a force majeure supply shortage that

the market-based protections would not cover, namely a "freeze-off

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53 Our review is confined to the the capacity release

provisions before they were amended by Order No. 577. See supra

at 19 n.18. 

" of wells that would prevent all producers from producing

sufficient quantities of gas during cold weather, the petitioners

have provided no evidence that such an event has ever occurred or

is likely to occur in the future. The Commission's decision that

such an occurrence is unlikely "given foreseeable supply

conditions" is reasonable. Order No. 636-A, ¶ 30,950, at 30,591.

In addition, the Commission noted that title III of the NGPA, 15

U.S.C. §§ 3361-3364, authorizes the President to "declare a natural

gas supply emergency" in the event of "a severe natural gas

shortage, endangering the supply of natural gas for high-priority

uses." Id. § 3361(a); see Order No. 636-A, ¶ 30,950, at 30,591.

Thus, the Commission has complied with the

continuity-of-service guarantee of the NGA, as articulated in City

of Mesa, with respect to supply shortages of third-party gas.

III. Capacity Release

In this part of the opinion, we address challenges to the

voluntary capacity release provisions of Order No. 636, which

permit holders of firm transportation rights on a gas pipeline to

resell them. 18 C.F.R. § 284.243 (1995).53 Petitioners challenge

the Commission's jurisdiction to institute its capacity release

program generally, as well as its jurisdiction over (1) LDCs'

capacity sales to their local end-users; (2) capacity sales by

municipal LDCs; and (3) state-regulated "buy/sell" transactions.

Petitioners also challenge the exclusion of individually

certificated shippers from the capacity release program, the

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54 In this sense, the Commission's description of capacity

release as creating a secondary transportation market is somewhat

misleading, given that both resales of firm capacity and initial

sales by pipelines are in direct competition with each other, and

unavailable in any other forum. 

standards that FERC promulgated for determining the prevailing

bidder in the capacity release transaction, and the mechanism for

crediting interruptible transportation revenues. We conclude that

each of petitioners' claims is either incorrect on the merits or is

not suited for review in these proceedings.

A. Introduction

Among the central goals of Order Nos. 436 and 636 has been the

conversion of bundled sales arrangements into separate

transportation and gas sales transactions. On the transportation

side, the Commission recognized that while much of the nation's

interstate pipeline capacity was reserved for firm transportation,

those transportation rights ultimately were not being utilized.

See supra Part I.C. FERC therefore sought to develop an active

"secondary transportation market," with holders of unutilized firm

capacity rights reselling them in competition with any capacity

offered directly by the pipeline.54 According to the Commission:

Capacity reallocation will promote efficient load

management by the pipeline and its customers and,

therefore, efficient use of the pipeline capacity on a

firm basis throughout the year. Because more buyers will

be able to reach more sellers through firm transportation

capacity, capacity reallocation comports with the goal of

improving nondiscriminatory, open-access transportation

to maximize the benefits of the decontrol of natural gas

at the wellhead and in the field.

Order No. 636, ¶ 30,939, at 30,418. Understanding petitioners'

challenges to the capacity release program requires a brief review

of related policies that the Commission has employed in the past to

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accomplish a similar end.

If a firm capacity holder does not ship gas under its

transportation right, it pays the pipeline a "reservation fee," but

does not pay a "usage fee." Historically, FERC prohibited such

holders of unutilized firm capacity rights from transferring those

rights to other shippers, and shippers were therefore able to

purchase capacity rights only directly from pipelines. See

generally United Gas Pipe Line Co., 46 F.E.R.C. ¶ 61,060 (1989)

(approving first experimental capacity brokering program).

Beginning with the Texas Eastern Transmission Corp. proceedings, 48

F.E.R.C. ¶ 61,248, order on reh'g, 48 F.E.R.C. ¶ 61,378 (1989),

order on reh'g, 51 F.E.R.C. ¶ 51,170, order on reh'g, 52 F.E.R.C.

¶ 61,273 (1990), however, the Commission authorized shippers on

some pipelines to engage in nondiscriminatory "capacity brokering."

Brokering arrangements allowed a holder of firm capacity rights

(the "releasing shipper") to sell those rights to a "replacement

shipper." The transaction took place directly between the two

parties, and the replacement shipper essentially stepped into the

shoes of the releasing shipper.

Three years later, in the Order No. 636 and companion

Algonquin Gas Transmission Corp. proceedings, 59 F.E.R.C. ¶ 61,032

(1992), FERC concluded that it could not ensure that the extant

capacity brokering programs were operating in a nondiscriminatory

manner. When transactions occurred directly and privately between

shippers, there was no way to verify that certain purchasers were

not being favored unreasonably over others. "Simply put, there

[were] too many potential assignors of capacity and too many

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55 Capacity brokering agreements already in effect on the

date that the pipeline implemented its capacity release program

were not substantially altered by Order No. 636. Order No. 636,

¶ 30,939, at 30,421. The Order required that the pipeline enter

into a contract directly with the replacement shipper, as it

would under capacity release, with terms that mirrored those in

the capacity brokering agreement. Algonquin Gas Trans. Co., 59

F.E.R.C. ¶ 61,032, at 61,096-97. 

different programs for the Commission to oversee capacity

brokering...." Order No. 636, ¶ 30,939, at 30,416. In FERC's

view, fairness could be secured only if capacity resale

transactions were both centralized on each pipeline and subject to

open bidding. Moreover, uniformity among the various pipelines was

necessary to "prevent any pipeline or firm shipper from achieving

an undue advantage, or incurring an undue disadvantage, compared to

firm shippers on other pipelines." Id.

Accordingly, in Order No. 636, the Commission instituted a

uniform national "capacity release" program, and exercised its

power under NGA § 5 to conform pipelines' existing capacity

brokering certificates to that program.55 Id. While both capacity

brokering and capacity release arrangements involve the releasing

shipper's decision to sell excess capacity, capacity release

requires the central involvement of the pipeline in the

transaction. Specifically, under capacity release, each interstate

pipeline is required to establish and administer an electronic

bulletin board ("EBB"), which is a computer through which putative

releasing and replacement shippers may communicate. Id. at 30,418.

The EBB carries information about available and consummated

capacity release transactions. For example, holders of excess firm

capacity rights may "post" their available capacity on the EBB.

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56 For example, the releasing shipper may elect to release

capacity only for so long as the temperature remains above a

certain level. If the temperature were to drop, the firm

capacity rights would revert to the releasing shipper. Order No.

636, ¶ 30,939, at 30,418. 

57 FERC has amended the short-term transactions provision

specifically to encompass those capacity releases of no more than

31 days. See supra at 19 n.18. That amendment does not affect

our review. 

58 The transaction must still be posted on the EBB. In

addition, extensions and roll-overs of "short-term" transactions

are prohibited. 18 C.F.R. § 284.243(h)(2); Order No. 636, ¶

30,939, at 30,551. 

Further, they may establish nondiscriminatory conditions on the

sale, including a minimum price and any terms under which the

release may continue.56 Pipelines are also required to post on the

EBB any firm capacity that they have available for sale, where the

capacity competes for buyers against capacity made available for

resale by shippers. "Potential purchasers of capacity will then be

able to choose from among the pipeline and the releasers the

service that best suits their needs." Id. at 30,419. In addition,

shippers that wish to acquire firm capacity rights may post offers

to purchase capacity on the EBB. 18 C.F.R. § 284.243(d); Order

No. 636-A, ¶ 30,950, at 30,565.

With two exceptions, the pipeline must sell the capacity to

the highest bidder. First, "short-term transactions," i.e., those

for capacity releases of less than one month,57 may be arranged

between shippers without competitive bidding.58 18 C.F.R. §

284.243(h)(1); Order No. 636-A, ¶ 30,950, at 30,554. Second, a

releasing shipper may identify a replacement shipper on its own and

enter into a "pre-arranged" deal. 18 C.F.R. § 284.243(b); Order

No. 636, ¶ 30,939, at 30,418. In such a transaction, the selected

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59 Order No. 636 pre-granted shippers a limited blanket

certificate under NGA § 7 to release capacity in a

nondiscriminatory manner. 18 C.F.R. § 284.243(g); Order No.

636, ¶ 30,939, at 30,421. 

replacement shipper need only matchrather than outbidthe highest

offer made by any other shipper. 18 C.F.R. § 284.243(e). The net

effect is that a shipper may ensure that it will receive certain

capacity by entering into a pre-arranged deal that both conforms to

the releasing shipper's conditions and matches the maximum

allowable rate for the capacity. No matter what form the capacity

release transaction takes, however, the purchase price for released

capacity may not exceed the maximum rate set by FERC for the

capacity. 18 C.F.R. § 284.243(e); Order No. 636, ¶ 30,939, at

30,420.

After the replacement shipper has been identified, the

pipeline enters into a contract with it for firm capacity rights.59

The pipeline then may elect to excuse completely the releasing

shipper's obligation to pay the reservation fee and related costs.

Order No. 636, ¶ 30,939, at 30,419. Otherwise, the releasing

shipper is credited for those costs unless the replacement shipper

defaults. 18 C.F.R. § 284.243(f); Order No. 636-A, ¶ 30,950, at

30,553. In no instance, however, is the releasing shipper liable

for costs associated with the replacement shipper's transportation

of gas.

We now turn to petitioners' varied challenges to the

Commission's capacity release program.

B. Jurisdictional Challenges

Various petitioners challenge both FERC's jurisdiction to

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60 For an overview of the history of the Act's inception,

see generally Arkansas Elec. Coop. v. Arkansas Pub. Serv. Comm'n,

461 U.S. 375, 377-80 (1983); Panhandle Pipe Line Co. v. Public

Serv. Comm'n, 332 U.S. 495, 514-21 (1947); Illinois Gas Co. v.

Central Ill. Pub. Serv. Co., 314 U.S. 498, 504-08 (1942); 

National Ass'n of Regulatory Util. Comm'rs v. FERC, 823 F.2d

1377, 1382-87 (D.C. Cir. 1987). 

institute a uniform capacity release program and its jurisdiction

over specific transactions and entities. We begin, then, by

outlining the Commission's jurisdiction under § 1(b) of the Natural

Gas Act of 1938. Ultimately, we conclude that FERC's capacity

release program is a legitimate exercise of its jurisdiction over

the interstate transportation of natural gas.

In the early part of this century, state regulatory agencies

actively involved themselves in structuring the natural gas

industry. The Supreme Court, however, severely cabined those

efforts in a series of decisions that interpreted the dormant

Commerce Clause to preclude state regulation of both the interstate

transportation of natural gas and its ensuing sale in wholesale

markets.60 Congress enacted the Natural Gas Act of 1938 to fill the

resulting regulatory gap. The Act, as provided in § 1(b), applies

[1] to the transportation of natural gas in interstate

commerce, [2] to the sale in interstate commerce of

natural gas for resale for ultimate public consumption

for domestic, commercial, industrial, or any other use,

and [3] to natural-gas companies engaged in such

transportation or sale, but [does] not apply [4] to any

other transportation or sale of natural gas or [5] to the

local distribution of natural gas or to the facilities

used for such distribution or [6] to the production or

gathering of natural gas.

15 U.S.C. § 717(b).

Petitioners' jurisdictional challenges require us to interpret

the first and fifth provisions of § 1(b), which address the

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61 For an overview of the Commission's transportation

jurisdiction, see generally Louisiana Power & Light, 406 U.S. at

636-40; United Gas Pipe Line Co. v. FPC, 385 U.S. 83, 89 (1966); 

East Ohio Gas, 338 U.S. at 467-74; Cascade Natural Gas Corp. v.

FERC, 955 F.2d 1412, 1415-21 (10th Cir. 1992); Michigan Consol. 

Gas Co. v. FERC, 883 F.2d 117, 121-22 (D.C. Cir. 1989). 

interstate transportation and "local distribution" of natural gas.61

In truth, the two provisions are a unity. "It is well established

that the ["local distribution"] proviso was added to the Act merely

for clarification and was not intended to deprive [FERC] of any

jurisdiction otherwise granted by § 1(b)." Louisiana Power &

Light, 406 U.S. at 637 n.14; see also East Ohio Gas, 338 U.S. at

469-70 ("[W]hat Congress must have meant by "facilities' for "local

distribution' was equipment for distributing gas among consumers

within a particular local community, not the high-pressure pipe

lines transporting the gas to the local mains."). As explained in

the House Report on the Act:

That part of the negative declaration that the act shall

not apply to "the local distribution of natural gas" is

surplusage by reason of the fact that distribution is

made only to consumers in connection with sales, and

since no jurisdiction is given to the Commission to

regulate sales to consumers the Commission would have no

authority over distribution, whether or not local in

character.

H.R. REP. NO. 709, 75th Cong., 1st Sess. 3 (1937). And, as this

circuit has concluded:

Insofar as congressional committees spoke to the matter,

therefore, they appear to have viewed distribution as

confined to its parceling out function and (probably)

even more narrowly, to parceling out accompanied by

retail sales. As § 1(b) gave the Commission jurisdiction

only over sales for resale, the states had unquestioned

authority over retail sales anyway, making the

reservation for distribution surplusage.

Public Utils. Comm'n v. FERC, 900 F.2d 269, 276 (D.C. Cir. 1990).

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We now consider whether FERC has done more than its interstate

transportation jurisdiction permits.

1. FERC's jurisdiction to regulate capacity release

Petitioners' first jurisdictional challenge is the claim of

the LDCs that FERC lacks any authority whatsoever to regulate

shippers' resale of firm capacity rights. "LDCs' capacity

assignments," they maintain, "involve sales of LDCs' rights to

transportation service but do not involve interstate transportation

or sale for resale of gas itself." As we understand their

position, the LDCs would limit FERC's regulatory authority over

transportation to the rendition of interstate gas transportation

services, as opposed to authority over the rights to receive those

services. As their theory goes, the Commission has jurisdiction

over the pipelines' initial sales of transportation capacitygiven

that it is the pipelines that render transportation servicesbut is

without jurisdiction over resales of those same capacity rights by

third partiesgiven that those third parties do not render

transportation services.

Initially, we believe that the distinction drawn by the LDCs

between the "rights to" and "rendition of " interstate

transportation services is not a meaningful one. While the

pipeline provides transportation only when a party utilizes

capacity rights to transport gas, the pipeline provides

transportation services throughout the capacity release process.

Specifically, the pipeline operates the electronic bulletin board

on which all prospective transactions are posted and consummated.

The pipeline also selects the winning bidder in the transaction.

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Moreover, unlike capacity brokering arrangements, which occur

directly between releasing and replacement shippers, capacity

release requires the pipeline to contract with the replacement

shipper. "In effect, the pipeline is temporarily abandoning

service to the releasing shipper and instituting service to the

replacement shipper. Both of these activities are subject to the

Commission's jurisdiction under NGA section[ ] 1(b)...." Order No.

636-A, ¶ 30,939, at 30,551. In sum, the capacity release

regulations operate as a term or condition of pipeline service,

with which its customers must comply.

As an entirely separate matter, the Commission's jurisdiction

attaches to the subject of the capacity resale transaction:

interstate transportation rights. "By controlling such capacity,

the assignors are effectively determining by whom, and under what

circumstances, gas will be transported and are using the pipeline's

facilities as if they were the assignors' facilities." Id.

(quotation marks, alteration, and citation omitted). In contrast,

under the regulatory system envisioned by the LDCs, holders of

capacity rights could engage in resales without regard to the

principles of open access and nondiscrimination that are at the

heart of the uniform capacity release system. Such a result is

directly contrary to Congress' intent in enacting the Natural Gas

Act. Responding to the Supreme Court's conclusion that the

Constitution's dormant Commerce Clause prohibited state regulation

of the interstate transportation of natural gas, see supra at 67,

the federal government interceded to ensure stability and protect

the interests of the consuming public. It thereby occupied the

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field, which necessarily includes both the sale and resale of

interstate transportation rights.

2. Jurisdiction over LDCs' capacity sales to their own end-users

Several petitioners make more limited claims that specific

classes of entities and transactions must be exempted from the

Commission's control over capacity resales. First, the PUCs and

LDCs together argue that FERC lacks jurisdiction over capacity

sales by LDCs to their own end-users. Such transactions, they

maintain, fall within the NGA's "local distribution" exemption.

Specifically, according to petitioners, the Commission has always

recognized that the states have jurisdiction to regulate bundled

sales of natural gas by LDCs to their end-users, which necessarily

involves some indirect influence over the interstate transportation

element of the sale. State authority remains intact for LDCs'

rebundled sales of gas and transportation even after the

implementation of Order No. 636. They contend that there is no

functional difference between that jurisdictional arrangement and

state regulation of LDCs' sales of unbundled gas andmore relevant

heretransportation to local end-users. In particular, petitioners

contend that state regulatory commissions need the freedom to

control LDCs' assignment of capacity so that local end-users will

be ensured of access to pipeline service.

But, as we have already explained, petitioners' reading of NGA

§ 1(b)'s reference to "local distribution" is flawed; the proviso

does not withdraw from FERC's jurisdiction any aspect of the

interstate transportation of natural gas. In this regard, we find

the Commission's explanation of the regulatory environment far more

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62 The LDCs briefly argue that NGA § 1(c), the so-called

"Hinshaw exemption," deprives the Commission of jurisdiction over

their capacity sales to their own end-users. In this regard,

they refer us to Congress' determination in § 1(c) that certain

pipelines are "matters primarily of local concern and subject to

regulation by the several States." 15 U.S.C. § 717(c). Section

1(c), however, addresses a very specific type of natural gas

pipeline, namely those "interstate pipelines that receive natural

gas at their state boundary that is consumed within the state and

subject to state commission regulation." ANR Pipeline Co. v.

FERC, 71 F.3d 897, 898 n.2 (D.C. Cir. 1995). Accordingly, we

reject the LDCs' claim, given that the LDCs do not suggest that

they fall within that specific class of pipelines. 

convincing. States have beenand are stillpermitted to regulate

LDCs' bundled sales of natural gas to end-users because those

transactions include transportation over local mains and the retail

sale of gas. In contrast, states have never regulated the terms

and conditions of interstate pipeline transportation. When the gas

sales element is severedi.e., unbundledfrom the transaction, FERC

retains jurisdiction over the interstate transportation component.62

3. Jurisdiction over municipal capacity release

We now turn to the claim of the municipally owned local

distribution companies ("municipalities") that FERC does not have

jurisdiction to require them to comply with its capacity release

regulations. Petitioners parse the terms of the Natural Gas Act as

follows:

Municipalities are exempt from the Commission's

jurisdiction under the NGA. The Commission's NGA

jurisdiction extends only to "natural gas companies." A

"natural gas company" is defined in NGA Section 2(6) as

"a person engaged in the transportation of natural gas in

interstate commerce, or the sale in interstate commerce

of such gas for resale." NGA Section 2(1) defines a

"person" as an "individual" or a "corporation." NGA

Section 2(2) defines a "corporation" as inter alia, any

corporation, partnership or association, but the

definition expressly excludes "municipalities."

Small Distributors' and Municipalities' Br. at 11-12 (footnotes

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63 Our opinion should not be read to either approve or

disapprove the Commission's reading of the Natural Gas Act in

this regard. 

64 Accord Texas Eastern Transmission Corp., 51 F.E.R.C. ¶

61,170 (1990) ("The Philadelphia Gas Works requests clarification

that all the conditions imposed upon [capacity brokering] program

participants do not apply to municipalities. Since

municipalities are beyond the jurisdiction of this Commission,

the Philadelphia Gas Works is correct."); Northwest Alabama Gas

District, 42 F.E.R.C. ¶ 61,371, at 62,086 (1988) ("It is well

settled that we cannot regulate a municipality under the NGA or

the NGPA."); Panhandle Eastern Pipe Line Co. v. City of Rolla,

26 F.P.C. 736, 738 (1961) ("From [the plain language of the

Natural Gas Act] it is clear that municipalities cannot be

"natural-gas companies' as that term is used by the Act. We are

not, therefore, vested with jurisdiction to regulate

municipalities, even though they are engaged in the sale of

natural gas to interstate pipeline companies."). 

omitted).

