Appendix — City of Willcox v. Federal Energy Regulatory Commission
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IN THE eal
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Supreme Court of the Gnited States
OCTOBER TERM, 1990
City oF WILLCOX, ARIZONA,
ARIZONA ELECTRIC POWER COOPERATIVE, INC.,
CONSOLIDATED EDISON COMPANY OF NEw York, INC.,
and AMERICAN PUBLIC GAS ASSOCIATION,
Petitioners,
Ms
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent.
APPENDICES TO
PETITION FOR WRIT OF CERTIORARI
TO THE
UNITED STATES COURT OF APPEALS
FOR THE DISTRICT OF COLUMBIA CIRCUIT
*ARNOLD D. BERKELEY
RICHARD I. CHAIFETZ
HowARD L. NELSON
BERKELEY, CHAIFETZ & NELSON
Suite 360
1819 H Street, N.W.
Washington, D.C. 20006
(202) 785-0611
Counsel for City of Willcox, Arizona
and Arizona Electric Power
Cooperative, Inc.
* Counsel of Record
November 21, 1990
[Additional Counsel Listed on Inside Front Cover]
PRESS OF BYRON S. ADAMS, WASHINGTON, D.C. (202) 347-8203
«4
WILLIAM T. MILLER
Susan N. KELLY
MILLER, BALIS, & O’NEIL, P.C.
1101 14th Street, N.W.
Suite 1400
Washington, D.C. 20005
(202) 789-7573
Counsel for American Public
Gas Association
BARBARA M. GUNTHER
Assistant General Counsel
CONSOLIDATED EDISON COMPANY
OF NEw YorK, INC.
4 Irving Place
Room 1815-S
New York, NY 10003
(212) 460-4917
Attorneys for Consolidated Edison
Company of New York, Inc.
WILLIAM I. HARKAWAY
HarRVEY L. REITER
McCarRTHY, SWEENEY, & HARKAWAY
1750 Pennsylvania Avenue, N.W.
Washington, D.C. 20006
(202) 393-5710
Attorneys on Behalf of Consolidated
Edison Company of New York, Inc.
i
TABLE OF CONTENTS
Page
Appendix A
American Gas Association et al. v. FERC, 912
RR RR All la
Appendix B
Order 500-H, 54 Fed. Reg. 52,344 (Dec. 21, 1989),
III FERC Stats. & Regs. (CCH) 430,867
IIE cinta thctnibadioWinnichsaseiicbtiseldeicunicbenst ee. 47a
Appendix C
Order No. 500-I, 55 Fed. Reg. 6,605 (Feb. 26,
1990), III FERC Stats. & Regs. (CCH) 430,880
NI Slack nich nen ccoenincoubties Caine ccbamtiacsiasteas dee ctexadacs 231la
Appendix D
Natural Gas Act of 1938, 15 U.S.C. §717, et
en sidirnoivisindsinehecaibavnicaneininintniinaentdinnianceinannaeens 345a
ly Be Res ET MID bviviicsencccancteversicecesissens 345a
§7, 15 U.S.C. §717f (1984 & Supp. 1990) .......... 346a
Appendix E
SN I ETT ios ccastcicsanasckdoaseaekandacdineainwan 35la
Fe We IIE © sci vsiiinessrnecsincseaiceondctempicicieocadions 353a
la
APPENDIX A
Opinion of the Court Below
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued May 8, 1990 Decided August 24, 1990
No. 87-1588
AMERICAN Gas ASSOCIATION, PETITIONER
Vv.
FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT
THE INDEPENDENT OIL & Gas ASSOCIATION,
NORTHWEST PIPELINE CORPORATION,
EL Paso NATURAL Gas Company,
Bay STATE Gas ComMPANY, et al.,
TENNECO OIL COMPANY,
APACHE CORPORATION,
THE PENNSYLVANIA PUBLIC UTILITY COMMISSION,
_CiTy OF ALBANY, et al.,
C.G. TRANSMISSION COMPANY, et al.,
PUBLIC GERVICE COMMISSION OF THE STATE OF NEW YORK,
MOoBIL NATURAL Gas INc.,
Conoco INc.,
INTERVENORS
2a
Petitions for Review of an Order of the
Federal Energy Regulatory Commission
Raymond N. Shibley, with whom the following were on
the joint brief for pipeline petitioners in 87-1588, et al.:
Frank R. Lindh, John A. Sieger, and Judy M. Johnson for
Panhandle Eastern Pipe Line Company and Trunkline
Gas Company; John H. Cheatham, III for Interstate Natu-
ral Gas Association of America, Inc.; Paul E. Goldstein
and Paul W. Mallory for Natural Gas Pipeline Company
of America; Robert H. Benna and Terrence J. Collins for
Tennessee Gas Pipeline Company; Michael R. Waller for
United Gas Pipe Line Company; Michael E. Small for
Williams Natural Gas Company; Daniel F. Collins and
William W. Brackett for ANR Pipeline Company and Col-
orado Interstate Pipeline Company; William B. Grealis
and Deborah A. MacDonald for Transwestern Pipeline
Company; and Stephen L. Huntoon for Williston Basin
Interstate Pipeline Company.
Jennifer N. Waters, with whom the following were on
the joint brief for petitioner state commission, distribu-
tion companies, and related agencies in 87-1588, et al.:
Frederick Moring and Toni M. Fine for Associated Gas
Distributors; William T. Miller and Susan N. Kelly for
American Public Gas Association; Roberta L. Halladay,
Marilyn A. Specht, and C. William Cooper for United Dis-
tribution Companies; Richard A. Solomon and David
D'Alessandro for Public Service Commission, State of
New York; Lynne H. Church and Robert Fleishman for
Baltimore Gas and Electric Company; Robert B. Langstaff
for Board of Water Gas and Light Commissioners,
Albany, Georgia; William I. Harkaway, Harvey L. Reiter,
Barbara M. Gunther, and Martin J. Bregman for Consoli-
dated Edison Company of New York, The Kansas Power
and Light Company, Kansas Public Service, Missouri
Public Service, and Peoples Natural Gas Company.
Harvey L. Reiter, with whom the following were on the
joint brief for petitioner distributors, consumers, end-
3a
users, and certain producers in 87-1588, et al.: William I.
Harkaway and Barbara M Gunther for Consolidated Edi-
son Company of New York, Inc., et al.; John K. Rosenberg
and Martin J. Bregman for The Kansas Power and Light
Company; William T. Miller and Susan N. Kelly for Amer-
ican Public Gas Association; Joel L. Greene and Barbara
S. Yost for Apache Powder Company, et al.; Frederick
Moring, Jennifer N. Waters, and Toni M. Fine for Associ-
ated Gas Distributors; Joseph P. Stevens for The Brook-
lyn Union Gas Company; Donald K. Dankner and Fred J.
Killion for Central Hudson Gas and Electric Corporation,
et al.; Arnold D. Berkeley, Richard I. Chaifetz, and Howard
L. Nelson for City of Willcox, Arizona and Arizona Elec-
tric Power Cooperative, Inc.; Jennifer N. Waters, Toni M.
Fine, and Kenneth J. Neises for Laclede Gas Company;
Jeffrey M. Petrach and Daniel L. Schiffer for Michigan
Consolidated Gas Company; David I. Bloom for Northern
Illinois Gas Company; Margaret Ann Samuels for Office
of the Consumers’ Counsel, State of Ohio; Edward B.
Myers for Orange and Rockland Utilities, Inc.; Edward J.
Grenier, Jr. and William H. Penniman for Process Gas
Consumers Group, et al.; Stephen F. Greenwald, Lindsey
How-Downing, and Patrick G. Golden for Pacific Gas and
Electric Company; Thomas M. Patrick and Karen Lee for
the Peoples Gas Light & Coke Company and North Shore
Gas Company; Lawrence F. Barth and Veronica A. Smith
for The Pennsylvania Public Utilities Commission;
Richard A. Solemon and David D’Alessandro for The Pub-
lic Service Commision, State of New York; Janice E. Kerr,
Michael B. Day, Edward W. O’Neill, and Harvey Y. Morris
for The Public Utilities Commission of the State of Cali-
fornia; E.R. Island and David L. Huard for Southern Cali-
fornia Gas Company; Robert J. Haggerty, Dandrea Lynn
Miller, and Robert B. Rice for Southern Union Gas Com-
pany; William I. Harkaway for Southwest Gas
Corporation; Frank J. Kelley, Louis J. Caruso, Don L.
Keskey, Henry J. Boynton, Patricia S. Barone, Ronald D.
Eastman, Lynda S. Mounts, and Joel Kaufman for The
State of Michigan and Michigan Public Service Commis-
4a
sion; Frederick Moring, Jennifer N. Waters, and Toni M.
Fine for United Cities Gas Company; Roberta L. Halladay,
Marilyn A. Specht, and C. William Cooper for United Dis-
tribution Companies.
Thomas G. Johnson, with whom the following were on
the joint brief for producer petitioners in 87-1588, et al.:
Charles J. McClees, Jr. and James A. Ruoff for Shell Off-
shore Inc. and Shell Western E&P Inc.; Jack M. Wilhelm
for Amoco Production Company; R. Gordon Gooch for
Anadarko Petroleum Company; Richard G. Morgan for
Apache Corporation; Harris S. Wood and Kathleen E.
Magruder for Arco Oil and Gas Company; Gerald P. Thur-
mond and David J. Evans for Chevron U.S.A. Inc.; Ernest
J. Altegelt, II] for Conoco, Inc.; C. Roger Hoffman and
D.W. Rasch for Exxon Corporation; Toni D. Hennike and
Gerald M. Bendo for Hunt Oil Company; John J. Akins
for Kerr-McGee Corporation; Robert C. Murray for Mara-
thon Oil Company; Paul F. O’Konski and Randolph C.
Bruton for Mitchell Energy Corporation; Jay G. Martin
for Mobil Natural Gas Inc. and Mobil Oil Exploration &
Producing Southeast Inc.; Michael L. Pate for OXY USA
Inc.; John B. Chapman, Sylvia McCormack, and John K.
McDonald for Pennzoil Company; Larry Pain and Luke A.
Mickum for Phillips Petroleum Company and Phillips 66
Natural Gas Company; Ronald D. Hurst for Placid Oil
Company; John Wolfe for Rosewood Resources, Inc.;
Ralph J. Pearson, Jr. for Texaco Inc.; Kenneth L. Ried-
man, dr. for Union Oil Company of California; Kerry R.
Brittain for Union Pacific Resources Company; and
Timothy J. Jacquet for Union Texas Petroleum Corpora-
tion.
William W. Brackett, with whom the following were on
the joint brief for pipeline petitioners in 87-1588, et al.:
Daniel F. Collins for ANR Pipeline Company and Colo-
rado Interstate Gas Company; William G. von Glahn,
Lewis A. Posekany, J. Diana Hall, and Michael E. Small
for Williams Natural Gas Company; Michael R. Waller
and Jacob M. Hiatt for United Gas Pipeline Company;
5a
Deborah A. MacDonald, Rockford G. Meyer, and William
J. Grealis for Transwestern Pipeline Company.
Timothy N. Black, with whom the following were on the
joint brief for certain petitioners and intervenors in oppo
sition to continued use of disallowed deficiency-based allo-
cation mechanism for take-or-pay passthrough in 87-1588,
et al.: John H. Pickering, Stephen J. Small, and Mark D.
Clark for Columbia Gas Transmission Corporation; Lynne
H. Church, Robert Fleishman, and Jeffrey D. Watkiss for
Baltimore Gas and Electric Company; Roger C. Post and
Jack L. Shailer for Columbia Gas Distribution Companies;
Stephen E. Williams, Kevin J. Lipson, John E. Holtzinger,
and Charles C. Thebaud, Jr. for CNG Transmission Cor-
poration; Paul S. Buckley for Maryland People’s Counsel;
Jeffrey M. Petrach for Michigan Consolidated Gas Com-
pany; Margaret Ann Samuels for Office of the Consumers’
Counsel, State of Ohio; Lindsey How-Downing, Merek E.
Lipson, and Patrick G. Golden for Pacific Gas and Electric
Company; and Christopher J. Barr for UGI Corporation.
Charles F. Wheatley, Jr. and Philip B. Malter were on
the brief for petitioner The National Association of Gas
Consumers.
Arnold D. Berkeley was on the brief for petitioners The
City of Willcox, Arizona and Arizona Electric Power
Cooperative, Inc.
Jeffrey M. Petrach for Michigan Consolidated Gas
Company; Frederick Moring, Jennifer N. Waters, and Toni
M. Fine for Associated Gas Distributors; Robert Fleishman
for Baltimore Gas and Electric Company; Margaret Ann
Samuels for Office of Consumers’ Counsel, State of Ohio;
Kenneth J. Neises for Laclede Gas Company; John M.
Glynn for Maryland People’s Counsel; Glenn W. Letham
and Kenneth M. Albert for Memphis Light, Gas and
Water Division, City of Memphis, Tennessee; Frank J.
Kelley, Louis J. Caruso, Don L. Keskey, Henry J. Boynton,
Patricia S. Barone, Ronald D. Eastman, Lynda S. Mounts,
and Joel Kaufman for the State of Michigan and Michigan
Public Service Commission; and David L. Bloom for
6a
Northern Illinois Gas Company also were on the joint
brief for petitioners concerning contract demand reduc-
tion in 87-1588, et al.
Richard C. Green, Donald J. Maclver, Jr., Richard Qwen
Baish, Scott D. Fobes, and T. Rush Moody, dr. entered
appearances for petitioner E] Paso Natural Gas Company
in 87-1588, et al.
Robert Y. Hirasuna entered an appearance for peti-
tioner Hadson Gas Systems, Inc.
Jerome M. Feit, Solicitor, Federal Energy Regulatory
Commission, with whom William S. Scherman, General .
Counsel, Dwight C. Alpern and Jill Hall, Attorneys, Fed-
eral Energy Regulatory Commission, were on the brief, for
respondent in 87-1588, et al. John Estes and Joseph
Davies, Attorneys, Federal Energy Regulatory Commis-
sion, also entered appearances for respondent.
Edward J. Grenier, Jr., with whom the following were
on the joint brief of intervenor industrial end user groups,
state commissions, and consumer advocates in 87-1588, et
al.: William H. Penniman, Glen S. Howard, and Sterling
H. Smith for Process Gas Consumers Group, et al.; Paul
S. Buckley for Maryland People’s Counsel; Ronald D.
Eastman, Lynda S. Mounts, and Joel Kaufman for The
State of Michigan and Michigan Public Service Commis-
sion; Margaret Ann Samuels for Office of the Consumers’
Counsel, State of Ohio; Janice E. Kerr, Michael B. Day,
Edward W. O’Neill, and Harvey Y. Morris for The Public
Utilities Commission of the State of Californie; Richard
A. Solomon and David D'Alessandro for The Public Ser-
vice Commission, State of New York; Robert F. Shapiro,
Thomas E. Hirsch, III, and Gregory D. Chafee for Ameri-
can Paper Institute, Inc.; Lawrence F. Barth and Veronica
A. Smith for The Pennsylvania Public Utilities Commis-
sion.
John H. Cheatham, III for Interstate Natural Gas Asso-
ciation of America, Inc.; Raymond N. Shibley, Frank R.
Lindh, and John A. Siegar for Panhandle Eastern Pipe
7a
Line Company and Trunkline Gas Company; Paul E.
Goldstein and Paul W. Mallory for Natural Gas Pipeline
Company of America; Robert H. Benna and Terrence J.
Collins for Tennessee Gas Pipeline Company; Michael R.
Waller for United Gas Pipe Line Company; Daniel F. Col-
lins and William W. Brackett for ANR Pipeline Company
and Colorado Interstate Pipeline Company; William B.
Grealis and Deborah A. MacDonald for Transwestern
Pipeline Company; and Stepher. L. Huntoon for Williston
Basin Interstate Pipeline Company were also on the joint
brief for pipeline intervenors in 87-1588, et al.
Frederick Moring, Jennifer N. Waters, and Toni M. Fine
for Associated Gas Distributors; William T. Miller and
Susan N. Kelly for American Public Gas Association;
Richard A. Solomon and David D’Alessandro for Public
Service Commission, State of New York; Robert Fleishman
for Baltimore Gas and Electric Company; John W. Glen-
dening, Jr. and Barbara K. Keffernan for the Berkshire
Gas Company, et al.; Robert B. Langstaff for Board of
Water Gas and Light Commissioners, Albany, Georgia;
William I. Harkaway, Harvey L. Reiter, Barbara M.
Gunther, and Martin J. Bregman for Consolidated Edison
Company of New York, The Kansas Power and Light
Company, Kansas Public Service, Missouri Public Service,
and Peoples Natural Gas Company; Jennifer N. Waters,
Toni M. Fine, and Kenneth J. Neises for Laclede Gas
Company; James F. Bowe, Jr. and O. Julia Weller for Long
Island Lighting Company; Glenn W. Letham and Kenneth
M. Albert for Memphis Light Gas and Water Division,
City of Memphis, Tennessee; Jeffrey M. Petrash and
Daniel L. Schiffer for Michigan Consolidated Gas Com-
pany; Frank J. Kelley, Louis J. Caruso, Don L. Keskey,
Henry J. Boynton, Patricia S. Barone, Ronald D. Eastman,
Lynda S. Mounts, and Joel Kaufman for The State of
Michigan and Michigan Public Service Commission;
Charles F. Wheatley, Jr. for National Association of Gas
Consumers; Harry H. Voight and M. Reamy Ancarrow for
Niagara Mohawk Power Corporation; David J. Bloom for
Northern Illinois Gas Company; William A. Spratley and
8a
Margaret Ann Samuels for Office of the Consumers’ Coun-
sel, State of Ohio; Thomas M. Patrick, Mark J. McGuire,
and Karen Lee for The Peoples Gas Light & Coke Com-
pany and North Shore Gas Company; Lawrence F. Barth
and Veronica A. Smith for the Pennsylvania Public Utility
Commission; William R. Hoatson and James R. Lacey for
Public Service Electric & Gas Company; Janice E. Kerr
and Harvey Y. Morris for the Public Utilities Commission
of the State of California; Frank H. Stricklker, Gordon M.
