Appendix — California v. Tenneco Oil Co.
Supreme Court brief1984
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PTE D
88-1321 FEB 9 1984
No, ___ ALEXANDER \. STEVAS. |
IN THE
Supreme Court of the United States
OCTOBER TERM, 1983
THE PEOPLE OF THE STATE OF CALIFORNIA
AND THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA,
Petitioners,
Vv.
TENNECO OIL CoMPANY, et al.,
Respondents.
APPENDIX
Petition For A Writ Of Certiorari To The
United States Court Of Appeals
For The Fifth Circuit
JANICE E. KERR
J. CALVIN SIMPSON
HARVEY Y. Morris
PuBLic UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
5066 State Building
350 McAllister Avenue
San Francisco, California 94102
(415) 557-2403
Counsel for Petitioners
PRESS OF BYRON 8, ADAMS PRINTING, INC,, WASHINGTON, D.C, (202) 347-8203
12.
INDEX TO APPENDIX
. Opinion of the Court of Appeals, E/ Paso Natural
Gas Co. v. Sun Oil Co., F.2d 1011 (July 5,
BEUED be vervencadseclvcsuct cencuueeneuecreel la-19a
Order of Federal Energy Regulatory Commission
Affirming Initial Decision an ~~ Further
Hearing, El Paso Natural Gas Co., 12 FERC
4 61,297 (September 25, 1980) ............4. 2la-3la
ALJ’s Initial Decision on Jurisdictional Status of
Lease Sale A ments, El Paso Natural Gas Co., 6
FERC 4 63,037 (February 20, 1979) ........ 33a-120a
Opinion of the United States District Court for the
estern District of Texas, E/ Paso Natural Gas Co.
v. Sun Oil Co., 426 F. Supp. 963 (January 27,
SNE in'c gnbwe obs ok LU neeecaee aa eee 121la-136a
Order of Court of yo Tenneco Oil Co. v.
FERC, 580 F.2d 722 & ptember 6, 1978) . 137a-l4la
Order of the Court of Appeals, Tenneco Oil Co. v.
FERC (October 25, 1978) ........cceeeees 143a-144a
Judgment of the Court of Appeals, Tenneco Oil Co.
v. FERC, No. 80-2404 (July 5, 1983) ........... 145a
Judgment of the Court of Appeals, Tenneco Oil Co.
v. FERC, No. 77-2613 (July 5, 1988) ........... 147a
Judgment of the Court of Appeals, E/ Paso Natural
Gas Co. v. Sun Oil Company, No. 77-1762 (July 5,
GEE « ci.cccsvoehysueeed Mich aeskanennenneiies 149a
. Order of the Court of Appeals Denying Petition for
Rehearing and Suggestion for Rehearing En Banc
(Deemed B, TH voce cccaceindesucuaews 15la-152a
. Order of Federal Energy poguaory Commission
Denying Applications for Rehearing, Z/ Paso Natu-
ral Co., 18 FERC 4 61,239 ( mber 18,
SOOO) s ccwecevescobecesstdpeepaucavedan .. 158a-154a
Natural Gas Act, §§ 1(b), 2(6), 4(a), 7(c) ........ 155a
1.
OPINION OF THE COURT OF APPEALS, EL
PASO NATURAL GAS CO. v. SUN OIL CO., 708
F.2d 1011 (JULY £, 1983)
St
la
UNITED STATES COURT OF APPEALS,
FIFTH CIRCUIT.*
July 5, 1983
Nos. 77-1762, 77-2613 and 80-2404
EL Paso NATURAL GAs CoMPANY, et al.,
Plaintiffs-Appellants,
v.
SuN OIL ComMPANY, et al.,
Defendants-Appellees.
TENNECO OIL Co., et al.,
Petitioners,
Vv.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent.
TENNECO OIL COMPANY, et al.,
Petitioners,
Vv.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent.
Petitions were filed seeking review of orders of the Federal
Energy Regulatory Commission which determined that it had
jurisdiction over certain lease-sale agreements transferring
rights to certain gas-bearing lands in the San Juan Basin of
New Mexico and Colorado. After consolidation with a decision
of the United States District Court for the Western District of
Texas, Dorwin W. Suttle, J., which found that such agree-
ments were not within regulatory jurisdiction of the Commis-
sion, the Court of Appeals, Roney, Circuit Judge, held that
where reserves underlying the leaseholds were not sub-
stantially developed at the time the lease sales were executed
*Former Fifth Circuit case, Section 9(3) of Public Law 96-452,
October 14, 1980.
2a
because of lack of imminent ability to produce in commercial
quanities, series of lease-sale agreements transferring rights
to certain gas-bearing lands in the San Juan Basin of New
Mexico were not sales of natural gas in interstate commerce
within meaning of Natural Gas Act and were therefore beyond
regulatory jurisdiction of Federal Energy Regulatory Com-
mission.
Appeal from district court’s decision affirmed; one petition
for review dismissed and the other reversed.
Danie: Joseph, Jack W. Hanks, Daniel Watkiss, Washing-
ton, D.C., Donald C. Shepler, Salt Lake City, Utah, David K.
Watkiss, Jack D. Bachman, Salt Lake City, Utah, for North-
west Pipeline Corp.
Rufus G. Thayer, Jr., Janice E. Kerr, J. Calvin Simpson,
San Francisco, Cal., for People of State of Cal. and Public
Utilities Com’n of State of California.
Howard V. Golub, Shirley A. Woo, Malcolm H. Furbush,
San Francisco, Cal., for Pacific Gas & Elec. Co.
Charles F. Hawkins, Dallas, Tex., for Southern Union Co.
J. Alan Galbraith, Washington, D.C., Arthur R. Formanek,
E] Paso, Tex., for E] Paso Natural Gas Co.
Steven A. Taube, Atty., George H. Williams, Jr., Jerome
Nelson, Sol., Washington, D.C., for amicus curiae F.E.R.C.
Leo J. Hoffman, Herf M. Weinert, Julius L. Lybrand, Dal-
las, Tex., for Sun Oil Co.
George B. Mickum, III, Steven H. Brose, Washington,
D.C., Edward J. Kremer, Jr., Dallas, Tex., for Atlantic Rich-
field Co.
Craig W. Hulvey, Washington, D.C., Robert D. Haworth,
Houston, Tex., for Mobil Oil Corp.
Gordon Gooch, Charles M. Darling, IV, Washington, D.C.,
for Tenneco, Continental, American Petrofina, Crown Cen-
tral, Delta Drilling, M/MS Morris Mizel.
3a
Vernon M. Turner, Houston, Tex., for Tenneco.