Of course, as discussed above, see supra Part III.B.1, NGA §

1(b) extends the Commission's jurisdiction over not only

"natural-gas companies" but also the interstate transportation of

natural gas. FERC, however, has twice rejected the suggestion that

it should invoke its transportation jurisdiction over

municipalities.63 See Tennessee Gas Pipeline Co., 69 F.E.R.C. ¶

61,239, at 61,906-07 (1994), reh'g denied, 70 F.E.R.C. ¶ 61,329

(1995); Texas Eastern Transmission Corp., 51 F.E.R.C. ¶ 61,170, at

61,453-54 (1990). Accordingly, FERC wholly "agrees with

[petitioners] that municipalities are beyond [its] jurisdiction."

Order No. 636-A, ¶ 30,950, at 30,551.64

That notwithstanding, FERC may, consistent with the NGA,

require municipalities to comply with its capacity release

regulations. As we explained above, see supra Part III.B.1, FERC's

transportation jurisdiction extends as a separate matter over

capacity release given the involvement of interstate gas

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65 Thus, in instituting the capacity release program, the

Commission legitimately invoked its authority under NGA § 5 over

"any rate, charge, or classification" or "any natural-gas

company," 15 U.S.C. § 717d, given that pipelines are natural-gas

companies under the Act. 

66 That factor distinguishes this case from the Texas

Eastern proceedings, 51 F.E.R.C. ¶ 61,170 (1990), in which FERC

concluded that it lacked jurisdiction to require municipal LDCs

to comply with its capacity brokering standards. 

67 The municipalities contend that the pipelines'

involvement in capacity release is too ministerial to establish

the Commission's jurisdiction. While we ultimately disagree with

that argument for the reasons set forth in the text, we recognize

its relevance. This could well be a different case had FERC in

fact merely manipulated its regulations to involve the pipelines

in a minimal way only to thereby create a jurisdictional toehold

over a nonjurisdictional entity. 

pipelines.65 The pipelines' role in capacity release is absolutely

central,66 and the transaction itself controls access to interstate

transportation capacity, entirely independent of the jurisdictional

nature of the releasing and replacement shippers.67

The analogy drawn by the Commission, and the one we find most

persuasive, is to the pipeline curtailment regime. As explained in

Judge Rogers' opinion for the court, see supra Part II.C, pipelines

at times must interrupt and redistribute their service based on

shortages of both gas supply and pipeline capacity. The Supreme

Court has expressly approved the Commission's authority to regulate

such curtailments pursuant to its § 1(b) interstate transportation

jurisdiction. See Louisiana Power & Light Co., 406 U.S. at 640-41.

The Commission's capacity release program is strikingly similar to

its curtailment regulations, in that both involve the pipelines'

allocation of transportation capacity among their shippers in

compliance with federally mandated strictures. As the

municipalities are subject to the curtailment regulations, so too

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68 "Buy/sell" agreements in place before the date that Order

No. 636 went into effect were allowed to continue in force, but

were required to be posted on the pipeline's electronic bulletin

board for informational purposes. Order No. 636, ¶ 30,939, at

30,416-17. 

69 Hadson Gas Co. contends that FERC has yet to make clear

the precise nature of the transactions that it has prohibited. 

But as the Orders under review explain, the bar to "buy/sells"

"applies to all firm capacity that is subject to the Order No.

636 capacity release program." Thus, in the now-prohibited

transactions, an LDC holds title to gas specifically purchased by

the LDC for the customer while utilizing its firm capacity rights

must they comply with FERC's standards for capacity release.

We also find compelling the acknowledged jurisdictional

arrangement prior to the implementation of either capacity

brokering or capacity release. At that time, shippers acquired

firm capacity rights directly from pipelines on a first-come,

first-served basis. Resales of capacity by shippers, including

municipalities, simply did not occur. We therefore conclude that

the Commission has jurisdiction to require open, nondiscriminatory

capacity release by municipalities.

4. Jurisdiction over "buy/sell" arrangements

The final jurisdictional challenge to the capacity release

mechanism involves "buy/sell" transactions, which FERC professed to

bar68 in Order No. 636 and the companion El Paso Natural Gas Co.

proceedings, 59 F.E.R.C. ¶ 61,031, reh'g denied, 60 F.E.R.C. ¶

61,117 (1992). "Buy/sells" occur in three stages. First, an

end-user of gas either purchases or identifies certain natural gas

at the point of production. The LDC that services the end-user

then purchases the gas and transports it first under its own

transportation rights on an interstate pipeline and later across

its local distribution facilities.69 The end-user then receives the

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to transport the designated gas over the interstate pipeline. El

Paso Natural Gas Co., 60 F.E.R.C. ¶ 61,117. It is not, of

course, necessarily the identical gas that the end-user receives

at the delivery point. 

70 See generally New York St. Conf. v. Travelers Ins. Co.,

115 S. Ct. 1671, 1676-77 (1995); Cipillone v. Liggett Group, 505

U.S. 504, 516 (1992); Silkwood v. Kerr-McGee Corp., 464 U.S.

238, 248 (1984); Florida Lime & Avocado Growers v. Paul, 373

U.S. 132, 141-42 (1963). 

gas from the LDC. The "buy/sells" reviewed by the Commission in the

El Paso proceedings were conducted under the authority and

oversight of the California Public Utility Commission.

FERC acknowledges that "buy/sell" transactions implicate

legitimate state regulatory interests. El Paso Natural Gas Co., 60

F.E.R.C. ¶ 61,117, at 61,383-84. That said, given the

transactions' intermediate stagein which the end-user expressly

arranges for the interstate transportation of specifically

identified gasthe Commission contends that it has authority to

preempt such state regulation. We therefore begin by setting forth

settled principles of federal preemption.

a. Introduction to federal preemption

The Constitution provides that the laws of the federal

government "shall be the supreme Law of the Land; ... any Thing in

the Constitution or Laws of any state to the Contrary

notwithstanding." U.S. CONST. art. VII. That principle of

supremacy is implemented through the doctrine of federal

"preemption,"70 under which state and local law may be stripped of

its effect. Federal preemption may occur in a variety of

circumstances:

[1] It is well established that within

constitutional limits Congress may pre-empt state

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71 See generally Fidelity Fed. Sav. & Loan Ass'n v. De la

Cuesta, 458 U.S. 141, 152-52 (1982); Lincoln Sav. & Loan Ass'n

v. Federal Home Loan Bank Bd., 856 F.2d 1558, 1560-61 (D.C. Cir.

1988); Conference of St. Bank Super. v. Conover, 710 F.2d 878,

881-83 (D.C. Cir. 1983). 

authority by so stating in express terms. [2] Absent

explicit pre-emptive language, Congress' intent to

supersede state law altogether may be found from a scheme

of federal regulation so pervasive as to make reasonable

the inference that Congress left no room for the States

to supplement it, because [(a)] the Act of Congress may

touch a field in which the federal interest is so

dominant that the federal system will be assumed to

preclude enforcement of state laws on the same subject,

or [(b)] because the object sought to be obtained by the

federal law and the character of obligations imposed by

it may reveal the same purpose. [3] Even where Congress

has not entirely displaced state regulation in a specific

area, state law is pre-empted to the extent that it

actually conflicts with federal law. Such a conflict

arises when compliance with both federal and state

regulations is [(a)] a physical impossibility, or [(b)]

where state law stands as an obstacle to the

accomplishment and execution of the full purposes and

objectives of Congress.

Pacific Gas & Elec. Co. v. State Energy Resources Conserv. &

Devel. Comm'n, 461 U.S. 190, 203-04 (1983) (internal citations,

quotation marks, and ellipses omitted).

Moreover, federal preemptive authority may be exercised not

only through federal statutes but also regulations issued by

administrative agencies.71 When an agency announces its intent to

pre-empt state authority in a particular area,

the correct focus is on the federal agency that seeks to

displace state law and on the proper bounds of its lawful

authority to undertake such action. The statutorily

authorized regulations of an agency will pre-empt any

state or local law that conflicts with such regulations

or frustrates the purposes thereof. Beyond that,

however, in proper circumstances the agency may determine

that its authority is exclusive and pre-empts any state

efforts to regulate in the forbidden area. It has long

been recognized that many of the responsibilities

conferred on federal agencies involve a broad grant of

authority to reconcile conflicting policies. Where this

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is true, the Court has cautioned that even in the area of

pre-emption, if the agency's choice to pre-empt

represents a reasonable accommodation of conflicting

policies that were committed to the agency's care by the

statute, we should not disturb it unless it appears from

the statute or its legislative history that the

accommodation is not one that Congress would have

sanctioned.

City of New York v. FCC, 486 U.S. 57, 64 (1988) (citations and

quotation marks omitted) (emphasis added).

b. Analysis

We consider petitioners' arguments regarding "buy/sell"

transactions under the branch of pre-emption doctrine that concerns

"conflicts" between state and federal law, and particularly state

law that "stands as an obstacle to the accomplishment and execution

of the full purposes and objectives of Congress," Hines v.

Davidowitz, 312 U.S. 52, 67 (1941). The Commission's goal in

preempting "buy/sell" transactions was to preserve the integrity of

its uniform capacity release program. See El Paso Natural Gas, 60

F.E.R.C. ¶ 61,117, at 61,385. Specifically, the Commission

concluded that "buy/sells" offer a ready means of circumventing the

open, nondiscriminatory bidding process central to capacity

release. Under Order No. 636, an end-user seeking firm interstate

transportation for gas that it has identified or acquired at the

point of production must attempt to purchase capacity by

contracting on the open market. In a "buy/sell" transaction, in

contrast, the end-user can contract with an LDC without being

forced to compete with other shippers that value the capacity.

FERC reasoned that because "buy/sells" occur without open bidding,

and result in the tying-up of interstate pipeline capacity, they

circumvent and distort the transportation market envisioned by

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72 Hadson Gas Co. suggests that FERC "ignored relevant

differences among shippers" in prohibiting all "buy/sell"

arrangements, without regard to the market power of the

particular shipper. In particular, Hadson contends that while

LDCs may hold sufficiently substantial capacity rights to

exercise market power, the same cannot be said of gas marketers. 

As FERC notes, however, when the capacity available for sale on a

particular pipeline is limited, holders of even relatively small

capacity allotments can exercise market power. Further, holders

of smaller capacity shares are able to increase their market

power by pooling their holdings and marketing them together. See

Order No. 636-A, ¶ 30,950, at 30,558. 

Order No. 636.72

The LDCs contend that preemption is inappropriate in this

instance because the Commission's prohibition on "buy/sells"

constitutes a regulation of the retail sale of natural gas, which

Congress reserved to the jurisdiction of state regulatory bodies.

While the Commission emphasizes the intermediate, transportation

stage of the transaction, the LDCs focus on the terminal stage,

describing "buy/sell" agreements as a classic instance of an LDC

making a retail sale to a retail customer. Cf. AGD I, 824 F.2d at

995 ("LDCs purchase gas for resale to end users, large and small.

Their services and prices are subject to state regulation but not

to that of FERC."). As the LDCs characterize the transaction:

A retail customer participating in a buy/sell

arrangement with an LDC purchases the same product

purchased by other retail gas customers: natural gas,

delivered to the point of consumption, at a

state-regulated price that includes the cost of (a) the

gas; (b) the inter- and intrastate transportation

required to move the gas from the market or production

area to the point of consumption; and, (c) all other

local distribution services, such as balancing and

metering costs.

LDCs' Reply Br. at 8. Further, given the express terms of NGA §

1(b), the LDCs maintain that the Commission's jurisdiction cannot

arise merely by means of some effect of "buy/sell" agreements on

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73 Indeed, it is in truth the LDCs that would bootstrap

jurisdictional implications to the effects of Order No. 636. 

According to the LDCs, "buy/sell" agreements allow them to

distribute and utilize their capacity rights more efficiently. 

This has as a secondary effect "lowering the unit cost of gas to"

end-users, which the LDCs characterize as a "traditional and

legitimate state interest[ ]." That proposition sweeps far too

broadly. Almost every element of the Commission's regulation of

interstate transportation affects distributors' costs, which must

be passed on to local end-users. Regulation of interstate

transportation is not thereby converted into a ground for

exclusive state jurisdiction. 

interstate transportation; such an interpretation of the Act would

dramatically expand FERC's jurisdiction because almost all gas

travels interstate and therefore almost all retail sales of gas

affect interstate transportation. See also Schneidewind v. ANR

Pipeline Co., 485 U.S. 293, 308 (1988) ("Of course, every state

statute that has some indirect effect on rates and facilities of

natural gas companies is not preempted."). Thus, conflict

pre-emption analysis must be applied with particular care in those

instances in which the Commission seeks to preempt state regulation

merely because it has some effect on the interstate transportation

of natural gas. Northwest Central Pipeline v. State Corp. Comm'n,

489 U.S. 493, 515-16 & n.12 (1989).

We believe that the LDCs have confused two separate issues.

While the Commission's rationale in preempting "buy/sells" is the

transactions' effect on interstate transportationnamely, that

"buy/sells" facilitate circumvention of the capacity release

programthe Commission's authority is grounded in the transaction

itself.73 In the intermediate stage of a "buy/sell" transaction,

the LDC carries the gas identified by the end-user on its own firm

capacity and under its own title on an interstate pipeline.

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Contrary to the LDCs' characterization, FERC's jurisdiction arises

from the transportation itself; interstate transportation of gas

selected by the end-user is a central element of the parties'

agreement. As FERC states in its brief, "buy/sells" are "at bottom

nothing more than agreements by which firm shippers allocate space

on an interstate pipeline to customers who negotiate their own

wellhead transactions." Transactions that do not include this

transportation element are not "buy/sells" and are not preempted.

In a standard retail sale, by contrast, the end-user purchases

gas from an LDC at the local delivery point without regard to

aspects of gas transportation at points further upstream. See id.

at 97 ("Traditional LDC retail sales consisted of sales of gas to

local customers from generic system supply through local

distribution facilities after the gas had completed its interstate

journey."). Order No. 636 does not prohibit or condition such

sales. Nor does the Order preempt state regulatory agencies from

modifying an LDC's rate structure to accommodate differences in

local conditions. Further still, LDCs remain free to sell gas to

retail customers under the terms and conditions set by state

regulators. Under Order No. 636, an end-user that would previously

have engaged in a "buy/sell" transaction will still purchase the

gas from the producer and still receive the gas at its delivery

point. The crucial difference is that the end-user must purchase

capacity rights from the LDC in the open market through the

capacity release mechanism rather than by transferring title to the

gas to the LDC and regaining title at the local delivery point.

Accordingly, we sustain the Commission's determination to ion

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74 These shippers transport gas pursuant to individual

certificates issued by the Commission under Part 157 of its

regulations. The critical difference between Part 157 and Part

284 shippers is that Part 157 shippers have always been able to

transport non-pipeline owned gas, while Part 284 shippers

generally have had that capability only since the promulgation of

Order No. 436. See MPC I, 761 F.2d at 782. 

to pre-empt state regulation of "buy/sell" transactions. FERC's

effort to avoid circumvention of its capacity release regulations

"represents a reasonable accommodation of conflicting policies that

were committed to [its] care" under the Natural Gas Act. City of

New York, 486 U.S. at 64. Further, given that the regulations do

not impinge upon state control over retail gas sales, it appears

that the Commission's accommodation is one that Congress would have

sanctioned. See id.

C. Substantive Challenges

1. Exclusion of Part 157 shippers from capacity release

In Order No. 636-A, the Commission concluded that only "Part

284" blanket-certificated shippers would be permitted to engage in

capacity release and utilize flexible receipt and delivery points.

Order No. 636-A, ¶ 30,950, at 30,565. The Electric Generator

Petitioners ("Electric Generators") contend that FERC's exclusion

of Part 157 "individually certificated" shippers74 was arbitrary and

capricious. Their theory is that capacity release and flexible

receipt and delivery points were intended to compensate for the

greater costs of straight-fixed-variable rate design, which both

Part 284 and Part 157 shippers are subject to; excluding Part 157

shippers from capacity release therefore allegedly deprives them of

a necessary and equivalent means of cost mitigation. They also

contend that subjecting Part 157 shippers to SFV rate design while

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75 The Electric Generators maintain that their exclusion

from capacity release represents a downgrade in their service

because Order No. 636 also prohibited them from selling capacity

under the Commission's predecessor "capacity brokering" program. 

They contend that because the Commission is eliminating a

pre-existing program, it is obligated to offer a particularly

persuasive rationale for its decision. Cf. Williams Natural Gas

Co. v. FERC, 872 F.2d 438, 444 (D.C. Cir. 1989). But, as FERC

notes, capacity brokering was authorized on only a few pipelines,

so that widespread capacity release is in fact a major service

upgrade. Moreover, the Commission's rationale in implementing

capacity release applies equally to its decision to bar Part 157

customers from continuing to engage in capacity brokering, and is

persuasive. Finally, as the Commission maintains, and the

Electric Generators essentially concede in their reply brief,

FERC's policy granting Part 157 shippers access to capacity

brokering "was a settlement, was expressly limited to the facts

in that proceeding, was adopted only on an interim basis, and was

never intended to survive Order No. 636." 

excluding them from capacity release is unduly discriminatory,

given that both SFV rate design and capacity release were intended

to develop a national natural gas market.

The Commission's decision to exclude Part 157 shippers from

capacity release and flexible receipt and delivery points was not

arbitrary and capricious. While capacity release does ameliorate

the costs of SFV rate design, it was never intended as the central

cost-mitigation measure, see Order No. 636-A, ¶ 30,950, at 30,594,

30,597-98, for there are specific mechanisms in place intended to

address the particular costs associated with SFV, including

alternative ratemaking techniques, phase-in measures, and the

continued use of one-part rates for small customers. See infra

Part IV.C.1. Moreover, allowing individually certificated shippers

to utilize capacity release would in effect require Part 284

shippers to subsidize their Part 157 counterparts, given that Part

284 shippers pay costs that Part 157 shippers do not.75

Specifically, Part 157 shippers are not required to pay the

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transition costs of Order No. 636, and their transportation

arrangements are not subject to pre-granted abandonment. Further,

the Commission prohibits Part 157 shippers, which do not operate

under open-access provisions, from including unique terms and

conditions in their contracts in order to avoid undue

discrimination. For that very reason, the Commission prohibits

Part 157 shippers from granting discounts, which itself presents a

major obstacle to Part 157 shippers' participation in capacity

release because competitive bidding presumes the ability to offer

a lower price.

The Electric Generators reply that these factors have no

connection to the cost-mitigation effects of the capacity release

program. The more salient issue, however, is whether the factors

identified by either the Commission or the Electric Generators have

any intrinsic connection to SFV rate design; they do not.

Fundamentally, the petitioners contend that they are entitled to

release capacity as one way of making up for the costs of SFV.

FERC replies, quite sensibly, that while capacity release would

reduce the Electric Generators' costs, including costs associated

with SFV, the Electric Generators are already receiving cost

benefits not available to Part 284 customers, and are not entitled

to further benefits.