Grant, and Ralph E. Fisher for Washington Gas Light
Company were also on the joint brief for intervenors local
distribution companies, state commissions, and related
agencies in 87-1588, et al.
Charles J. McClees, Jr., James A. Ruoff, and Thomas G.
Johnson for Shell Offshore Inc. and Shell Western E&P
Inc.; Jack M. Wilhelm for Amoco Production Company;
R. Gordon Gooch and F. Nan Wagoner for Anadarko
Petroleum Company; Richard G. Morgan for Apache Cor-
poration; Harris S. Wood and Kathleen E. Magruder for
Arco Oil and Gas Company; David J. Evans for Chevron
U.S.A. Inc.; Ernest J. Altgelt, III for Conoco, Inc.; C. Roger
Hoffman and D.W. Rasch for Exxon Corporation; Toni D.
Hennike and Gerald M. Bendo for Hunt Oil Company;
John J. Akins for Kerr-McGee Corporation; Robert C.
Murray for Marathon Oil Company; R. Brent Harshman
for Maxus Energy Corporation; Randolph C. Bruton for
Mitchell Energy Corporation; Jay G. Martin for Mobil
Natural Gas Inc. and Mobil Oil Exploration & Producing
Southeast Inc.; Michael L. Pate for OXY USA Inc.; John
B. Chapman, Sylvia McCormack, and John K. McDonald
for Pennzoil Company; Larry Pain and Luke A. Mickum
for Phillips Petroleum Company and Phillips 66 Natural
Gas Company; Ronald D. Hurst for Placid Oil Company;
John Wolfe for Rosewood Resources, Inc.; Ralph J. Pear-
son, Jr. for Texaco Inc.; Kenneth L. Riedman, dr. for
Union Oil Company of California; Kerry R. Brittain for
Union Pacific Resources Company; and Timothy J. dac-
quet for Union Texas Petroleum Corporation also were on
the joint brief for intervenors producers and the State of
Louisiana in 87-1588, et al.
9a
Charles F. Wheatley, Jr. and Philip B. Malter also were
on the brief for intervenor The National Association of
Gas Consumers.
David I. Bloom and Evan M. Tager for Northern Illinois
Gas Company; Frederick Moring, Jennifer N. Waters, and
Toni M. Fine for Associated Gas Distributors; Harry H.
Voight and M. Reamy Ancarrow for Niagara Mohawk
Power Corporation; Edward B. Myers for Orange and
Rockland Utilities, Inc.; Thomas M. Patrick for The Peo-
ples Gas Light and Coke Company and North Shore Gas
Company; Lindsay How-Downing for Pacific Gas and
Electric Company; E.R. Island and David L. Huard for
Southern California Gas Company; Jennifer N. Waters
and Toni M. Fine for United Cities Gas Company also
were on the joint brief for intervenors Northern Illincis
Gas Company, et al. in 87-1588, et al.
Robert C. Platt and Mark K. Seifert entered appearances
for intervenor Independent Petroleum Association of
America.
Ivy Lincoln entered an appearance for intervenor The
Arkansas Public Service Commission.
Richard C. Green also entered an appearance for inter-
venor El Paso Natural Gas Company.
Christopher K. Sandberg and Dennis D. Ahlers entered
appearances for intervenor Energy Issues Intervention
Office of the Minnesota Department of Public Service.
Norma K. Scogin and Sarah F. Miller entered appear-
ances for intervenor Railroad Commission of Texas.
Ralph E. Simon, Jr. entered an appearance for interve-
nor Transok, Inc.
Luis M. Guzman entered an appearance for intervenor
Valero Transmission, L.P.
M. Frazier King, Jr. entered an appearance for interve-
nor Valero Interstate Transmission Company.
10a
R. David Henrickson and Donna J. Bailey entered
appearances for intervenor Southern Natural Gas Com-
pany.
Stephen A. Herman entered an appearance for interve-
nor The Fertilizer Institute.
(
Patricia A. Curran entered an appearance for intervenor
Cabot Corporation.
Jerry M. Amos entered an appearance for intervenor
Piedmont Natural Gas Company.
Charles H. Shoneman entered an appearance for inter-
venor The Independent Oil & Gas Association of West
Virginia. :
John W. Glendening, Jr. and Bruce B. Glendening
entered appearances for intervenor Bay State Gas Com-
pany, et al.
Phyllis G. Rainey entered an appearance for intervenor
Tenneco Oil Company.
Michael J. Manning, James F. Moriarty, and James P.
White entered appearances for intervenor The Tennessee
Small General Service Customer Group.
James T. Bailey, Platt W. Davis, III, and David T.
Andril entered appearances for intervenor Arkla Energy
Resources.
Robert Y. Hirasuna entered an appearance for interve-
nor The State of Louisiana.
Charles M. Darling, Stephen L. Teichler, and Sheryl S.
Hendrickson entered appearances for intervenor Ashland
Exploration, Inc.
C. Burnett Dunn and William I. Harkaway entered
appearances for intervenor ONG Transmission Company,
et al.
David P. Yaffe entered an appearance for intervenor
Citizens Energy Corporation, et al.
lla
George L. Weber entered an appearance for intervenor
National Fuel Gas Supply Corporation.
John E. Holtzinger, Jr. and Jacolyn A. Simmons entered
appearances for intervenor Atlanta Gas Light Company.
F. Nan Wasgoner, Gordon Gooch, and Katherine B.
Edwards also entered appearances for intervenor Union
Texas Petroleum Corporation.
Before: WiLuiams, D.H. Ginspurc and SENTELLE, Circuit
Judges. ,
Opinion for the Court filed by Circuit Judge WILLIAMS.
WILLIAMS, Circuit Judge:
Table of Contents
be MI k.............. 12
II. Inaction under Section 5....................... 14
WM, eee... ........................ 14
eo mL 15
1. Absence of power over nonjurisdictional
ee occ cee cue eccece. 16
em... ......... ae 20
3. Comparative advantages of individual settle-
ment negotiations ......................... 22
III. Crediting Mechanism .......................... 25
A. Producer Claims that Crediting is No Longer
Needed and Pipeline Claims to a Broader Weapon
Mg Pees. ............................ 25
B. Panhandle/Northern Natural............... 26
C. Outer Continental Shelf Lands Act.......... 29
a MLL... 31
E. “Double Crediting” ........................ 32
IV. Pregranted Abandonment ..................__.. 33
UU eee 35
eae 36
1. Decision illegally delegated to pipeline ... .36
2. Reasoned decisionmaking
rol kt, 42
12a
A. Contract Demand Reduction ................ 43
B. Take-or-pay Cost Passthrough .............. 44
i Ag tS a 44
2. Opportunity to recover prudently incurred
AE peg Sa ee te re ee ee 45
3. Continued use of passthrough mecha-
SE sag htt Sh ih oa 45
C. Passthrough at the State Level ............. 45
REE: AE OE" ie ee ee 46
I. Introduction
In the Spring of 1985, as Mikhail Gorbachev was
assuming the duties of General Secretary and inaugurat-
ing perestroika, the Federal Energy Regulatory Commis-
sion launched its own restructuring of the natural gas
industry. See Notice of Proposed Rulemaking, Regulation
of Natural Gas Pipelines After Partial Wellhead Decontrol,
50 Fed. Reg. 24,130 (June 7, 1985) (issued May 30, 1985).
The cornerstone was “open access” — a process by which
a pipeline would be able to avoid many of the regulatory
hurdles otherwise impeding the provision of gas transpor-
tation, in exchange for committing itself to carry gas for
any party, including gas that would be sold in competition
with its own. Open access would thus provide a market-
based incentive to pipelines to keep the costs of their own
gas competitive.
As with Gorbachev, the road has not been smooth. The
Commission issued its final rule, Order No. 436, in Octo-
ber 1985. In Associated Gas Distributors v. FERC (“AGD
I”), 824 F.2d 981 (D.C. Cir. 1987), we generally approved
the rule but vacated it on the ground that the Commission
had failed to adequately address some fundamental prob-
lems, especially the rule’s effect on pipelines’ take-or-pay
liabilities. The Commission moved swiftly to promulgate
-a substitute rule (Order No. 500, 52 Fed. Reg. 35,334 (Aug.
14, 1987)) before our mandate issued, so that open access
transportation could continue without interruption.
Innumerable parties attacked not only Order No. 500
(and later orders of the 500 series), but also many individ-
13a
ual FERC adjudications of issues based on Order No. 500.
Many of these were consolidated and argued before us in
the Fall of 1989. In American Gas Ass’n v. FERC (“AGA
I”), 888 F.2d 136 (D.C. Cir. 1989), the court resolved sev-
eral of the claims but remanded the record to the Com-
mission to address some issues that AGD I] had said it
must consider, as well as some new problems posed by
Order No. 500 itself. (We disposed of still other compo-
nents of the case in Associated Gas Distributors v. FERC
(“AGD IT’), 893 F.2d 349 (D.C. Cir. 1989), petitions for
certiorari filed, 59 U.S.L.W. 3017 (Nos. 89-1988, -1989,
-1990, -2000, -2016), and Transwestern Pipeline Co. v.
FERC, 897 F.2d 570 (D.C. Cir. 1990)). As a result of the
remand, the Commission issued Order No. 500-H, III
FERC Stats. & Regs. 9 30,867 (1989), and, on applica-
tions for rehearing, Order No. 500-I, III FERC Stats. &
Regs. § 30,880 (1990). The contending parties were of
course not satisfied, and here we review their contentions.
First, we affirm the Commission’s rejection of demands
that it should have intervened under § 5 of the Natural
Gas Act, 15 U.S.C. § 717d (1988), to modify uneconomic
take-or-pay contracts between producers and pipelines.
Second, we affirm in virtually all respects its decisions
creating a “crediting” mechanism. This allows pipelines
that carry gas under open access (which is likely to dis-
place their own and thus aggravate their take-or-pay lia-
bilities) to obtain credit in an equal amount against their -
take-or-pay obligations under contracts with the gas’s
producer. As to one feature, however, we remand the case
to the Commission for further consideration. Third,
although we cannot find any insuperable legal obstacle to
the Commission’s provision for “pregranted abandon-
ment” of transportation services provided under “blanket
certificates,” we remand the case on that issue because the
Commission’s explanations do not adequately justify its
decision or respond to opponents’ claims. Finally, we
reject a series of miscellaneous contentions as either
unripe or lacking in merit.
aa aaa tial
l4a
Il. Inaction under Section 5
In AGD I, this court vacated Order No. 436 and
remanded for the Commission to reassess both its reason-
ing and its factual premises for refusing to modify
“uneconomical pipeline-producer contracts” under § 5 of
the Natural Gas Act. 824 F.2d at 1030. The Commission
then collected extensive data from the pipelines, including
figures on the relation between high prices and take-or-
pay provisions, and on the proportion of contracts that
were within or without its jurisdiction. On issuing its
requests to the pipelines for data, it promised to aggregate
and analyze the results promptly. Order No. 500, 52 Fed.
Reg. at 30,341.
Despite that promise, the Commission did virtually
nothing after collecting the data, and its “half-explained
cunctation [convinced the AGA I court] that it delayed]
in order to avoid having to do the analysis that we
required in AGD until after the take-or-pay problem ...
disappeared.” AGA I, 888 F.2d at 148. Accordingly we
remanded for FERC to explain in a final rule whether it
planned to take § 5 action, and if not, why not. Jd. The
Commission has now done so in Order Nos. 500-H and
500-1, and we find its explanation sufficient.
A. Scope of Review.
Certain petitioners attempt to cast the Commission’s
duty to act under § 5 in mandatory terms. Drawing on the
language of §5 saying that the Commission “shall
determine the just and reasonable rate ... to be thereafter
observed and in force,” 15 U.S.C. § 717d (1988) (emphasis
added), they argue that the Commission must undertake
a §5 investigation whenever requested to do so. But the
directive to impose a just and reasonable rate or provision
is triggered only by the Commission’s finding that the
existing one is “unjust, unreasonable, unduly discrimina-
tory, or preferential.” Nothing in §5 requires the Com-
mission to embark on the inquiry in the first place.'
‘As noted at page 21-22 below, the Commission affirmatively
found that it could not make any generic finding that any one
l5a
Nor did our decision in AGD IJ impose any such burden.
We simply concluded that the Commission had not con-
sidered all the factors relevant to pursuit of such an
inquiry. Most particularly, the Commission appeared vir-
tually to deny the tendency of its restructuring program
— open access transportation and a grant to customers
of authority to convert purchase arrangements into trans-
portation — to aggravate the pipelines’ take-or-pay liabili-
ties and thus, arguably, to generate a need for action
under § 5. AGD I, 824 F.2d at 1021-28, 1044; see also San
Diego Gas & Elec. Co. v. FERC, No. 88-1744, slip op. at
8-9 (D.C. Cir. June 8, 1990) (summarizing material pas-
sages of AGD J). Thus our remand insisted that the Com-
mission reassess whether §5 should play a role in the
solution.
Our review of the Commission’s decision not to take
action is therefore quite limited in scope. The Commission
correctly invokes General Motors Corp. v. FERC, 613 F.2d
939 (D.C. Cir. 1979), stating that we review a no-
investigation decision under § 5 only to ensure that the
Commission has “consider[ed] all the relevant factors.”
Id. at 944; see also Southern Union Gas Co. v. FERC, 840
F.2d 964, 968-70 (D.C. Cir. 1988). As neither the Commis-
sion nor any petitioners have invoked Heckler v. Chaney,
470 U.S. 821, 831-35 (1985), holding that nonenforcement
decisions are ordinarily unreviewable by virtue of
§ 701(a)(2) of the Administrative Procedure Act, we need
not consider whether it argues for nonreviewability or for
greater deference.
B. The Merits.
The core of the Commission’s analysis was as follows:
First, its authority to modify take-or-pay provisions under
take-or-pay level was unjust or unreasonable, and that making
contract-by-contract assessments would be administratively diffi-
cult. We reject any claim, to the extent that petitioners may be
making one, that the embryonic inquiry necessary to reach these
negative conclusions somehow exposed the Commission to closer
scrutiny.
l6a
§ 5 reaches only wellhead contracts subject to its jurisdic-
tion. Second, even as to contracts accessible under § 5,
permissibie modifications would not suitably match the
problems. Third, private negotiation with’n the industry,
under Commission-created incentives, had good prospects
of working and indeed seemed to be doing so. We address
these in turn, concentrating on the want of authority over
nonjurisdictional contracts, the only purely legal issue.
1. Absence of power over nonjurisdictional contracts. A
major premise of the Commission’s decision was its con-
clusion that its § 5 power could not reach even the non-
price terms of nonjurisdictional contracts. In Order Nos.
500-H and 500-I it found that these accounted for 53%
of the roughly $9 billion of unresolved take-or-pay liabil-
ity at year-end 1986. III FERC Stats. & Regs. at 31,542,
31,715 n.88. (The proportion of wellhead sales that is sub-
ject to FERC jurisdiction steadily declines, as Congress in
the Natural Gas Policy Act eliminated such jurisdiction
over what may loosely be characterized as “new” gas,
which gradually increases as a share of the total as old
gas is exhausted. 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).) Accordingly, the Commis-
sion reasoned that use of § 5 would provide a less finely
tuned solution than other means — private negotiation
under the incentives created by its crediting mechanism
— to offset the effects of its restructuring program and
to correct the industry’s disequilibrium.
In reviewing the Commission’s resolution of the juris-
dictional issue, we need not decide whether Chevron
U.S.A. Inc. v. NRDC, 467 U.S. 837 (1984), mandates def-
erence to an agency interpretation of its ow,. jurisdiction.
See The Business Roundtable v. SEC, No. 88-1651, slip op.
at 3-5 (D.C. Cir. June 12, 1990) (reviewing authorities).
As we read the Natural Gas Act, the Commission was
absolutely right: Congress clearly limited its § 5 powers to
jurisdictional contracts.
Section 5(a) of the Natural Gas Act provides:
17a
Whenever the Commission, after hearing had upon
its own motion or upon complaint of any State [etc.],
shall find that any rate, charge, or classification
demanded, observed, charged, or collected by any
natural-gas company in connection with any trans-
portation or sale of natural gas, subject to the juris-
diction of the Commission, or that any rule,
regulation, practice, or contract affecting such rate,
charge, or classification is unjust, unreasonable,
unduly discriminatory, or preferential, the Commis-
sion shall determine the just and reasonable rate,
charge, classification, rule, regulation, practice, or
contract to be thereafter observed and in force, and
shall fix the same by order... .
15 U.S.C. § 717d (1988).
The pipeline petitioners isolate the words “contract
affecting such rate,” and argue that the Commission may
assess the justness and reasonableness of the provisions
of any contract that would likely influence a pipeline’s
end-of-the-pipeline charges, and, if it finds any such pro-
vision unjust or unreasonable, replace it with one that
meets that standard. Even they, of course, concede that
any such power could not reach the prices set forth in
nonjurisdictional contracts, as § 601(b)(1)(A) of the Natu-
ral Gas Policy Act, 15 U.S.C. § 3431(b)(1)(A), generally
determines that the prices of even jurisdictional wellhead
sales are automatically just and reasonable if they are
either within their NGPA ceilings or are exempt from
such ceilings.