Michael J. Henke, Washington, D.C., Dee H. Richardson,
Midland, Tex., for Union Oil Co. of Cal.
Thomas Burton, Jr., Houston, Tex., for Continental Oil Co.
W.B. Browder, Jr., Midland, Tex., for W. Watson LaForce,
et al.
Donald F. Burke, Baltimore, Md., for Crown Central Pet-
roleum.
Terry R. Barrett, Stanley L. Cunningham, Oklahoma City,
Okl., for F.H.N., Ltd.
Robert D. Haworth, Houston, Tex., for Mobil Oil Corp.
Craig W. Hulvey, Washington, D.C., for Getty Oil Co.
Sherman S. Poland, Bernard A. Foster, III, Ross, Marsh &
Foster, Washington, D.C., for William G. Webb, et al.
J.O. Terrell Couch, Hutcheson & Grundy, Randel R. Young,
Houston, Tex., for Robert Beamon, et al.
Steven R. Hunsicker, Gordon Gooch, Charles M. Darling,
IV, Baker & Botts, Washington, D.C., Strasburger & Price,
Leo J. Hoffman, Dallas, Tex., for Tenneco Oil Co., et al.
Larry Pain, John L. Williford, Bartlesville, Okl., for Phillips
Petroleum Co.
John S. Fick, Los Angeles, Cal., for Southern Cal. Gas Co.
William M. Lange, Colorado Springs, Colo., for Colo. In-
terstate Gas Co.
Robert H. Landt, Denver, Colo., for Amoco Production Co.
J. Alan Galbraith, Washington, D.C., for E] Paso Natural
Gas Co.
Donald K. Dankner, Washington, D.C., for CP National
Corp.
Robert L. Simpson, Spokane, Wash., for Wash. Water Pow-
er Co.
da
G. Thomas Dohn, Yakima, Wash., for City of Ellensburg.
Justin R. Wolf, Washington, D.C., Bruce R. DeBolt, Associ-
ate Counsel, Portland, Or., for Northwest Natural Gas Co.
Thomas F. Brosnan, Washington, D.C., for Washington
Natural Gas Co.
John H. Socolofsky, Asst. Atty. Gen., Salem, Or., for Public
Utility Com’r of Oregon.
Kenneth O. Eikenberry, Atty. Gen., Donald D. Trotter,
Asst. Atty. Gen., Olympia, Wash., for Washington Utilities
and 1 nsportation Com’n.
John Ketcham, Washington, D.C., for Cascade Natural
Gas Corp.
P. Michael Koenig, William M. Lange, Colorado Springs,
Colo., for Colo. Interstate Gas Co.
Lester D. Sitter, Denver, Colo., for Rocky Mountain Natu-
ral Gas Co., Inc.
Gary G. Sackett, Associate Gen. Counsel, Salt Lake City,
Utah, for Mountain Fuel Supply Co.
Steven R. Shanahan, Sr., Asst. Atty. Gen., Cheyenne,
Wyo., for Public Service Com’n of Wyoming.
Zev E. Kaplan, Deputy Atty. Gen., Carson City, Nev., for
Public Service Com’n of Nev.
J. Richard Tiano, Washington, D.C., for Intermountain Gas
Co.
Wm. W. Bedwell, Washington, D.C., for Southwest Gas
Corporation.
Michael S. Gilmore, Deputy Atty. Gen., Boise, Idaho, for
Idaho Pub. Utilities Comm.
Appeal from the United States District Court for the West-
ern District of Texas.
5a
Petitions for Review of Orders of the Federal Energy Regu-
latory Commission.
Before Brown, Roney and TJoFLaT, Circuit Judges.
Roney, Circuit Judge:
The basic question presented by these consolidated appeals
is whether a series of lease-sale agreements transferring
rights to certain gas-bearing lands in the San Juan Basin of
New Mexico are sales of natural gas in interstate commerce
within the meaning of section 1(b) of the Natural Gas Act, 15
U.S.C.A. § 717(b). Holding the agreements are not sales as
defined by the Act, and are therefore beyond regulatory
jurisdiction, we affirm the district court judgment to that
effect and reverse the decision of the Federal Energy Regula-
tory Commission to the contrary.
Before considering a case of this kind, it is necessary to
remind ourselves that the Commission’s power to regulate the
economics of natural gas transactions has been limited by
Congress. Although it presumably has the power to regulate
every nook and cranny of the natural gas business, Congress
chose not to do so. FPC v. Panhandle Eastern Pipe Line Co.,
337 U.S. 498, 502, 69S.Ct. 1251, 1254, 93 L.Ed. 1499 (1949). In
this situation, it is important that the courts restrict the regu-
latory agencies to precisely that authority delivered to them by
Congress, and to stop where Congress intended to stop no
matter how tempting it might be to hearken to persuasive
arguments that more regulation is appropriate. Agencies have
a tendency to perceive a need for regulation. Congress is the
determinative body in the matter, however, and this case has
been considered and decided on that precise premise. If Con-
gress had intended to regulate the transactions here involved,
it easily could have done so with simple legislative language.
We make no judgment whether it should have done so. We only
decide, based upon the leading Supreme Court decision and the
prior precedent of this Court, that it did not.
Before reviewing the facts and getting on with the decision,
it might be helpful to describe the parties to this litigation while
6a
footnoting the names of all litigants, to state briefly the source
of these appeals and the lengthy history of the litigation, and in
a simplified way to suggest the issues that have been presented
for decision.
THE PARTIES
On one side of this litigation are two pipeline companies, '
which acquired leasehold rights in gas-bearing lands, and the
Federal Energy Regulation Commission. On the other side are
numerous oil and gas concerns and a few individuals who
transferred the leasehold rights in question.* A number of
state commissions and interested private entities have been
granted permission to intervene or file amicus briefs.’
' E] Paso Natural Gas Company and Northwest Pipeline Corpora-
tion.
“Sun Oil Company, Atlantic Richfield Company, Mobil Oil
Corporation, Tenneco Oil Company, Continental Oil Company,
American Petrofina Company of Texas, Union Oil Company of Cali-
fornia, Crown Central Petroleum Corporation, Delta Drilling Com-
pany, Amoco Production Company, Phillips Petroleum Company,
F.H.N., Ltd., Getty Oil Company, W. Watson Laforce, Jr., Morris
and Flora Mizel, William G. Webb, et al., Robert Beamon, in-
dividually and as trustee, Thomas L. Hail, Trustee, and Pattie Ann
Beamon Lundell.