Nor was the Commission's decision to exclude Part 157 shippers

unduly discriminatory. The Commission applied SFV rate design to

both Part 284 and Part 157 shippers because both generally have

been subject to the same rate design. See Order No. 636-B, ¶

61,272, at 61,992. Even if the goal of both SFV rate design and

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capacity release is the creation of a national gas market, that

does not mean that FERC's decision to apply only one to Part 157

shippers constitutes undue discrimination. "[T]he competitive

rationale for adopting SFV rate design as a means to promote the

development of a national gas market applies equally to [Part 284

and] Part 157 rates." Id. While allowing Part 157 shippers to

engage in capacity release might expand the national gas

marketplace, as we have explained, it would also give them an

unfair subsidy over Part 284 shippers. As FERC notes in its brief,

"[g]iven the significant differences between these two forms of

service under Order No. 636, it was not unreasonable to confine the

capacity release program to Part 284 open access service." We see

no reason to disturb the Commission's conclusion that those cost

considerations outweighed any benefit to the national gas

marketplace and disentitled Part 157 shippers from engaging in

capacity release.

Moreover, as the Commission explains, the Electric Generators

may receive access to capacity release and flexible receipt and

delivery points by converting to Part 284 service. This does not

mean, as petitioners contend, that the Commission is unlawfully

attempting to leverage the Electric Generators' conversion. Here,

we reject petitioners' reliance on National Fuel Gas Supply Corp.

v. FERC, 909 F.2d 1519 (D.C. Cir. 1990). In National Fuel, this

court turned back an effort by FERC to condition its certification

of a Part 157 shipper's gas services on the shipper's obtaining a

blanket Part 284 certificate as well. Our ruling there was based

on the fact that the Commission had already determined that a Part

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157 certificate was "required by the public convenience and

necessity" when it nonetheless attempted to add the additional

condition of acquiring a Part 284 certificate. Given the

Commission's conclusion that the shipper was already entitled to a

Part 157 certificate, "[i]t was thus clear at the outset that the

Commission considered certification ... to be in the public

interest regardless of whether the pipeline also accepted a blanket

transportation certificate." Id. at 1522. FERC therefore lacked

authority to deny the shipper a Part 157 certificate. In this

case, in contrast, the Electric Generators do not contend that the

Commission has determined that Part 157 shippers have the right to

engage in a certain service, but is nonetheless denying them the

right to engage in it. Moreover, even under the petitioners' far

more expansive reading of National Fuel, this is not an instance in

which FERC is attempting to coerce a conversion from Part 157 to

Part 284 service; the Commission is simply pointing out that

conversion offers the Electric Generators one means of

cost-mitigation.

2. The standard for determining the best bid

The LDCs and Industrial End-Users raise three challenges to

the methods selected by the Commission for determining the

prevailing bidder and price in the capacity release transaction.

In Order No. 636, FERC concluded that conditions set by LDCs on

their release of capacity "must not prefer any shipper, such as an

end-user, over other shippers, and cannot take into account the use

of the LDC's own facilities." Order No. 636-B, ¶ 61,272, at

61,997. The LDCs maintain that, in a market sense, this rule

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76 While an LDC could conceivably refuse to make such a

deal, it would have no incentive to do so because no other

transaction can provide it with a higher price. Further, as the

Commission notes in its brief, claims that an LDC discriminated

against its end-users in allocating capacity may be addressed

through the NGA § 5 complaint procedure. 

prohibits them from selecting what is truly the "best" bid, i.e.,

"one that reflects [the] greatest economic benefit to the releasing

shipper." Specifically, the LDCs want the right to favor their own

end-users in capacity sales, a practice that ultimately would

reduce the LDCs' own costs. But that is not a right to which they

are entitled under the Natural Gas Act. The LDCs' claim is at

bottom nothing more than an objection to FERC's open-access,

nondiscrimination policy. The goal of capacity release is to

create a uniform national market for transportation, not to

maximize the benefit to LDCs. Only by utilizing nondiscriminatory

factors in determining the prevailing bid can FERC ensure that the

shipper that places the highest value on capacity receives it.

The Industrial End-Users make the related argument that FERC

acted arbitrarily in refusing to grant a bidding preference to

LDCs' existing end-users. In particular, they note that FERC did

grant existing end-users a preference in acquiring capacity

released by upstream pipelines under the section 284.242 mandatory

capacity release program. As with the immediately preceding claim,

however, the standard set by FERC fundamentally is part of its

nondiscrimination and open-access policy. Moreover, as FERC notes,

an end-user can be sure of receiving capacity by entering into a

pre-arranged deal with its LDC at the maximum allowable price.76

The preference granted under the mandatory program, in contrast, is

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77 For a discussion of incremental rates, see generally

Transcanada Pipelines Ltd. v. FERC, 24 F.3d 305, 308-11 (D.C.

Cir. 1994); Algonquin Gas Transmission Co. v. FERC, 948 F.2d

1305, 1312-14 (D.C. Cir. 1994). 

unrelated to the development of a transportation market through

capacity release; it is specifically intended to ensure that when

pipelines engage in unbundling, their end-users are not deprived of

the transportation necessary to fulfill their pre-existing gas

needs.

The Electric Generators finally contend that FERC should not

uniformly have set the maximum allowable rate for resales of

capacity at the originally determined maximum rate. They contend

that this will in some instances result in discrimination against

shippers who pay higher initial "incremental" rates.77 The

Commission responds that this issue is too complex and fact-bound

to address in the overarching Order No. 636 proceedings, and that

it should be deferred to the restructuring proceedings, where a

better record can be developed. See Order No. 636-A, ¶ 30,950, at

30,561 ("[T]he parties in restructuring proceedings involving

incremental rates should consider and propose methodologies to

ensure that the capacity release mechanism operates efficiently and

that all parties are treated fairly and equitably, without undue

discrimination."). We agree. The Electric Generators' explication

of their claim in these proceedings is far too sparse to allow for

reasoned evaluation, primarily because the relevant factual record

is not before us. Their claim may properly be evaluated by the

Commission in individual restructuring proceedings where further

facts can be developed.

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3. Interruptible transportation revenue crediting

After the implementation of capacity release under Order No.

636, the number of firm transportation sellers in the marketplace

substantially increased. As a result, it became difficult for

pipelines to determine how much demand there will be for

interruptible transportation ("IT") service. In turn, it is

difficult for the pipelines to determine what portion of their

costs to recoup through billings to IT (as opposed to firm)

service. In the Order No. 636 proceedings, FERC suggested that a

pipeline

might decide to attribute no revenue responsibility to

interruptible transportation. Since the pipeline's firm

shippers would be responsible for all pipeline costs,

revenues from the sale of interruptible transportation

would [later] be credited to the firm shippers.

Order No. 636-A, ¶ 30,950, at 30,563. Under true cost accounting,

100% of IT revenues would be credited to firm shippers, because

firm customers are essentially being overcharged until the pipeline

can figure out how much money it is recovering from IT service.

The Commission suggested, however, that pipelines might adopt a

90/10 mechanism, under which only 90% of IT revenues would be

credited to firm shippers. This 10% difference was thought by FERC

to be a necessary incentive for pipelines to market interruptible

transportation. Without it, pipelines would be assured of

recovering their costs through firm sales charges, and therefore

would have no reason to maximize IT throughput.

The Industrial End-Users, who utilize interruptible

transportation, challenge the Commission's endorsement of a 90/10

IT revenue crediting mechanism on two grounds. First, they argue

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78 While the Industrial End-Users contend that the

Commission has been applying the 90/10 mechanism as a rigid rule,

they concede that it approved an 80/20 mechanism in CNG

Transmission Corp., 64 F.E.R.C. ¶ 61,082, at 61,776-66 (1993). 

that the 10% gain creates an insufficient incentive for pipelines

to market IT. The Industrial End-Users note that FERC rejected

proposals for revenue crediting under Order No. 436, because they

"give[ ] the pipeline little or no incentive to provide service

under the rule." Order No. 436, ¶ 30,665, at 31,537. Second, they

argue that the 90/10 mechanism reduces other shippers' incentive to

release capacity; shippers know that if they do not put their firm

capacity on the market, thereby forcing other companies to utilize

IT service, they will receive some portion of the IT revenues

through the crediting mechanism anyway.

We conclude that the Industrial End-Users' challenge to the IT

revenue crediting mechanism is premature. Order No. 636-A

expressly provides that pipelines "might" adopt this "potential

approach," and that "parties to the restructuring proceedings also

may consider whether other methods are needed." Order No. 636-A,

¶ 30,950, at 30,563; see also Order No. 636-B, ¶ 61,272, at 62,000

("[T]he parties to the restructuring proceedings could consider a

variety of approaches, such as agreeing on an appropriate level of

throughput for interruptible transportation or some type of revenue

crediting mechanism.").78 Our concerns are magnified given that the

Industrial End-Users maintain that the 10% pipeline credit does not

provide pipelines with a sufficient incentive to market IT, but

provide no data or explanation of why that is the case. The only

way to evaluate their claim is in the light of the particular facts

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presented in individual pipelines' restructuring proceedings. See

id. ("The petitioners requesting rehearing have not been aggrieved

by the suggestion that the Commission would consider a revenue

crediting approach proposed in a specific restructuring proceeding.

In implementing its regulations, the Commission will not adopt

rigid rate-making methodologies that fail to reflect the reality of

the market or the intent of its regulations."). We therefore defer

resolution of the Industrial End-Users' IT revenue crediting

challenge to the individual pipeline restructuring proceedings.

D. Conclusion

We deny the petitions for review insofar as they dispute the

Commission's jurisdiction over capacity release transactions. We

further deny the petitions for review insofar as they challenge (1)

the exclusion of Part 157 shippers from the capacity release

program, (2) the mechanism chosen by the Commission for determining

the best bid in capacity release transactions, and (3) the

Commission's suggestion that a 90/10 mechanism is an appropriate

means of crediting interruptible transportation revenues. We

specifically defer to later proceedings consideration of the merits

of both the revenue crediting mechanism and the Commission's

treatment of incremental rates.

IV. Rate Design

Various petitioners raise three major challenges to the rate

design portion of the Order No. 636 series. As noted above, FERC

ordered a change from the preexisting modified fixed variable (MFV)

to a straight fixed variable (SFV) rate design. First, petitioners

question whether FERC has authority under the NGA to adopt SFV rate

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design. Second, they question whether FERC's decision to switch

from MFV rate design to SFV rate design was a reasonable one.

Third, they question whether the mitigation measures FERC employed

to ease the shift to SFV rate design are within FERC's ratemaking

discretion.

A. FERC's Authority to Adopt SFV Rate Design

1. MFV rate design's anticompetitive effects

FERC's authority over rate design in this case derives from

NGA § 5, which requires it to replace any "unjust, unreasonable,

unduly discriminatory, or preferential" rate, charge or

classification charged "by any natural-gas company in connection

with any transportation or sale of natural gas" with a "just and

reasonable rate, charge, [or] classification." 15 U.S.C. § 717d.

Under the preexisting MFV design, the pipelines incorporated into

commodity charges to their sales customers and usage charges to

their transportation customers fixed costs that varied greatly from

pipeline to pipeline. Accordingly, the unit prices to gas

customers did not accurately reflect the actual variable cost of

supplying gas, because producers in different gas fields "compete

for market share via different pipelines," so that their

competitive positions in the market reflected the fixed costs in

the pipelines' respective transportation usage charges and not

simply "the producers' own costs and efficiencies in producing

gas." Order No. 636, ¶ 30,939, at 30,434. The Commission

concluded that a shift to the SFV rate design, under which the

usage charges accurately reflect the actual variable costs of

delivering gas, would remove this impediment to efficient

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79 LDC petitioners presenting this argument include Atlanta

Gas Light Co., Chattanooga Gas Co., Peoples Natural Gas Co., and

Southwest Gas Co. Washington Gas Light Co. is a supporting

intervenor. 

competition.

The LDC petitioners79 argue that FERC had no authority to take

regulatory action on the basis of MFV rate design's anticompetitive

effects on gas producers. They admit that FERC must consider the

anticompetitive effects of rate design systems, but contend that

FERC can only consider the anticompetitive effects of a system on

entities it regulates directly (i.e., pipelines themselves), not on

unregulated industries such as gas producers, and they argue that

MFV's anticompetitive effect on gas suppliers does not constitute

an anticompetitive effect on pipelines. The LDCs cite in support

of their position Official Airline Guides, Inc. v. Federal Trade

Comm'n, 630 F.2d 920, 927-28 (2d Cir. 1980), cert. denied, 450 U.S.

917 (1981), in which the Second Circuit struck down a Federal Trade

Commission ("FTC") ruling that a monopoly airline guide publisher's

refusal to publish flight schedules for certain airlines impaired

competition in the airline industry. The Second Circuit held that

the FTC Act's power to proscribe anticompetitive conduct did not

extend to the restraint of a business's practices solely because of

the conduct's incidental effect on competition between third

parties in another industry.

As the LDCs stress, antitrust policy "does not outlaw the

practices of a party solely because those practices may indirectly

affect competition between other entities with which it does not

compete." Though the LDCs' premise is valid, it does not answer

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the question of whether FERC has the authority to consider

anticompetitive effects on unregulated segments of the gas industry

in setting rates for the regulated pipelines. The Second Circuit's

decision simply does not purport to answer that question. Rather,

the Official Airline Guides court was extending the doctrine

established in United States v. Colgate & Co., 250 U.S. 300, 307

(1919) (as quoted in Official Airline Guides, 630 F.2d at 925),

that, "[i]n the absence of any purpose to create or maintain a

monopoly," antitrust policy "does not restrict the long recognized

right of trader or manufacturer engaged in an entirely private

business, freely to exercise his own independent discretion as to

parties with whom he will deal." In fact, the Official Airline

Guides court noted the dangers of departing from this principle of

independent business judgment: "[W]e think enforcement of the

FTC's order here would give the FTC too much power to substitute

its own business judgment for that of the monopolist in any

decision that arguably affects competition in another industry."

Official Airline Guides, 630 F.2d at 927.

In contrast, FERC's decision in Order 636 represents not the

rolling back of an independent business judgment because of its

anticompetitive effect on an unrelated industry, but rather the

substitution of one administratively imposed ratemaking regime for

another based on the anticompetitive effect of the preexisting

regime on unregulated entities dealing through regulated entities

in a partially regulated segment of the economythat is, the

regulated pipeline segment of the partially regulated natural gas

industry. The Commission's express duty under NGA § 5 to set aside

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rates and practices that it finds unjust, unreasonable, unduly

discriminatory, or preferential is not limited to the remedies that

the FTC may order in an unregulated market; nor is FERC's basis

for the exercise of that authority necessarily as limited as the

FTC's bases for enforcement decisionmaking. Antitrust policies

governing the FTC in the unregulated market do not exhaust the

public interest grounds on which the Commission may order a change

in rates under NGA § 5. Here, given that we review the Commission's

acts under the deferential "substantial evidence" standard, 15

U.S.C. § 717r(b); Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C.

Cir. 1992), we hold that the Commission adequately justified its

exercise of its authority when it stated that its ratemaking

authority "includes the establishing of just and reasonable

transportation rates that maximize the benefits of decontrol to gas

consumers," Order No. 636-A, ¶ 30,950, at 30,594-95, and that

regulated transportation rates "should in no way inhibit the

creation of a national gas market of efficient gas merchants as

envisioned by Congress in enacting the Decontrol Act." Order No.

636, ¶ 30,939, at 30,433. Unlike the FTC in Official Airline

Guides, FERC was not attempting to limit the options of a free

business actor in order to promote competition in an adjacent

industry, but only to prevent the regulatorily imposed price

decisions of a regulated industry from creating anticompetitive

factors in economically adjacent markets.

2. SFV rate design and NGA § 5

The PUCs argue that FERC's ordering of the switch to SFV rate

design exceeds its statutory authority. Under the NGA, FERC draws

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its ratesetting authority from two sections: NGA § 4 (15 U.S.C. §

717c) authorizes FERC to accept or reject rates and rate

adjustments filed by natural gas companies; and NGA § 5 (15 U.S.C.

§ 717d) authorizes FERC after a hearing and upon findings that an

existing rate is "unjust, unreasonable, unduly discriminatory, or

preferential" to fix "just and reasonable rate[s] ... by order."

The PUCs contend, and FERC admits if we reach the merits, that the

Commission draws its authority in the present restructuring from §

5, or not at all, as no natural gas company has filed the rate

structure which FERC is imposing. The PUCs argue that FERC's order

imposing the new rate structure exceeds its authority under § 5

because that section expressly provides "[t]hat the Commission

shall have no power to order any increase in any rate contained in

the currently effective schedule" then on file with the Commission.

Because the new rate structure will result in an increase in

charges to some customers, the PUCs argue that FERC's order

violates this provision.

FERC first contends that this rate increase argument is not

properly before the court "because none of these petitioners raised

it before the Commission in their requests for rehearing of Order

No. 636." As FERC rightly suggests, the party who raises an issue

in a petition for review must have raised the same issue in its

petition for rehearing before the agency. ASARCO, Inc. v. FERC,

777 F.2d 764, 773-75 (D.C. Cir. 1985). However, Atlanta Gas Light

Company ("Atlanta") and Chattanooga Gas Company ("Chattanooga")

specifically raised the rate increase argument in their petition

for rehearing of Order No. 636. Request of Atlanta Gas Light

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Company and Chattanooga Gas Company for Rehearing and Clarification

at 14-16 (May 8, 1992). And in the LDCs' brief in this court,

several LDCs (including Atlanta and Chattanooga) cross-reference

the PUCs' presentation of the rate increase argument, thereby

incorporating the argument into the LDC brief before us.

Therefore, because Atlanta and Chattanooga raised the rate increase

argument in their petition for rehearing before FERC and raise it

again in the present proceeding, the argument is properly before

us, and we must consider it on its merits.

In Order No. 636-A, FERC disposed of the rate increase

argument by relying on ANR Pipeline Co. v. FERC, 863 F.2d 959 (D.C.

Cir. 1988). In that case a pipeline filed a § 4 schedule to

implement a rate reduction. Order No. 636-A, ¶ 30,950, at 30,666.

FERC, using its § 5 authority, determined that the pipeline's rate

design methodology was unjust and unreasonable (when a pipeline

files a § 4 rate schedule, FERC can transform the proceedings into

a § 5 action. Western Resources, Inc. v. FERC, 9 F.3d 1568, 1579

(D.C. Cir. 1993)), and ordered the company to implement MFV rate

design and to eliminate its minimum billing practice. Under the

minimum billing practice, certain customers "were obligated to pay

ANR, in each contract year, an amount equal to the fixed-cost

portion of the commodity rate times the greater of (1) the volume

actually purchased by the customer, or (2) a "minimum bill

quantity' (MBQ) specified by contract." ANR Pipeline, 863 F.2d at

960; see also supra at 27 n.29 (describing minimum billing

practices). One of ANR's largest customers, Michigan Consolidated

Gas Company ("MichCon"), was paying more than its allocatable share

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of fixed costs because of the minimum bill requirement. ANR

Pipeline, 863 F.2d at 960. Once ANR eliminated the minimum bill in

compliance with FERC's order, it recalculated the per-unit share of

fixed costs based on the decreased number of total units over which

to allocate fixed costs. (After eliminating the minimum bill, the

projected number of units over which to allocate fixed costs

necessarily decreased for MichCon, since MichCon had not purchased

and was not expected to purchase the MBQ of gas.) As a result, the

per-unit share of fixed costs incorporated in the commodity charge

went up.

Although FERC initially rejected ANR's proposed "increase" in

commodity rates as a violation of the filed rate doctrine, we

reversed that decision, concluding that FERC "had not rationally

explained why its requirement that ANR's minimum bill had to be

removed would not authorize the removal of volumes attributable to

the minimum bill for purposes of calculating the amount of the

fixed-cost commodity charge." Order No. 636-A, ¶ 30,950, at

30,667. The Commission therefore reads ANR Pipeline as standing

for the proposition that "when the Commission orders a pipeline to

implement a different rate design method that requires reductions

in one component of the pipeline's rates, it must permit the

pipeline to implement offsetting increases in some other component

simultaneously in order for the pipeline to recover its cost of

service." Id.