The Commission reads “contract affecting such rate” as
limited to contracts in which a “natural gas company”
(within the meaning of the NGA) acts as seller and which
directly governs the rate in a jurisdictional sale — provid-
ing for the rate in whole or in part, or specifying or
embodying it, or setting forth rules by which it is to be
calculated. III FERC Stats. & Regs. at 31,539. Contracts
that “affect” a rate indirectly, merely by affecting the
costs that determine what pipeline sales rates are permis-
sible under the NGA’s “just and reasonable” standard, are
beyond § 5’s reach.
iittala
18a
We think petitioners’ view would make a nonsense of
the Supreme Court’s decision in Phillips Petroleum Co. v.
Wisconsin, 347 U.S. 672 (1954), and (more significantly)
of Congress’s effort 24 years later to undo Phillips with
the Natural Gas Policy Act. The Natural Gas Act’s basic
grant of jurisdiction appears in §1(b), and extends to
interstate transportation of gas, to interstate sales for
resale, and to natural gas companies engaging in either.
15 U.S.C. § 717(b). In Phillips, the Supreme Court con-
strued the authority over interstate sales for resale to
encompass producers’ wellhead sales for resale, against a
contention that §1(b)’s exclusion of “production or
gathering” foreclosed such a view. The Court explicitly
saw as the consequence of its decision the fulfillment of
a congressional intent “to give the Commission jurisdic-
tion over the rates of all wholesales of natural gas in
interstate commerce.” Jd. at 682. On petitioners’ view,
Phillips’s narrow construction of the “production or
gathering” exemption was completely urnecessary for ful-
fillment of that intent; under § 5 the Commission would
have had the authority to control wellhead rates merely
because those rates are elements in the computation of
pipelines’ sales rates. Indeed, petitioners’ theory is, more
generally, an oxymoron — Commission jurisdiction over
nonjurisdictional contracts.
Twenty-four years after Phillips, Congress in the
NGPA took away FERC’s jurisdiction over wellhead sales
of what may loosely be called “new” gas, see NGPA
§ 601(a)(1)(A) & (B), 15 U.S.C. § 3431(a)(1)(A) & (B). In
more sweeping terms, it reduced FERC’s jurisdiction over
wellhead prices. The prices of wellhead sales that
remained jurisdictional were deemed to satisfy the NGA’s
requirement that jurisdictional prices be “just and
reasonable” so long as they complied with the NGPA’s
ceilings. See NGPA §601(b)(1)(A), 15 U.S.C.
§ 3431(b)(1)(A). Finally, as to downstream prices, the
NGPA guaranteed interstate pipelines’ recovery of
amounts paid for gas if the price was deemed “just and
reasonable” under § 601(b), i.e., was in compliance with
19a
the NGPA. See § 601(c), 15 U.S.C. § 3431(c). The interac-
tion of the Commission’s residual “non-price” jurisdiction
over transactions whose prices are beyond its jurisdiction
itself raises a delicate issue: what kinds of § 5 control over
non-price terms might the Commission exert without
commandeering the price authority that Congress
expressly denied? We need not answer that question, as
the Commission has declined to exercise its § 5 power at
all. But it would greatly extend the scope of the dilemma
if the Commission were empowered to reach the non-price
terms of nonjurisdictional contracts.
The Supreme Court has not defined the class of con-
tracts reached by § 5, but has spoken to the ecope of the
parallel section of the Federal Power Act, § 206, 16 U.S.C.
§ 824e (1988). In FPC v. Conway Corp., 426 U.S. 271
(1976), it found that the Commission (actually, FERC’s
predecessor, the Federal Power Commission) had a duty
to consider whether the structure of a utility’s jurisdic-
tional (wholesale) and nonjurisdictional (retail) races
might impose a “price squeeze” on the firms that bought
from it at wholesale and sold in competition with it at
retail. In identifying a price squeeze, of course the Com-
mission would have to compare nonjurisdictional with
jurisdictional rates, but the Court was quite clear that
“(t}he remedy, if any, would operate only against the rate
for jurisdictional sales.” Jd. at 279 (emphasis added); see
also id. at 276 (“the Commission’s power to set just and
reasonable rates under § 206(a) [is] accordingly limited to
sales ‘subject to the jurisdiction of the Commission’ ”).? Of
course Conway denies the Commission power only over a
utility’s nonjurisdictional sales contracts, and so is not
direct authority for want of such power over nonjurisdic-
tional purchase contracts. But it surely suggests that the
potential impact of nonjurisdictional contracts’ prices on
the justness and reasonableness of jurisdictional rates
"The inner quote “subject to the jurisdiction of the
Commission” comes from § 206 of the Federal Power Act, 16
U.S.C. § 824e (1988), but is exactly the same phrase as appears
in the parallel passage of § 5 of the NGA.
|
20a
provides no license for the Commission to monkey with
the former.
Pennzoil Co. v. FERC, 645 F.2d 360, 381 (5th Cir. 1981),
also argues against petitioners’ position (but also incon-
clusively). The court held that the Commission’s authority
to interpret (and nullify) price escalation clauses in con-
tracts as to which the price increase could take effect only
by a filing under § 4 of the NGA ({i.e., jurisdictional con-
tracts), did not give it any such interpretive or nullifica-
tion authority over price escalation clauses in
nonjurisdictional contracts. As the petitioners justly
observe, Pennzoil involves § 4, not §5. But they fail to
advance any logic supporting a far greater reach for the
Commission under § 5.
Petitioners claim that somewhere in the chain of deci-
sions captioned Office of Consumers’ Counsel, Ohio v.
FERC, 783 F.2d 206 (1986), 826 F.2d 1136 (1987), 842 F.2d
1308 (1988), we held that § 5 cffords authority to modify
non-price terms of nonjurisdictional contracts. The third
decision reviews the entire series and makes clear that the
facts did not pose the issue and that the court never pur-
ported to address it. See OCC III, 842 F.2d at 1309-10.
Weighing against petitioners’ theory is that logically it
reaches pipelines’ contracts for every other possible factor
of production — even legal services. Petitioners them-
selves offer no distinction between these and gas contracts
except as to the degree of impact on the pipelines’ selling
prices. That line, in contrast to the Commission’s, has no
conceptual core and thus seems awkward and implausible
as a jurisdictional boundary.
Accordingly, we find the Commission entirely correct in
its premise that it lacks authority to modify even the non-
price terms of nonjurisdictional contracts.
2. Mismatch. As the Commission explained, the so-
called take-or-pay problem arises in reality from “the
combination of high take and high price provisions.” III
FERC Stats. & Regs. at 31,543; see also id. at 31,545 (con-
2la
tracts “a problem only because [the] expectation [of con-
tinued high demand for gas at relatively high prices],
reasonable at the time, proved incorrect”). Indeed, take-
or-pay provisions are primarily contract authorizations of
a kind of specific performance for the seller. The central-
ity of price is underscored by the fact that most specific
§5 proposals called for the Commission to modify the
contracts by inserting “market-out” clauses, allowing the
pipeline to escape if the producer refused to lower the
price. III FERC Stats. & Regs. at 31,543-45; see, e.g.,
Responses of AGD to Questions Posed by Commissioners
Concerning Order No. 500 at 18, R. 10803 (reproduced in
Appendix of Local Distribution Companies, State Com-
missions and Related Agencies (“LDC App.”) at 107) (in-
sert market-out clause for any contract containing a take-
or-pay clause above 50% and a price above pipeline’s
weighted average cost of gas); Supplemental Comments of
Allied Commenters at 24 (LDC App. at 137) (same); Com-
ments of the Illinois Commerce Commission in Response
to Order 500 Interim Rule and Statement of Policy at 15,
R. 3226 (LDC App. at 20) (delete the take-or-pay require-
ments). Adoption cf any such proposals would appear to
undercut Congress’s decision that NGPA-complying
prices are to be deemed just and reasonable.
Any across-the-board reduction of take percentages
(the percentage of deliverable gas that a pipeline must
take or pay for) would be both under- and overinclusive.
About 25% percent of remaining high take-or-pay_con-
tracts are for low-priced gas. See II] FERC Stats. & Regs.
at 31,545. An across-the-board reduction in take percent-
ages would reach these, impairing producers’ contract
rights with little benefit for pipelines. At the same time,
such a reduction would leave the pipelines subject to con-
tract duties to buy large amounts of high-priced gas and
thus partially disabled from successfully competing with
lower-priced spot-market gas. Jd. at 31,543-44.
The Commission affirmed, moreover, that take-or-pay
provisions have a legitimate role in producer-pipeline con-
tracts. (Not to do so would seem to condemn longterm gas
a
22a
purchase contracts to extinction. They would be virtually
meaningless with no remedy, and it is not clear that take-
or-pay is much more draconian than ordinary contract
damages, as the forced purchaser can take and resell at
a loss.) The Commission saw the clauses as assuring the
producer some mimimum level of revenue to cover operat-
ing expenses and debt. Jd. at 31,544. Further, it noted that
the suitable level varies with the circumstances. Individual
operators’ financial circumstances vary, as does the mini-
mum rate of extraction from a reservoir necessary to
secure the optimal level of total recovery. Jd. at 31,545.
(Indeed, one can readily imagine other potentially rele-
vant variations, such as the contracting parties’ risk aver-
sion and their means of influencing each other’s
behavior.) Thus the Commission could make no generic
finding of a reasonable take-or-pay percentage, and case-
by-case analysis of thousands of contracts would be, it
observed conservatively, “administratively difficult.” Jd.
The Commission is entitled, of course, to give great
weight to issues of internal resource allocation in making
a no-go decision under § 5. See National Fuel Gas Supply
Corp. v. FERC, 900 F.2d 340, 345 (D.C. Cir. 1990), and
cases cited therein.
3. Comparative advantages of individual settlement
negotiations. The Commission found that individual set-
tlement negotiations, under incentives structured by its
crediting mechanism, provided an avenue for resolution
of the take-or-pay difficulties that was free of the incon-
gruities of action under § 5. Such settlements would take
into account specific factors relevant to the contracting
parties, see II] FERC Stats. & Regs. at 31,546, and would
accord with Congress’s strong preference for reliance on
private agreements for structuring the wellhead market,
see id. at 31,546-47. See also Natural Gas Wellhead
Decontrol Act of 1989, Pub. L. No. 101-60, 103 Stat. 157
(1989) (generally removing all wellhead price limits and
all Commission jurisdiction over wellhead sales by 1993).
Although the Commission was actually making this
decision in 1989-90, petitioners argue (and we will
23a
assume) that its duty was to consider matters as they
stood at the time it adopted open access in 1985. See OCC
II, 826 F.2d 1136 (D.C. Cir. 1987) (where legal error has
caused a delay in Commission action under § 5, it should
afford a remedy that corrects for the delay). On this view,
the policy question was whether adding § 5 action to the
picture at that time would have been wise. We read the
Commission analysis as fundamentally addressing that
question. Nevertheless, it reported figures as to the actual
resolution of conflicts in the meantime, presumably to
show that ex post data confirmed its ex ante analysis. For
example, it found that by March 1989 negotiations had
resolved all but about $2.4 billion of $9 billion in liabilities
outstanding at year-end i986, III FERC Stats. & Regs. at
31,542-43, and that on average pipelines paid only 18.6
cents on the dollar for these settlements, id. at 31,522.
The local distribution company (“LDC”) petitioners
attack this figure as inaccurate, or at least unverifiable.’
°We uphold the Commission’s decision not to release the raw
data about individual settlements it compiled in deciding whether
to take action under § 5. It had agreed not to do so because of
some parties’ expressions of concern about the competitive effect
of release. See 18 CFR § 388.112 (1989). Only AGD moved for
rehearing on the issue, which the Commission denied separately
after Orders 500-H and 500-I had already been appealed. AGD’s
appeal to this court (docketed as No. 90-1264) was consolidated
with this complex case and AGD agreed “to let the issues raised
in No. 90-1264 be governed by the briefs already submitted.”
Motion to Consolidate of Petitioner Associated Gas Distributors,
No. 90-1264, filed May 22, 1990, at 3.
The briefs arguing for disclosure of the raw data point to no
cases supporting their claim of a “clear violation of due process”
or otherwise supporting release. (In fact, they point to no case law
at all.) Their only real argument is that the pipelines that pro- .
vided the information had an incentive to overestimate the
amount of potential exposure they resolved in order to make the
amount they wish to pass downstream seem more reasonable. The
Commission’s response to this point seems well-founded: that
incentive would be balanced by the pipelines’ desire to make cost
look high relative to relief afforded so as to strengthen the case
for Commission action under § 5.
24a
They argue that the true cost of the take-or-pay buyouts
and buydowns for pipelines has been much higher.
It is true that the precision suggested by the figure 18.6
cents is illusory. As the LDCs point out, most of the
ingredients of the conclusion are squishy soft. For exam-
ple, in comparing the amounts paid out with relief
obtained, the Commission included in the latter not only
take-or-pay liabilities extinguished but also $27 billion in
“future-oriented relief.” Jd. at 31,522. How the latter was
calculated is not revealed, and in the nature of things
could not be firm: how could the Commission accurately
estimate how a pipeline’s sales would match its contract
obligations over years into the future? Moreover, it is not
altogether clear to what extent the liabilities extinguished
were gross or net — i.e., offset by the value of the gas paid
for (to the extent that pipelines by contract still could
take the gas). But the Commission has not used the 18.6
cent figure as a precise measure of tle allocation of the
burden between producers and pipelines — a measure
that, besides being unverifiable, would be largely meaning-
less as there is no “right” allocation. Rather, we read the
Commission as gleaning from the data a general confir-
mation of the proposition that the crediting mechanism
and other factors would force the producers to assume a
significant share of the sunk costs arising from actions
taken long ago in the expectation of continued high
prices. The LDCs’ and pipelines’ arguments do not seri-
ously draw that proposition in question.
All in all, we find that the Commission’s approach
handily meets the standard of General Motors, Southern
Union and AGD I. We have no basis whatever for forcing
the Commission into interference with thousands of con-
tracts, in the form either of generic rules or interminable
case-by-case decisions, which in either event would be
only dimly related to the price difficulty that is the core
of the pipelines’ problem and is plainly off the Commis-
sion’s reservation.
25a
III. Crediting Mechanism
Under the crediting mechanism, a pipeline accepting a
blanket certificate may deny a producer the benefits of
open access unless the producer allows the pipeline to
credit each unit of transported gas (subject to some excep-
tions) against outstanding take-or-pay contracts. The
pipeline may apply the credit to any contract between the
producer and the pipeline which was entered into before
June 23, 1987 (the date of our decision in AGD J); because
of this power to select among contracts, the producers dub
the process “cross-crediting.” The mechanism continues
in effect until the earlier of December 31, 1990 (or, if our
mandate in this case has not issued by then, 60 days after
our mandate issues), or the date on which a pipeline
accepts a “gas inventory charge” certificate, II] FERC
Stats. & Regs. at 31,528-29, under which a pipeline can
charge its customers for the cost of standing ready to sup-
ply gas. See Transwestern Pipeline Co. v. FERC, 897 F.2d
570, 573 (D.C. Cir. 1990).
A. Producer Claims that Crediting Is No Longer Needed
and Pipeline Claims to a Broader Weapon Against
Producers.
The producers argue that the take-or-pay problem has
largely gone away, rendering the crediting mechanism
obsolete. The pipelines make an argument in the opposite
direction — that they should be allowed to deny any
access to a producer who has refused “to modernize its
contracts.” Joint Brief for Pipeline Petitioners on Man-
date Compliance at 26. (We take “modernize” to be a
euphemism for accommodating pipeline wishes.) Neither
argument has legal merit.
The producers concede that the crediting mechanism
(or the threat of its use) helped pressure them into set-
tling much of their take-or-pay rights against the pipe-
lines. The Commission, reasonably enough, concluded
that in future negotiations over the remaining take-or-pay
liability, the mechanism would serve the same purpose. II]
FERC Stats. & Regs. at 31,527-28, 31,700. To the extent
26a
that the producers argue that the mechanics of crediting
(which we will spare the reader) have become more of a
hassle than they are worth, we must defer to the Commis-
sion’s judgment call the other way. Finally, the producers
suggest that most of the remaining take-or-pay liability
is in litigation, dispensing (they say) with any further
need for a pipeline bargaining chip. As lawsuits can settle
(and most do), the utility of bargaining chips survives
their filing.
The pipelines rest their claim on language in AGD /
expressing skepticism about the Commission’s apparent
assumption that “pipeline denial of access to producers
that stand on the letter of their contract rights [would be]
unduly discriminatory.” 824 F.2d at 1028. The pipelines
would transform this observation into a mandate that the
Commission give the pipelines an absolute veto over recal-
citrant producers. Obviously it was not — the passage
went on to suggest types of conditions that the Commis-
sion might place on any sucn pipeline veto power. Jd. at
1028-29. In adopting the crediting mechanism the Com-
mission in effect gave the pipelines a conditional veto.
The Commission has in this respect fulfilled the mandate
of AGD I.
B. Panhandle/Northern Natural.
The producer petitioners attack the Commission’s
approval of the crediting mechanism as a violation of the
principles of Panhandle Eastern Pipe Line Co. v. FERC,
613 F.2d 1120 (D.C. Cir. 1979), and Northern Natural Gas
Co. v. FERC, 827 F.2d 779 (D.C. Cir. 1987), which forbid
it from using its power to impose conditions on certifi-
cates of service, under § 7(e) of the Natural Gas Act, 15
U.S.C. §717fle), to “adjust[ ] previously approved rates
for services not before the Commission in the relevant
certificat@ proceeding.”* 827 F.2d at 786. In both those
‘Petitioners limit their attack here to the contracts governed by
§ 7 of the NGA as we have already approved, in AGA /, 888 F.2d
at 149, the Commission's authority to promulgate the ‘crediting
mechanism under contracts governed by § 311 of the NGPA.
27a
cases, the Commission had conditioned new service on the
pipelines’ “crediting” part of the resulting revenues to
users of other service, i.e., reducing the rates charged for
the other service. See 613 F.2d at 1130-31 n.52; 827 F.2d
at 786.