* Washington Utilities and Transportation Commission, The Peo-
ple of the State of California, The Public Utilities Commission of the
State of California, The Public Utility Commissioner of Oregon, City
of Ellensburg, Washington, The Public Service Commission of Neva-
da, The Public Service Commission of Wyoming, Idaho Public Utili-
ties Commission, Pacific Gas and Electric Company, Southern Cali-
fornia Gas Company, Southern Union Company, C.P. National
Corporation, Colorado Interstate Gas Company, Cascade Natural
Gas Corporation, Northwest Natural Gas Company, Rocky Moun-
tain Natural Gas Company, Intermountain Gas Company, South-
west Gas Corporation, Mountain Fuel Supply Company, Washington
Natural Gas Company, and Washington Water Power Company.
7a
HISTORY OF THE LITIGATION
During the 1950s, Tenneco Oil, Sun Oil, Continental Oil,
Atlantic Richfield, Phillips Petroleum, and several other oil
companies entered into gas lease-sale agreements with E] Paso
Natural Gas Company and Pacific Northwest Pipeline Com-
pany, both gas pipeline companies. In return for their working
interests in certain leases in the San Juan Basin of New Mexico
and Colorado, the oil companies were to receive so-called
overriding royalties or production payments. The rates estab-
lished for these royalties were subject to redetermination at
the expiration of the initial term. If at the expiration of the
term the parties could not agree on a new rate, the rate was to
be fixed by arbitration.
In 1973, Sun Oil and E] Paso failed to agree on a new override
rate, and the dispute was submitted to arbitration. The
arbitration board awarded Sun Oil an override based on the
well head price of intrastate gas which exceeded the regulated
interstate rate. Other oil companies then sought redetermina-
tion of their rates, and E] Paso thereafter brought four actions
in the United States District Court for the District of Columbia
seeking a declaratory judgment that the royalty recipients
were selling gas in interstate commerce within the meaning of
section 1(b) of the Natural Gas Act, 15 U.S.C.A. § 717(b). Ifin
interstate commerce, the lease-sale agreements came within
the jurisdiction of the Natural Gas Act, and the royalty reci-
pients could not receive more than the interstate rates estab-
lished by the Federal Power Commission (now the Federal
Energy Regulatory Commission).
The suits were consolidated and transferred to the Western
District of Texas. 28 U.S.C.A. § 1406. El Paso sought refer-
ence of the case to the Commission, and the district court
carried the request with the case. At the same time, E] Paso
filed a complaint with the Commission seeking a determination
as to the status of the leases under the Act. After a protracted
trial, the district court held the lease-sale agreements were not
sales of gas within the meaning of the Act and dismissed the
case for want of jurisdiction, implicitly denying E] Paso’s mo-
8a
tion for reference to the Commission. E/ Paso Natural Gas Co.
v. Sun Oil Co., 426 F.Supp. 963 (W.D.Tex.1977). El Paso
appealed, moving this Court to refer the matter to the Com-
mission.
The Commission thereafter issued an order instituting a
show cause proceeding directed to the jurisdictional issue. E/
Paso Natural Gas Co., 58 F.P.C. 2181 (1977). Tenneco Oil,
Atlantic Richfield, Sun Oil, and others sought review of the
order in this Court. We denied their motions to stay the Com-
mission’s show cause proceeding but withheld decision of the
appeal from the district court pending receipt of the Commis-
sion’s opinion. Tenneco Oil Co. v. FERC, 580 F.2d 722 (Sth
Cir. 1978).
A record was fully developed before an administrative law
judge. Affirming and adopting the decision of the administra-
tive law judge, the Commission ruled that the lease-sale agree-
ments were within its jurisdiction. E/ Paso Natural Gas Co.,
12 F.E.R.C. © 61,297 (1980). Petitions for review of the Com-
mission’s decision were thereafter filed with this Court.
Thus the district court and the Commission, albeit on differ-
ent records, reached opposite conclusions. Both decisions came
before us for review. We heard extended oral argument in
October 1981, permitted supplemental briefing to the end of
that year and continued to receive helpful memoranda through
April 1982.
THE ISSUES
The basic question that confronts the Court on these appeals
is whether the natural gas lease-sale agreements are sales of
gas within the meaning of the Natural Gas Act, 15 U.S.C.A.
§ 717-717w. Underlying this ultimate issue are subissues
which seem to be no longer critical in light of our decision: (1)
since the district court on oe the Commission's
decision, did it have a res judi effect that bound the Com-
mission? (2) having litigated and lost in the district court, were
E] Paso and Northwest collaterally estopped from claiming
9a
before the Commission that the transactions are jurisdictional?
(3) was the Commission bound to treat the transactions as
nonjurisdictional because of its prior rulings in connection with
such transfers involving some of the same parties and the same
basic facts? and (4) should the district court have referred the
jurisdictional issue to the Commission under the doctrine of
primary jurisdiction? Other subissues argued but not decided
are: (a) whether the Commission prejudged the issues, (b)
whether the petitions for review in No. 77-2613 concerning the
Commission’s decision to conduct a show-cause proceeding on
the jurisdictional issue should be dismissed for seeking review
of nonfinal interlocutory orders, and (c) whether the Commis-
sion’s resolution of the jurisdictional question should be given
only advisory effect in the court of appeals.
FACTS
The San Juan Basin is located mainly in northwestern New
Mexico, with a part extending northward into Colorado.
Underlying the Basin are bowl-shaped sandstone formations
permeated by large volumes of natural gas. There are three
gas productive formations in the Basin: Pictured Cliffs, Mesa
Verde, and Dakota. All three are characterized by low to
moderate permeability and low porosity. As the district court
correctly found, actual drilling is the only method of definitely
locating recoverable gas saturations.
Unable to obtain all the gas reserves it desired through
conventional wellhead sales, E] Paso in 1951 entered into
negotiations with Delhi Oil Corporation, a lease holder in the
Basin. Delhi and E] Paso entered into the first of the lease-sale
transéctions in issue in this case, GLA (Gas Lease Agreement)
47, in March 1952. In exchange for Delhi’s gas reserve acreage,
E] Paso agreed to pay Delhi a fixed price per Mcf produced,
subject to escalation over a specified period of time and there-
after subject to redetermination at the fair market value of the
gas. The parties agreed to submit to arbitration any price they
could not settle upon.
10a
E] Paso’s program of acquiring gas reserves in the San Juan
Basin, through transactions similar to GLA-47, proceeded
rapidly. In all, over a six-year period, E] Paso entered into 36
such lease-sale contracts with the owners of gas leaseholds in
the Basin, thereby acquiring the gas underlying more than a
quarter of a million acres. Thirty-five of these GLAs are in
issue here. Prior to the lease-sale transactions, natural gas
from some of the acreage had been sold to E] Paso under
conventional wellhead sales contracts.