FERC's argument based on ANR Pipeline is a powerful one. Our

reasoning in ANR supports a small scale version of the large scale

balanced restructuring with offsetting features that FERC has

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ordered in the present proceeding. ANR is not, however, totally

dispositive. The issue in that case came to us at a later stage.

In ANR, after the Commission had made its initial § 5 ruling, the

pipeline had made a compliance filing. That filing incorporated

the contested "increase." Reviewing FERC's rejection of the

compliance filing, we could not conclude that the Commission had

"rationally explained why that filing [did] not comport with" the

earlier instruction to the submitting pipeline. ANR Pipeline, 863

F.2d at 964. We did not therefore purport to authoritatively

decide the breadth of the limitation in § 5 providing "that the

Commission shall have no power to order any increase ... unless

such increase is in accordance with a new schedule filed by such

natural gas company." 15 U.S.C. § 717d. That is, we did not

determine how that section applies in the case of a

Commission-initiated rate restructuring which, while reducing rates

for some customers, necessarily offsets that reduction by an at

least present increase in the share borne by others. Thus, ANR is

at best persuasive rather than controlling authority in favor of

the Commission's asserted power to order a restructuring that

results in increasing some components to the detriment of some

pipeline customers.

Also relevant to our determination of the issue is our

decision in Western Resources Inc. v. FERC, 9 F.3d 1568 (D.C. Cir.

1993). In that case, the existing schedule included a

"forward-haul rate" of approximately 20.05 cents per Mcf and a

"backhaul rate" of one cent per Mcf. Id. at 1571. The pipeline

filed a § 4 revised tariff sheet featuring increases in both the

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forward-haul and backhaul rates, making them equal to one another

at a level above the former 20.05 cents per Mcf forward-haul rate.

Id. FERC approved the forward-haul rate increase, but set the new

backhaul rate at one-half the forward-haul rate. Id. at 1571-72.

We remanded the case to FERC, however, holding that it had failed

to sufficiently justify its decision as to the forward-haul rate

and that it had improperly concluded that it could use its § 4

authority to grant half the requested backhaul increase. We

determined that FERC's decision to increase the backhaul rate to

only half the level requested was so far removed from the requested

increase that it constituted an exercise of § 5 authority and not

§ 4. See id. at 1578-79. We remanded the backhaul increase on the

grounds that FERC had not met the burden of proof imposed on it by

§ 5. See id. at 1580. Our opinion in Western Resources is

susceptible of two interpretations. First, because we remanded for

further consideration rather than vacating altogether a Commission

order that amounted to a restructuring under § 5 including

component increases, we implicitly concluded that FERC had the

general authority to conduct such restructuring and only remanded

for a determination as to FERC's use of that authority on the

specific rate before it. In Western Resources, the turning point

of our decision was that FERC had erroneously purported to use § 4

authority where it was unavailable. As § 5 authority was the only

authority left, if FERC had acted properly at all, it must have

been under § 5. Our Western Resources opinion is also subject to

the interpretation that in that case we remanded to FERC for the

possibility of a rate decrease under § 5, considering the relevant

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baseline to be the pipeline's § 4 submission, which proposed rates

higher than those that the Commission was willing to approve.

Under the first of these possible interpretations, our remand to

the Commission to reconsider its action under § 5 may carry some

implication that we deemed it to have the authority it purports to

use now, but that implication is not a strong one, and again, our

existing circuit law at most inclines us toward FERC's position but

does not compel us to adopt it. Under the second possible

interpretation of Western Resources, the case is simply not on

point at all.

We therefore today for the first time authoritatively

determine the issue of whether a § 5 rate restructuring that

includes an increase in some rate components to the detriment of

some customers amounts to a prohibited "rate increase" under § 5

itself. As FERC claims this authority under the Natural Gas Act,

a statute committed to its administration, we review the

Commission's decision under the deferential standard dictated in

Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc.,

467 U.S. 837, 842-43 (1984). At the first step of that familiar

two-step inquiry, we ask "whether Congress has directly spoken to

the precise question at issue." Id. at 842. That is the point at

which our inquiry ends "if we can come to the unmistakable

conclusion that Congress had an intention on the precise question

at issue," Nuclear Information Resource Service v. NRC, 969 F.2d

1169, 1173 (D.C. Cir. 1992) (in banc) (internal quotations and

citations omitted). This is not such a case.

In reaching that conclusion we have examined first the plain

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language of the statute. The relevant text states: "[T]he

Commission shall have no power to order any increase in any rate

contained in the currently effective schedule of such natural gas

company on file with the Commission, unless such increase is in

accordance with a new schedule filed by such natural gas company."

15 U.S.C. § 717d(a). At first reading, it may be most natural to

suppose that Congress included within the prohibition against "any

increase in any rate" a preclusion of Commission orders for rate

restructuring that would ultimately lead to rate increases for some

pipeline customers. However, supposition and first reading are not

the stuff of unambiguous expressions of intent, and the plain

language does not convince us that Congress unambiguously intended

the interpretation petitioners support. To further inform our

inquiry into congressional intent, we examine the complete

statutory scheme. Davis v. Michigan Dep't of the Treasury, 489

U.S. 803, 809 (1989) ("It is a fundamental canon of statutory

construction that the words of a statute must be read in their

context and with a view to their place in the overall statutory

scheme."). The scheme considered under the NGA today contemplates

that FERC must act consistently with the Natural Gas Wellhead

Decontrol Act of 1989, Pub. L. No. 101-60, 103 Stat. 157 (1989), as

well. That enactment contemplates a considerably changed natural

gas world in which regulation plays a much reduced role and the

free market operates at the wellhead. While a court construing

congressional intent in one enactment should not be too greatly

influenced by the enactments of a later Congress, we must

necessarily consider the duties faced by an agency in examining its

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construction of its enabling acts. While this part of our analysis

usually occurs at the second step of Chevron, it is not irrelevant

to the first. A commission charged with the regulation of the

rates of an industry may be expected to restructure its general

mandates when its world changes. If the enabling act under which

it operates can be construed so as to give it that authority, that

construction should not be ruled out in the absence of a genuinely

unambiguous expression of a congressional intent to the contrary.

The general language prohibiting "rate increases" under § 5 is not

so plainly directed at such a preclusion.

Insofar as legislative history is an appropriate guide to the

unambiguous intent of Congress, the little available in the present

instances argues against rather than for the claim of unambiguous

congressional intent advanced by petitioners. At the time of the

adoption of the NGA, Representative Clarence Lea, a principal

sponsor of the NGA and chairman of the committee which reported it

to the House, declared that "[t]he purpose of [the amendment

creating the § 5 rate increase prohibition] was to prevent any

company's rates being raised over their objection, with the idea of

stifling competition with a competitor." 83 CONG. REC. 9101 (1938)

(Statement of Rep. Lea). Under this interpretation, the

prohibition was included not so much for the protection of gas

consumers from rate increases, but to protect a pipeline disfavored

by FERC from suffering under FERC-imposed rate increases that would

harm the pipeline's ability to compete. While it is not of course

impossible for a statute to have two purposes, the intent advanced

by Lea supports the proposition that Congress did not unambiguously

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intend that § 5 would protect customers from restructured rate

designs ultimately leading to increased charges. In short, § 5 is

not unambiguous. The provision may easily be read to prohibit FERC

from ordering increases in specific filed rates while leaving it

free to order the restructuring of rates as it has attempted to do

here.

As we have found that the statute is not unambiguous with

respect to the specific issue before us, we proceed to the second

step of the Chevron analysis. "At this stage, we defer to the

agency's interpretation of the statute if it is reasonable and

consistent with the statute's purpose." Nuclear Information

Resource Service, 969 F.2d at 1173 (internal quotations and

citation omitted). Having already observed in our step one

analysis that the Commission's interpretation is consistent with

the structure and purpose of the statute, we have no difficulty in

finding that interpretation a reasonable one at step two. The

petitioners' proffered interpretation is also a reasonable, indeed,

perhaps a more natural interpretation of the statutory language.

That, however, is not the standard. Even if we were convinced that

the petitioners' interpretation were the better one, "we are not

free to impose our own construction on the statute, as would be

necessary in the absence of an administrative interpretation." Id.

(internal quotations, brackets, and citation omitted). The only

question is whether the agency's interpretation is reasonable and

consistent with the statutory purpose. The answer to that question

is yes. FERC undoubtedly has the authority to restructure pipeline

rate calculation mechanisms, as long as it does so in an otherwise

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80 It does appear that the Commission has used a rate design

method similar to SFV in the distant past of natural gas

regulation. See, e.g., Mississippi River Fuel Corp. v. FPC, 163

F.2d 433, 437-39 (D.C. Cir. 1947) (explaining the

"demand-commodity formula"). 

lawful manner and supports its actions with substantial evidence.

Any restructuring, even if it does not alter a pipeline's revenues

by one cent, will virtually always increase by some amount the

charges that some individual customers pay and decrease the charges

to some others. Reading § 5 in such a way that these increases for

some customers constitute prohibited "rate increases" leads to the

conclusion that FERC has no authority to restructure pipeline rates

at all. FERC is not required to so interpret the statute.

B. SFV Rate Design and Substantial Evidence

1. MFV rate design's distortions of the natural gas market

For several decades, FERC's ratemaking regime has included

some portion of a pipeline's fixed costs in the pipeline's

commodity and usage charges. Over the years, it varied the

specific percentage of fixed costs actually included in those

charges, but it generally followed the principle that some portion

of fixed costs should be recouped through quantity-dependent

charges.80 In 1986, the Seventh Circuit upheld FERC's 1983 adoption

of the MFV rate design in use prior to the promulgation of Order

No. 636. See Order No. 636, ¶ 30,939, at 30,432 (citing Northern

Indiana Pub. Serv. Co. v. FERC, 782 F.2d 730 (7th Cir. 1986)). The

PUCs argue that FERC cannot depart from this approved use of MFV

rate design without giving a reasonable justification for doing so,

and that FERC has failed to do so in the Order No. 636 series.

They claim that FERC's determination that MFV distorts the gas

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market is inconsistent with prior FERC decisions and court rulings

approving of MFV. Essentially, they maintain that if MFV was good

in the past, it must still be good today. Additionally, the PUCs

find plenty of evidence of competitive markets under MFV rate

design, and they maintain that dropping MFV rate design is

therefore improper. Finally, they stress that the full

incorporation of fixed costs in variable charges seems to work well

for the oil pipeline industry, so it should also work in the case

of gas pipelines.

As the Supreme Court has noted, "[a]llocation of costs is not

a matter for the slide-rule. It involves judgment on a myriad of

facts." Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589

(1945). Although the relevant technology has changed since

Colorado Interstate Gas, the point that "[r]ate-making is

essentially a legislative function," id., has not. Our task, then,

is not to determine whether MFV rate design is superior to SFV rate

design, but merely to determine whether FERC has "made a reasoned

decision based upon substantial evidence in the record" in

departing from MFV rate design. Town of Norwood v. FERC, 962 F.2d

20, 22 (D.C. Cir. 1992).

Initially, we note that the PUCs have mischaracterized FERC's

decision to depart from MFV rate design. As FERC notes in its

brief, "modifying pipeline rate design to promote competition is

nothing new." The switch from MFV rate design to SFV rate design

does not represent a reversal in ratemaking policy. FERC simply

ordered a reallocation of fixed costs in pipeline rate design. The

fact that the old system was labeled "MFV" and the new system "SFV"

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does not mean that the new system represents a radical departure

from precedent. Rather, the change in Order No. 636 is simply one

more adjustment, albeit a significant one, in a decades-long series

of adjustments in rate design. See, e.g., Canadian River Gas Co.,

3 FPC 32 (1942), aff'd, Colorado Interstate Gas Co. v. FPC, 324

U.S. 581 (1945); Mississippi River Fuel Corp., 4 FPC 340 (1945),

aff'd in part and remanded, Mississippi River Fuel Corp. v. FPC,

163 F.2d 433 (D.C. Cir. 1947); Atlantic Seaboard Corp., 11 FPC 43

(1952); State Corp. Comm'n v. FPC, 206 F.2d 690 (8th Cir. 1953),

cert. denied, 346 U.S. 922 (1954); Fuels Research Council, Inc. v.

FPC, 374 F.2d 842 (7th Cir. 1967); United Gas Pipeline Co., 50 FPC

1348 (1973), reh'g denied, 51 FPC 1014 (1974), aff'd sub nom.

Consolidated Gas Supply Corp. v. FPC, 520 F.2d 1176 (D.C. Cir.

1975); Columbia Gas Transmission Corp. v. FERC, 628 F.2d 578 (D.C.

Cir. 1979); Northern Indiana Pub. Serv. Co. v. FERC, 782 F.2d 730

(7th Cir. 1986) (NIPSCO).

Like past changes in rate design, FERC initiated the departure

from MFV in response to changing market conditions. Specifically,

the agency determined that continued adherence to MFV rate design

would "inhibit the goal of the development of a competitive,

national gas market and, therefore, ... [would] not comport with

the goals set forth" in Order No. 636. Order No. 636, ¶ 30,939, at

30,433. For various reasons, pipelines prior to Order No. 636 had

differing amounts of fixed costs in their commodity and usage

charges. As FERC determined, "[t]his situation ... can hinder

competition between gas sellers at the wellhead because competition

is not based on the seller's costs and therefore on their ability

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81 For example, one crucial difference between rate design

for oil pipelines and gas pipelines is that oil pipelines do not

impose separate reservation and demand charges, thus occasioning

no design problem analogous to the one the Commission confronted

here. See Association of Oil Pipe Lines v. FERC, 83 F.3d 1424

(D.C. Cir. 1996). 

to compete directly with each other." Id.; see also supra Part

IV.A.1.

The PUCs' objection that FERC has used MFV pricing in the past

does not come to terms with the fact that the natural gas industry

is being reorganized at Congress' direction and that FERC is now

attempting to structure the rate design system to favor the

development of a nationwide, competitive natural gas marketplace.

FERC reasonably determined that, "because in its current assessment

of the prevalent economic and market circumstances it believes the

goal of achieving an efficient, national gas market is the factor

that should control the selection of the appropriate rate design

method," Order No. 636-A, ¶ 30,950, at 30,605, its departure from

the strict terms of MFV rate design as approved in 1986 was

justified. Similarly, the PUCs' reliance on the practices in the

oil pipeline industry is misplaced. The same goals, problems, and

solutions may or may not apply to oil pipelines,81 but there is no

requirement that rate design function in the same manner across

both industries. Finally, as FERC stresses, the Order No. 636

regime permits parties to seek approval of non-SFV rate design

methods in individual rate proceedings. See Order No. 636, ¶

30,939, at 30,434; Order No. 636-A, ¶ 30,950, at 30,605. For all

these reasons, we hold that FERC has supported its determination to

abandon MFV rate design with substantial evidence in the record.

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82 LDCs presenting this argument include Atlanta Gas Light

Co., Chattanooga Gas Co., Peoples Natural Gas Co., and Southwest

Gas Co. 

2. FERC's choice of SFV rate design

Several petitioners raise challenges to FERC's determination

that SFV is the appropriate rate design method for the natural gas

market. The LDCs argue that the commodity and usage charges under

SFV rate design will not reflect differences in transportation

costs for different pipelines, thus sending improper price signals

to gas purchasers. The PUCs argue that under SFV rate design,

pipelines will recover all of their fixed costs through reservation

and demand charges and will hence have no incentive to maximize

pipeline throughput. The Electric Generators argue that FERC

failed to consider adequately an alternative rate design method

proposed by Arizona Electric. Finally, the Small Distributors

argue that the switch to SFV will result in an increase in gas

prices at the wellhead, and that FERC has failed to demonstrate

that such an increase is necessary to assure an adequate supply of

gas. As we noted in the previous section, our task is not to

determine whether SFV is in fact the best rate design method

available, but merely to determine whether FERC can support its

choice with substantial evidence in the record.

a. LDCs' claim

The LDCs82 claim that the switch to SFV rate design will

undermine gas purchasers' ability to make economically efficient

choices of gas suppliers because the per unit gas price they face

from a supplier will not reflect the distance which the gas must

travel over a pipeline to reach the customer. In consequence, a

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gas purchaser might choose to buy from supplier A, who transmits

gas over pipeline AA for a distance of 1,000 miles, when the

economically efficient outcome would have been for the purchaser to

buy from supplier B, who transmits slightly more expensive gas over

pipeline BB for a distance of only 500 miles. The LDCs' analysis,

however, overlooks two important facts. First, as FERC points out,

"the variable cost of transportationbasically the cost of fuel for

pipeline compressors," will still be included in the commodity and

usage charges. So gas purchasers will receive the proper signal

regarding the actual differences among suppliers in variable

transportation costs. See Order No. 636, ¶ 30,939, at 30,437.

Furthermore, gas purchasers will still take differences in fixed

transportation costs into account, because those cost components

will be included in the reservation and demand charges. Id. As

FERC notes, "[l]ocational advantages will continue to matter,

because long-distance transportation generally will require more

facilities, and thus will have higher fixed costs, than

shorter-distance arrangements."

The LDCs argue citing Catalano, Inc. v. Target Sales, Inc.,

446 U.S. 643, 648 n.10 (1980) (per curiam) that FERC's removal of

transportation costs from per unit charges at the supplier level

amounts to "base point pricing," which, they argue, "would be [a]

per se violation [ ] of the antitrust laws," if done by agreement

among private parties to fix the price of transportation added to

the price of products. While we have concluded that FERC's

response to this argument is adequate, we further note that the

base point pricing cases have involved private agreement in

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otherwise unregulated markets, and commodities such as cement,

expensive to transport as contrasted with natural gas, a product

which not only is the subject of pricing regulation but also is

extraordinarily inexpensive to transport over pre-existing

pipelines. Cf. FTC v. Cement Institute, 333 U.S. 683, 697 (1948).

We accordingly reject the LDCs' challenge to FERC's decision to

implement SFV rate design.

b. PUCs' claim

The PUCs argue that the switch to SFV rate design "will

frustrate, rather than promote, the goals of maximizing efficiency

and competition." Their complaint centers on the claim that

because pipelines under SFV rate design will be able to collect all

their fixed costs, including return on investment and taxes, in the

demand charge, they will have no incentive to assure that gas

actually flows through the pipeline under firm service

arrangements. That is, because a pipeline will recover no fixed

costs or return on investment through the commodity or usage

charge, it will have no incentive to transport any gas.

FERC recognized this potential incentive problem in Order No.

636, but determined that "the pipelines will now have much less

influence on the use of their systems because they are transporting

gas to, rather than selling gas at, the city-gate." Order No. 636,

¶ 30,939, at 30,436. Accordingly, "[t]ransportation volumes will

mainly be a function of the needs of gas purchasers and the prices

offered by gas sellers in the production areas." Id. In any case,

"the goals to be accomplished via SFV outweigh generally the goal

of allocating fixed costs to annual throughput." Order No. 636-A,

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83 Arizona Electric Power Cooperative, Inc., sponsors this

argument. 