The producers can at most be appealing to the spirit
of Panhandle and Northern Natural, for the Commission’s
action by no means fits the letter. Whereas in those cases
the Commission conditioned its grant of the applying
pipelines’ certificates on their reducing rates for other ser-
vice, here it has provided that pipelines applying for and
receiving blanket certificates shall have the authority to
deny open access to a specific class of would-be custom-
ers; in other words, it has refined the concept of nondis-
crimination that is the essence of the service itself being
certificated.
But in any event we do not propose to kill the spirit
of Panhandle and Northern Natural. One might express
that spirit as a proposition that the Commission may not
use its § 7 conditioning power to do indirectly (1) things
that it can do only by satisfying specific safeguards not
contained in § 7(e) (in the case of reducing previously-
approved jurisdictional rates, by meeting its burden under
§ 5, see Panhandle, 613 F.2d at 1130; Northern Natural,
827 F.2d at 782), or (2), a fortiori, things that it cannot
do at all. If the crediting mechanism reduced the rates
charged in pipeline/producer contracts, the second variant
would be applicable, for under § 601(b)(1)(A) of the Natu-
ral Gas Policy Act, 15 U.S.C. § 3431(b)(1)(A) (1988), well-
head prices are (generally) lawfu: under the Natural Gas
Act if they are within the NGPA ceilings or subject to no
such ceilings. If the mechanism modified non-price terms
of the contracts, then as to jurisdictional contracts it
would be an act that the Commission can perform only
by meeting §5’s requirements; as to nonjurisdictional
ones, it would be, as we have just seen, an act the Com-
mission cannot perform at all.
But the crediting mechanism neither reduces rates nor
modifies non-price terms; it creates incentives for produc-
28a
ers to agree to reductions and modifications. There is a
difference, and the producers recognize it. They concede
that the Commission’s authorization of pipeline insistence
on credits is within its jurisdiction as to credits against
take-or-pay obligations in a contract to which the gas
being transported is (or was) subject. See Joint Initial
Brief of Indicated Producers at 19-20; see also II] FERC
Stats. & Regs. at 31,709. But provision for pipeline insis-
tence on that more limited credit also alters the bargain-
ing relationship of the parties; it establishes that any
producer shipment of contract gas over the (formerly pur-
chasing) pipeline ipso facto reduces the pipeline’s take-or-
pay obligation. Thus the producers recognize that the
Panhandle/Northern Natural principle does not bar the
Commission from establishing certificate conditions with
an eye to inducing changes in transactions that are
beyond its direct grasp.
The producers accordingly are reduced to arguing that
transportation service has “no relation whatsoever” to gas
sold by a producer to a pipeline under other contracts.
Joint Initial Brief of Indicated Producers at 20. But the
core purpose of open access was to extend the competitive
character of the wellhead markt all the way to the burner
tip by unbundling the gas commodity from its transporta-
tion and assuring consumers access to the wellhead mar-
ket. A major stumbling block to its implementation was
the pipelines’ reasonable fear that producers’ and others’
use of it would displace their own gas sales and balloon
their take-or-pay liabilities. The Commission therefore
adopted the crediting mechanism in order to give pipe-
lines “the bargaining power necessary to negotiate reason-
able settlements of their take-or-pay problems.” See III
FERC Stats. & Regs. at 31,549. The relation could hardly
be tighter.
In essence, the producers want to have their cake and
eat it. They want both the full benefit of very favorable
contracts under the old regime, and the full right to force
pipelines to carry their gas under the new. Instead the
Commission put them to the choice. By defining limits to
29a
the producers’ entitlement to open access, it enhanced the
prospect of achieving its goals. We do not read this struc-
turing of incentives as an invasion of territory beyond the
Commission’s jurisdiction.
C. Outer Continental Shelf Lands Act.
In Order No. 500, the Commission allowed pipelines to
refuse to transport gas on the Outer Continental Shelf for
producers who would not give credits for such gas. The
producers argued in AGA I that the Commission lacked
the power to so restrict open access on the OCS because
§§ 5(e) and 5(f) of the OCSLA, 43 U.S.C. §§ 1334(e)-(f)
(1982), already gave them an unqualified right of access
to OCS pipelines. Specifically, § 5(e) allows pipelines
rights-of-way across the OCS
upon the express condition that [they] shall trans-
port or purchase without discrimination, oil or natu-
ral gas produced from submerged lands or outer
Continents! Shelf lands.
43 U.S.C. § 1334(e). And § 5(f), added in 1978, provides
that .
every permit, license, easement, right-of-way, or
other grant of authority for the transportation by
pipeline on or across the outer Continental Shelf of
oil or gas shall require that the pipeline be operated
in accordance with the following competitive princi-
ples:
(A) The pipeline must provide open and non-
discriminatory access to both owner and non-
owner shippers.
43 U.S.C. § 1334(f)(1)(A).
Because the Commission had evidently not grasped the
nature of the producers’ argument, we remanded for it
either to except gas carried on the OCS from the crediting
mechanism, or to respond to the producers’ claim. AGA
I, 888 F.2d at 149. On remand, the Commission rested its
authority to impose the crediting mechanism in the OCS
primarily on two grounds: a savings clause in § 5(f)(4),
30a
and its power to interpret “without discrimination” and
“open and nondiscriminatory access” in §§5({e) and
5(f)(1)(A), respectively. We believe its interpretive power
is indeed enough.
We reject the Commission’s view that § 5(f)(4)’s savings
clause necessarily imbues it with exactly the same discre-
tion in the OCS as the NGA allows onshore. It provides
simply:
Nothing in this subsection shall be deemed to limit,
abridge, or modify any authority of the United States
under any other provision of law with respect to pipe-
lines on or across the outer Continental Shelf.
43 U.S.C. § 1334(f)(4). With respect to § 5(f), we question
whether Congress intended the savings clause to merge
§ 5(f)(1)(A)’s specific mandate with Natural Gas Act's
vaguer bans on “undue preference[s],” “unreasonable
difference[s],” and “unduly discriminatory” rates, classifi-
cations, etc. See NGA §§4 & 5, 15 U.S.C. §§ 717c(b),
717d(a). First, § 5(f)(4) is specifically a savings clause only
against subsection 5(f), and cannot save any FERC power
as against § 5(e). In eny event, it would make little sense
for the savings clause to wipe out an explicit prohibition
contained in subsection 5(f), if there were one. If FERC’s
decision is to be upheld, then, it must be on the basis of
its power to interpret the anti-discrimination clauses of
§§ 5(e) and 5(f)(1)(A).
No party before us disputes the Commission’s power to
interpret those mandates. See, e.g., High Island Offshore
System, 14 FERC 963,036 at 65,096-104 (1981) (ALJ
interprets § 5(f)(1)(A)’s “nondiscriminatory access” provi-
sion). Thus the question reduces to the reasonableness of
the interpretation.
The producers argue that the plain meaning of
“nondiscriminatory” precludes any restriction on producer
access to OCS pipelines. But as we noted in AGD J, statu-
tory bans on discrimination by natural monopolies have
always allowed the regulatory agencies discretion to per-
mit differing categories, including, for example, rate clas-
3la
sifications based on customers’ differing elasticities of
demand. See AGD I, 824 F.2d at 1011 (citing cases). Here
Congress expressly characterized § 1334(f)(1)(A)’s open
access mandate as one of several “competitive principles.”
See 43 U.S.C. § 1334(f)(1). The Commission has created
categories that in its view (which is uncontested as a mat-
ter of fact or policy) will advance the pro-competitive goal
of its open access policy. It has thus given a meaning to
Congress’s anti-discrimination norm that fits the overall
congressional purpose. This is neither a violation of law
nor arbitrary or capricious.
D. Casinghead Gas.
Casinghead gas is gas “produced with oil from oil
wells.” Howard R. Williams, Oil and Gas Terms 120 (7th
ed. 1987); compare “associated gas,” id. at 58 (gas occur-
ring in the form of a gas cap associated with an oil zone).
A pipeline’s failure to take it promptly jeopardizes a pro-
ducer’s efficient operation of a field, typically requiring it
“either to shut in the oil production or flare the casing-
head gas.” See AGA I, 888 F.2d at 149 (quoting Order No.
500-C). The shutting-in of production may reduce the
amount ultimately recoverable from the reservoir. III
FERC Stats. & Regs. at 31,531. Because of this exigency,
the Commission in Order No. 500-C excepted casinghead
gas from the crediting mechanism. In AGA I, we
remanded for the Commission to address an argument it
had previously ignored, namely, that producers could
avoid the waste of resources foreseen by the Commission
simply by selling the gas on the open market. 888 F.2d
at 149.
On remand, the Commission eliminated the exemption.
It found that whereas at the start of its restructuring pro-
ducers had lacked access to pipelines to carry released
gas, open access transportation was now “much more
widely available.” III FERC Stats. & Regs. at 31,531. It
therefore prospectively eliminated the casinghead gas
exception, but provided for “blanket abandonment and
certificate authority to permit the release and resale of the
32a
gas to others” for all so-called “must-take” gas, including
casinghead gas. Jd. It also required pipelines to give pro-
ducers 60-days’ notice before applying credits against a
contract, in order to give producers enough time to scare
up alternative buyers and transportation, and it provided
a chance for them to seek emergency relief from the Com-
mission. Jd. at 31,708-09.
Producers argue, however, that their gas supplies
remain in danger of being shut in because gas shifted
from a take-and-pay contract to mere open access drops
to the end of the line of claimants to pipeline capacity.
If that is limited enough, producers will not be able to get
their gas to market.
We recognize that the Commission’s approach may not
work 100% of the time. But that is hardly a reason for
doing away with it altogether; few rules could survive that
standard. Further, the Commission’s provisions for notice
and expedited relief seem apt to reduce the risks to a rea-
sonable minimum. Producers offer no basis for us to
second-guess the Commission here.
The producers also claim that far from extinguishing
the casinghead gas exemption, the Commission should
have extended it to all other “must-take” gas. The above
analysis obviously dooms this broader contention.
E. “Double Crediting.”
Under the crediting mechanism, a pipeline can demand
credit for transporting gas that another pipeline has pur-
chased from a producer. Producers claim this amounts to
“double crediting,” as purchase of the unit will also reduce
the purchasing pipeline’s take-or-pay liability.
In Order No. 500-H the Commission followed its con-
ventional style of listing everybody's points at length but
without analysis, and then dispatching the claims with a
brief discussion. It mentioned the double-crediting argu-
ment, see III FERC Stats. & Regs. at 31,569, but never
really responded to it, see id. at 31,570. The only arguably
responsive remark is an observation that a purchasing
33a
pipeline’s-sales to customers in the transporting pipeline’e
sales market “could displace a sale of the [transporting]
pipeline.” Jd. This, of course, is true, but it fails to explain
why the rule does not in fact force producers to give two
credits for one unit of gas sold. After all, the unit can only
be used once; that one use would seem to state the aggre-
gate amount of displacement. If the unit displaces ea sale
the transporting pipeline would have made, then perhaps
it has been diverted from the purchasing pipeline’s usual
market, opening up potential for a sale there. In any
event, though the true displacement caused by sale of a
fungible commodity is necessarily obscure (if not in fact
an arbitrary concept), we return to the point that the
same unit can be used only once.
The rule here seems particularly puzzling because the
producer has no say over which pipelines will transport
the gas. This appears to provide rich opportunities for
mutual back-scratching among pipelines — to arrange for
transporting of each other’s gas for the purpose of gener-
ating credits.
There may well be a good answer’ to all this (for
instance, there may be some good reason to exclude per-
formance under a contract from the concept of a credit),
but the Commission has not disclosed it intelligibly
enough for us. If it wishes to maintain this part of credit-
ing, it must on remand address the producers’ concerns
head-on.
IV. Pregranted Abandonment
In Order No. 436 the Commission provided “pregranted
abandonment,” at the end of the contract term, for every
“individual transportation arrangement authorized under
a certificate granted under this section [authorizing
“blanket” certificates].” 18 CFR § 284.221(d) (1989). With-
out pregranted abandonment, a pipeline would have been
legally bound to make any such service available indefi-
nitely, despite expiration of the contract, until it received
34a
individual Commission approval under § 7(b) of the Natu-
ral Gas Act, 15 U.S.C. § 717f(b).
Although no one challenged pregranted abandonment
in AGD I, this court vacated it along with the rest of
Order No. 436 because Commission errors in other areas
had “taint[ed] the package.” 824 F.2d at 1044. On remand,
the Commission in Order No. 500 (and 500-H) repromul-
gated § 284.221(d) without change. After issuance of
Order No. 500, it construed § 284.221(d) to encompass
“conversion transportation”: transportation arising out of
sales customers’ exercising their right to convert purchase
arrangements into transportation, a right created origi-
nally in Order No. 436 and renewed in Order No. 500. See
Transco, 44 FERC 9 61,105 (1988).° In Order Nos. 500-H
and -I the Commission adhered to the view that
§ 284.221(d) covered conversion transportation, offering
only the most oblique explanation of why transportation
under a converted individualized sales certificate fell
within the language of § 284.221(d) — “transportation
arrangement authorized under a certificate granted under
this section.” (Section 221 does not provide for conversion
transportation; it appears in § 284.10.) See III FERC
Stats. & Regs. at 31,730.
This time around, several parties challenged pregranted
abandonment as an abdication of the Commission’s
responsibilities under § 7 of the NGA and as unsupported
by reasoned decisionmaking. They attack it especially in
_the context of conversion transportation.
®The Commission in Order No. 500-H also made abandonment
of sales service automatic on customer conversion to transporta-
tion, on the ground that the customer was no longer paying a sales
demand charge, and that abandonment would better enable pipe-
lines to estimate their supply needs. It regarded these advantages
as overcoming the resulting slight diminution in customers’ secur-
ity of supply. II] FERC Stats. & Regs. at 31,584. We reject the
LDCs’ weakly urged contention that this decision is unreasoned.
~ SSS owtor —
35a
A. Jurisdiction
The Commission claims that we have no jurisdiction to
hear petitioners’ arguments because they constitute an
impermissible collateral attack on Order No. 436, on
which the 60-day time limit provided in 15 U.S.C.
§ 717r(b) has long since expired.
We find this clearly without merit as to conversion
transportation. The Commission recognizes that under
such cases as Raton Gas Transmission Co. v. FERC, 852
F.2d 612, 615 (D.C. Cir. 1988), and RCA Global Communi-
cations, Inc. v. FCC, 758 F.2d 722, 730 (D.C. Cir. 1985),
we will hear attacks on an agency regulation, despite expi-
ration of statutory time limits, if the agency did not
“reasonably put[ ] aggrieved parties on notice of the rule’s
content.” Here, not only does the language of § 284.221(d)
appear only tenuously related to conversion transporta-
tion, but the Commission’s construction is somewhat
inconsistent with its statement, in the preamble to Order
No. 436, that conversion from firm sales to firm transpor-
tation would in no way alter the “quality or priority” of
the transportation service. Order No. 436, FERC Stats. &
Regs. [Regs. Preambles], 1 30,665 at 31,517. Even the
Commission views Order No. 500-H as having “clarified”
§ 284.221(d), III FERC Stats. & Regs. at 31,583, and it
justified this clarification at some length, see id. at 31,727-
35. To treat converting sales customers as barred by their
inaction against § 284.221(d) in its original incarnation
would allow unconscionable sandbagging.
The issue is closer with regard to transportation other
than that converted from sales. We have permitted chal-
lenges to regulations outside statutory time limits if the
agency has reopened an issue. See State of Ohio v. EPA,
838 F.2d 1325, 1328-29 (D.C. Cir. 1988); Association of
American Railroads v. ICC, 846 F.2d 1465, 1473 (D.C. Cir.
1988). Order No. 500-H does not address the issue of the
permissibility of pregranted abandonment generally, but
parties seeking rehearing of that order did so, and the
Commission, far from treating the matter as settled from
36a
Order No. 436, responded in full on the merits. Much of
the discussion drew no distinction between conversion and
other transportation, and in view of that intermingling we
applicable.
We leave to another day the effect of the vacation of
an order (Order No. 436) and the agency’s inclusion of an
unchallenged component (§ 284.221(d)) in its promulga-
tion of a revised version of the original order. As no
attack was made on § 284.221(d) in the challenges to the
original promulgation, and as it was a forgone conclusion
that after Order No. 436’s vacation the Commission would
resurrect the basic policy decision inherent in the order,
one might question whether challengers should get a sec-
ond crack at § 284.221(d) through the fortuity of the
broad remedy chdsen in AGD I. Here, even assuming a
negative answer to that question, our cases require us to
reach the merits.
B. The Merits.
Petitioners” attacks on pregranted abandonment take
essentially two forms. The first, phrased as a claim that
the rule “[writes] Section 7(b) out of the Act,” is essen-
tially an argument that any rule permitting abandonment
on the expiration of contracts effectively delegates the
abandonment decision to the pipeline and is therefore an
unlawful abdication of Commission responsibilities under
§ 7(b). The second is that, assuming that the Commission
may (in some or all instances) make abandonment auto-
matic on contract expiration, it has not adequately justi-
fied its doing so here. We reject the first claim and accept
the second.
1. Decision ulegally delegated to pipeline. First, we note
that petitioners quite rightly, and necessarily, concede
that the Commission may decide on abandonment in
"Those attacking pregranted abandonment are a group of local
distribution companies, state commissions, state agencies and end
users. For simplicity’s sake, we refer to them collectively as LDCs.
37a
advance, even before service has begun, see FPC v. Moss,
424 U.S. 494, 501 (1976), and that it may make such a
determination generically, covering an entire class of
cases, see Joint Initial Brief of Indicated LDCs, State
Commissions, State Agencies, and End Users, on Issue of
Pregranted Abandonment of Firm Service at 8; see also
AGD I, 824 F.2d at 1015 n.17; 18 CFR § 157.30(c),
§ 157.301 (1989) (providing for pregranted abandonment
of gas sold for resale by a producer upon expiraticn of the
contract).