All the GLAs followed the same general pattern: in ex-
change for the producer’s agreement to transfer the leasehold,
E] Paso agreed to make overriding royalty payments for the
gas when produced.
In 1952, Pacific Northwest Pipeline Corporation, a prospec-
tive interstate natural gas pipeline company, filed an applica-
tion with the Commission for a certificate of convenience and
necessity to build a pipeline to supply gas to the Pacific North-
west market. Since Pacific Northwest had no gas supplies, it
sought commitments from independent producers who owned
substantial reserves in the San Juan Basin.
Pacific Northwest obtained commitments for San Juan Basin
gas from several producers based on a lease-sale format (called
“PLAs” for Pacific Lease Agreement) closely similar in most
important respects to the GLAs in the E] Paso transactions.
The basic scheme called for Pacific Northwest to compensate
the interest owner of the acreage by paying an overriding
royalty, calculated as a specified sum for each Mef of gas
produced from the acreage, subject to periodic escalation. The
price was also subject to later redetermination under a speci-
fied formula tied to the market, i.e., the unregulated value of
the gas. The PLAs conveyed rights only to gas, not oil.
Northwest Pipeline Corporation is the successor in interest,
through E] Paso, of Pacific Northwest.
lla
JURISDICTIONAL ISSUE
Whether the gas lease-sale agreements are sales of gas
within the meaning of the Natural Gas Act, 15 U.S.C.A. § 717-
717w, and thus subject to the jurisdiction of the Federal Ener-
gy Regulatory Commission, is of substantial significance. If
they are sales under the Act, the royalty recipients must seek
certification from FERC and cannot receive payments exceed-
ing the regulated interstate rate. If they are not sales, the
recipients are entitled to the rate provided in the contracts.
The issue is difficult to decide. Neither the statute nor the
cases give definitive direction. Congress intended to regulate
only interstate sales of natural gas, leaving intrastate sales and
the production of gas regulated exclusively by the states, if
regulated at all. See Interstate Natural Gas Co. v. FPC, 331
U.S. 682, 690, 67 S.Ct. 1482, 1487, 91 L.Ed. 1742 (1947). An
easy line to draw in legislative halls, in the real world there is
much confusion between sales and production, made ever in-
creasingly so by legal craftsmanship that sometimes makes
production look like sales, or sales look like production,
depending upon the interest of the client.
The main cases addressing the question focus on the geology
and development of the acreage and the terms of the contracts
involved. The fountainhead decision setting forth the factors to
apply in determining whether a transaction is jurisdictional is
United Gas Improvement Co. v. Continental Oil Co. (“Rayne
Field”), 381 U.S. 392, 85 S.Ct. 1517, 14 L.Ed.2d 466 (1965).
The significant case in this Circuit is Continental Oil Co. v.
FPC (“Ship Shoal”), 370 F.2d 57 (Sth Cir. 1966).
While ordinary wellhead sales of natural gas for resale in
interstate commerce come within the jurisdiction of the Natu-
ral Gas Act, see Phillips Petroleum Co. v. Wisconsin, 347 U.S.
672, 677, 681-82, 74 S.Ct. 794, 796, 798-99, 98 L.Ed. 1035
(1954), lease transfers and the royalties collected thereunder
are generally within “production or gathering” exemption of
the Act, 15 U.S.C.A. § 717(b), and thus not jurisdictional. See
Mobil Oil Corp. v. FPC, 463 F.2d 256 (D.C.Cir.1971), cert.
12a
denied, 406 U.S. 976, 92 S.Ct. 2409, 32 L.Ed.2d 676 (1972).
Difficulties arise, however, where, as in the instant case, the
transactions are hybrid, manifesting characteristics of both
arrangements.
In the leading case of United Gas Improvement Co. v. Con-
tinental Oil Co., commonly known as “Rayne Field,” the
United States Supreme Court directed a case-by-case analysis
of hybrid lease-sale arrangements, the fundamental inquiry
being whether “the sales of these leases in. . . a proven and
substantially developed field. . . accomplished the transfer of
large amounts of natural gas to an interstate pipeline company
for resale in other states.” 381 U.S. at 401, 85 S.Ct. at 1522.
The Fifth Circuit expounded on the Rayne Field test in Con-
tinental Oil Co. v. F.P.C. (“Ship Shoal”), stating the test as
follows:
(1) Isthe economic effect of the transfer similar to that of
a conventional sale?
(2) Is the subject of the transaction “proven and sub-
stantially developed” reserves?
(3) Is the transfer of the reserves for purpose of in-
terstate transmission and resale?
370 F.2d at 62. Ship Shoal further articulated the standard for
applying the second factor, whether reserves are “proven and
substantially developed” within the meaning of Rayne Field,
focusing on (1) definability of gas volume based upon proof of
reserves and (2) imminent ability to produce in commercial
quantities. Jd. at 63-64.
While both the administrative law judge’s decision and that
of the Commission invoke Rayne F ie/d, it is clear from acareful
reading of the administrative law judge’s opinion and the Com-
mission’s affirmance that neither correctly applied it under the
law of this Circuit. In determining whether a transfer is juris-
dictional under the Act, Ship Shoal teaches that all three of the
above factors must be present. The administrative law judge
and the Commission, however, elevated the first prong—
economic equivalency—from 4 component in the Rayne Field
13a
test to the determinative factor on the issue. Thus, the admin-
istrative law judge stated:
Under the Rayne Field case’s “economic equivalent”
doctrine, a lease-sale agreement would clearly be subject
to regulation as a jurisdictional sale of gas at the wellhead
if it is held to be economically equivalent in substance to
the conventional wellhead sale which the Court held to be
jurisdictional in Phillips.
x « ~ * * *
The legal principles fashioned in the Rayne Field line of
cases, when applied to the facts of this proceeding, lead
inescapably to the conclusion that all of the lease-sale
agreements at issue are jurisdictional. The crucial test
that emerges from the cases is whether a particular
transaction accomplished the transfer of large volumes of
natural gas reserves to an interstate pipeline for resale in
— commerce. If it did, the transaction is jurisdic-
tional.
x * * * * &*
What is significant is the essential message of Rayne
Field—that the transfer of large amounts of natural gas
reserves to an interstate pipeline for resale in interstate
commerce is a jurisdictional transaction, no matter how
the lawyers decide to structure the transfer. Rayne’s
specification that “proven and substantially developed re-
serves” must be present is not a quantitative test, a
license for future courts and Commissions to engage in
massive well counting in order to ascertain whether some
formulaic criterion has been satisfied. Rather, Rayne is
concerned witn commercial realities. It asks whether
what was sold was gas or merely the right to explore for
and develop it in the uncertain event it is found.