¶ 30,950, at 30,606. We find these explanations sufficiently

convincing to meet the substantial evidence standard for rate

design in the face of the PUCs' incentive argument.

c. Electric Generators' claim83

The Electric Generators argue that FERC failed to consider

adequately the demand-responsive volumetric charge system proposed

by Arizona Electric Power Cooperative, Inc. (AEPCO), as an

alternative to SFV rate design. They claim that AEPCO's proposed

system does a better job of rationing scarce capacity during peak

demand. However, FERC correctly counters that the fact that AEPCO

may have proposed a reasonable alternative to SFV rate design is

not compelling. The existence of a second reasonable course of

action does not invalidate an agency's determination. See Cities

of Batavia v. FERC, 672 F.2d 64, 84 (D.C. Cir. 1982) ("[T]he

billing design need only be reasonable, not theoretically

perfect."). Although an administrative agency must respond to

"comments which, if true, ... would require a change in an agency's

proposed rule," American Mining Congress v. EPA, 907 F.2d 1179,

1188 (D.C. Cir. 1990) (internal quotation marks and citations

omitted), FERC has met that standard as to AEPCO's proposal. FERC

noted the generator's concerns, but concluded that its own plan

would better avoid the distorting influences on the gas market

experienced during MFV ratemaking. Order No. 636-A, ¶ 30,950, at

30,606-07. Though AEPCO and FERC each briefly debate the merits of

the two proposals, we see no basis for voiding FERC's ruling, which

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84 The National Association of Gas Consumers supports this

argument. 

appears based on substantial evidence in the record.

d. Small Distributors' and Municipalities' claim84

The Small Distributors and Municipalities argue that the

effect of SFV rate design is to increase gas prices at the

wellhead. They further claim that FERC failed to demonstrate that

such an increase is necessary to assure adequate supply. FERC

points out that this argument is not properly before the court

because petitioners did not raise it in the administrative

proceedings in their request for rehearing of Order No. 636. As we

noted earlier, see supra Part IV.A.2, 15 U.S.C. § 717r(b) (NGA §

19(b)) clearly states that "[n]o objection to the order of the

Commission shall be considered by the court unless such objection

shall have been urged before the Commission in the application for

rehearing unless there is reasonable ground for failure so to do."

See also ASARCO, 777 F.2d at 773-75 (elaborating on the

significance of the § 717r(b) requirement that the objection be

raised before FERC). Finding no mention of this price increase

objection in the petitioner's rehearing request, and hearing no

explanation by the petitioner of a reasonable ground for this

omission, we conclude that the price increase objection is not

properly before the court and decline to reach it.

3. Regulatory Flexibility Act

The Regulatory Flexibility Act, 5 U.S.C. §§ 601-612 (RFA),

requires that an agency conduct a regulatory flexibility analysis

(or "small entity impact analysis") for any rule that will have a

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"significant economic impact on a substantial number of small

entities." 5 U.S.C. § 605(b). The PUCs argue that the RFA

required that FERC perform a small entity impact analysis for Order

No. 636 because of its significant economic effect on LDCs.

However, in Mid-Tex Elec. Co-op, Inc. v. FERC, 773 F.2d 327, 340-43

(D.C. Cir. 1985), we conducted an extensive analysis of the RFA

provisions governing when a regulatory flexibility analysis is

required and concluded that no analysis is necessary when an agency

determines "that the rule will not have a significant economic

impact on a substantial number of small entities that are subject

to the requirements of the rule." Id. at 342 (emphasis added).

FERC has no jurisdiction to regulate the local distribution of

natural gas. 15 U.S.C. § 717(b) ("The provisions of this chapter

... shall not apply to ... the local distribution of natural gas or

to the facilities used for such distribution."). Accordingly, the

allegation that Order No. 636 may have a significant economic

impact on LDCs (an assertion FERC disputes) is not sufficient to

trigger the mandate of the RFA. FERC had no obligation to conduct

a small entity impact analysis of effects on entities which it does

not regulate.

C. FERC's Discretion to Adopt Mitigation Measures

1. Background

FERC recognized that the adoption of SFV rate design could

result in cost shifting among pipeline customers because of their

differing load factors. Order No. 636, ¶ 30,939, at 30,435; Order

No. 636-A, ¶ 30,950, at 30,601-03; Order No. 636-B, ¶ 61,272, at

62,015-16. The adoption of SFV will, at least arguably, shift

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costs to low load factor customers in two ways: first by removing

all fixed charges from the usage charge; and second by measuring

usage solely based on peak demand, rather than annual usage. To

elaborate, a low load factor customer transports most of its gas

during the winter heating season; therefore, its average daily

usage of its capacity entitlement is significantly below its usage

on a peak day. As a result of this demand structure for low load

factor customers, they usually pay proportionately more in

reservation and demand fees than do high load factor customers.

This result follows logically when reservation fees are constant

throughout the year for a high and a low load factor customer who

each have the same capacity entitlement. The low load factor

customer purchases a lower annual volume of gas; hence, a larger

proportion of its payments to the pipeline are made up of

reservation fees. The existence of this phenomenon means that,

once the pipeline has switched to SFV, the low load factor

customers will pay a higher share of pipeline fixed costs than they

did under MFV. Under MFV, low load factor customers could escape

some of the fixed costs by not purchasing their full entitlement of

gas because the per unit price of the gas contained some fixed

costs. Additionally, under SFV, FERC has determined that the

reservation and demand charges will no longer vary with annual

usage, as they did under MFV. Order No. 636-A, ¶ 30,950, at

30,599.

To offset these cost shifts likely to result from Order No.

636, FERC adopted several mitigation measures. First, it required

that pipelines "use some measure, such as seasonal contract

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quantities," in calculating reservation and demand fees when the

switch to SFV rate design "causes significant cost shifts" to

individual customers. Order No. 636-A, ¶ 30,950, at 30,599. If,

even after the seasonal adjustments, the switch to SFV still

resulted in a ten percent or greater rate increase under SFV for a

particular customer class, FERC required that the pipeline phase in

SFV rate design over four years for that customer class, allowing

the customer class to avoid "rate shock." Order No. 636, ¶ 30,939,

at 30,435-46; Order No. 636-A, ¶ 30,950, at 30,603-04. FERC also

sought to retain the protection for small customers that the old

regime offered by requiring all pipelines that offered service

under a one-part volumetric rate at an imputed load factor on May

18, 1992, to offer transportation service under a similar rate

structure to all customers who were eligible on that date for such

an arrangement. Order No. 636-A, ¶ 30,950, at 30,600; Order No.

636-B, ¶ 61,272, at 62,018-22. We will label this mitigation

measure the "small customer discount."

Petitioners bring several different challenges to the adoption

of these mitigation measures and to various aspects of their

implementation. We now consider each of these challenges.

2. Justifications for mitigation measures

The high load factor LDCs object to FERC's requirement of a

small customer discount and to the use of seasonal adjustments for

low load factor customers. They argue that the small customer

discount results in high load factor customers having to pay higher

unit charges than would be the case without the requirement. They

also maintain that the use of seasonal adjustments for low load

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factor customers eliminates the incentive for these customers to

flatten their demand over the course of the year. Seasonal

adjustments also allegedly penalize high load factor customers for

their foresight in using storage and other peak shaving tools in

winter months to flatten their demand. The LDCs claim that the

higher charges to high load factor customers resulting from these

mitigation measures "unduly discriminate against residential

customers of high load factor LDCs and give preferential treatment

to customers" of low load factor LDCs in violation of NGA § 5(a).

FERC responds to the LDCs' claims by stressing that the effect

of the mitigation measures is to preserve as much of the status quo

as possible with respect to cost allocation. The intervenors point

out that the LDCs' attack on the mitigation measures improperly

assumes that SFV rate design is a baseline from which any

mitigation measures should be judged. Both FERC and the

intervenors are correct. The LDCs' claim of "discrimination" is

based on the assertion that they, and ultimately their customers,

will have to pay a larger share of fixed costs than they would pay

without the mitigation measures. But the LDCs have no sustainable

argument for why this should invalidate the measures. There is no

"neutral" or inherently "fair" allocation of fixed costs, as the

history of rate design amply demonstrates. The LDCs assume that

allocating fixed costs according to a straight SFV methodology is

the "fair" way of doing things, a curious position in light of the

LDCs' opposition throughout these proceedings to the adoption of

SFV rate design. But there is no "fair" baseline from which to

judge a particular cost allocation scheme.

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In any case, FERC correctly points out that it has long

rejected the position that fixed costs should be allocated solely

on the basis of peak day demand, as would apparently result under

a straight SFV system with no mitigation measures. The courts have

concurred in FERC's rejection of such a regime. See NIPSCO, 782

F.2d at 742 ("[T]he Commission long ago with judicial approval

rejected the argument that fixed costs should only be allocated and

recovered solely on the basis of peak day demands."). As for the

LDCs' argument that the seasonal adjustments remove the incentive

for low load factor customers to flatten their demand throughout

the year, we note that this incentive is greatly magnified under a

"pure" SFV system as compared to an MFV system. Under MFV, the low

load factor customers could have avoided part of the fixed costs

during periods of low demand because part of the per unit gas

charge included fixed costs. "Reducing" the stronger incentive to

flatten demand that would otherwise exist under SFV is not

problematic because, as we have just explained, a pure SFV system

is not a proper baseline from which to judge the appropriateness of

mitigation measures.

The same reasoning applies to the LDCs' claim that the

mitigation measures unfairly penalize those LDCs whose foresight

led them to invest in peak-shaving facilities before Order No. 636.

The mitigation measures only look like an unprecedented subsidy

flowing from high load factor customers to low load factor

customers when one compares the Order No. 636 regime to a straight

SFV regime with no mitigation measures at all. Once again, a

strict SFV regime is not the proper baseline. When one compares

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85 The LDCs also argue that under the Order No. 636 regime,

low load factor customers have several new means of adaptation at

their disposal and are not in need of mitigation measures. 

However, as FERC points out, none of the LDCs raised this

argument in their rehearing petitions before the Commission. 

They are accordingly barred from raising it in this court under

15 U.S.C. § 717r(b). See supra Part IV.A.2. 

the Order No. 636 system with the pre-Order No. 636 system, in

which low load factor customers escaped part of their share of

fixed costs by reducing purchases in low demand periods, the

mitigation measures make sense in light of FERC's goal of avoiding

sudden and shocking departures from the status quo with respect to

cost allocation. In short, low load factor customers avoided some

fixed costs in low demand periods before Order No. 636, and they

are still avoiding some fixed costs in low demand periods after

Order No. 636. LDCs which adopted peak-shaving techniques are no

worse off than they were before Order No. 636. It is therefore

improper to say that FERC has "penalized" them.85

There being no neutral standard or baseline to guide the court

in evaluating mitigation measures, the only relevant question is

whether FERC has made a reasonable allocation of fixed costs

supported by substantial evidence. Considering the Order No. 636

series as a whole and bearing in mind FERC's regulatory goals and

history, we are convinced that FERC has supported its adoption of

mitigation procedures with substantial evidence. We now turn to

the various challenges raised by petitioners to specific aspects of

the mitigation measures.

3. Non-permanence of mitigation measures

As we noted above, see supra Part IV.C.1, FERC ordered that

under certain circumstances, pipelines must phase in SFV rate

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86 Distributors joining in this argument include the

American Public Gas Association and the National Association of

Gas Consumers. 

design over four years for a customer class, allowing the customer

class to avoid "rate shock." Order No. 636, ¶ 30,939, at 30,435-

46; Order No. 636-A, ¶ 30,950, at 30,603-04. The Small

Distributors and Municipalities86 contend that, rather than phasing

in new rates, FERC should have adopted permanent mitigation of

their rates. They argue that "[u]nreasonable rates do not become

just and reasonable by phasing them in over a four-year period.

Mitigation is no less vital four years later when the Commission's

four-year "remedy' expires." But FERC responds that the purpose of

the four-year phase in period was not to protect the customer class

from cost shifting altogether, but merely to avoid the shock of

allowing it to happen all at once. FERC's response is perfectly

sensible, and we hold that the Commission has justified under the

substantial evidence standard the four-year phase in period in the

circumstances in which Order No. 636 requires it.

4. Impact on pipeline rate of return

The PUCs argue that FERC should have reduced the pipelines'

rate of return because the pipelines will be able to recover all of

their fixed costs and return on investment through demand and

reservation charges instead of facing the uncertainty of recovering

a portion of their fixed costs and return through gas sales

throughout the year. See supra Part IV.B.2.b (describing reduced

pipeline uncertainty under SFV rate design). Specifically, the

PUCs contend that FERC should have followed its decision in

Transcontinental Gas Pipe Line Corp., 56 FERC ¶ 61,037, modified in

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87 Williston Basin Pipeline Company seeks review of this

issue. 

part, 57 FERC ¶ 61,331 (1991), 62 FERC ¶ 61,221 (1993), 64 FERC ¶

61,099 (1993), rev'd in part on other grounds, Transcontinental Gas

Pipe Line Corp. v. FERC, 54 F.3d 893 (D.C. Cir. 1995), and imposed

a 25 basis point reduction in pipelines' return on equity to

reflect the lower risk under SFV rate design. However, FERC

stresses that it deferred any such adjustments in rates of return

to the individual restructuring proceedings in light of the fact

that "pipeline risk is a matter for pipeline-specific analysis in

light of all risks." Order No. 636, ¶ 30,939, at 30,437. As we

have said before, setting a rate of return is "an intensely

practical affair requiring the conversion of inexact data into

exact rates or limits upon rates." Matson Navigation Co. v.

Federal Maritime Comm'n, 959 F.2d 1039, 1043 (D.C. Cir. 1992)

(citations and internal quotation marks omitted). Nothing in the

law requires that FERC take a "shotgun" approach to the problem of

decreased pipeline risk by ordering an across-the-board rate

reduction, much less that the court do so. We note in this regard

that Transcontinental Gas, the decision upon which petitioners

rely, was itself an individual pipeline ratemaking decision. FERC

easily meets its burden of supporting its decision to defer rate of

return adjustments to individual restructuring proceedings.

5. Individual customer vs. customer class 87

FERC required that pipelines use measures such as seasonal

contract adjustments to avoid significant cost shifting for

individual customers. If, after application of these mitigation

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measures, the use of SFV "still results in a 10 percent or greater

increase in revenue responsibility for any historic customer

class," then the pipelines are required to phase in the increase

over four years. Order No. 636-B, ¶ 61,272, at 62,016 (emphasis

added). The Pipeline Petitioners argue that the mitigation

measures short of four-year phase in should also have been required

on the basis of customer class rather than on the basis of SFV's

effects on individual customers.

In deciding to base the initial mitigation measures on SFV

rate design's effects on individual customers rather than customer

class, FERC cited several recent decisions in individual pipeline

restructuring proceedings. Id. at 62,016 n.140. However, these

rulings simply implement Order No. 636 and order studies on the

effect of SFV rate design on individual customers, anticipating the

adoption of mitigation measures on a customer-by-customer basis.

But relying on these orders as a justification for the

customer-by-customer basis would be a classic case of

bootstrapping, amounting to a conclusion that Order No. 636

properly requires the customer-by-customer approach since several

decisions implementing Order No. 636 take that approach. Nothing

in any of the decisions justifies the basic determination in favor

of the individual customer approach. Significantly, FERC cites no

other support for its decision in Order No. 636-B to favor the

individual customer approach.

The Pipeline Petitioners also raise an important question

about the danger of the individual customer approach with respect

to pipeline cost recovery:

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[R]ates are determined on the basis of costs incurred and

billing quantities during a specified test period. While

it is reasonable to expect that the actual billing

quantities of all customers in each class during the

period the rates are in effect will approximate those

experienced by the class during the test period, it is

likely that individual customers may experience larger

variances in billing quantities. The establishment of

rates on a customer-by-customer basis therefore increases

the risk that a pipeline will fail to collect its total

costs during the period in which rates are in effect.

Pipeline Petitioners' Brief at 27. They also argue that FERC's

order fails to take into account potential customer cost reductions

under Order No. 636 that are not directly related to the switch to

SFV rate design, and that the individual customer method "increases

the likelihood for discrimination in rates to similarly situated

customers in violation of Sections 4 and 5 of the Natural Gas Act."

FERC has provided, in response to our request at oral

argument, several citations to Order Nos. 636-A and 636-B which

supposedly explain FERC's decision to implement the initial

mitigation measures on a customer-by-customer basis. However,

after examination of these citations, we conclude that the

discussions cited on this question are ambiguous at best and

incomplete at worst. FERC has failed to address adequately, in

either the Order No. 636 series or in its brief, the Pipeline

Petitioners' objections which we have outlined above. Because, as

previously noted, the Commission has failed to provide any reasoned

justification for its decision on this issue, and because the

petitioners' objections raise serious questions about the

appropriateness of FERC's ruling, we conclude that the Commission

has failed to support its decision on this issue with substantial

evidence. We therefore remand to the Commission the question of

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88 The East Tennessee Group, the National Association of Gas

Consumers, and the Tennessee Valley Municipal Gas Association

support this argument. 

whether the initial mitigation measures should be implemented on

the basis of customer class for further examination.

6. Discounts for former customers of downstream pipelines

In requiring a continuation of the pre-Order No. 636 small

customer discounts, FERC only mandated that downstream pipelines

offer the discount to the class of customers eligible for it on May

18, 1992. But the Small Distributors88 argue that FERC should have

required upstream pipelines to provide the discounts to any

customers of downstream pipelines who received the discounts on May

18, 1992. The downstream pipeline customers were indirect

customers of the upstream pipelines under the old regime and now

are direct customers of these upstream pipelines. The Small

Distributors argue that these former downstream pipelines customers

"are now indistinguishable from the upstream pipeline's other small

customers, with whom they compete directly for markets." FERC's

failure to account for this fact results in "undue discrimination

between similarly-situated small customers on the same pipeline

solely on the basis of whether they used to be served through a

downstream pipeline prior to Order [No.] 636." Although FERC did

indicate in Order No. 636-B that the former downstream pipeline

customers' need for discounts should be examined in individual

restructuring proceedings, the Small Distributors contend that it

is unfair and unreasonable to make them demonstrate such a need in

restructuring proceedings when that need has already been presumed

for other small customers.

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The Small Distributors raise excellent points. FERC's failure

to counter them with anything but its insistence that former

downstream customers can raise their need for small customer

discounts in upstream pipeline restructuring proceedings (perhaps

they can, although the Small Distributors dispute the effectiveness

of such a course of action), does not address the core of the Small

Distributors' argument. FERC has made an arbitrary distinction

between former indirect small customers of upstream pipelines (who

are now direct small customers) and small customers who have always

been direct customers of the same pipelines. Because FERC has not

supported this distinction with substantial evidence in the record,

we remand this 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.

7. Triennial rate review

In Order No. 636-A, FERC abandoned the requirement of

triennial rate review, which it had formerly imposed on many

pipelines in exchange for granting the pipelines certain powers

over their rates. FERC explained that the only reason it had

formerly required triennial rate review was because of the power it

had granted the pipelines. Specifically, under the purchased gas

adjustment (PGA) regulatory scheme, participating pipelines had

discretion to change the gas supply cost element of their rates.

In exchange for this ability, "pipelines had to agree to a

reexamination of all their costs and rates at three year intervals

to assure that gas cost increases were not offset by decreases in

other costs." Order No. 636-A, ¶ 30,950, at 30,671; see also 18

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89 Associated Gas Distributors, Consolidated Edison Company

of New York, Inc., Illinois Power Co., and Peoples Natural Gas

Co. present this argument. Supporting intervenors are PECO

Energy Co. and Washington Gas Light Co. 

C.F.R. § 154.303(e) (laying out triennial rate review requirement).

Under the Order No. 636 regime, pipelines have no special rate

adjustment mechanism comparable to the PGA scheme, so FERC

concluded that triennial rate review was unnecessary. In Order No.

636-B, FERC even raised the question of whether it had the

discretion to order triennial rate review under the Order No. 636

regime, noting that "there are limits to the authority of the

Commission to require pipelines to periodically justify their

existing rate levels." Order No. 636-B, ¶ 61,272, at 62,044-45

(citing Public Serv. Comm'n v. FERC, 866 F.2d 487 (D.C. Cir. 1989)

(PSCNY) (holding that requiring periodic filings under NGA § 4 is

beyond FERC's statutory authority)).