Petitioners rest the idea that contract expiration may
not be the triggering event on United Gas Pipe Line Co.
v. McCombs, 442 U.S. 529 (1979). The court of appeals,
on the theory that apparent exhaustion of reserves auto-
matically and necessarily effected abandonment for § 7(b)
purposes, had overturned a Commission decision rejecting
that notion and insisting that reserves remained dedicated
to interstate commerce until the Commission granted
abandonment. The Supreme Court reversed, thus protect-
ing the Commission’s opportunity to determine whether
the exhaustion had in fact occurred. Jd. at 535-39. In the
course of the opinion the Court observed that treating
apparent exhaustion as a legal abandonment would vest
the abandonment decision “in the producer’s control, a
result clearly at odds with Congress’ purpose to regulate
the supply and price of natural gas.” Jd. at 539. Here, of
course, the Commission has exercised its authority over
abandonment (in advance and generically, to be sure), so
the holding is not pertinent.
The 5th Circuit has recently given McCombs a broad
reading, finding it to prohibit the Commission from pre-
granting abandonment of producer sales of gas to pipe-
lines in the event producer and pipeline do not reach
agreement after a “good faith negotiation” conducted pur-
suant to certain Commission ground rules. Mobil Oil
Exploration and Producing Southeast, Inc. v. FERC, 885
F.2d 209, 221-23 (5th Cir. 1989), stay granted, 110 S. Ct.
830, cert. granted, 110 S. Ct. 2585 (June 4, 1990). The
court may have reached this conclusion because only a
38a
producer could initiate the negotiation process, 885 F.2d
at 217, so it would occur only if the producer saw a pros-
pect of a net price increase; the court evidently did not
find in the Commission’s discussion an adequate explana-
tion of how the process as a whole was consistent with
the NGA’s consumer-protection purposes. As to McCombs
more generally, even if we read § 7(b) as prohibiting aban-
donment at the unconstrained election of a natural gas
company, the present rule does no such thing. It provides
for abandonment only at the expiration of an agreement
between the pipeline and customer. We see neither Mobil
Oil nor McCombs as a barrier to pregranted abandonment
in that circumstance, so long as the Commission supports
it with proper reasoning.
2. Reasoned decisionmering. The local distribution
companies’ basic complaint is that allowing pipelines to
terminate transportation service on expiration of the
applicable contracts violates the Commission’s duty to
protect consumers by endangering the LDCs’ ability to
guarantee their customers a steady supply of gas. The
importance of continued service, they argue, is embedded
in §7(b) of the NGA, which prohibits any natural gas
company from discontinuing certificated service (even
after the underlying contract expires) until the Commis-
sion determines that abandonment is in the public conve-
nience and necessity. Thus in Sunray Mid-Continent Oil
Co. v. FPC, 364 U.S. 137, 143 (1960), the Court found
§ 7(b) rooted in a congressional concern that with pipeline
freedom to terminate “a local economy which had grown
dependent on natural gas as a fuel would be at [the pipe-
line’s] mercy.” See also McCombs, 442 U.S. at 536; Sunrey
Mid-Continent Oil Co. v. FPC, 239 F.2d 97, 101 (10th Cir.
1956) (“No single factor in the Commission’s duty to pro-
tect the public can be more important to the public than
the continuity of service furnished.”). Recognizing that
even a monopolist with the capacity to provide a service
will do so at a price, the LDCs go on to argue that they
will be able to secure continued service only by yielding
to monopolistic demands. Cf. Sunray Mid-Continent, 364
39a
U.S. at 143 (referring to “great economic power of the
pipeline companies”). As the Commission controls the
terms on which transportation is supplied, they suggest
that this pipeline pressure may take the form of insisting
on special advantages in matters not covered by the pipe-
line’s tariff, see, e.g., R. 12211-12 (reproduced in Joint
Appendix Vol. VII), or extracting a customer’s agreement
to forgo challenges to the prudence of the pipeline’s costs,
see Joint Initial Brief of LDCs et al. on Issue of Pre-
granted Abandonment of Firm Service at 24 n.20.
The Commission’s response to this takes two forms —
a denial that its rule will have the feared effect on pipeline
customers, and assertion of a variety of policy arguments
that might justify exposing them to the risk of the effects
anyway. Neither component of the response appears very
persuasive. The Commission’s denial never directly
responds to the suggestion that pregranted abandonment
— in the broad form provided here — would allow pipe-
lines indirectly to extract monopoly profits from their cus-
tomers. Perhaps the answer is that no regulatory system
can really provide that protection — that market power
is irrepressible, as Shakespeare’s Rosalind says of
women’s wit: “Make the doors upon a woman’s wit, and
it will out at the casement; shut that, and ‘twill out at the
keyhole; stop that, ‘twill fly with the smoke out at the
chimney.” As You Like It, IV, 1, 148-51. See also William
A. Niskanen, Natural Gas Price Controls: An Alternative
View, Regulation at 46 (Nov/Dec 1986). Whatever the
truth of such a theory, it appears inconsistent with the
congressional assumption that Commission control over
certain critical features, including termination of service,
could materially offset the effects of monopoly. Alterna-
tively, perhaps the Commission believes the opposite —
that it can readily cure any such efforts to exploit market
power. In any event, the Commission did not offer any
direct response.
At points the Commission seems to be arguing that the
LDCs have ample alternatives — interruptible transporta-
tion, “standby” gas service from the terminating pipeline,
40a
or gas supplied by other pipelines — , so that there is,
in effect, no pipeline monopoly to be feared. II] FERC
Stats. & Regs. at 31,728-29. But interruptible and standby
service are palpably inadequate for LDCs’ longterm needs,
as they are likely — probably certain — to be unavailable
during the peak winter months. As to alternative pipe-
lines, the Commission has made no finding that these are
available (to an extent that would seriously constrain
pipeline market power) for most, much less all, of the cus-
tomers; indeed, in Order No. 436 it successfully asserted
the exact opposite. See AGD IJ, 824 F.2d at 1017-18.
The Commission also argues that pregranted abandon-
ment, even for conversion transportation, has such desir-
able effects — relevant to the purposes of the NGA — as
to justify whatever risks it may pose of abuse of market
power. First it says that pregranted abandonment helps
assure that pipeline capacity will go to those who value
it most. Without it, “the capacity needed by other pur-
chasers ... may never practically become available.” III
FERC Stats. & Regs. at 31,584, 31,728. It is surely true
that capacity dedicated to one customer cannot be avail-
able to others until undedicated. But as the Commission
requires that pipeline transportation capacity be allocated
on a first-come, first-served basis, Order No. 436, FERC
Stats & Regs. 130,665 at 31,515 (1985), it is hard to see
how displacement of an existing customer has much pros-
pect of shifting the capacity to a user that values it more
highly; getting into line early is not necessarily evidence
of high valuation. The usual device for allocations in
accordance with value is price — i.e., value measured by
willingness to pay.’ While the Commission’s goal here is
commendable, and while it is by no means its fault that
the NGA’s rate regulation requirements may complicate
any efforts to use price to clear the market for capacity,
the point still remains that pregranted abandonment, if
"Converted sales customers are initially placed at the head of
the line, id. at 31,517, but presumably get bumped to the end if
they fail to negotiate successfully with pipelines once the con-
verted sales contracts expire.
}
4la
coupled with first-come-first-served allocation, can’t get it
much of the way toward allocation in accordance with
value.
FERC also argues that pregranted abandonment “helps
ensure that capacity will not be retained by existing cus-
tomers if it is not needed by them, and ... gives custom-
ers an incentive to accurately nominate the length [of]
their contracts.” See III FERC Stats. & Regs. at 31,728.
We fail to see how pregranted abandonment accomplishes
this. Surely the primary determinant of whether a cus-
tomer will hold onto excess capacity rights is price, specif-
ically the size of demand charge and the degree to which
it is related to peak-period use. If it is too low, parties will
sign up for capacity (through the first-come-first-served
device, if that is the one provided) without full regard to
opportunity cost — the value foregone by the capacity
being unavailable to others. If price matches opportunity
cost, they will not. In this context, then, pregranted aban-
donment seems at most only to switch the incidence of
the excess capacity from one user to another.
As to conversion transportation — where the LDCs’
attack is fiercest — the Commission asserts that here pre-
granted abandonment presents no problem because the
LDCs could always have remained sales customers. But
their having to remain so (in order to be sure of supplies)
would disable them from using gas supplied by others —
or the realistic threat of turning to such gas — to put
pipelines under pressure to keep prices competitive, which
was the fundamental idea of open access. Thus the Com-
mission’s response seems to entail an enormous qualifica-
tion of its basic purpose. Of course an agency can pursue
a goal without being absolutely gung-ho, but for it to jus-
tify universal pregranted abandonment, which is lightly
supported on the present record, on the grounds that it
will do no harm to a customer that gives up the benefits
of the restructuring program, does not much advance its
argument. Moreover, the argument does not take account
of the customers who converted before they were on
notice that their transportation would not be as secure as
42a
the converted sales, despite the Commission’s apparent
promise to the contrary. See text above at 35.
By way of mitigation of § 284.221(d), the Commission
has committed itself to considering necessary deviations
from pregranted abandonment in individual GIC and rate
and service proceedings, or in response to individual com-
plaints. III FERC Stats. & Regs. at 31,728. Indeed, it cites
specific instances in which it has already determined that
a factual inquiry is necessary to determine whether a
pipeline might be able to use its monopoly power to
LDCs’ detriment. Jd. at 31,731. While such a safety valve
can help secure the validity of a basically sound rule, see,
e.g., the treatment of casinghead gas in the crediting
mechanism, above at 32, it cannot save one so poorly sup-
ported as this.
C. Conclusion.
As in any case of unreasoned decisionmaking, we do not
mean to suggest that the Commission is without power to
implement pregranted abandonment. In FPC v. Moss, 424
U.S. 494 (1976), for instance, the Commiesion successfully
defended limited-term certifications on the basis that its
goal of stimulating increased production outweighed one
of the basic features of natural gas regulation up to that
point — that producers were bound to continue to supply
gas beyond the terms of the contract until the Commis-
sion granted abandonment in an individualized proceeding
occurring at the time of the producer’s attempted end of
service — and the policies behind that tradition (Here, the
Commission has not yet adequately explained how pre-
granted abandonment trumps another basic precept of
natural gas regulation — protection of gas customers
from pipeline exercise of monopoly power through refusai
of service at the end of a contract period.
We remand the case to the Commission for reconsider-
ation of this point. We refrain from a reversal of
§ 284.221(d) because all parties appear to agree that it
makes sense for some transportation arrangements. There
is, for example, no claim that it is at all troubling as to
43a
interruptibie service; it would make no sense for us to
bring that even temporarily to an end. The same may well
be true of a wide range of short-term transportation
arrangements. But it is the Commission, not us, that can
identify those transactions for which pregranted abandon-
ment is most suitable, assuming it is to apply to less than
the entire universe. However, lest customers be cut off
from supplies or otherwise subjected to pipeline market
power under an insufficiently supported rule, we require
that the Commission address the matter in a final rule
within 90 days.
V. Miscellaneous Claims
A. Contract Demand Reduction.
As part of Order No. 436, the Commission provided
that any sales customer of an open access pipeline could
at its option reduce its contractual obligation to purchase
gas (its “contract demand” or “CD”). In AGD I, we held
that the Commission had failed to develop an adequate
rationale in support of this option. 824 F.2d at 1018-20.
On remand, although sticking to its guns as a policy mat-
ter, II] FERC Stats. & Regs. at 31,580-81, the Commission
decided not to repromulgate a generic customer entitle-
ment to CD reduction, choosing instead to approach it
case-by-case, id. at 31,582. It reasoned that this would
allow it to tailor any remedy to the facts such as the like-
lihood of its inducing rate reductions, risks of cost-shifting
to captive customers, and correspondence with actual cus-
tomer demand. Jd. at 31,581-82; see also id. at 31,724-27.
Some petitioners argue that because the Commission on
remand reiterated its belief that CD reduction is sound
policy (and had claimed in Order No. 436 that CD reduc-
tion was “essential” to open access), its decision not to act
across the board is arbitrary and capricious. But agency
discretion is at its peak in deciding such matters as
whether to address an issue by rulemaking or adjudica-
tion. See SEC v. Chenery Corp., 332 U.S. 194, 201-03
(1947); NLRB v. Bell Aerospace Co., 416 U.S. 267 (1974).
44a
The Commission seems on especially solid ground in
choosing an individualized process where important fac-
tors may vary radically from case to case. This discretion
remains even when the argument for generic CD reduc-
tion in a particular context appears very strong, such as
when a pipeline bypasses an LDC and sells directly to an
end user.
B. Take-or-pay Cost Passthrough.
1. Sunset date. In Order No. 500 and its successors,
the Commission established, and extended, a sunset date
after which pipelines would not be allowed to file under
its “equitable sharing” mechanism for passing through to
customers the costs of take-or-pay buyouts and buydowns.
In AGA I, we invalidated the sunset date because it forced
a pipeline to choose that mechanism (at the expense of
possible pursuit of others) before securing judicial review
of its adequacy. See 888 F.2d at 151. The court was also
concerned that even a sunset date falling after completion
of review would not allow a pipeline to file alternative
recovery proposals, and appeal the Commission’s rejec-
tion, without foregoing its ability to participate in the
Commission’s chosen mechanism. Jd.
In Order Nos. 500-H and -I the Commission established
a December 31, 1990 sunset date (with an extension until
30 days after completion of review if this case were pend-
ing on that date) “for the alternative passthrough
mechanism.” III FERC Stats. & Regs. at 31,533; see also
id. at 31,721 (sunset date “for the alternative, equitable
sharing mechanism”). In AGD II, 893 F.2d 349 (D.C. Cir.
1989), however, we struck down that mechanism as a vio-
lation of the filed rate doctrine. The full court has
declined to rehear the case en banc, 898 F.2d 809 (D.C.
Cir. 1990); we (the panel) granted a stay of the mandate
to allow the Commission to consider pursuit of certiorari
in the Supreme Court, and it has in fact filed for certio-
rari. 59 U.S.L.W. 3017 (U.S. June 21, 1990) (No. 89-2016).
At this point, therefore, there is nothing for us to
decide. Should AGD [IJ remain good law, the Commission
45a
will have to start over if it wants to adopt another pass-
through mechanism. The Commission’s language does not
suggest that it intended to apply the December 31, 1990
sunset date to any recovery proposal it should develop.
Pipelines could challenge such a novel reading on appeal
of a new recovery proposal. Should the Supreme Court
overturn AGD I], then any party aggrieved by the new
sunset date can challenge its validity. Until that happens,
however, we see no reason to review a time limit for use
of an invalid rule.
2. Opportunity to recover prudently incurred costs. Sev-
eral petitioners claim that the passthrough mechanism
adopted in the Order No. 500 series unlawfully denies
pipelines a reasonable opportunity to recover prudently
incurred costs. As we invalidated that mechanism from a
rather different perspective in AGD IJ, 893 F.2d at 354-57,
on the ground that it violated the filed rate doctrine, we
have no passthrough mechanism before us and such
claims are unripe. .
3. Continued use of passthrough mechanism. Implicit in
our stay of the AGD J mandate was a decision that the
Commission could wait until judicial review was complete
before complying with our decision. Grant of some peti-
tioners’ demand that we order an end to the Commis-
sion’s use of the mechanism in the meantime would be
inconsistent with that earlier judgment. Our mandate will
issue when the review process comes to a complete end;
the Commission may wait till then to unscramble the
equitable sharing egg.
C. Passthrough at the State Level.
Some parties complain that the Commission issued
what they view as “gratuitous dicta” on state regulators’
options for ensuring that LDCs shoulder a portion of the
take-or-pay costs passed through to them. III FERC
Stats. & Regs. at 31,723. On petitioners’ own characteriza-
tion, we have no jurisdiction to review these remarks. See
Office of the Consumers’ Counsel, Ohio v. FERC, 808 F.2d
125, 128-29 (D.C. Cir. 1987). The only possible injury
46a
LDCs have suffered — that state agencies might defer
excessively to FERC’s remarks — is not challengeable
here but in the relevant state proceedings.
VI. Conclusion
We conclude that the Commission has adequately
‘explained why no further steps — § 5 action, an enhanced
crediting mechanism, or any other — are necessary in
order to solve the take-or-pay problem or address the
effect of open access on the pipelines’ bargaining power
vis-a-vis producers. We uphold the orders under review,
remanding the case only for want of reasoned decision-
making on pregranted abandonment and so-called “double
crediting.”
So ordered.
47a
APPENDIX B
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
[18 C.F.R. Parts 2 and 284]
Before Commissioner: Martin L. Allday, Chairman;
Charles A. Trabandt,
Elizabeth Anne Moler
and Jerry J. Langdon.
Docket No. RM87-34-000
Regulation of Natural Gas Pipeline
After Partial Wellhead Decontroi
ORDER NO. 590-H
FINAL RULE
(Issued December 13, 1989)
[Table of Contents omitted in printing]
I. INTRODUCTION
The Federal Energy Regulatory Commission (Commis-
sion) is adopting this final rule, superseding the Order No.
500 interim rule,’ in response to the mandates of the
‘ Regulation of Natural Gas Pipelines After Partial Wellhead Decon-
trol, 52 Fed. Reg. 30,334 (Aug. 14, 1987), FERC Stats. & Regs., Reg-
ulations Preambles q 30,761, extension granted, Order No. 500-A, FERC
Stats. & Regs., Regulations Premables ¢ 30,770, modified, Order No.