« a x * * *
Here, too, the significant economic fact that will not go
away no matter how much the respondents try to wish it
away is that the GLA and PLA contracts at issue, each and
— of them, transferred large volumes of natural
gas from a producer of natural gas to an interstate natural
gas pipeline for transmission and sale for resale in other
states. That fact requires the finding that each of the
contracts was, as a matter of law, economically equivalent
l4a
to a wellhead sale of natural gas for resale in interstate
commerce.
El Paso Natural Gas Co., 6 F.E.R.C. © 63,037, at 65,212;
65,217-19 (1979). In affirming, the Commission held:
We find the magnitude of the overriding royalties and the
fact that they apply to each Mcf of gas sold, irrespective of
the quanitities of gas the contracting parties might origi-
nally have thought were involved, lends, in our pudgment,
strong support to the proposition that these lease sales
were virtually identical in “economic effect” to con-
ventional sales.
El Paso Natural Gas Co., 12 F.E.R.C. © 61,297, at 61,683
(1980).
By focusing on “commercial realities” and the parties’
assumption while negotiating that gas existed in the ground,
the administrative law judge and the Commission misread and
misapplied Rayne Field and Ship Shoal, almost ignoring the
requirement for a finding of jurisdiction under the Natural Gas
Act that the acreage involved must be proven and substantial-
ly developed. See Ship Shoal, 370 F.2d at 62. Neither the
Supreme Court nor our precedents have signaled a retreat
from this requirement or indicated it is swallowed up by the
first prong of Ship Shoal’s test. Thus, in holding the lease-sales
jurisdictional in Rayne Field, the Supreme Court emphasized
that the land included “proven and substantially developed”
gas reserves. 381 U.S. at 401, 85 S.Ct. at 1522.
Carried to its logical conclusion, the Commission's economic
equivalency/commercial realities approach could render any
sale of lease rights to an interstate pipeline company jurisdic-
tional merely because the transaction ultimately results in
successful production and disposition of gas in interstate com-
merce, Certainly, E] Paso entered into the agreements in
question in this litigation with the hope and expectation of
obtaining gas for sale in interstate commerce. It had the same
goal as a purchaser in the ordinary wellhead sale. But this
statement is equally true of the lessee in a traditional transfer
of a lease to gas-bearing lands. Unless all the Rajjne Field
l5a
factors, including proven and substantial development, are
satisfied, such a transaction is not jurisdictional. See Mobil Oil
Corp. v. FPC, 463 F.2d at 261-62; see also FPC v. Panhandle
Eastern Pipeline Co., 337 U.S. 498, 69 S.Ct. 1251, 93 L.Ed.
1499 (1949). The Supreme Court emphasized the difference in
degree of development in explaining why it held the transac-
tion jurisdictional in Rayne Field, but nonjurisdictional in
Panhandle. Rayne Field, 381 U.S. at 403, 85 S.Ct. at 1523.
While the Commission's down-playing of the development
issue may well foreshadow the next stage in the evolution of
the law, for the time being our precedents demand full applica-
tion of all components of the Rayne Field test, including the
proven and substantial development factor, as explained in
Ship Shoal. We perceive the Rayne Field test to reflect the
Supreme Court’s concern with the apparent congressional in-
tent not to regulate production. A purely economic test would
seem to encroach on that concern.
Focusing on the “proven and substantially developed” com-
ponent of Rayne Field and Ship Shoal, the record reveals the
reserves in the Basin may well have been “proven” at least
within reasonable estimates. See generally Ship Shoal, 370
F.2d at 64-65. The district judge was correct, however, in
deciding the lease-sale agreements did not involve substantial-
ly developed reserves, and the Commission erred in determin-
ing the same transfers did. Specifically, we hold the reserves
underlying the leaseholds were not substantially developed at
the time the lease sales were executed because of the lack of
“imminent ability to produce in commercial quantities.” Ship
Shoal, 370 F.2d at 64.
An important factor in our decision is the limited extent to
which the Basin had been drilled at the time the GLAs and
PLAs were executed. Although different tracts varied as to
development, taking the Basin as a whole, the acreage was far
less drilled than the land covered by the agreements found
jurisdictional in Rayne Field. Unlike in that case, massive
efforts were required to make the fields in the Basin commer-
cially productive. For example, GLA No. 47 covered approxi-
l6a
mately 102,400 acres. At the time of the signing of the agree-
ment, there were fifteen wells in the Mesa Verde formation
and nine in the Pictured Cliffs formation included under the
GLA. State law, however, permitted far more extensive drill-
ing: one Mesa Verde well for each 320 acres and one Pictured
Cliffs well for each 160 acres. Substantial drilling took place
after the agreement was reached. By December 1976, 736
wells were in the ground. An even more dramatic example of
the lack of substantial development when the agreements were
reached is provided by PLA-5. At the time of the agreement,
there were no wells on the 188,000 acres. By December 1977,
however, 365 wells were productive. Although a few GLAs
and PLAs reflect substantial development, neither the Com-
mission nor the parties have sought to approach the issue here
on an individual agreement basis.
In comparison, the acreage in Rayne Field featured far more
development prior to execution of the agreements. In Rayne
Field, nineteen wells were in the ground with only seven more
to be drilled. 381 U.S. at 396 n.3, 85 S.Ct. at 1520 n.3. This
significant drilling enabled the purchaser-lessee to receive gas
for interstate distribution shortly after execution. /d. at 397,
85 S.Ct. at 1520.
The evidence in the present litigation reveals that the few
wells in the ground when the agreements were executed could
not have come close to depleting the acreage. For example,
even after adding numerous wells in the land covered by GLA-
47, the purchaser-lessee sought and received permission to
double the number of wells previously allowed under state law
in the Mesa Verde formation. According to the purchaser-
lessee, the party favoring Commission jurisdiction and arguing
the reserves were substantially developed, the additional
wells were necessary to deplete the formation.
While the number of wells existing at execution of the agree-
ment is not the sine qua non of substantial development, the
Commission has considered this factor, and the cases point up
its significance. E.g., Rayne Field, 381 U.S. at 396 & n.3, 403 &
17a
n.8, 85 S.Ct. at 1520 & n.3, 1523 & n.8; Texas Gas Transmis-
sion Corp., Docket No. CP77-612, “Findings and Order After
Statutory Hearing Issuing Certificate of Public Convenience
and Necessity and Granting Petition to Intervene,” at 3 (May
10, 1978). Since substantial development turns on whether the
acreage is capable of imminent production of natural gas in
commercial quantities, Ship Shoal, 370 F.2d at 64, it stands to
reason that the actual number of wells in comparison to the
number needed to complete production from the land is a
relevant factor. As the Supreme Court stated in explaining the
relevance of the substantial development criteria, “the more
that must be done before the gas begins its interstate journey,
the less the transaction resembles the conventional wellhead
sale of natural gas in interstate commerce.” Rayne Field, 381
U.S. at 403, 85 S.Ct. at 1523. The pipeline companies’ ability to
tie in a few wells shortly after consummation of the transaction
does not demonstrate an “imminent ability to produce in com-
mercial quantities,” Ship Shoal, 370 F.2d at 64 (emphasis
added), or substantial development. We therefore conclude
that because the acreage was not substantially developed, the
agreements in issue were not sales of gas under the Natural
Gas Act.