The LDCs89 argue that FERC should not have abandoned triennial

rate review. First, they claim that FERC "ignored that the

market-based sales rate authority granted pipelines under Order

[No.] 636 is a "special rate adjustment mechanism' " justifying a

periodic rate review. In any case, they argue that FERC certainly

does have the authority to impose triennial rate review under the

Order No. 636 regime. In their view, PSCNY simply means that "FERC

cannot impose [a periodic filing] requirement except as a condition

of some other benefit voluntarily accepted by the pipeline."

Because Order No. 636 conferred several benefits on pipelines, the

LDCs contend that FERC's failure to attach periodic rate review to

at least one of those benefits was unjustified. FERC, however,

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contends that the "benefits" to pipelines cited by the LDCs are not

nearly so certain: "there is no reason to believe that by allowing

a pipeline to sell gas at market-based rates, rather than regulated

cost-based rates, Order No. 636 makes it more likely that rates for

unbundled transportation service will become unjust and

unreasonable."

The PUCs also argue in favor of retaining triennial rate

review, restating the LDCs' argument that FERC has conferred a

benefit on pipelines by instituting SFV rate design and can

accordingly require periodic rate review. They also point out

that, under SFV, as long as fixed costs continue to decline,

pipelines will have no incentive to file NGA § 4 rate cases since

they will be recovering all of their fixed costs through

reservation and usage fees. Consumers will then be left with an

NGA § 5 complaint as their only option for protecting themselves,

but a § 5 complaint is less satisfactory than a § 4 rate case

because under § 5 the burden is on the complainant to establish the

unjustness or unreasonableness of the rate. Also, § 5 relief is

prospective only; § 4 relief can encompass a refund order. FERC

responds that "traditional ratemaking tools are available to take

account of long-run declining costs, and a three-year review [is]

unnecessary."

FERC's position that it lacks authority to impose triennial

rate review is quite strong. The LDCs' claim that the market-based

sales authority granted to pipelines is a "benefit" to which

triennial rate review may be attached rings hollow in light of the

fact that pipelines are leaving the gas sales business in favor of

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gas transportation under Order No. 636. Furthermore, whatever the

benefits of SFV rate design to pipelines, they are not benefits

voluntarily accepted by the pipelines and so cannot be the basis

for the imposition of periodic rate review. See PSCNY, 866 F.2d at

492 (noting that FERC's authority to impose triennial rate review

in the PGA context "obviously rests on pipeline consent" to

triennial rate review in exchange for automatic PGA adjustment

authority). In any case, in the presence of these serious doubts

about FERC's authority to impose periodic rate review in the Order

No. 636 context and in view of the alternative procedures available

to the Commission for ensuring reasonable rates, we hold that

petitioners have failed to show that FERC has not supported its

decision to drop triennial rate review with substantial evidence.

V. Transition Costs

In this part of the opinion, we briefly review the history

behind the transition cost issue and consider each of the

petitioners' challenges to FERC's treatment of transition costs.

A. Background to Transition Costs

1. Order No. 436 and its successors

Order No. 436 began the natural gas pipeline industry's

transition from its historic role as gas merchant to gas

transporter. The Order authorized interstate gas pipelines to

convert to blanket-certificated "open-access" transportation

service. See supra Part I.B. In exchange, however, customers of

those pipelines that did convert were permitted both (1) to convert

their firm sales obligations into firm transportation contracts and

also (2) to reduce their obligations to purchase gas from the

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pipelines. Pipeline customers in large numbers exercised their

right under the Order to buy less gas from the pipelines, and

secured gas supplies from less expensive sources. The pipelines

themselves were then left with massive obligations to purchase

high-priced gas at the wellhead:

[T]he conditions under which the NGPA began to relax

wellhead price controlsnamely acute gas shortage and

sharply rising prices for alternative fuelstended to

divert pipeline attention from the hazards of incurring

long-term obligations to buy high-priced gas. Under

pressure from the Commission, the pipelines had typically

purchased gas under contracts for very long terms.

Besides incorporating high prices (and provisions for

escalation upward), the contracts commonly included

"take-or-pay" provisions, requiring the pipeline to pay

for some specified percentage, say 75%, of the

deliverable gas even if it took less. While usually

subject to recoupment later, and while a perfectly

natural allocation of risk between producer and

purchaser, the take-or-pay provisions effectively

committed the pipelines to high gas costs in what by 1982

proved to be a time of falling prices, both for competing

fuels and for substitute supplies of gas not covered by

contract.

AGD I, 824 at 995-96 (citations omitted) (emphasis added).

Thus arose the "take-or-pay" liabilities addressed by the

Commission in Order No. 436 and its successors, as well as by this

court in a variety of opinions. See supra Part I.B. Specifically,

because most customers could purchase gas more cheaply from other

sources, pipelines essentially were unable to pass through the

costs of their own supply obligations. With purchases sharply

reduced, pipelines owed massive "take-or-pay" liabilities to gas

producers, which they had to either "buydown"i.e., reduceor

"buyout"i.e., eliminate. In Order No. 436, the Commission refused

to set a general policy on whether or how pipelines could attempt

to recover these costs. We vacated and remanded the Order,

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concluding that, in this regard, it was not based on reasoned

decisionmaking, primarily because it appeared to grossly

underestimate the financial impact of take-or-pay liability on

pipelines. Id. at 1021-30. Of great concern to the court was the

likelihood that even higher gas prices would simply cause more

customers to switch suppliers, thereby exacerbating the take-or-pay

crisis. This cycle of ever increasing prices and ever shrinking

customer basea phenomenon that petitioners label the "death

spiral"made it very unlikely that the pipelines would in fact

recoup their take-or-pay liabilities absent some mechanism for

separately passing those costs through to their customers.

In subsequent proceedings, the Commission adopted and this

court approved various measures designed to address that concern

and allow pipelines to pass through some of their take-or-pay

liabilities to a broader range of customers. See supra Part I.B.

Most pertinent to our analysis here, under Commission policy, a

pipeline could agree to absorb between 25% and 50% of its

take-or-pay costs in exchange for the right to bill customers an

equal share through a fixed charge, and recover the remaining

amount through a volumetric surcharge based on total throughput.

Customers, and in turn the consuming public, ultimately reimbursed

pipelines for approximately $6.4 billion in take-or-pay costs,

while the pipelines themselves absorbed $3.6 billion.

2. Order No. 636 and petitioners' challenges

After Order No. 436, all of the major interstate pipelines

converted to open-access transportation. Not all customers on

those pipelines, however, exercised their right to unbundle their

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sales agreements and reduce their gas purchase obligations.

Several years later in Order No. 636, the Commission mandated

unbundling and authorized sales customers to reduce their pipeline

gas purchases. When customers exercised that right and secured gas

supplies from other sources, the pipelines once again incurred

substantial take-or-pay liabilities; though the Commission labeled

these liabilities "gas supply realignment costs" in Order No. 636,

they arose from the same type of producer-pipeline contract

provisions as the "take-or-pay" costs considered in Order No. 436.

Cf. Order No. 636-A, ¶ 30,950, at 30,649 n.466 ("Any costs that

would qualify for recovery as GSR costs could be filed for recovery

under [the successor to Order No. 436,] Order No. 528.").

In allocating recovery of GSR costs, however, the Commission

adopted a policy more advantageous to the pipelines. Instead of

refusing to establish a mechanism for pipelines to recover their

take-or-pay costs, as it originally had in Order No. 436, FERC

authorized pipelines to bill their customers separately for 100% of

their GSR costs. This policy was, in fact, a substantial change

from even Order No. 500, which permitted pipelines to surcharge

their transportation customers for take-or-pay costs only if they

agreed to absorb between 25 and 50% of those costs. The Commission

set forth the mechanisms available to pipelines under Order No. 636

as follows:

... The Commission will permit pipelines full cost

recovery of prudently incurred gas supply realignment

costs deemed to be eligible under this rule. To recover

those costs, a pipeline will be permitted to use either

a negotiated exit fee, or a reservation fee surcharge

recoverable from Part 284 firm transportation customers.

Under this rule, a firm entitlement holder has

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options as to how to react to gas supply realignment

costs: it may remain a sales customer of the pipeline;

otherwise, it may take an assignment of the pipeline's

existing contracts or pay an exit fee/reservation fee

surcharge for costs approved by the Commission.

Order No. 636, ¶ 30,939, at 30,458. On rehearing, FERC modified

this ruling somewhat, and required pipelines to bill 10% of their

GSR costs to interruptible transportation customers. See infra

Part V.E.3.b.2.

Pipelines also face three other types of significant

transition costs under Order No. 636: (1) unrecovered gas costs or

credits remaining in the purchased gas adjustment (PGA) account

when a pipeline terminates its PGA mechanism; (2) costs of

pipeline assets (such as storage facilities) currently used to

provide bundled sales service which are not directly assignable to

customers of the unbundled services ("stranded costs"); and (3)

costs for equipment required to physically implement the rule ("new

facility costs"). Order No. 636, ¶ 30,939, at 30,457. FERC

determined in Order No. 636 that pipelines would generally be

allowed to recover 100% of these costs. Id. at 30,457-60.

Petitioners raise several challenges to FERC's treatment of

transition costs. First, they claim that FERC erred in allowing

pipelines to recover 100% of their stranded costs, arguing that

such recovery violates applicable legal standards. Second, they

contend that FERC failed to adequately address the problem of "LDC

bypass," which occurs when large industrial customers bypass LDCs,

thereby avoiding transition costs properly attributable to them.

Third, they oppose Order No. 636's passthrough of above-market

prices paid by pipelines for synthetic natural gas from the Great

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Plains Gasification Plant. Finally, they challenge in several

respects FERC's treatment of GSR costs. 

B. Stranded Costs and the "Used and Useful" Doctrine 

A separate class of Order No. 636 transition costs are

"stranded costs," which are those "incurred by pipelines in

connection with their bundled sales services that cannot be

directly allocated to customers of the unbundled services." Order

No. 636, ¶ 30,939, at 30,460. To be denominated "stranded," an

investment (1) must have been prudently made, Order No. 636-A, ¶

30,950, at 30,662, but (2) must be no longer "used and useful"

after Order No. 636, Order No. 636-B, ¶ 61,272, at 62,041.

Examples include upstream pipeline capacity for which a downstream

pipeline cannot find a buyer, and storage capacity that a pipeline

no longer needs when the volume of its sales service shrinks.

Order No. 636, ¶ 30,939, at 30,460. According to the Commission,

pipelines can recover their stranded costs in NGA § 4 rate filings.

Id.; see also Order No. 636-B, ¶ 30,950, at 62,042 ("The

Commission will allow pipelines to make limited section 4 filings

to recover ... the costs of stranded facilities that are currently

incrementally priced.... However, pipelines must file to recover

the costs of most, if not all other stranded facilities in general

section 4 rate proceedings.").

The PUCs challenge the Commission's ruling, see Order No. 636-

B, ¶ 61,272, at 62,041, that pipelines may recover 100% of their

stranded costs. Their presentation is straightforward: items that

are not currently "used and useful" may not be included in a

utility's rates. In support, the PUCs invoke the Commission's

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statement in New England Power Co., 42 F.E.R.C. ¶ 61,016, at 61,078

(1988), that "[i]n general, the used and useful standard provides

that an asset may be included in a utility's rate base only when

the item is used and useful in providing service." They also cite

to this Court's statement in Tennessee Gas Pipeline v. FERC, 606

F.2d 1094, 1109 (D.C. Cir. 1979), that "the precept endures that an

item may be included in a rate base only when it is "used and

useful' in providing service."

In its brief, the Commission replies along two fronts. First,

it contends that the PUCs' objection is premature, given that in

Order No. 636, the Commission stated that, in subsequent

restructuring proceedings, it would "consider arguments about

whether particular facilities are used and useful, or whether the

costs should be recoverable as transition costs" in § 4 rate

proceedings. Order No. 636-A, ¶ 30,950, at 30,662. Second, the

Commission contends that the "used and useful" principle invoked by

the PUCs, while generally sound, does not apply to facilities that

have been stranded only because of the Commission's own action. In

other words, the pipelines should recover on their investments as

they would have had Order No. 636 never been promulgated.

While we ultimately affirm the position taken by the

Commission in the administrative proceedings, we believe that both

the PUCs and the Commission itself may have overlooked a relevant

distinction on appeal: the difference between a utility's rates

and its rate base. "The rate allowed a utility is the sum of (1)

its cost of service, and (2) its rate base multiplied by its rate

of return." Jersey Central Power & Light Co. v. FERC, 810 F.2d

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90 Our opinion should not be read to prohibit the Commission

from applying the "used and useful" principle to issues of

recovery through cost of service. Instead, as we explain in our

discussion, infra at 125, of NEPCO Municipal Rate Committee v.

FERC, 668 F.2d 1327, 1333 (D.C. Cir. 1981), this Court has

recognized that the Commission is not required to do so in all

instances. 

1168, 1172 (D.C. Cir. 1987) (en banc). "Generally, the rate base

is comprised of total capital invested in facilities minus

depreciation plus cash working capital. The rate of return, on the

other hand, is a weighted average of different rates applied to

debt, preferred stock and common stock." Id. at 1203 (Mikva, J.,

dissenting). "Calculation of rate base is a critical step in

establishing maximum rates, since the product of rate base

multiplied by allowed rate of return is the total sum of money the

agency allows to investors in the firm." RICHARD J. PIERCE, JR. &

ERNEST GELLHORN, REGULATED INDUSTRIES 102 (3d ed. 1994).

The cases cited by the PUCs, and not challenged by the

Commission, stand for the proposition that the items in a utility's

rate base generally should currently be used and useful to

consumers. As a result, investors generally profit only from those

investments that presently benefit consumers. However, that

principle does not answer the question whether investments that are

not used and useful may nonetheless be included in the utility's

rates, i.e., still treated as part of the utility's cost of

service.90

Viewed in this light, the general statement in Order No. 636

that pipelines will recover 100% of their stranded costs still

leaves the Commission with a number of options in the § 4 rate

proceedings. For example, the Commission could decide that

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stranded costs should merely be included in the pipeline's cost of

service, recoverable through amortization over time. In such an

instance, "FERC has already moved somewhat in the direction of

balancing competing interests by permitting recovery of the costs

of building the plant in the cost of service. Investor interests

have not, therefore, been entirely ignored." Jersey Central, 810

F.2d at 1192 (Starr, J., concurring). The Commission might also

allow the pipeline to recover not only the amortization, but also

interest, i.e., the "cost" of the unamortized portion of the

investment. The Commission could further decide to include

stranded investments in the utility's rate base and thereby

generate a profit for investors.

In the administrative proceedings, the Commission assiduously

avoided announcing a general standard that would control the manner

in which stranded costs may be recovered. Thus, Order No. 636, at

30,460 (emphasis added), states that while "most of the costs of

new facilities would be includable in rate base, ... there is no

way of anticipating the nature and amount of the stranded costs,

and thus no way at this time of devising an appropriate billing

mechanism on a generic basis." Similarly, in Order No. 636-B, ¶

61,272, at 30,662, the Commission deferred until individual rate

cases a party's objection that "costs associated with physical

plant that is no longer used and useful ... should ... no longer be

includable in the rate base."

The PUCs' objection therefore is ripe for review only to the

extent that they contend that pipelines should not recover 100% of

their Order No. 636 stranded costs in any fashion. We cannot at

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this point address the specific question of whether pipelines

should be permitted to include stranded costs in their rate base,

and thereby receive a profit on the investment, because Order No.

636 adopted no such rule. Accord, e.g., Columbia Gas Trans. Corp.,

64 F.E.R.C. ¶ 61,060 (1993) (deferring determination of rate base

treatment of stranded cost recovery to § 4 proceeding); National

Fuel Gas Supply Corp., 63 F.E.R.C. ¶ 61,291 (1993) (same). In

fact, in at least one NGA section 4 rate proceeding, the Commission

expressly refused to permit such treatment of stranded costs,

explaining:

Included in [the pipeline's] claim for stranded cost

treatment for the production facilities, is a pretax

return allowance on the unamortized balance.... As

discussed above, in order for [the pipeline] to receive

stranded cost treatment for these facilities, they must

no longer be used and useful. It is long standing

Commission policy that when facilities are not used and

useful, they do not qualify for rate base treatment. In

addition, the recovery of stranded costs is designed to

compensate pipelines for out-of-pocket costs that they

have no other means of recovering. While the costs of

facilities are out-of-pocket costs, equity return and

related income taxes are not. Therefore, [the pipeline]

should not be allowed a pretax return allowance on the

unamortized balance. The Commission will limit [the

pipeline's] recovery to interest on the unamortized

amount....

This is consistent with the way the Commission has

treated other costs of a transitional nature that are

being amortized over a period of years to reduce the rate

impact on customers, e.g., GSR cost amortizations or

take-or-pay buyout and buydown cost amortizations. The

interest treatment prescribed above adequately

compensates the pipeline for the time value of the

outstanding unamortized balance, but recognizes the

nature of the costs being amortized.

Equitrans, Inc., 64 F.E.R.C. ¶ 61,374, at 63,601 (1993); cf.

National Fuel Gas Supply Corp., 71 F.E.R.C. ¶ 61,031, at 61,138

(1995) ("A rate of return on the amount of written down facilities

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would be inappropriate since this allows a return on facilities

that are not economically viable, and may also result in a

competitive advantage for the pipeline. The pipeline would,

however, be allowed to recover interest on the unamortized portion

of its written-down plant over a reasonable amortization period, as

this will keep the pipeline whole for the direct cost of its

investment in the facilities.").

We reject the PUCs' claim (now properly limited to the

argument that the "used and useful" principle per se prohibits

pipeline recovery of stranded costs even when merely amortized as

part of the cost of service), because it was previously rejected in

NEPCO Municipal Rate Committee v. FERC, 668 F.2d 1327, 1333 (D.C.

Cir. 1981) (NEPCO). In NEPCO, we considered "whether FERC's

refusal to include project expenditures in the rate base, while

allowing their recovery as costs over time, is a valid approach to

allocating the risks of project cancellation." We found such an

approach acceptable because, in that case, the Commission's

decision was based on substantial evidence and had adequately

balanced the interests of investors and ratepayers. Id.; see also

Jersey Central, 810 F.2d at 1183 (rejecting claim that NEPCO

adopted per se bar to including in rate base items not currently

"used and useful"). So long as the Commission's decisionmaking in

the individual § 4 proceedings satisfies that standard, it will

survive any subsequent challenge brought on "used and useful"

grounds.

C. LDC Bypasses

Order No. 636 creates new opportunities for large retail

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customers to bypass LDCs and connect directly to pipelines. 

Problems of scale and efficiency preclude other customers from

taking advantage of such options, however. State regulators and

LDCs argued before FERC that it is unfair to force an LDC's

remaining customers to pay the transition costs that they contend

are fairly allocatable to the departed customers of the LDC. Order

No. 636, ¶ 30,939, at 30,461; Order No. 636-A, ¶ 30,950, at

30,658-59. FERC, however, refused to adopt a generic rule to

address this problem, determining instead that it would consider

requests for relief on a case-by-case basis. The Commission

believes that it is reasonable to require that "an LDC seeking

relief in a bypass situation ... show that there is a direct nexus

between the bypass and the pipeline, so that the costs it seeks to

avoid should be reallocated to the bypassing customer." Order No.

636-A, ¶ 30,950, at 30,659.