500-B, FERC Stats. & REgs., Regulations Preambles q 30,772, modified
further, Order No. 500-C, FERC Stats. & Regs., Regulations Preamble
q 30,786 (1987), modified further, Order No. 500-D, FERC Stats. &
Regs, Regulations Preambles { 30,800, reh’g denied, Order No. 500-E,
43 FERC 4 61,234, modified further, Order No. 500-F, FERC Stats.
& Regs., Regulations Preambles { 30,841 (1988), reh’g denied, Order
No. 500-G, 46 FERC 4 61,148 (1989).
48a
United States Court of Appeals for the District of Colum-
bia Circuit in Associated Gas Distributors v. FERC (AGD),?
and American Gas Association v. FERC (AGA).® The final
rule continues, with certain modifications, the open access
transportation program originally adopted in Order No.
436‘ and kept in place on an interim basis by Order No.
500.
The AGD decision generally upheld the substance of
Order No. 436. The court, however, vacated and remanded
Order No. 436 to the Commission for it to, among other
things, “‘more convincingly address” the effects of various
provisions of Order No. 436 on pipeline take-or-pay prob-
lems.5 The AGA decision held that the Order No. 500
interim rule, issued in response to the AGD decision, did
not comply with the court’s mandate in that decision. The
court identified a number of areas where the Commission
had not adequately explained its actions, including its fail-
ure to take action under section 5 of the Natural Gas Act
(NGA)® to modify producer-pipeline take-or-pay contracts.
The court also held that the Commission improperly es-
tablished a sunset date for proposals to pass through take-
or-pay settlement costs under the alternative passthrough
2 824 F.2d 981 (D.C. Cir. 1987), cert. denied sub nom. Southern Cal-
ifornia Gas Co. v. FERC, 108 S. Ct. 1468 (1988).
* No. 87-1588, et al., (D.C. Cir., Oct. 16, 1989).
‘Regulation of Natural Gas Pipelines After Partial Wellhead De-
control (Order No. 436), 50 Fed. Reg. 42,408 (Oct. 18, 1985), FERC
Stats. & Regs., Regulations Preambles 1982-1985 4 30,665 (Oct. 9,
1985), modified, Order No. 436-A, 50 Fed. Reg. 52,217 (Dec. 23, 1985).
FERC Stats. & Regs., Regulations Preambles 1982-1985 4 30,675
(Dec. 12, 1985), modified further, 51 Fed. Reg. 6398 (Feb. 14, 1986),
reh’g denied, Order No. 436-C, 34 FERC 4 61,404 (Mar. 28, 1986),
reh’g denied, Order No. 436-D, 34 FERC 4 61,405 (Mar. 28, 1986),
reconsideration denied, Order No. 436-E, 34 FERC 4 61,403 (Mar. 28,
1986).
* 824 F.2d at 1044.
€15 U.S.C. § 717 (1988).
ae ees
ne ee eee
49a
mechanism established in Order No. 500 which took place
before the Commission had taken a final, reasoned position
on how this should be done.
The final rule continues in effect, with two modifica-
tions, the provisions of Order No. 500 requiring that a
producer offer to credit gas transported by a pipeline
against that pipeline’s take-or-pay liability to the producer
accruing under certain pre-June 23, 1987 gas purchase
contracts. The final rule provides that crediting will cease
on the earlier of December 31, 1990,’ or the date on which
a pipeline accepts a gas inventory charge certificate (GIC).
The final rule eliminates prospectively the provision that
pipelines may not apply credits against minimum take ob-
ligations for casinghead gas, but provides that a pipeline
must release the casinghead gas not taken so that it can
be marketed to another purchaser. Similarly, the final rule
provides that a pipeline must release any other gas not
taken as a result of applying credits against a must-take
obligation.
In response to the court’s concern about the sunset date
for the Order No. 500 alternative passthrough mechanism,
the final rule extends the sunset deadline until
December 31, 1990, the same dace as crediting will ter-
minate. If the United States Court of Appeals for the
District of Columbia Circuit has not completed judicia! re-
view of this final rule by that date, the Commission wiil
further extend the sunset date for the alternative passth-
rough mechanism until 30 days after the date of issuance
of the court’s mandate upon completion of judicial review.
The final rule makes no other changes in the Order No.
500 policy statement concerning pipelines’ passthrough of
‘If the United States Court of Appeals for the District of Columbia
has not completed judicial review of this final rule by that date, the
Commission will further extend the December 31, 1990, deadline until
20 days after the date of issuance of the court’s mandate upon com-
pletion of judicial review.
50a
take-or-pay settlement costs. The Commission will continue
to develop its policies on the passthrough of these costs
in individual cases.
The final rule does not take action under NGA section
5 to modify producer-pipeline take-or-pay contracts. After
a full review of the record in this case, including the data
obtained through the Commission’s Order No. 500 take-
or-pay data request, the Commission concludes that section
5 action would be ineffective or inequitable or both. Be-
cause the Commission’s section 5 authority is limited, sec-
tion 5 action could not bring about, and could discourage,
the complete restructuring of all pipeline-producer con-
tracts necessary to resolve fully the pipeline’s take-or-pay
problems and complete the transition to a competitive well-
head market. The Commission also believes that section 5
action would improperly interfere with the ability of par-
ties to rely on private contracts as a tool for structuring
basic economic relationships. Accordingly, since pipelines
have substantially resolved the bulk of their take-or-pay
problems through individually negotiated settlements and
since the provisions of the final rule discussed above should
enable pipelines to settle the remainder of their take-or-
pay problems, the Commission will not take section 5 ac-
tion.
The Commission is also continuing in effect, unchanged,
the policy statement on GICs as a means of avoiding a
future recurrence of the pipeline take-or-pay problems of
the 1980s. The Commission intends to develop further its
GIC policy in individual cases addressing pipeline proposals
to institute GICs.
The Commission has decided not to restore contract de-
mand reduction on a generic basis. However, restructuring
of the pipelines’ relationship with their customers contin-
ues to be an essential element of the Commission’s attempt
to foster competition in the natural gas industry. There-
fore, although the Commission will not restore the contract
5la
demand reduction option here, the Commission will require
parties to address contract demand reduction mechanisms
in conjunction with rate design proposals to implement
pricing schemes to ration capacity (including seasonal rates
and one-part demand rates) in individual rate cases,* and
in conjunction with pipeline proposals for GICs. The Com-
mission will, however, amend its regulations to provide for
automatic abandonment of pipeline sales obligations upon
a customer’s conversion to transportation.
The final rule also seeks information from Tennessee
Gas Pipeline Company and its customers in order to enable
the Commission to address the AGA court’s concerns re-
garding the Commission’s decision in the Order No. 500
interim rule not to eliminate retroactively the contract
demand reduction provision.
Il. THE RECORD UPON WHICH THE FINAL RULE IS
BASED
A voluminous record of comments and data submissions
by parties representing all segments of the natural gas
industry has been compiled in this proceeding. Comments
were filed by numerous parties in connection with all is-
sues arising under Order No. 500 and its several orders
on rehearing and modifications.? In Order No. 500-C, the
Commission specifically requested that the parties file,
among other things, information concerning the effects on
pipeline crediting rights of the various provisions adopted
in that order. The comments filed in response to these
requests have provided the Commission useful information.
The parties have also provided some additional information
in their rehearing requests of Order Nos. 500 and 500-C
and in various other miscellaneous filings.
* See Interstate Natural Gas Pipeline Rate Design, 47 FERC 4 61,295,
order on reh’g, 48 FERC 4 61,122 (1989).
* See n. 1, supra.
52a
Additional information available to the Commission with
respect to the status of the take-or-pay problem and the
pipelines’ outstanding take-or-pay exposure consists of a
large amount of data compiled from a variety of sources.
First, as indicated in Order No. 500, the Commission, on
August 26, 1987, issued a Take-or-Pay Data Request
(FERC Form No. 593) to 43 interstate natural gas pipe-
lines regarding their contracts with producers. Producers
were invited to file similar data. In response, 31 pipelines
submitted data on about 10,500 individual contracts. Seven
producers also voluntarily filed data. For the reporting
period covered by the data requests, January 1, 1983
through June 30, 1987, the pipelines reported on outstand-
ing take-or-pay exposure, settlements, prepayments, con-
tracts subject to take-or-pay and their categories under
the Natural Gas Policy Act of 1978 (NGPA),’° and other
related data. Attached as Appendix A to this rule is a
summary of the responses to the Commission’s take-or-
pay data request. With these data, the Commission has
been able to evaluate the developments in the take-or-pay
situation through the four and a half year period imme-
diately preceding the issuance of Order No. 500.
On April 11 and 12, 1988, the Commission convened a
public hearing on the Order No. 500 final rule. In con-
nection with that hearing both the Interstate Natural Gas
Association of America (INGAA) and the Natural Gas Sup-
ply Association (NGSA) submitted studies to the Commis-
sion concerning pipelines’ take-or-pay exposure through
1987. On April 22, 1988, the Commission issued a notice
setting forth the questions each Commissioner had asked
at the hearing and allowing all interested parties to file
written responses by May 27, 1988. Including among the
questions were a number concerning the INGAA and
NGSA studies. The Commission has used that material in
its analysis here as well.
© 15 U.S.C. §3301 (1988).
53a
On April 28 and May 19, 1989, in orders addressing
the March 31, 1989 filings made under Order No. 500’s
alternative mechanism for recovery of settlement costs,
the Commission requested additional information from 20
of the 22 pipelines passing through take-or-pay settlement
costs under the alternative passthrough mechanism. The
information was not requested from Southern Natural Gas
Company, since it had an already approved settlement con-
cerning its take-or-pay recovery. Also, because Valero
Transmission Company did not make a March 31, 1989
filing to recover take-or-pay costs, no information was re-
quested from it at that time. Specifically, the Commission
ordered each pipeline to file:
supporting documentation of its claimed take-or-
pay buyout and buydown costs and interest cal-
culation, including copies of all its settlements
with its producer suppliers with an explanation
of the take-or-pay exposure for each year settled
and the amount of exposure that was eliminated
through the settlements.”
In response, the 20 pipelines provided the Commission sub-
stantial information concerning their settlements and the
amount of relief obtained under them. That information
has been used in the analysis here. The two pipelines not
subject to this data request had filed similar information
earlier.
Additional data have also been obtained in pleadings, at
technical conferences, and in formal testimony in a variety
of individual cases for specific pipelines involving Order
No. 500 prudence reviews and reviews of buyouts and
buydowns alleged to be eligible for Order No. 500 direct
billing treatment.
4 See, e.g., United Gas Pipe Line Co., 47 FERC 4 61,153 at 61,491
(1989); Williams Natural Gas Co., 47 FERC 4 61,155 at 61,508 (1989).
54a
The Commission has also reviewed 10-K and 10-Q forms
filed by interstate pipelines with the Securities and Ex-
change Commission concerning their financial situations.
Finally, the Commission has had available to it significant
information concerning take-or-pay contained in various
trade and financial publications, including a September
1989 update by INGAA of its take-or-pay study.
Ill. THE FACTUAL BACKGROUND
A. The Development of the Take-or-Pay Issue.
The interstate pipelines’ take-or-pay problems of the
1980’s arose from the market distortions originally set in
motion by various policies of the 1960’s and early to mid-
1970’s. The artificially low controlled gas prices of those
years encouraged consumers to use natural gas, thereby
increasing demand, while at the same time discouraging
producers from exploring and drilling for new supplies,
thereby reducing supply. The resulting severe gas short-
ages in the interstate market led to enactment of th2
NGPA in 1978, in which Congress determined “‘that a new
system of natural gas pricing was needed to balance supply
and demand....’’* Accordingly, the NGPA provided for
a phased, partial decontrol of most new gas prices. The
NGPA also established increased (and increasing) ceiling
prices for first sales of new gas that remained controlled
and for some categories of old gas.
However, while the NGPA provided needed market in-
centives for new gas production and deliveries to the in-
terstate market, it also caused, at least in the short-term,
artificially high prices for new gas supplies. Because it
took time for producers to find and to produce new gas
supplies in response to the higher natural gas prices, and
for consumers also to respond to higher gas prices by for
example, installing equipment in order to switch to lower
2 Transcontinental Gas Pipe Line Corp. v. State Oil and Gas Board
of Mis. issippi, 474 U.S. 409, 417 (1986).
55a
priced alternative supplies, the increased prices could not
immediately bring supply and demand into balance. As a
result, prices were bid to higher levels than they would
have reached had prices not been kept artificially low in
the first place. This was exacerbated by the fact that the
NGPA continued low ceiling prices on most old gas sup-
plies, so that only new gas prices could respond to the
market. As a result, the overall wellhead price of natural
gas increased from 91 cents in 1978 to $2.43 in 1982, with
new gas prices going even higher."
The artificially high prices of the late 1970’s and early
1980’s caused producers to increase greatiy their explo-
ration and drilling for new gas supplies.’* By 1981, new
additions to gas reserves actually exceeded current pro-
duction, having averaged only 46 percent of current pro-
duction during the 10 years preceding enactment of the
NGPA. At the same time, pipelines, expecting demand to
continue at high levels and even increase, and recalling
their recent experience with curtailments, continued to en-
ter into long-term contracts to purchase additional gas
supplies at high prices and subject to high take-or-pay
requirements.
However, by 1982, demand for gas was falling. High
natural gas prices, combined with decreasing oil prices, led
to increased fuel switching, particularly as customers who
did not already have the necessary equipment to burn
8 United States Energy Information Administration (EIA), Natural
Gas Monthly, July 1983, Table 10 at 23.
Gas well completions jumped from 12,120 in 1977 to 19,910 in
1981. EIA, Monthly Energy Review, Table 5.2 (May 1989). As a result,
while reserve additions in the lower-48 states averaged only 46 percent
of annual production during the 10 years before the NGPA, they in-
creased to 90 percent of production in the period 1978-1984. See Ceiling
Prices; Old Gas Pricing Structure (Order No. 451), 51 Fed. Reg. 22,168
(June 18, 1986), FERC Stats. & Regs., Regulations Preambles 4 30,701
at 30,205-30,206.
56a
alternative fuels installed it. The recession of the early
1980’s and warmer than normal weather further decreased
demand. These factors combined to create an excess of
the supply of natural gas (i.e., current deliverability from
the nation’s gas wells) over the demand for natural gas.
The deliverability surplus persisted for the remainder of
the 1980’s. In 1982 the deliverability surplus was about
1.5 Tef, or 8.3 percent of total deliverability. By 1983,
with the demand for natural gas 17 percent below its 1979
level,’® the deliverability surplus was about 4 Tcf, or nearly
20 percent of total deliverability.’®
As a result of the reduced demand for gas, pipelines
began to incur significant take-or-pay liabilities under the
contracts entered into with the expectation of continued
high demand. The responses to the Commission’s 1987
take-or-pay data request indicate that, by year-end 1983,
pipeline take-or-pay exposure was $5.15 billion. Take-or-
pay exposure increased to $6.04 billion by year-enu 1984,
and $9.34 billion by year-end 1985.1”
However, in spite of the deliverability surplus, the av-
erage price paid at the wellhead continued to increase,
rising from $1.98 in 1981, to $2.43 in 1982, $2.59 in 1983
and $2.66 in 1984.'* The pipelines’ weighted average cost
of gas (WACOGs) also continued to increase, averaging
$2.01 in 1981, $2.46 in 1982, $2.76 in 1983, and $2.78 in
* Order No. 451, FERC Stats. & Regs., Regulations Preambles at
30,206.
6 Executive Enterprises Publications Co., Inc., The 1988 Natural Gas
Yearbook, Figure XI.
7 INGAA, based on a study published in September 1989, reports
that pipelines’ outstanding take-or-pay exposure was $4.7 billion at year-
end 1984, $6.1 billion at year-end 1985, and $10.0 billion at year-end
1986.
* EIA, Natural Gas Monthly, July 1983, Table 10 at 23; June 1989,
Table 4, at 14.
57a
1984.'® Similarly, the average residential cost of gas rose
from $5.17 in 1982 to $6.06 in 1983 to $6.12 in 1984”
While these price increases during a time of oversupply
were partly due to the automatic escalations in NGPA
ceiling prices, the more fundamental cause escalations in
NGPA ceiling prices, the more fundamental cause was the
inflexible supply arrangements between producers, pipe-
lines, LDCs, and consumers which had arisen in the earlier
era of a tightly price-controlled wellhead market.
Under these arrangements, most users of natural gas
could obtain gas only through purchases from a pipeline.
The pipelines generally exercised their monopoly power
over transportation by refusing to transport gas in com-
petition with their own sales (except where the customer
desiring the transportation could switch to alternative fuels
at little or no cost). Local distribution companies (LCDs)
were further discouraged from purchasing from sellers
other than the pipeline by minimum bills which required
them to pay a part of the pipeline’s demand and com-
modity costs, including its gas costs, even if they did not
purchase gas from the pipeline. These practices frustrated
the move toward a competitive wellhead market initiated
by Congress in the NGPA, since purchasers could not ob-
tain access to cheaper sources of supply than those pro-
vided by the pipelines, for example, by purchasing directly
from the producer. The result was unnecessarily high costs
for consumers of natural gas.
The Commission’s first major action to address these
supply arrangements was the issuance of Order No. 380
on May 25, 1984, requiring pipelines to eliminate com-
'* ETA, Natural Gas Monthly, June 1989, Table 5 at 18; EIA, Natural
Gas Monthly, December 1983, Table 24 at 44.
* EIA, Natural Gas Monthly, April 1988, Table 4 at 20.
58a
modity costs from their minimum bills.2) The Commission
has subsequently, on a case-by-case basis, eliminated pipe-
line minimum bills altogether.”