The pipeline companies urge and the Commission ruled that
even if the lease-sales were not covered by the Act at the
outset, they “ripened” into jurisdictional transactions when
the price paid under the contracts was redetermined through
the much later 1973 arbitration. Relying on Weymouth v.
Colorado Interstate Gas Co., 367 F.2d 84 (5th Cir. 1966), the
Commission held the price redetermination proceedings con-
stituted a reassertion of “control over the price of gas sold at a
time when the gas was undeniably from a proven and sub-
stantially developed field.” E/ Paso Natural Gas Co., 12
F.E.R.C. § 61,297, at 61,684 (1980).
We reject the Commission's approach because it is implicit in
the controlling authorities that jurisdiction must be evaluated
at the time lease-sale agreements are executed. In Rayne
Field, the Supreme Court found the gas reserves proven and
18a
substantially developed at the time the lease-sales were
signed. See 381 U.S. at 396, 85 S.Ct. at 1520. Similarly, the
Fifth Circuit in Ship Shoal treated the pipeline company’s
readiness to connect to the field upon execution as a “strong
indication that the field was ‘substantially developed’ at the
time of transfer.” 370 F.2d at 65 (emphasis added).
Weymouth, relied on by the Commission, is inapposite. In
that case, the parties entered into a new lease which super-
seded various individual leases and incorporated many sub-
stantial changes. The Fifth Circuit referred the case to the
Commission for a jurisdictional determination, noting the ap-
plicability of the Natural Gas Act to agreements reached or
significantly altered after the date of its enactment. 367 F.2d at
102. In the instant case, however, redetermination of rates
followed precisely according to the terms of the lease-sale
agreements which remained unchanged. The mere
redetermination of rates pursuant to the original contracts
does not render the arrangements sales and is not factually
analogous to the exercise of a retained right to withhold con-
sent to sublease or assign, deemed jurisdictional in Louisiana
Land and Exploration Co. v. FERC, 574 F.2d 204 (Sth Cir.),
cert. denied, 439 U.S. 1127, 99 S.Ct. 1043, 59 L.Ed.2d 88
(1979). Thus, in the absence of authority commanding a contra-
ry rule, we hold the agreements must be evaluated for jurisdic-
tion under the Natural Gas Act as of the date of execution.
PRIMARY JURISDICTION, RES JUDICATA, COLLATERAL
ESTOPPEL
The issue concerning FERC’s statutory jurisdiction was
pending simultaneously before both the agency and the district
court. Throughout this litigation both the purchaser-lessees
and the Commission have consistently maintained that under
the doctrine of primary jurisdiction, the agency’s expert and
specialized knowledge should have been utilized from the out-
set and that the district court erred in failing to refer the case to
the Commission for initial determination.
19a
Whether the district court should have referred this action
to the Commission under the doctrine of primary jurisdiction
is, at this juncture, without consequence. Our decision in this
case has been preceded by and we have considered both tribun-
als’ decisions so that the spirit of the flexible doctrine, if not the
letter, has been satisfied. Cf. J.M. Huber Corp. v. Denman,
367 F.2d 104, 111 (5th Cir.1966) (primary jurisdiction is a
flexible doctrine). Beyond holding that we did not, as has been
argued, refer the jurisdiction issue to the Commission in Ten-
neco Oil Co. v. FERC, 580 F.2d 722 (5th Cir. 1978), this ques-
tion requires no further analysis.
Similarly, we need not decide the res judicata or collateral
estoppel effect, if any, of the district court opinion vis-a-vis the
decision of the Commission. Our holding that the district court
decision is not clearly erroneous as to the lease-sale agree-
ments before it and that the Commission’s ruling is not sup-
ported by substantial evidence obviates the need for a detailed
discussion of these issues. Those parties claiming the Commis-
sion;s actions were precluded by the doctrine, especially Wil-
liam G. Webb, et al., prevail under our approach even without
their rationale. See William G. Webb, 49 F.P.C. 17(1973).
NO. 77-1762: AFFIRMED.
NO. 77-2613: DISMISSED.
NO. 80-2404: REVERSED.
2. ORDER OF FEDERAL ENERGY
REGULATORY COMMISSION AFFIRMING
INITIAL DECISION AND INITIATING FURTHER ©
HEARING, EL PASO NATURAL GAS CO., 12
FERC { 61,297 (SEPTEMBER 25, 1980)
2la
12 FERC £ 61,297
El Paso Natural Gas Company, Docket No. CP74-314;
Northwest Pipeline Corporation, Docket No. CP76-327; Sun
Oil Company, et al., Docket No. C177-526
Order Affirming Initial Decision and Initiating Further
Hearing
(Issued September 25, 1980)
[Initial decision issued February 20, 1979 appears at 6
FERC £ 63,037.)
Syllabus
Commission affirms without modification that a series of
lease-sale agreements constituted sales of natural gas for re-
sale in interstate commerce under the Natural Gas Act.
{1] PIPELINE-RATEMAKING & REGULATION
Jurisdiction
Commission finds that overriding royalty owners initially
received approximately the same net amount under lease-sale
contracts as would have been received under conventional
wellhead sales after costs of production were considered. The
magnitude of the overriding royalties and the fact that they
apply to each Mef of gas sold, irrespective of the quantities of
gas the contracting parties might originally have thought were
involved, strongly supports this finding and leads the Commis-
sion to conclude that the lease-sales are jurisdictional.
(2) PIPELINE-RATEMAKING & REGULATION
Jurisdiction
Commission finds that persons acquiring leases of land later
sold to pipelines were not real estate speculators. Instead
these lease-sales accomplished the transfer of natural gas to an
interstate pipeline company for resale in other states. The
sellers bought leases from the original landowners and sold the
gas contained in those leases to the pipelines. The original
22a
landowners received a standard royalty for the rights which
they sold and controlled no aspects of the ultimate sale of the
gas to pipelines. The Commission also finds the inclusion of
take-or-pay provisions and the section of noncommercial
acreage provision in the lease-sale contract between pipelines
and those acquiring the leases leads to the conclusion that gas,
not land, was being sold.