The PUCs protest that the burden placed on LDCs of

demonstrating the nexus between the bypass and the pipeline is

"nearly impossible to meet" because of its specificity. They

accordingly argue that the pipeline and the bypassing customer

should have to explain why they shouldn't bear the bypassing

customer's share of transition costs. FERC counters that it has

"made no statement as to the ultimate burden of proof in such

situations" but has left resolution of LDC bypass claims to

individual proceedings. However, as noted above, FERC did find it

"fair" to require an LDC seeking bypass relief to show a "direct

nexus between the bypass and the pipeline." While arguably it may

not constitute a "burden of proof" in a technical sense, it does

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constitute a hurdle of causation which LDCs seeking relief must

clear in individual proceedings. Therefore, in contrast to the

Intervenors' argument, FERC's "direct nexus" requirement is ripe

for review.

We find the PUCs' arguments unpersuasive. First, we note that

the "burden" LDCs face in these cases is not "impossible to meet."

As FERC notes, it has already made it clear that at least one

bypassing customer still must bear its fair share of GSR costs.

See Arcadian Corp. v. Southern Natural Gas Co., 67 FERC ¶ 61,176,

at 61,538 (1994). Second, FERC reasonably determined that the

factual circumstances surrounding LDC bypasses "differ sufficiently

that the Commission cannot justify a generic rule [apart from the

"direct nexus" requirement] that would be appropriate in all

circumstances." Order No. 636-A, ¶ 30,950, at 30,659. We

accordingly reject the PUCs' challenges on this issue.

D. Above-Market Recovery for Great Plains Gas

The Great Plains Gasification Plant was constructed to convert

coal into synthetic natural gas (SNG). In Order No. 636-A, FERC

noted that in Transcontinental Gas Pipe Line Corp., 55 FERC ¶

61,446, reh'g denied, 57 FERC ¶ 61,345 (1991) (Transco), it had

"approved a settlement that provided for a volumetric surcharge on

system throughput to recover the above-market gas costs and

associated transportation costs related to Transco's obligations to

purchase synthetic gas from Great Plains." Order No. 636-A, ¶

30,950, at 30,657-58. Several petitioners complained that this

arrangement was in substantial conflict with the

competition-enhancing purposes of Order No. 636. FERC admitted as

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much in Order No. 636-A, but determined that the volumetric

surcharge "is consistent with the Commission's goal of providing a

smooth transition from the prior regulatory environment to the new

market-oriented environment." Id. at 30,658. Furthermore, FERC

followed its reasoning in Transco, concluding that "it is

"reasonable for all [the pipeline's] customers to share in the

above-market costs of the nation's first large-scale synthetic

fuels plant, whose technological benefits would have redounded to

all future gas users ... by increasing the supply of available

gas.' " Id.

The PUCs challenge FERC's treatment of Great Plains gas,

contending that it "conflicts with the goal which forms the heart

of Order [No.] 636providing consumer access to competitively

priced supply." They also cite Commissioner Langdon's partial

dissent in Order No. 636, in which he stated that "every comma,

word, sentence and paragraph of the order is internally

inconsistent" with respect to Great Plains gas. Order No. 636, ¶

30,939, at 30,472 (Langdon, C., concurring in part and dissenting

in part). "I fail to see how the [volumetric surcharge] will

ultimately benefit the consumer, or transmit accurate pricing

signals." Id. The PUCs also claim that FERC's decision requires

gas consumers to subsidize Great Plains, an outcome the Commission

has previously rejected with respect to failed SNG plants.

FERC responds to the PUCs' claims by arguing that

Elizabethtown III, 10 F.3d at 873-74, has already settled this

issue. Elizabethtown III reviewed FERC's orders approving

restructuring agreements between Transco and its customers. The

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petitioners challenged Transco's passthrough of its above-market

cost of SNG from Great Plains on the basis that "customers should

pay rates based only upon the costs they cause the pipeline to

incur." Id. at 873. We rejected that argument, however,

concluding that the departure from cost-causation principles was

justified because, "had the Great Plains plant succeeded in

increasing the supply of natural gas, it would have contributed

also to reducing the price of natural gas, to the benefit of all

natural gas consumers." Id. at 874.

The PUCs argue that Elizabethtown III is inapposite because it

did not consider the treatment of Great Plains gas in a

restructuring proceeding in light of the overall purposes of Order

No. 636. Although the PUCs are correct that Elizabethtown III does

not address Great Plains gas in light of Order No. 636, we note

that the case was both argued (February 23, 1993) and decided

(December 17, 1993) after the issuance of Order No. 636 (April 16,

1992), Order No. 636-A (August 12, 1992), Order No. 636-B (November

27, 1992), and even Order No. 636-C (January 8, 1993). The

Elizabethtown III court thus had ample opportunity to consider the

consistency of the Great Plains volumetric surcharge with the

overall policy objectives of the Order No. 636 regime. Petitioners

point to no developments since the Elizabethtown III decision that

effectively distinguish that case from the issue before us, and we

are accordingly constrained by Elizabethtown III 's treatment of

the Great Plains issue. We therefore reject petitioners'

challenges to FERC's treatment of Great Plains gas.

E. GSR Costs

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91 In Order No. 636-B, ¶ 61,272, at 62,040-41, the

Commission suggested that those pipelines that offered discounted

transportation services might not be permitted 100% recovery, a

statement that the pipelines challenged in this proceeding. The

Commission has since withdrawn that suggestion, however, Natural

Gas Pipeline Co. of Am., 69 FERC ¶ 61,029, at 61,116-17 (1994),

rendering the pipelines' claim moot. 

In this part of the opinion, we consider petitioners'

challenges to the GSR costs that arose from the modification of

producer-pipeline contracts. Order No. 636 both (1) required

pipelines to unbundle their firm sales contracts into separate

transportation and gas sales arrangements and (2) permitted

customers to reduce or eliminate their obligations to buy gas from

pipelines under the sales component. The pipelines, with fewer

sales customers, were in turn forced by market pressures to buy

their way out of many costly supply contracts with gas producers,

thereby incurring some $1.7 billion in "gas supply realignment

(GSR) costs." In Order No. 636, the Commission authorized

pipelines to recover 100% of their prudently incurred GSR costs

from their blanket-certificated transportation customers.91

Petitioners raise several objections to this recovery policy,

all of which we conclude are ripe for review. First, they argue

that FERC should have used its NGA § 5 authority to require gas

producers to bear part of the GSR costs. We conclude that FERC

reasonably declined to exercise the limited authority it possessed

over producer-pipeline contracts. Second, petitioners contend that

the Commission erred in its assignment of GSR costs to two classes

of pipeline transportation customers. By and large, we conclude

that the Commission's allocation of GSR costs among customers was

an acceptable application of "cost spreading" and "value of

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service" principles. We do conclude, however, that the Commission

has failed to explain adequately its decision in all instances to

allocate 10% of GSR costs to the pipelines' interruptible

transportation customers. Third, petitioners contend that the

pipelines themselves should have been required to absorb some

portion of their GSR costs. After carefully reviewing the issue,

we conclude that the Commission did not engage in reasoned

decisionmaking such that we can sustain its decision to exempt the

pipelines altogether. We do not hold that the Commission was

required to assign a particular portion of GSR costs to pipelines,

however, but instead remand this question (along with the 10%

interruptible transportation figure) for further consideration.

1. Ripeness of petitioners' challenges to FERC's treatment of GSR

transition costs

"Settled principles of ripeness require that [a court]

postpone review of administrative decisions where (1) delay would

permit better review of the issues while (2) causing no significant

hardship to the parties." Northern Indiana Public Service Co. v.

FERC, 954 F.2d 736, 738 (D.C. Cir. 1992) (NIPSCO). FERC argues

that none of the petitioners' challenges to its allocation of GSR

costs are ripe for review. It notes that, under Order No. 636, "a

pipeline may file ... to recover GSR costs only after it has

restructured its system in full compliance with the rule" and

argues that disputes over GSR cost recovery are therefore better

left to individual restructuring proceedings. See Order No. 636,

¶ 30,939, at 30,460; Order No. 636-B, ¶ 61,272, at 62,042.

Additionally, FERC noted in Order No. 636-B that the Order No. 636

series transition cost policies "are not incorporated in the

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regulations, but are policy statements." Order No. 636-B, ¶

61,272, at 62,034-35. It further explained that it would "review

specific proposals for recovering transition costs with reference

to the particular circumstances of each pipeline system and the

degree of support those proposals enjoy from the affected parties."

Id.; see also Order No. 636-A, ¶ 30,950, at 30,648-49 ("Guidelines

and policies will be developed ... in concrete cases" to address

concerns about GSR cost recovery.). FERC thus compares this case

to AGA I, 888 F.2d 136, which held unripe challenges to Order 500's

equitable sharing policy in light of the strong norm against

reviewing policy statements and other tentative agency positions

where no hardship will result to the parties.

The problem with FERC's ripeness argument is that it fails to

meet NIPSCO's two criteria for declaring a case unripe. The

Commission claims that it intended in the Order No. 636 series to

merely announce a general policy approach to GSR costs and leave

analysis of specific GSR cost disputes to individual pipeline

restructuring proceedings. "Where the language and context of [an

agency] statement are inconclusive, we have turned to the agency's

actual applications." Public Citizen, Inc. v. NRC, 940 F.2d 679,

682 (D.C. Cir. 1991). In this case, FERC's treatment of the GSR

cost issue in subsequent proceedings is inconsistent with a general

policy approach. For example, in restructuring proceedings for

Texas Eastern Transmission Corporation, petitioners challenged

FERC's allocation of GSR costs, but FERC determined that "[b]ecause

the Commission has addressed all of the Industrial Groups'

arguments in Order No. 636 et seq., the Industrial Groups' request

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for rehearing is denied." Texas Eastern Transmission Corp., 63

FERC ¶ 61,100, at 61,512 (1993). In Texas Eastern's NGA § 4 filing

for the recovery of GSR costs, FERC again refused to consider these

arguments. See Texas Eastern Transmission Corp., 63 FERC ¶ 61,254,

at 63,245-46 (1993). In Columbia Gas Transmission Corp., 64 FERC

¶ 61,365, at 63,588 (1993), FERC refused to consider certain GSR

cost arguments because they were "essentially a request for

rehearing of Order No. 636. There is no need to revisit these

arguments again. We deny rehearing." In ANR Pipeline Co., 64 FERC

¶ 61,140, at 62,083-84 (1993), FERC rejected arguments about GSR

costs "for the same reasons stated in Order No. 636-B."

Unlike the situation in Papago Tribal Utility Authority v.

FERC, 628 F.2d 235, 240 (D.C. Cir. 1980), where we found that FERC

might "resolve the claims of the parties and obviate any injury to

them if we allow it to complete its proceedings," FERC has

demonstrated that it does not plan to offer any significant

justifications for its treatment of GSR costs as outlined in the

Order No. 636 series other than those presented in the Order No.

636 series itself. We therefore hold that FERC's treatment of GSR

costs does not constitute an unreviewable general "policy

statement" but rather a final determination ripe for judicial

review. Because FERC continually relies on the Order No. 636

series' treatment of GSR costs, it is not reasonable to conclude

that a delay in review would permit better review of the issue.

The second part of the NIPSCO test asks whether delay in

review would cause significant hardship to the parties. Put

another way, the petitioners must show "a direct and immediate

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effect on their primary conduct." Tenneco Gas v. FERC, 969 F.2d

1187, 1211 (D.C. Cir. 1992). FERC admits that Order No. 636 GSR

costs as of February 7, 1996, totaled almost $1.7 billion without

interest, hardly an insignificant amount. In any case, it is

unlikely that FERC would have gone to such lengths to assure that

pipelines recover 100% of GSR costs if those costs were unlikely to

have an immediate effect on the conduct of the parties having to

pay them. Furthermore, to the extent that pipelines and gas

producers continue to renegotiate contracts, such negotiations will

undoubtedly be affected by FERC's treatment of GSR costs in the

Order No. 636 series (and in the individual restructuring

proceedings). We accordingly conclude that FERC's treatment of GSR

costs causes "a direct and immediate effect" on the petitioners'

primary conduct, and that the petitioners' claims are ripe for

review.

2. Gas producers' exemption from GSR costs

In the Order No. 636 series proceedings, petitioners presented

several alternative solutions to the transition cost problems, some

of which would have required that FERC abrogate existing

contractual obligations between pipelines and gas producers. These

alternative solutions would have forced gas producers to bear part

of the transition costs. FERC declined to adopt these proposals on

the grounds that, among other things, it lacked § 5 authority to

abrogate producer-pipeline contracts. Order No. 636-A, ¶ 30,950,

at 30,643. The Commission is correct that it lacks such authority.

We have already said as much in AGA II, 912 F.2d at 1505, where we

concluded that Congress unambiguously restricted FERC's § 5 powers

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to jurisdictional contracts. And FERC's jurisdiction over wellhead

contracts began to decline as soon as Congress eliminated such

jurisdiction over new wellhead contracts. See NGPA § 601(a)(1)(A),

(B), 15 U.S.C. § 3431(a)(1)(A), (B); Pennzoil Co. v. FERC, 645

F.2d 360, 380 (5th Cir. 1981). The PUCs' claims that FERC's

authority to regulate pipeline rates for the benefit of consumers

gives it implicit authority over nonjurisdictional contracts

crumble against the wall of the AGA II holding.

The PUCs also argue that, even if AGA II applies, FERC still

retained jurisdiction over some "old" gas contracts when it issued

Order No. 636 and that it should have used its § 5 authority to

reform those contracts. (In AGA II we recognized that FERC still

had jurisdiction over some wellhead contracts, noting that "[t]he

proportion of wellhead sales that is subject to FERC jurisdiction

steadily declines ... as old gas is exhausted." AGA II, 912 F.2d

at 1505.) But exercising such jurisdiction would have conflicted

with Congress' clear intent that FERC get out of the business of

regulating wellhead gas prices, making such an approach a

questionable vehicle for addressing the petitioners' concerns.

Furthermore, as FERC noted in Order No. 636-A, its jurisdiction

"over most producer/pipeline supply contracts has already been

removed under the NGPA. As of January 1, 1993, there will be no

remaining vestiges of such jurisdiction by virtue of the Decontrol

Act." Order No. 636-A, ¶ 30,950, at 30,643 n.460. In light of

these concerns, it would be unreasonable to conclude that FERC

should have reformed any producer-pipeline contracts to force

producers to bear part of the GSR costs. We accordingly decline to

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accept the petitioners' invitation to remand this issue to the

Commission.

3. Allocation of GSR costs among customer classes

Order No. 636 authorizes pipelines to recover their GSR costs

from all of their blanket-certificated transportation customers.

Petitioners contend that the Commission erred in allocating costs

to two specific classes of customers: customers that were not

directly responsible for GSR costs under Order No. 636 (i.e., those

that did not reduce their pipeline gas purchases in response to

mandatory unbundling); and interruptible transportation customers.

FERC defends its allocation of GSR costs based on the principles of

"cost spreading" and "value of service." It is there that we

begin.

a. "Cost spreading" and "value of service"

Order No. 500, the immediate successor to Order No. 436,

authorized pipelines to recover take-or-pay costs from both their

customers that were blanket certificated under the Commission's

open-access regime and customers that were individually

certificated under NGA § 7(c). The § 7(c) shippers objected that

they were merely transportation customers of pipelines, and were

therefore not in any way responsible for the fact that the

pipelines, in preparing to accommodate their anticipated sales

obligations, had incurred take-or-pay liabilities. According to

the § 7(c) shippers, the Commission's allocation of take-or-pay

costs therefore violated accepted principles of "cost causation,"

under which "[p]roperly designed rates should produce revenues from

each class of customers which match, as closely as practicable, the

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costs to serve each class or individual customer," Alabama Electric

Coop. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982) (citation and

internal quotation marks omitted).

The Commission conceded that its take-or-pay allocation could

not be sustained under a narrow view of cost causation. It argued,

however, that "circumstances surrounding the take-or-pay crisis and

the transformation of the pipeline industry necessitate and justify

the crafting of new ratemaking principles." K N Energy v. FERC,

968 F.2d 1295, 1301 (D.C. Cir. 1992). Specifically, the Commission

defended its policy on grounds of "cost spreading" and "value of

service":

Under this first notion, allocating take-or-pay costs to

transportation customers who admittedly may not have

directly caused them is acceptable because, in the

Commission's judgment, the extraordinary nature of this

problem requires the aid of the entire industry to solve

it; there are no other alternatives that would allow a

transition to a market-based pipeline industry to be

effectuated. Closely related to this rationale is FERC's

second: namely that all segments of the

industryincluding those who may not have caused

take-or-pay problemswill nonetheless ultimately benefit

from their resolution and the concomitant move toward an

open access regime; consequently, all segments can

rightly be assessed a portion of take-or-pay costs.

Id.

In K N Energy, we sustained the Commission's invocation of

"cost spreading" and "value of service," id. at 1302, though we

made clear that our approval of those principles was limited, see

id. ("A more searching inquiry may well prove necessary ... if the

Commission should attempt to adopt these ratemaking rationales

outside the take-or-pay context."). We did not, however, approve

of the Commission's conclusion that application of "cost spreading"

and "value of service" justified billing take-or-pay costs to §

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92 On remand, the Commission concluded that the application

of take-or-pay costs to § 7(c) customers was not justified. 

Williston Basin Interstate Pipeline Co., 63 FERC ¶ 61,171, at

62,175 (1993). 

7(c) customers. While the Commission contended that § 7(c)

customers benefitted from Order Nos. 436 and 500 through lower

transportation rates, the data before the court suggested that

those rates had in fact increased. Id. Moreover, the Commission's

Orders allocated costs to pipelines' remaining sales customers

inconsistently. Id. at 1303. We therefore remanded for further

consideration of the manner in which take-or-pay liabilities should

be applied to § 7(c) customers.92

In this case, the Commission contends that its assignment of

GSR costs to all blanket-certificated shippers was an appropriate

application of "cost spreading" and "value of service" principles.

b. Petitioners' challenges

1.) Limitation to bundled sales customers

The Industrial End-Users object to FERC's decision to allow

recovery of transition costs from all blanket-certificated

transportation customers, including those that were not pipeline

sales customers at the time of the implementation of Order No. 636.

The ground for their objection is straightforward: GSR costs arose

from the contracts between the pipelines and those firm sales

customers that they retained after Order No. 436, not from

contracts with customers that had previously converted under Order

No. 436. Specifically, Order No. 636 required firm sales customers

to convert their sales entitlements into firm transportation

entitlements. Some of those customers also exercised their option

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93 The same is true of § 7(c) individually certificated

shippers, which FERC exempted from paying GSR costs under Order

No. 636. The Industrial End-Users maintain that exempting § 7(c)

shippers but including all Part 284 shippers is arbitrary. As is

discussed in Part III.C.1, supra, however, FERC excluded § 7(c)

shippers both from the capacity release program and from paying

transition costs in order to equitably spread both the costs and

benefits of Order No. 636. 

94 The Small Distributors and Municipalities briefly make

the separate argument that the Commission's allocation of GSR

costs constitutes unlawful "retroactive ratemaking." They

contend that "many small customers had converted to

transportation prior to July 31, 1991 [the date of issuance for

the Order No. 636 Notice of Proposed Rulemaking] and were

therefore not on notice that they would be held responsible for

such pipeline gas supply costs when taking transportation service

prior to that date." Those customers, however, were on notice as

of July 31, 1991 that if they continued to receive open-access

transportation services, they would be responsible for paying GSR

costs that arose after that date. See Notice of Proposed

to reduce their pipeline gas purchases, leaving the pipelines with

excess sales capacity, purchase obligations, and related costs:

Indeed, nearly 65 percent of pipeline capacity was

committed to sales customers prior to Order 636 even

though pipelines' sales accounted for less than 20% of

deliveries by 1991. Transportation customers who had

earlier converted under Order 436 and 500 from sales

service to transportation service, or who had never been

pipeline sales customers, had already negotiated their

gas supply arrangements and had previously paid the cost

of restructuring prior to Order 636. Significantly,

nothing in Order 636 permits these transportation

customers to reform their supply or transportation

arrangements (or to pass on to others the associated

costs).