During 1985, with a deliverability, surplus of about 2
Tcf, or 16.5 percent of total deliverability,“ the average
wellhead price of gas fell for the first time since the gas
shortages of the 1970’s began, decreasing from $2.66 to
$2.51. However, pipelines’ WACOGs averaged only
slightly less in 1985 than in 1984 ($2.75, instead of $2.78),?°
and average residentia! prices remained at the same level
as in 1984, $6.12.%° Furthermore, even though many gas
purchasers were seeking to purchase gas directly in the
field at prices lower than the pipelines’ WACOGs, pipelines
continued to refuse to transport gas where such trans-
portation might displace the pipelines’ own sales. This dis-
21 Elimination of Variable Costs From Certain Natural Gas Pipeline
Minimum Commodity Bill Provisions, 49 Fed. Reg. 22,778 (June 1,
1984), FERC Stats. & Regs., Regulations Preamble. 1982-1985 4 30,571;
reh'g denied and stay granted in part, Order No. 380-A, 49 Fed. Reg.
31,259 (Aug. 6, 1984), FERC Stats. & Regs., Regulations Preambles
1982-1985 4 30,584; reh’g denied and order clarified, Order No. 380-
B, 29 FERC 4 61,076; reh’g denied, Order No. 380-C, 49 Fed. Reg.
43,625 (Oct. 31, 1984), FERC Stats. & Regs., Regulations Preambles
1982-1985 4 30,607; reh’g denied, Order No. 380-D, 29 FERC 4 61,332
(1984); affd in part, remanded in part sub nom. Wisconsin Gas Co. v.
FERC, 770 F.2d 1144 (D.C. Cir. 1985), cert. denied sub nom. Trans-
western Pipeline Co. v. FERC, 476 U.S. 1114 (1986); order on remand,
Order No. 380-E, 35 FERC 4 61,384 (1986); reh’g denied, Order No.
380-F, 40 FERC 4 61,190 (1987).
» F.g., East Tennessee Natural Gas Co., 40 FERC 461,201, reh’g
denied, 41 FERC 4 61,271 (1987), affd in part and rev'd in part, 863
F.2d 932 (D.C. Cir. 1988); Transwestern Pipeline Co., 32 FERC 4 61,009
(1985), reh’g denied, 36 FERC 4 61,175 (1986), aff'd, 820 F.2d 733 (5th
Cir. 1987), cert. denied, 108 Sup. Ct. 696 (1988).
#1988 Natural Gas Yearbook, Figure XI.
* EIA, Natural Gas Monthly, June 1989, Table 4 at 14.
* EIA, Natural Gas Monthly, June 1989, Table 5 at 18.
EIA, Natural Gas Monthly, June 1989, Table 4 at 14.
59a
placement, the pipelines reasoned, could cause them to
incur even greater take-or-pay liability, under the take-or-
pay contracts entered into during the 1970’s and early
1980’s than they were already incurring.
In addition, while the Commission authorized special pro-
grams under which pipelines were given blanket certifi-
cates to transport gas, the Commission limited the
purchasers to whom this gas could be transported to fuel
switchable, non-high priority end-users. The U.S. Court of
Appeals for the D.C. Circuit vacated the Commission or-
ders authorizing these programs, on the ground that the
Commission had failed to explain why requiring pipelines
to extend the benefits of these services to LDCs and cap-
tive customers would not increase the benefits to these
customers.”’
B. Order No. 436.
In response to these events, the Commission, on
October 9, 1985, issued Order No. 436, taking even more
fundamental action to address the pipelines’ continued ex-
ercise of their market power over transportation than the
Commission had taken in Order No. 380. In Order No.
436, the Commission found that the pipelines’ refusal to
transport gas in displacement of their own sales was un-
duly discriminatory because it caused increased costs to
consumers by denying them access to gas at the lowest
reasonabie prices. The Commission found that the refusal
to transport was adversely affecting the economy and the
nation. The refusal to transport was also frustrating the
goal of the NGPA of relying on a competitive wellhead
market.
In light of these findings, the Commission exercised its
broad jurisdiction over transportation of natural gas under
the NGA and the NGPA to revise its regulations governing
2? Maryland People’s Counsel v. FERC, 761 F.2d 780 and 768 F.2d
450 (D.C. Cir. 1985).
60a
the interstate transportation of natural gas. First, the
Commission required that all pipelines performing self-im-
plementing transportation, either pursuant to blanket NGA
section 7(c) certificates or NGPA section 311 (other than
certain transportation under grandfathered authorizations),
provide such transportation on a nondiscriminatory basis,
and thereby become open-access transporters. Second, the
Commission held that a pipeline’s refusal to transport gas,
because it would displace its own sales or because it had
not obtained relief from its take-or-pay contracts with pro-
ducers, would be unduly discriminatory.
Third, the Commission required open-access pipelines to
agree to allow their firm sales customers to adjust their
“contract demand”’ (CD) (the maximum amount of gas the
customer is contractually entitled to purchase on any day),
either to reduce the level or convert it from firm sales to
a right to firm transportation. These options were intended
to allow full requirements and other customers of a pipe-
line to take advantage of transportation by purchasing gas
from another supplier and have it transported either over
that or another pipeline. The CD reduction option was also
intended to reduce the pipeline’s presently contracted firm
capacity so that the transmission capacity could be avail-
able to other shippers.
Fourth, the Commission adopted optional procedures in
Order No. 436 for granting certificates for new facilities,
services, and operations intended to facilitate a pipeline’s
entry into and exit from new markets to compete with
existing suppliers and thereby give local distribution com-
panies and other customers, previously limited to one sup-
plier, access to other suppliers. The Commission also
provided for expedited abandonment of gas supplies (i.e.,
producer supplies), subject to reduced takes, in order that
those supplies could be made available to different cus-
tomers.
_ nal
6la
Last, the Commission did not take specific new action
in Order No. 436 to relieve pipelines from their take-or-
pay contracts. The Commission did not take action to mod-
ify producer-pipeline contracts largely because it believed
that such action ‘‘would raise extremely serious questions
regarding the ability of private parties in the gas produc-
tion industry to rely on private contracts as a tool for
structuring basic economic relationships’ and thus could
adversely affect the move toward a deregulated gas com-
modity market started by the NGPA. The Commission did,
however, reaffirm its April 1985 policy statement and in-
terpretative rule on payments to settle the take-or-pay
liabilities under those contracts. In that policy statement
and interpretative rule, the Commission held, among other
things, that settlement payments do not violate NGPA
Title I ceiling prices and that the Commission would eval-
uate the pipeline’s recovery of settlement costs in individ-
ual rate filings. The Commission stated that, pursuant to
these policies, pipelines had “‘made progress in renego-
tiating their contracts and substantial liabilities have been
settled.’ The Commission also stated that it would con-
sider any requests for abandonment necessary to carry out
a settlement of a take-or-pay obligation on an e<pedited
basis.*° Finally, the Commission stated that it lacked au-
thority to modify contracts for the sale of non-jurisdictional
gas and that it would be inequitable to modify only the
contracts still subject to the Commission’s NGA jurisdic-
tion.
* Order No. 436-A, FERC Stats & Regs., Regulations Preambles
1982-85 ¢ 30,665 at 31,492-3 (1985).
* Order No. 436-A, Jd. at 31,661. The Commission included in Order
No. 436-A a table showing that pipelines had filed with the Commission
to recover about $80 million in settlement payments. In return for
those payments, the producers had given the pipelines over $470 million
of take-or-pay relief.
* 18 C.F.R. § 2.76, 50 Fed. Reg. 16,076 (Apr. 24, 1985), FERC Stats.
& Regs., Regulations Preambles 1982-1985 4 30,637.
62a
C. Economic Developments after Order No. 436.
In 1986, the first full year following issuance of Order
No. 436, pipelines for the first time transported for others
more gas than they sold. See Table 3. Pipeline sales de-
creased from about 11 Tcf to under 8 Tcf, while trans-
portation increased from 8.6 Tcf to 9.6 Tcf.*! With the
deliverability surplus continuing and, indeed, increasing
from 16.5 percent of total deliverability in 1985 to 19.5
percent in 1986,°* wellhead prices declined even more
sharply than they had in 1985, decreasing from an average
of $2.51 to $1.94. Furthermore, for the first time, the
decrease in wellhead prices began to flow through to res-
idential consumers, with residential prices finally dropping
from an average of $6.12 during 1985 to an average of
$5.83 during i986.°* Prices to commercial and industrial
users fell even more steeply, from an average of $5.50
during 1985 to $5.08 during 1986 for commercials and an
average of $3.95 to $3.23 for industrials.** Thus, in 1986,
consumers and other users began to realize the benefits
of competition in the natural gas industry.
During 1986, pipelines also continued to accrue take-or-
pay liabilities. With pipeline sales decreasing by even more
than they had in 1985, pipelines’ outstanding take-or-pay
obligations continued to increase, although at a slower pace
than in 1985. While pipeline take-or-pay exposure had in-
creased from $6 billion to $9.34 billion in 1985, it increased
to $10.7 billion in 1986. Although pipelines’ take-or-pay
exposure was increasing, pipelines were also entering into
significant take-or-pay settlements with producers. In fact,
* EIA, Statistics of Interstate Natural Gas Pipeline Companies 1987,
Table 12 at 46.
* 1988 Natural Gas Yearbook, Figure XI.
ss’ EIA, Natural Gas Monthly, June 1989, Table 4 at 14.
* EiA, Natural Gas Monthly, June 1989, Table 4 at 14.
*s EIA, Natural Gas Monthly, June 1989, Table 4 at 14.
63a
according to the responses to the Commission’s 1987 take-
or-pay data request, by mid-1987, pipelines had resolved
nearly $14 billion of take-or-pay exposure through settle-
ments which in no year averaged more than 17 cents on
the dollar. See Table 1.% The take-or-pay exposure so re-
solved was about 56 percent of the over $24 billion take-
or-pay liability incurred by pipelines through the middle of
1987. Pipelines received additional take-or-pay retief
through release agreement credits. By mid-1987 pipelines
had released 1,831 TBtu of gas in return for such credits.
During 1986 and the first half of 1987 the amount of
take-or-pay exposure pipelines were able to resolve through
settlements and credits increased dramatically over the
amount similarly resolved in 1985, although the cents on
the dollar paid for these settlements also increased. In
1986 pipelines settled $5.09 billion in take-or-pay exposure
compared to $1.95 billion in 1985. During the first half of
1987, pipelines settled another $3 billion in take-or-pay
exposure. The cents on the dollar paid for these settle-
ments increased from 10 cents in 1985 to 12 cents in 1986
and 17 cents in the first half of 1987. As was the case
with take-or-pay relief through settlements, take-or-pay re-
lief through release agreement credits also increased. Vol-
umes released with credits increased from 401 TBtu in
1985 to 541 TBtu in 1986 and 541 TBtu in just the first
half of 1987.
While the deliverability surplus resulting from the mar-
ket distortions of the 1970’s and early 1980’s continued
to cause pipelines to incur take-or-pay liabilities under their
* The data set forth in Tables 1 and 5 in the Appendices A and B
are based on information supplied to the Commission by the pipelines
in response to Commission data requests. The reported dollar amounts
were derived according to the format and methodology specified by the
Commission in the data request for standardizing the data or were
estimates and may not reflect the actual take-or-pay liability or ben. «t
obtained by a pipeline under a particular take-or-pay contract.
64a
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65a
contracts, by 1985 and 1986 it was also causing many
producers significant problems. The average wellhead price
for gas, which had decreased from its $2.66 peak in 1984
to $2.51 in 1985, decreased even more to $1.94 in 1986.°*’
Total consumption, which had fallen in 1985, continued to
fall in 1986; consumption in 1986 was about 16 Tcf as
compared to about 18 Tcf in 1984. After 1983, pipelines
reduced their take levels substantially below take-or-pay
requirements in their contracts,** and did not honor the
bulk of their resulting take-or-pay claims. The responses
to the Commission’s 1987 take-or-pay data request indicate
that although pipelines had incurred total take-or-pay ex-
posure of over $24 billion or more during the period
January 1, 1983 through June 30, 1987, during the same
period they made take-or-pay payments for gas totalling
only $700 million or $.7 billion.‘
Perhaps the primary purpose of take-or-pay clauses is
to guarantee producers a minimum level of income in order
to pay off loans and cover current operating expenses.‘
Producers must make substantial investments in order to
#7 EIA, Natural Gas Monthly, June 1989, Table 4 at 14.
8 1988 Natural Gas Yearbook, Table XI.
** The responses of the Commission’s take-or-pay data request show
that, in the aggregate, during the period 1983 through 1986 pipelines
took about 44 percent of deliverability while their take-or-pay obliga-
tions were about 66 percent of deliverability.
“ Another $14 billion of exposure was settled by payments of 17
cents on the dollar during 1987 and lesser amounts during earlier years.
“ Take-or-pay clauses have also been included in producer-pipeline
contracts for other purposes. For example, the ultimate amount of
natural gas recoverable from some reservoirs is greater if the gas is
produced at a high rate. This is true of the large number of water-
drive reservoirs in the Outer Continental Shelf (OCS). In many of those
reservoirs, unless the gas is produced at a rapid and relatively constant
rate, water can entrap a part of the gas in the reservoir, making it
impossible to produce the entrapped gas. A take-or-pay clause serves
to encourage the necessary takes of gas.
66a
explore for, and produce, natural gas. Often, the necessary
private financing would be unavailable in the absence of a
take-or-pay or similar clause providing for revenue to pay off
loans. The take-or-pay clause thus serves as a legitimate, bar-
gained-for risk allocation mechanism and requires pipelines
and their customers to compensate the producer in part for
the risks the producer incurs in making substantial invest-
ments in order to meet the supply needs of these pipelines
and their customers. Producers thus made substantial invest-
ments and banks and others made substantial loans in reliance
on the take-or-pay clauses in their contracts with pipelines.
Pipelines failure to make prepayments meant that producers
were not receiving the revenue they had anticipated.
The loss of revenue to producers during the mid- and
late 1980’s as a result of falling gas prices, falling sales,
and few take-or-pay payments, combined with a simulta-
neous decrease in oil prices, has had serious adverse effects
not onlv on producers, but on the entire economies of the
producing regions of the nation. Many producers, particu-
larly small producers, went bankrupt, defaulting on loans
from banks secured in part on the basis of minimum rev-
enue levels provided for by the take-or-pay clauses in their
sales contracts. This in turn caused numerous banks in the
producing regions to fail, with the result that the Federal
Deposit Insurance Corporation (FDIC), through foreclosures
of producer properties, is now a substantial oil and gas
lease owner.” As the effects of the producers’ loss of rev-
enue spread through the economies of the producing regions
of the nation, the unemployment levels in those regions
rose significantly above the national average.“
While these adverse effects have for the most part been
limited to producing states, the collapse in exploration for
« See Petition of FDIC, filed December 31, 1987.
*“ See Table 2 comparing the unemployment rates in Texas and Lou-
isiana from 1975 to 1989 to the national average unemployment rates
during the same period.
67a
TABLE 2
CIVILIAN UNEMPLOYMENT RATES
JUNE, 1989
1975 -
— —
_ mM
_ _
i '
ro
——
T
1
LOUISTANA
|
UNITED STATES
Bh ® BI
SOURCE: BUFEAU OF LABOR STATISTICS
82
68a
new gas supplies, if continued, could create the potential
over the long term for new gas shortages, with all the
same adverse effects for the nation as the shortage of the
1970s.
D. The AGD Decision.
Numerous parties appealed Order No. 436 to the United
States Court of Appeals for the District of Columbia Cir-
cuit. On June 23, 1987, the court issued its decision in
Associated Gas Distributors v. FERC (AGD). The court
generally upheld the substance of Order No. 436. The court
observed that the Commission had found: ‘‘(a) that pipe-
lines continue to possess substantial market power; (b) that
they have exercised that power to deny their own sales
customers, and others without fuel-switching capability, ac-
cess to competitively priced gas; and (c) that this practice
has denied consumers access to gas at the lowest reason-
able rates.’’** The court found that these findings were
basically unchallenged by the parties seeking to overturn
the Commission’s order. The court upheld the Commis-
sion’s authority under the NGA and the NGPA to require
that all pipelines performing self-implementing transpor-
tation must do so on a not unduly discriminatory basis.
The court also upheld the rate provisions of Order No.
436, the optional certificate procedures, and the Commis-
sion’s earlier policy statement relating to buyouts of take-
or-pay obligations.
The court, however, remanded Order No. 436 to the
Commission for it, among other things, to “more con-
vincingly address’ the take-or-pay issue.*® The court con-
cluded that the Commission had failed to give reasoned
consideration to claims that open-access transportation
would deny pipelines the bargaining power necessary to
settle their take-or-pay liability with producers and would
“ 824 F.2d at 999.
“© 824 F.2d at 1004.
69a
have the effect of decreasing pipelines’ gas sales and im-
posing the resulting increase in take-or-pay costs on those
customers unable, or unwilling, to buy gas from non-pipe-
line suppliers. The court, however, specifically declined to
“require that FERC reach any particular conclusion’’ with
respect to the take-or-pay issue, stating that it “‘merely
mandate[d] that [the Commission] reach its conclusion by
reasoned decision-making.’
E. Order No. 500.
On August 7, 1987, to coincide with the issuance of the
court’s mandate in the AGD case, the Commission issued
Order No. 500, entitled “Interim Rule and Statement of
Policy.”” Order No. 500 was issued in order: (1) to ensure
that open-access transportation arrangements ‘‘remain in-
tact,’’*’ and (2) to meet the court’s concerns regarding,
inter alia, the take-or-pay liability of the pipelines resulting
from open-access transportation. The Commission ex-
plained that it was taking a “series of interrelated actions
designed to substantially mitigate the effects of... [its
open-access] rule on pipeline take-or-pay problems and to
provide some relief from take-or-pay problems not related
to or aggravated by the [open-access] transportation reg-
ulations.’’*
Stressing that ‘‘all segments of the industry should
shoulder some of the burden of resolving the [take-or-pay]
problem,’’** the Commission took the following actions:
(1) the adoption of a crediting requirement, as a condition
on open-access transportation, designed to minimize ag-
gravation of take-or-pay problems and assist pipelines in
the negotiation of take-or-pay obligations; and (2) the is-
suance of two policy statements, one announcing a method
“ 824 F.2d at 1030.