[3] PIPELINE-RATEMAKING & REGULATION
Jurisdiction
Commission reaffirms Weymouth decision in finding that
the lease-sales in question are subject to Commission jurisdic-
tion. Assuming arguendo that the lease-sales were not initially
jurisdictional, they became so at the time the price paid for the
gas pursuant to the contracts was redetermined through
arbitration and thereby established at levels equal to or ap-
proaching prevailing wellhead prices. Upon redetermination
of price, the sellers reasserted their control over the price of
gas sold at a time when the gas was undeniably from a proven
and substantially developed field.
[4] PIPELINE-RATEMAKING & REGULATION
Jurisdiction
Commission rejects argument that Commission is barred by
the doctrines of res judicata and collateral estoppel from hold-
ing lease-sale transactions to be jurisdictional. Webb-Turner
did not directly decide that lease-sales were non-jurisdictional.
That ruling was based on less than a complete record and
reached under different circumstances. In light of the increas-
ing burden on consumers of non-regulation of these lease-sale
transactions, the FPC was compelled to throughly examine
these lease-sales to determine whether they were jurisdiction-
al. After redetermination of prices, changes in fundamental
facts further necessitated a review of the jurisdictional issue.
The Commission has also been ordered by the Fifth Circuit to
decide whether the subject lease-sale contracts are sales of
23a
natural gas for resale in interstate commerce as defined by the
Natural Gas Act.
[5] PIPELINE-RATEMAKING & REGULATION
Refunds & Restitution
Commission remands for determination of the remedial
measures to be taken, including: (1) whether and if so to what
extent payments made by pipelines to overriding royalty own-
ers were excessive and therefore unlawful; (2) what amounts,
if any, should be required to be refunded by royalty owners to
pipelines and flowed through by them to their jurisdictional
customers; and (3) what level of royalties should be approved
for the future.
Paul R. Connolly, J. Alan Galbraith and Arthur R. For-
manek for El] Paso Natural Gas Company
David K. Watkiss, Jack W. Hanks and Joseph T. Casey
for Northwest Pipeline Corporation
Gordon Gooch and Charles M. Darling, IV for Tenneco Oil
Company, Continental Oil Company, American Petrofina
Company of Texas, Crown Central Petroleum Corpora-
tion, Delta Drilling Company and Mr. & Mrs. Morris Mizel
Michael J. Henke and MaryJane Reynolds for Union Oil
Company of California
Craig W. Hulvey for Mobil Oil Corporation and Getty Oil
Company
George Mickum, Steven H. Brose and Edward Leahy for
Atlantic Richfield Company
Leo J. Hoffman for Sun Oil Company (Delaware)
John L. Williford and Larry Pain for Phillips Petroleum
Company
R. H. Landt for Amoco Production Company
Seg Ral Barrett and Stanley L. Cunningham for
F.H.N., Ltd.
oe B. Browder, Jr. for W. Watson LaForce, Jr., et
al.
24a
J. O. Terrell Couch for Robert Beamon, et ai.
Sherman S. Poland and Bernard A. Foster, III for Wil-
liam G. Webb, et al.
John S. Fick and Thomas D. Clarke for Southern Califor-
nia Gas Company
Shirley A. Woo, Malcom Furbush and Peter Hanson for
Pacific Gas and Electric Company
Edwyn R. Sherwood, Henry E. Brown and Joel L. Greene
for Colorado Interstate Gas Company
Bruce R. Debolt and John H. Socolofsky for the Oregon
Public Utility Commissioner
Radovan Z. Pinto for the People of the State of California
and the California Public Utilities Commission
Richard E. Kelly for the Staff of the Federal Energy
Regulatory Commission
Before Commissioners: Charles B. Curtis, Chairman;
Georgiana Sheldon, Matthew Holden, Jr. and George R.
Hall.
{Order Text]
On February 20, 1979, the presiding administrative law
judge issued an initial decision in the above-captioned proceed-
ing. The judge found that a series of lease-sale agreements,
which are the subject matter of this proceeding, constituted
sales of natural gas for resale in interstate commerce under the
Natural Gas Act. We agree with the judge’s determination and
find nothing in the exceptions thereto warranting modification
of his decision.
[1] We do, however, want to stress several factors leading to
the conclusion that the lease-sales at issue are in fact jurisdic-
tional. The law judge found that the overriding royalty owners
initially received approximately the same net amount under
the lease-sale contracts as they would have received under
conventional wellhead sales after costs of production were
considered. The presiding judge also noted that when the
overriding royalty payments were tredetermined as provided
25a
for in the lease-sale contracts, they were established at the
fair-market value of wellhead sales in the case of the contracts
of El] Paso Natural Gas Company, and at 75% of wellhead value
in the case of the contracts now held by Northwest Pipeline
Company. The overriding royalties were to be paid on each Mef
of gas produced. These payments are sharply different from
payments normally made in a royalty situation. In an ordinary
royalty contract, the royalty owner is paid a royalty based ona
percentage of the value of production. Here, however, the
royalty owners are receiving royalties based on the fair-
market value at wellhead for each Mef produced. These pay-
ments are virtually equivalent to the payments that would
have been received in a conventional wellhead sale except that
in an ordinary wellhead sale the producers would be expected
to absorb the costs of production. In this case, of course, the
royalty owners are responsible for none of the production
costs. The pipelines are instead responsible for production
costs and such costs are passed on to their customers (and to
the ultimate consumer) in addition to the overriding royalties
paid to the lessors. We find that the magnitude of the overrid-
ing royalties and the fact that they apply to each Mef of gas
sold, irrespective of the quantities of gas the contracting par-
ties might originally have thought were involved, lends, in our
judgment, strong support to the proposition that these lease
sales were virtually identical in “economic effect” to con-
ventional sales.
[2] The law judge also found that persons who acquired the
leases and sold them to the pipelines were not real estate
speculators. The sellers bought leases from the landowners
and then sold the gas contained in those leases to the pipelines.
The landowners, who were the original sellers of the leases,
received a standard royalty for the rights which they sold.
They negotiated that royalty with the persons who sold the
' United Gas Improvement Co. v. Continental Oil Co. (“Rayne
Field”), 381 U.S. 392, 396 (1965).
26a
leases to the pipelines. The original landowners had no control
over the ultimate destination of any gas which might be dis-
covered, and no knowledge whether the gas, if discovered, will
be sold interstate or intrastate. Nor did the landowners control
the quantity to be sold, the price to be paid, or the identity of
the purchaser. The middlemen sellers controlled all these in-
cidents of sale. They sold the gas to the interstate pipelines,
specified how much was to be sold per year, negotiated the
price, and dealt with the purchasing pipelines. The sellers of
these lease-sale agreements were not landowners selling
rights to drill. They were sellers of the natural gas contained in
acreage which they had leased from landowners.