Industrial End-Users' Br. at 18 (emphasis in original). The

contracts of non-sales customers therefore did not directly give

rise to Order No. 636 GSR costs.93 The Industrial End-Users further

note that even if customers that had previously converted to firm

transportation service benefit from Order No. 636, the Commission

made no attempt to correlate the degree of that benefit with its

cost allocation decisions.94

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Rulemaking, [Current] F.E.R.C. Stats. & Regs. (CCH) ¶ 32,480, at

32,560 (1991). 

95 While the Commission suggests that in the restructuring

proceedings it may consider the manner in which the 10% is

collected, it apparently does not consider the 10% figure itself

open to negotiation. In three cases, the Commission has required

the allocation of 10% of GSR costs to interruptible

transportation cases based expressly on the ruling in Order No.

FERC's approach in Order No. 636, however, is valid under the

value-of-service and cost-spreading rationales approved by this

court in the K N Energy decision. Even those customers not

directly responsible for GSR costs benefit from the availability of

lower priced transportation in the unbundled marketplace.

Moreover, the Commission's options in spreading out costs to

pre-Order No. 636 firm sales customers are substantially limited by

the filed rate doctrine and the bar to retroactive ratemaking;

FERC simply cannot reach backwards through time in a truly

equitable manner. While the Industrial End-Users correctly note

that to date we have approved the Commission's departure from

traditional cost-causation principles in only limited

circumstances, those circumstances are squarely presented in this

case. GSR costs under Order No. 636 are the functional equivalent

of take-or-pay costs under Order No. 436, and "the Commission has

not betrayed its obligations to the NGA or precedent by employing

these ratemaking principles in its attempt to bring closure to the

take-or-pay drama," K N Energy, 968 F.2d at 1302.

2.) Interruptible transportation customers

The Industrial End-Users challenge the Commission's decision

to allocate 10% of a pipeline's GSR costs to interruptible

transportation customers.95 They contend that unbundling confers

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636-A. See Texas Gas Transmission Corp., 68 F.E.R.C. ¶ 61,118,

at 61,594 (1994); Florida Gas Transmission Co., 63 F.E.R.C. ¶

61,160, at 62,079 (1993); Southern Natural Gas Co., 62 F.E.R.C.

¶ 61,136, at 61,946 (1993). 

96 The Small Distributors and Municipalities also contend

that under the same principles GSR costs should be allocated to

gas producers. This point is discussed above, see supra Part

V.E.2. 

no real benefit on that class of customers, who therefore should

not be responsible for paying GSR costs. They further contend that

interruptible transportation customers in fact may receive inferior

service after Order No. 636 because the higher volume of firm

transportation expected to result under the Commission's capacity

release program may displace interruptible transportation services.

Moreover, given that less gas is transported by interruptible than

firm transportation, the GSR surcharges applied to interruptible

transportation in some cases may exceed those charges applied to

firm transportation.

The Small Distributors and Municipalities concur that FERC

should have better spread the costs of restructuring throughout the

industry, but take the contrary position that additional costs

should have been allocated to interruptible transportation.

Invoking "benefit of service" principles,96 the brunt of their claim

is a relatively complex economic analysis of why interruptible

transportation customers stand to gain a great deal under Order No.

636. In sum, their theory is that the customers who receive the

most benefit under Order No. 636 are those with elastic demands,

i.e., those most likely to use interruptible transportation.

Our concerns here mirror those in our review of the

application of take-or-pay costs to § 7(c) customers in K N Energy.

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The fact that interruptible transportation customers are part of

the "natural gas industry" is not, standing alone, sufficient to

assign them GSR costs; even the "cost spreading" and "value of

service" principles that we have approved allow for the imposition

of costs only upon those entities that either bear some

responsibility for the costs or derive some benefit from the

solution imposed. See K N Energy, 968 F.2d at 1302-04. We are

quite sensitive to the Commission's expert conclusion that

interruptible transportation customers do derive benefits from

unbundling under Order No. 636; 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. Moreover,

unlike our review of Order No. 500, we are not presented in this

case with evidence that the Commission's prediction of reduced

costs was wrong as a factual matter. 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.

More troubling, however, is the Commission's apparently

stringent adherence to the 10% figure in all instances. FERC

elected to allocate GSR costs to interruptible transportation (IT)

in response to claims by some pipelines that they would not be able

to recover all of their transition costs from firm customers alone.

It completely failed, however, to explain why it chose 10% rather

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than 5% or 15%, and why that 10% figure should be applied to every

pipeline; the Orders and FERC's brief simply do not attempt to

defend that figure whatsoever. For example, we are presented with

absolutely no explanation of why IT should contribute 10% of GSR

costs even on those pipelines on which IT constitutes less than 10%

of throughput. And, while the Commission correctly points out that

courts have recognized the inherent ambiguities in ratemaking, that

does not immunize an agency from engaging in reasoned

decisionmaking that is susceptible of appellate review. As we

explained in reviewing Order No. 500:

While we owe the Commission substantial deference in

matters predictive and economic, we cannot ignore the

Commission's unwillingness to address an important

challenge to its stated benefit rationale for charging

transportation customers. It most emphatically remains

the duty of this court to ensure that an agency engage

the arguments raised before itthat it conduct a process

of reasoned decisionmaking. The deference we owe FERC's

expert judgment does not strip us of that responsibility.

Indeed, ... we will uphold an agency's decision "if, but

only if, we can discern a reasoned path from the facts

and considerations before the [agency] to the decision it

reached."

Id. at 1303 (citations omitted) (second emphasis added).

In this instance, we cannot discern the Commission's path from

its view that interruptible transportation customers should bear

some of the burden for GSR costs to the conclusion that the share

should be 10%. Cf. WALT WHITMAN, LEAVES OF GRASS, Darest Thou Now O

Soul ("Darest thou now O soul, Walk out with me toward the unknown

region, Where neither ground is for the feet nor any path to

follow?"). And, while we are sympathetic to the Commission's view

that "[t]he task of determining fair allocations of transition

costs is ultimately thankless, even though [it] bring[s] all [its]

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97 In point of fact, there may be unique circumstances in

which it is simply impossible to attribute costs with anything

resembling mathematical accuracy. In such instances, however,

the Commission still must take the time to explain why that is

the case. 

experience and best judgment to bear on it," Order No. 636-B, ¶

61,272, at 62,034, the law requires more than simple guesswork.97

We therefore remand the issue to the Commission for further

consideration.

4. Pipelines' exemption from GSR costs

To this point, petitioners' objections to the distribution of

GSR costs have involved the allocation of those costs among groups

of pipeline transportation customers. As a separate matter,

petitioners forcefully contend that the Commission erred in not

requiring the pipelines themselves to absorb any GSR costs. They

note the remarkable similarities between Order No. 636 GSR costs

and Order No. 436 take-or-pay costs, and contend that the pipelines

should absorb GSR costs just as they do take-or-pay costs. While

we do not conclude that the Commission necessarily was required to

assign the pipelines responsibility for some portion of their GSR

costs, we do agree with petitioners that the Commission's stated

reasons for exempting the pipelines do not rise to the level of

"reasoned decisionmaking." We therefore remand the issue to the

Commission for further consideration.

Initially, we agree with petitioners that the Commission's

stated rationale for allocating take-or-pay costs to pipelines

substantially applies in the context of GSR costs as well. As we

explained above, see supra Part V.A, take-or-pay and GSR costs both

arise from the same provisions in producer-pipeline contracts and

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result from pipelines' former firm sales customers reducing their

gas purchases. We therefore find it instructive that in the

take-or-pay context, the Commission itself concluded that pipelines

should bear some of the burden, reasoning that

allowing a pipeline to recover 100 percent of its

settlement costs through a fixed charge would be

inconsistent with the Commission's holding in Order No.

500 that all segments of the natural gas industry should

share in the burden of resolving the take-or-pay problem,

since no single segment of the industry was to blame for

its take-or-pay problem.

Order No. 500-H, ¶ 30,867, at 31,575. In Order No. 636 as well,

the Commission acknowledged that GSR costs had arisen at least in

part due to the conduct of the pipelines, characterizing bundled

sales arrangements, which arose in substantial part from pipelines'

market power, as an unreasonable and unlawful restraint of trade.

Order No. 636, ¶ 30,939, at 30,405. Moreover, according to the

Commission, the pipelines benefit from Order No. 636, in that they

"will presumably receive more favorable prices or other valuable

consideration resulting from contract reformation." Order No. 636-

A, ¶ 30,950, at 30,643; cf. id. at 30,642 ("[Petitioners]

generally allege that since Order No. 636 will benefit all segments

of the gas industry, all segments should bear the costs. The

Commission believes that the benefits of Order No. 636 indeed will

be widespread.").

The Commission nevertheless puts forward a wide variety of

arguments for exempting pipelines from paying GSR costs, which we

will address on the merits seriatim. We begin, however, by noting

that, as a general matter, the Commission's arguments seem directed

toward proving the wrong point. FERC allocated Order No. 636 GSR

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98 Of course, there may be a world of difference between

what the Commission views as pipelines' legal entitlement to

recover GSR costs by charging their remaining sales customers

higher prices and the pipelines' economic ability to do so in the

marketplace. See supra at 123 (discussing possibility of

pipelines' "death spiral" of higher prices and smaller customer

base). 

costs to customers based on the principles of "cost spreading" and

"value of service" discussed above, see supra Part V.E.3.a. When

it exempted the pipelines from those costs, however, the Commission

reverted to traditional concepts of "cost causation," or to use its

characterization, "returned to first principles holding that a

utility is entitled to the opportunity to recover all of its

prudently incurred costs in providing public service."98 It is

important to emphasize that these are competing models for

allocating the industry's costs of service. "Cost causation"

correlates costs with those customers for whom a service is

rendered or a cost is incurred. For example, as we noted above,

see supra Part V.E.3.b.1, the Industrial End-Users argue that under

a cost causation model, the only customers who should be required

to pay GSR costs are those that reduced their pipeline gas

purchases in response to Order No. 636. "Cost spreading" and

"value of service," in contrast, take a much wider view, assigning

the costs of service to those classes of industry participants that

either are at fault for the take-or-pay dilemma or benefit from its

resolution. Applying these latter principles, we sustained the

Commission's determination that GSR costs should be paid by all

blanket-certificated transportation customers, even those that did

not directly cause the pipelines to incur liabilities under their

supply contracts. See supra Part V.E.3.b.1.

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99 For example, the Commission may conclude that

responsibility for GSR costs would cause such harm to a

particular segment of the industry as to raise substantial

concerns about its economic health. In this case, FERC contended

that it exempted pipelines from paying GSR costs because of the

pipelines' precarious financial position. The Commission never

articulated that rationale in the proceedings below, however, and

we therefore do not consider it. See Burlington Truck Lines v.

United States, 371 U.S. 156, 168-69 (1962). The issue remains

open for further consideration on remand. 

100 This applies, of course, only to those entities over

which the Commission may lawfully exercise jurisdiction. See

supra Part III.B. 

If the Commission intends to assign GSR costs according to

these "cost spreading" and "value of service" principles, it must

do so consistently or explain the rationale for proceeding in

another manner.99 We approved the invocation of those principles

in K N Energy because FERC had concluded that the take-or-pay

crisis could be resolved only by spreading costs throughout the

"entire industry," 968 F.2d at 1301 (emphasis added), and because

we recognized that "all segments of the industry ... will benefit,"

id. (emphasis added), from restructuring. Cf. Order No. 636-A, ¶

30,950, at 30,650 ("[I]n the Commission's judgment, [Order No. 636]

continues the general goal of spreading the costs of industry

restructuring.").100 The Commission therefore cannot, without

explanation, burden blanket-certificated transportation customers

on the ground that they will benefit from Order No. 636, and then

ignore that same factor as it relates to the pipelines. For

example, the fact that both pipelines and customers will benefit

from expanded open-access transportation is one argument in favor

of applying GSR costs to both. On the other hand, it is not

particularly relevant that GSR costs will total only approximately

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$1.7 billion, while take-or-pay costs were $10 billion, for that

proves nothing about the relative responsibility of various

segments of the industry for those costs. On the same footing is

the Commission's recognition that pipelines have already paid $3.6

billion in take-or-pay costs; petitioners are quite right when

they note that consumers have in the end paid nearly twice that

amount. The relevant question is instead whether the $3.6 billion

dollar figure should be even largerrecognizing that the figure for

consumers is sure to growbecause the pipelines are in part

responsible for GSR costs and will benefit from Order No. 636.

This is not to say, however, that it is impossible, or even

improbable, that the Commission on remand can establish a

convincing rationale for exempting the pipelines. For example,

arguably, the pipelines' contribution to the costs of the

industry's transition has already been so disproportionately large

vis-a-vis consumers that they are entitled to be excused from

further responsibility. It also may be 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. Such issues,

however, require a fuller airing in the administrative proceedings

on remand than is evident from the record developed in the initial

go-round.

Two final arguments raised by the Commission merit separate

attention. First, it notes that unbundling under Order No. 436 was

voluntary while under Order No. 636 it is mandatory. It is unclear

in the Order No. 636 series, however, how the "voluntariness" of

the reduction in pipeline gas purchases correlates with the

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101 Order No. 636 subjects GSR charges to the same form of

prudence review generally applied to pipeline billings. Thus,

customers have the burden of proving any claim they might press

that particular GSR charges were not prudently incurred. Order

No. 636-B, ¶ 61,272, at 62,039. Petitioners challenge the

Commission's conclusion that "the possibility of having to defend

the incurrence of [GSR] costs, and suffer disallowance of

recovery, should provide sufficient incentive for pipeline

diligence in minimizing these costs," Order No. 636, ¶ 30,939, at

30,461. Prudence review, however, is a well-settled practice,

pipelines' responsibility for the resulting costs. The fact that

certain pipelines made an economic choice to convert to open-access

transportation and thereby almost certainly incur take-or-pay costs

under Order No. 436 does not make other pipelines less responsible

for the same type of costs when the Commission ultimately decided

that it had to force the final stages of industry restructuring.

Moreover, we rejected that very distinction when we vacated Order

No. 436:

FERC also alludes to the "voluntary" character of

pipeline provision of Order No. 436 transportation.

There are two flaws in this. First, refusal of the

option may spell bankruptcy: inability to provide

blanket-certificate transportation for fuel-switchable

users may in current market circumstances cause critical

load loss....

Second, the argument obscures distinctions between

pipelines in the aggregate and alone. To be sure, Order

No. 436 gives pipelines an option, blanket-certificate

transportation, which ... is not available outside of

Order No. 436. But as soon as a single pipeline finds it

attractive enough to accept, each competing pipeline will

come under competitive pressure to match the first's

flexibility.

AGD I, 824 F.2d at 1024.

The Commission also notes that under Order No. 500, but not

Order No. 636, those pipelines that paid take-or-pay costs received

a heightened presumption that those liabilities were prudently

incurred.101 As with "voluntariness," however, the Order No. 636

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and petitioners have offered no particular reason for disallowing

its use in this context. In point of fact, petitioners'

complaint in large part seems to be that the Commission's

application of its prudence standards is too lax, not that the

use of prudence review is per se unlawful. See id. at 26 (citing

Columbia Gas Trans. Corp., 26 F.E.R.C. ¶ 61,034, on reh'g, 26

F.E.R.C. ¶ 61,334 (1984); Texas Gas Trans. Corp., 48 F.E.R.C. ¶

61,266 (1986), as examples of inadequate prudence review). We do

not foreclose such claims from being raised in any petition for

review of a ruling by the Commission that a pipeline's GSR costs

were prudently incurred. The same holds true for petitioners'

claim that the Commission will fail to distinguish correctly

between Order No. 636 GSR costs and charges that pipelines should

properly recover as Order No. 436 take-or-pay costs. We may

review the question when properly presented with a ruling by the

Commission on particular GSR costs. 

series does not explain how the presumption of prudence correlates

with FERC's cost-spreading and value-of-service rationales. The

Orders' differing treatment of prudence stems from the fact that

Order No. 500 and its successors allowed pipelines to recover some,

but not all, of their take-or-pay liabilities through a fixed

charge on transportation if and only if they absorbed some of those

costs themselves. The presumption of prudence created an incentive

for the pipelines to engage in cost absorption in that it reduced

expenses they might later incur in litigating the appropriateness

of their take-or-pay liabilities. Order No. 636 needs no such

incentive because pipelines can directly bill transportation

customers for 100% of GSR costs, an option that was never available

under Order No. 500. And, of course, were the Commission on remand

to assign some proportion of GSR costs to pipelines, it could apply

the same presumption of prudence that it used in the take-or-pay

context.

In sum, we cannot conclude from the record now before us that

the Commission's decision to exempt pipelines completely from

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paying GSR costs was the product of reasoned decisionmaking. 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. In addressing pipelines' liability for GSR

costs, however, the Commission at the very least undervalued those

considerations. We leave it to the Commission on remand to

consider whether the pipelines should nonetheless continue to be

exempted from such costs in light of the factors we have

identified.

F. Conclusion

With respect to stranded costs, we hold that FERC's

interpretation of the used and useful doctrine is supported by

substantial evidence. We reject petitioners' argument that FERC

inadequately addressed the LDC bypass issue, and we also reject

petitioners' challenges to the volumetric surcharge for

above-market Great Plains gas.

Turning to GSR costs, we first conclude that petitioners'

challenges are ripe for review. Next, we hold that FERC did not

err by failing to exercise its NGA § 5 authority so as to force gas

producers to bear part of the transition costs. Furthermore, we

sustain the Commission's application of GSR costs to the full range

of blanket-certificated transportation customers. We remand the

case to the Commission, however, for further consideration of the

appropriate share of those costs to be paid by interruptible

transportation customers and the gas pipelines.

VI. Conclusion

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In its broad contours and in most of its specifics, we uphold

Order No. 636. However, we remand certain aspects of Order No.

636, which we now recount, to the Commission for further

explanation. With regard to no-notice transportation service, we

remand for the Commission to explain why it restricted entitlement

to receive no-notice service to those customers who received

bundled firm-sales service on May 18, 1992. We remand the

right-of-first-refusal mechanism for the Commission to explain why

it adopted a twenty-year term-matching cap. Two aspects of the SFV

mitigation measures require further explanation: first, the

decision to require initial mitigation measures, such as seasonal

contract adjustments, on the basis of the effect of switching to

SFV on individual customers, whereas the four-year phase-in

mitigation measure is determined by the effect on customer classes;

and second, the decision that former customers of downstream

pipelines are ineligible for small-customer rates. Finally, with

regard to the recovery of GSR costs, we remand for an explanation

of why, in light of the equitable-sharing procedures in Order No.

500 and the general cost-spreading principles of Order No. 636,

pipelines can pass through all their GSR costs to customers, and

also for an explanation of why the Commission decided, in

allocating costs among customers, that interruptible-transportation

customers should bear 10% of GSR costs.

Until the Commission takes final action on remand, however, we

leave these measures in place as currently formulated. See A.L.

Pharma, Inc. v. Shalala, 62 F.3d 1484, 1492 (D.C. Cir. 1995);

Checkosky v. SEC, 23 F.3d 452, 462-65 (D.C. Cir. 1994) (opinion of

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Silberman, J.); cf. AGA I, 888 F.2d at 153 (stating that the

Commission must promptly provide a reasoned explanation).

It is so ordered.

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