“ FERC Stats. & Regs. at 30,799.
“FERC Stats. & Regs. at 30,779.
“ FERC Stats. & Regs. at 30,779.
70a
of allocating take-or-pay settlement costs equitably among
pipelines and their customers and the other announcing
standards for a new gas inventory charge designed to
prevent future accumulation of unfunded take-or-pay
costs.”
The Commission’s crediting rule required producers to
make an offer of credit for transported volumes against
take-or-pay liability as part of request for transportation
services.*! Specifically, a pipeline would have no obligation
to transport a particular producer’s gas unless that pro-
ducer offered to credit the volumes to be transported
against the pipeline’s existing take-or-pay liability under
any pre-June 23, 1987 contract with the producer.®* The
Commission explained that this crediting requirement was
intended to help prevent aggravation of take-or-pay lia-
bility particularly because it would permit credits to be
applied against any such contracts, including high-cost con-
tracts, and a pipeline would not have to show any dis-
placement of its own sales volumes in order to obtain this
credit.” Following Order No. 500, the Commission made
various adjustments to the crediting mechanism in Order
Nos. 500-B** and 500-C.*% These adjustments addressed
concerns raised in comments on and requests for rehearing
of Order No. 500.
“In addition, the Commission stated its intent to require that pipe-
lines submit “information relating to their take-or-pay problems... in
order to assist the Commission in developing a final rule.’”” FERC Stats.
& Regs. at 30,779. Subsequently, the Commission served pipelines with
a data request to elicit data about take-or-pay, and invited producers
to submit the same type of data.
* FERC Stats. & Regs. at 30,780.
* FERC Stats. & Regs. at 30,847.
* FERC Stats. & Regs. at 30,780.
“FERC Stats & Regs., Regulations Preambles q 30,772 (1987).
* FERC Stats. & Regs., Regulations Preambles 4 30,786 (1987).
’
7la
The Commission’s two policy statements dealt with the
allocation of take-or-pay costs between pipelines and their
customers. The first dealt with the passthrough mecha-
nisms, and related procedures, that pipelines could utilize
to recover the costs of buying out or buying down existing
take-or-pay obligations, i.e., the costs of settling claimed
liabilities under existing contracts with producers and/or
reforming take-or-pay and other provisions in those con-
tracts. The mechanism and procedures were, as the Com-
mission stressed, adopted in light of comments received
in response to the proposed take-or-pay policy statement
issued in FERC Docket No. PL87-3-000.*”
The buyout, buydown policy statement reiterated that
all pipelines—whether or not they agreed to open-access
transportation—would be permitted to pass through all
prudently incurred settlement costs in their sales com-
modity charge. The Commission also provided for an al-
ternative, equitable sharing mechanism, under which open-
access pipelines, if they agreed to absorb between 25 per-
cent and 50 percent of their take-or-pay costs, could apply
to recover an equal share of the costs through a fixed
charge. If a pipeline were to elect to absorb less than 50
percent, the costs remaining after an equal amount were
assigned to the fixed charges could be assigned for re-
covery through a volumetric surcharge applied to both sales
and transportation throughput.*
As part of this policy statement, the Commission also
adopted a rebuttable presumption that, where a pipeline
agreed to absorb at least 25 percent of its take-or-pay
costs, the remaining costs that could be passed through
were prudently incurred. The Commission stated its intent
not to initiate prudence reviews on its own motion in such
“ FERC Stats. & Regs., at 30,784.
*' 52 Fed. Reg. 7478 (1987), 38 FERC 4 61,230.
“FERC Stats. & Regs. at 30,789-90.
72a
circumstances. Intervening parties would be permitted,
however, to challenge the passthrough on grounds of im-
prudence. In that event, the pipeline could then recover
from such intervening party whatever amount (up to 100
percent) that the pipeline proved was prudent.*
In addition, the Commission adopted a “‘sunset’’ provi-
sion providing that the equitable sharing mechanism would
be available for a year and a half from the effective date
of Order No. 500—1.e., until December 31, 1988—in order
to resolve take-or-pay problems and recover the resulting
costs.” In subsequent orders on rehearing, the Commis-
sion, inter alia, adopted an extension, from the
December 31, 1988 date to March 31, 1989, “‘for the filing
of final tariff sheets including al] take-or-pay buyout and
buydown costs eligible for recovery under the [equitable
sharing] mechanism.’’* The Commission also adopted the
“litigation exception” to the sunset provision. For pro-
ducer-pipeline contracts that were in litigation or arbitra-
tion on March 31, 1989, “the Commission will permit a
pipeline to file by that date to include in its tariff language
permitting the pipeline to pursue the litigation to its nat-
ural end of judgment and final appeal or settlement and
then to file to recover eligible costs resulting from these
contracts under the equitable sharing mechanism.’’®
In its second policy statement, the Commission adopted
certain principles to avoid the recurrence of unfunded take-
or-pay costs in the future, by “‘establish[ing] the param-
eters in which pipelines may file to recover the costs of
maintaining supply for their customers.” To that end,
“ The Commission has subsequently decided in individual passthrough
cases that any additiona! amounts to be recovered by the pipeline would
be recovered through a fixed take-or-pay charge.
“FERC Stats. & Regs. at 30,792.
© FERC Stats. & Regs. at 31,267.
“ FERC Stats. & Regs. at 31,268.
© FERC Stats. & Regs. at 30,792.
73a
the Commission stated it would allow any open-access pipe-
line to adopt, in its tariff, a Gas Inventory Charge (GIC)
for “standing reacy” to satisfy its firm sales customers’
contract requirements.“ The Commission explained that
this policy was intended to allow pipelines to require firm
sales customers to pay on a current basis, through this
charge, the non-facilities costs of maintaining gas supply
for the system. The Commission stated that, by contrast,
under existing one-part purchase gas rates, a pipeline must
contract for supplies and stand ready to satisfy its sales
customers’ contract requirements, but its customers are
not required to pay for this service on a current basis. In
existing sales rates, the demand component consists only
of costs for transportation facilities. The gas sales reser-
vation component is paid, perhaps years later, in the form
of passed-through take-or-pay charges.
The Commission reasoned that the GIC would have the
dual effects of making a pipeline’s customers ‘‘careful in
nominating their demand because they will pay on a cur-
rent basis for excessive nominations” and make a pipeline
“more careful in contracting for long-term supplies’’ be-
cause customers would be unwilling to pay on a current
basis the costs of maintaining excessive supplies.“ The
Commission explained that, through the GIC, it was ‘‘seek-
ing to establish a rational, efficient pricing structure for
the pipeline merchant function with emphasis on reciproc-
ity and consideration of service obligations under the in-
creased options available to a pipeline’s sales customers.’’*’
“FERC Stats. Regs. at 30,792.
* FERC Stats. & Regs. at 30,793.
“FERC Stats. & Regs. at 30,793.
“ FERC Stats. & Regs. at 30,794.
74a
F. Economic Developments after Order No. 500.
In 1987 and 1988, transportation by pipelines increased
from about 9.6 Tcf during 1986® to over 15 Tcf during
1988.® Pipeline sales continued to decline, although at a
slower rate than during the two preceding years. Sales
decreased from about 7.8 Tcf during 1986” to about 5 Tcf
during 1988.” Both wellhead prices and pipeline WACOGs
fell significantly in 1987 and then stabilized in 1988. In
1987, wellhead prices fell from an average of $1.94 in 1986
to an average of $1.67,” and WACOGs fell from an av-
erage of $2.32 in 1986 to an average of $2.05." In 1988,
wellhead prices and WACOGs remained essentially *he
same, at $1.71 and $2.04 respectively. A survey by the
American Gas Association of 55 LDCs found that by 1988,
LDCs’ customers had benefitted significantly from the spot
gas purchases made possible by open access transportation.
The survey showed that in 1984 an average residential gas
customer paid $594 for 100 Mcf of gas, but in 1988 the
same customer paid $530. Adjusted for inflation, and shown
in 1984 constant dollars, the cost for 100 Mcf of gas fell
21 percent, from $594 to $471."
Until 1987, as transportation by pipelines increased and
their sales decreased (reducing the pipelines’ ability to take
* EIA, Statistics of Interstate Natural Gas Pipeline Companies 1988,
Table 12 at 46 (November 1989).
** EIA, Statistics of Interstate Natural Gas Pipeline Companies 1988,
Table 12 at 46 (November 1989).
% EIA, Statistics of Interstate Natural Gas Pipeline Companies 1988,
Table 12 at 46 (November 1989).
7 EIA, Statistics of Interstate Natura] Gas Pipeline Companies 1988,
Table 12 at 46 (November 1989).
7 EIA, Natural Gas Monthly, June 1989, Table 4 at 14.
7? EIA, Natural Gas Monthly, June 1989, Table 5 at 18.
% State Treatment of Take-or-Pay Settlement Costs, 17 Gas Energy
Review 2, 3 (September 1989).
75a
gas) the pipelines’ take-or-pay liabilities had also grown.
However, as illustrated by the graph in Table 3,” this
pattern reversed dramatically beginning in 1987. Although
pipelines sales continued to decline, outstanding take-or-
pay exposure fell at an increasing rate. By March 1989,
pipeline take-or-pay exposure was less than 25 percent of
its level at the end of 1986, the last full year before Order
No. 500. The responses to the Commission’s take-or-pay
data request indicated that, at the end of 1986, pipelines
had accrued take-or-pay “exposure” of $10.7 billion. A
survey by INGAA of its member pipelines representing
over 90 percent of total pipeline throughput similarly
showed take-or-pay exposure at the end of 1986 to be $10.0
billion. However, INGAA, in its September 1989 take-or-
pay study, has reported that during 1987 take-or-pay ex-
posure fell to $8.2 billion, during 1988 to $3.8 billion, and
by March 31, 1989 was $2.4 billion. The INGAA data are
consistent with the Commission’s own information, and are
further confirmed by a report prepared by NGSA, an as-
sociation of producers. The NGSA report declared that
“‘take-or-pay liability problems ... have been substantially
resolved and are now a thing of the past.’’*® The NGSA
study, based on an analysis of take-or-pay obligations of
23 interstate pipelines to 18 producers, shows that 95 per-
**In Tables 3 and 4, year-end data for one year is attributed to the
beginning of the subsequent year. For example, 1986 year-end take-or-
pay exposure is treated as 1/87 take-or-pay exposure.
** Natural Gas Supply Association, A Status Report on the Interstate
Pipeline Take-or-Pay Situation: Substantial Resolution Through Year-End
1988, at 1 (May 1989). See also a report recently issued by NGSA, Natural
Gas Supply Association, A Status Report on Current Interstate Pipeline
Take-or-Pay Liabilities for Jurisdictional and Non-Jurisdictional Gas and the
Prospects for Future Liability Accrual Associated with Jurisdictional Gas
at 8-9 (November 30, 1989). NGSA reports that the total take-or-pay liability
to these producers as of August 1, 1989 was $608 million. Similar to the
other trade association take-or-pay surveys mentioned throughout this order,
the Commission notes, without endorsing, the wide disparity in the various
estimates for the remaining take-or-pay problem.
76a
TABLE 3
SELECTED GAS INDUSTRY TRENDS
- MARCH 31, 1989
1981
6 0 TOF/$ BILLIONS
GAS SALES (TCF)
12.0 F Sax.
{0.0}
U0} gs macro
| 8 3
40F
2.0}
0. rrr ae Seer Serre a ae ee ee ee ae ae ee a ee
| ie 7m 7 mS
"ot
"e ott
77a
TABLE 4
GAS PRICES AND TAKE-OR-PAY EXPOSURE
1980 - MARCH 31, 1989
40
j.0
$/MF
§ BILLIONS
T
PIPELINES” NACOG
AVG WELLHEAD PRICES
ad
20/
1o- TAKE-ORPAY EXPOSURE t
& Te 1/82 1/8 1/84 1/6 1/6 1/87 1/8 1/69
nf) je 0 =~ M1 7m i / eV
SUES ETA, INGMA, FERC DATA
ht
i
I
10
78a
cent of the pipelines’ outstanding take-or-pay obligations
to those producers had been resolved by the end of 1988.
Given pipelines’ continued loss of sales and resultant
lower takes of gas, the simultaneous dramatic decrease in
their take-or-pay exposure could only have occurred as a
result of a fundamental restructuring of pipelines’ con-
tractual arrangements with producers and settlement of
previous take-or-pay exposure. In fact, since the issuance
of Order No. 500, all but two of the pipelines reporting
take-or-pay exposure at year-end 1986” have filed to pass
through, under the Order No. 500 equitable sharing mech-
anism, their costs of renegotiating and settling already
accrued take-or-pay costs and reforming take-or-pay con-
tracts for the future.* The 22 pipelines using the alter-
native mechanism have reported, in response to the
Commission’s data requests in its April 28 orders con-
cerning the pipelines’ March 31, 1989 passthrough filings,
that these settlements have reduced their outstanding take-
or-pay obligations by over $16 billion.”* The pipelines fur-
ther stated that their settlements with producers have re-
formed the contracts under which they will purchase gas
in the future and have reduced the future potential for
incurrence of unfunded take-or-pay costs. According to the
7 The two pipelines which reported take-or-pay exposure but have
not filed to recover costs under the Order No. 500 alternative mech-
anism are Florida Gas Transmission Co. and Mid-Louisiana Gas Co.
Florida Gas reported exposure of only $26 million at year-end and Mid-
Louisiana reported exposure of only $2 million.
% The Commission has issued approximately 300 orders on over 50
proposals by these 22 pipelines to recover the costs of their take-or-
pay settlements with producers and on over 60 proposals by down-
stream pipelines to pass those costs through to their customers.
” The derivation of this figure is shown in column 3 of Table 5. This
figure is greater than the approximately $10 billion in outstanding
exposure at the end of 1986, because pipelines have settled not only
their outstanding obligations as of the end of 1986, but also exposure
which they appear to have incurred from 1987 to the present.
79a
pipelines, these features of their settlements with produc-
ers will reduce their future take-or-pay costs by about
$12.2 billion® and reduce other future costs by about $15.4
billion,®! for total future relief of nearly $28 billion.*®
Thus, pipelines have received total relief under their
settlements with producers worth approximately $44 billion
($16 billion plus $28 billion). As shown in detail in Ap-
pendix B, these settlements have substantially resolved the
existing take-or-pay liabilities of most pipelines, and al] the
pipelines have made significant progress in resolving their
problems. For example, the President of E] Paso Natural
Gas Company, on July 6, 1989, in a letter to the Chairman
of the Commission, stated, “[e]xcluding a single, large take-
or-pay case presently in litigation, about 95 percent of El
Paso’s take-or-pay exposure has been fully resolved through
settlements, and almost al] of the remainder is in litigation.
Thus, as the Commission hoped in Order No. 500, E] Paso
has effectively reformed its gas supply base and is row
only dealing with those relatively few residual matters that
remain in the courts.’’®
The substantial progress described above in resolving
both past and potential future take-or-pay exposure ap-
* The derivation of this figure is shown in column 4 of Table 5.
* This figure is the sum of columns 5 and 6 in Table 5.
* The derivation of this figure is shown in column 7 of Table 5.
*® The derivation of the $44 billion figure is shown in column 8 of
Table 5. Southern has not filed information with the Commission con-
cerning the relief it obtained in exchange for the $700 million in set-
tlement payments it has made to producers. Southern settled al! take-
or-pay issues with its customers and that settlement was approved by
the Commission prior to the April 28, 1989 data request. If the relief
obtained by Southern were included, the $44 billion figure would be
higher.
“ Letter of William A. Wise, President and Chief Operating Officer,
E] Paso Natural Gas Company to then-Chairman Hesse, Docket No.
TA89-1-33-000, et al., July 7, 1989, at 3.
80a
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82a
pears to have been accomplished, for the most part, in a
manner consistent with the Commission’s goal that all seg-
ments of the industry shoulder the burden of resolving the
take-or-pay problem. See Table 5. While, as discussed
above, pipelines’ past exposure has been reduced by over
$16 billion, and future take-or-pay and other costs by nearly
$28 billion, for total relief of $44 billion, pipelines have
paid producers $8.2 billion under the settlements.® The
settlement payments to producers represent only 18.6 per-
cent of the total relief they have given pipelines.* Pro-
ducers’ agreements to receive an average of 18.6 cents on
the dollar appear to represent real and substantial conces-
sions in light of the fact that, where producers have pur-
sued their claims in court, courts have almost uniformly
ordered pipelines to pay producers the full amount of their
take-or-pay obligations under the applicable contract.
Although under most of the settlements the producers
retain the gas for which the pipelines had been obligated
to make take-or-pay payments, and thus the producers can
sell that gas to other purchasers, the take-or-pay contracts
generally provided that the pipelines forfeited after five
years any right to take the gas for which prepayments
were made. Thus, without the settlements, the producers
would have been able to sell any gas not made up upon
expiration of the contract in addition to retaining the pre-
payments. In light of the producers’ significant concessions
in their settlements with pipelines, it appears that pro-
ducers have continued to shoulder a substantial portion of
the burden of resolving the take-or-pay problems.
Pipelines have also shouldered a significant part of the
burden of resolving the take-or-pay problem, rather than
passing all the costs through to their customers.*’ Under
* The derivation of this figure is shown in column 2 of Table 5.
* The derivation of these figures is shown in column 9 of Table 5.
* The AGD court admonished against pipelines “‘simply moving costs
downstream to customers.” See 824 F.2d at 1025.
ct ali
83a
Order No. 500’s equitable sharing mechanism, the pipelines
are absorbing 39.3 percent of the $8.6 billion in payments
to producers included in Order No. 500 filings or about
$3.4 billion, while recovering through a fixed take-or-pay
charge another 39.3 percent
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