[2] We also wish to stress certain contractual provisions
which lead us to the conclusion that it was gas, proved re-
serves, which was being sold. The take-or-pay provisions, and
the return of non-commercial acreage provisions, are signifi-
cant in our determination that what was being sold was gas.
(2) The take-or-pay provisions are commonly found in con-
ventional sales contracts and support our conclusion that these
transactions contemplated the sale of proved reserves. More-
over, the return of non-commercial acreage provisions show
that all that was being sold was proved reserves as measured
by the results of actual drilling. The only difference between
these lease sales and producer sales, which may include clauses
giving the buyer an option not to attach reserves from wells
deemed non-commercial,’ is the fact that the buyers incurred
the risks and costs associated with drilling. Yet this difference
is one which, in our view, supports, and certainly does not
detract, from our conclusion that these agreements are the
functional equivalent of sales from successful wells by produc-
ers. We conclude that the evidence amply demonstrates that
* See Mitchell Energy Corporation, Docket No. C178-704, Order
Denying Petition For Declaratory Order, Directing Applicant to File
For Abandonment Authorization and Granting Intervention (Octo-
ber 23, 1979, 9 FERC € __).
27a
these lease sales “accomplished the transfer of large amounts
of natural gas to an interstate pipeline company for resale in
other States.”
[3] In support of the proposition that the lease-sales in ques-
tion are subject to the Commission’s jurisdiction, the staff cites
several cases including United States v. Southwestern Cable
Co., 392 U.S. 157 (1968), Mobil Oil Corp. v. F.P.C., 463 F.2d
256 (D.C. Cir. 1971) and Fanny Fern Weymouth v. Colorado
Interstate Gen. Co., 367 F.2d 84 (Sth Cir. 1966). We are not
persuaded that either the Southwestern Cable or Mobil case is
directly relevant to the jurisdictional issue presented in this
case. However, we do believe that support for the assertion of
Commission jurisdiction is provided by Weymouth. In that
case the court stated:
Unlike Huber which involves a lease from the Landowner
to the Lessee-Producer who in turn sells the gas to North-
ern, the Pipeline Purchaser, this transaction from its in-
ception was a one-step affair. It is between the
Landowner-Lessor and the Pipeline as Lessee and Pur-
chaser. Considering that the Natural Gas Act applies from
the date of its enactment, at least to all transactions which
come into being or are significantly altered thereafter—
whether the parties are aware of the existence of the
legislation or whether it is being actively enforced—there
is at least a possibility that, taking into account the nature
and extent of the reserves of this huge gas field, at some
stage or time and to some extent, this transaction ripened
into a “sale” of a kind comparable to that found to exist in
Rayne Field. (367 F.2d at 102).
[3] Assuming arguendo that the lease-sales here were not
initially jurisdictional, we think that they became jurisdiction-
al at the time the price paid for gas pursuant to these contracts
was redetermined through arbitration and thereby established
at levels equal to or approaching prevailing wellhead prices.
*381 U.S. at 401.
a
28a
Upon the redetermination of price, the sellers reasserted'
their control over the price of gas sold at a time when the gas
was undeniably from a proven and substantially developed
field.
{4} In their exceptions to the initial decision, the royalty
owners argue that this Conimission is barred by the doctrines
of res judicata and collateral estoppel from holding these
transactions to be jurisdictional.’ The FPC previously rejected
those contentions and we continue to do so. We cannot be
bound by the conclusion drawn by the FPC in the Webb-
Turner proceeding. This Commission has a continuing obliga-
tion to regulate sales which Congress has declared to be within
‘The sellers in negotiating the initial contracts had control over all
incidents of sale which a conventional seller-producer, as opposed toa
landowner-royalty owner, would have. These inclucled the ability to
contract of the quantity to be sold, the price to be paid, the identity of
the purchaser and whether it shall be sold in interstate or foreign
commerce. In initially contracting for a price for gas, the sellers
reserved the right to redetermine the price after the initial contract
period. They exercised this right which resulted in an arbitrated
finding of prices for the gas in excess of applicable F PC ceiling prices.
In stating that the arbitrators found that the contracts provided for
prices higher than the FPC ceiling prices, we in no way imply that
that result is consistent with applicable law or with the intent of the
parties at the time the agreements were negotiated.
‘Respondents also claim that this case is similar to Teras Gas
Transmission Corporation, Docket No. CP77-612, Findings and
Order After Statutory Hearing Issuing Certificate of Public Con-
venience and Necessity and Granting Petition to Intervene (May 10,
1978, 3 FERC © ___), in which we found that a sale of gas reserves in
place did not constitute a jurisdictional sale. Texas Gas is inapposite.
The sale in Texas Gas involved reserves where the magnitude of
reserves was unknown. And more importantly, the purchase price
was not tied to the level of any future production or to the magnitude
of reserves ultimately discovered. In this case, the purchase price
was tied directly to the level of future production.
*Webb-Turner, Opinion No. 642, 49 FPC 17 (1973).
29a
the Commission's jurisdiction. The Commission cannot waive
that jurisdiction.’ The producers, in this case, have no right to
continued non-regulation.* And the producers can show no
harm from relying on the FPC’s decision in the Webb-Turner
proceeding.
(4) Moreover, the Webb-Turner proceeding arose in a differ-
ent context. It involved primarily issues of wheher to grant the
Webb-Turner parties permission to abandon sales to El Paso,
whether to grant E] Paso a certificate to operate the facilities
involved in those sales, and what costs related to the gas in
question were properly includable in E] Paso’s cost-of-service.
In Webb-Turner, the FPC did not directly decide that the
lease-sale transactions were non-jurisdictional. Rather it
found that it would not impose a Rayne-type remedy in that
case. Although in so doing the FPC, in essence, indicated that
it considered the lease-sales not to be jurisdictional, in view of
more recent events there can be no dispute that the FPC’s
rather oblique ruling was based on less than a complete record
and was reached under substantially different circumstances.
In light of the increasing burden of consumers of non-
regulation of these lease-sale transactions, the FPC was com-
pelled to thoroughly examine these lease-sales to determine
whether they are in fact jurisdictional. Prior to the price
redetermination, payments were of less regulatory interest to
the Commission. After redetermination, when regulatory in-
terest in these leases was greater, changes in fundamental
facts necessitated a thorough review of the jurisdictional issue.
Additionally, this Commission has been directed by the Fifth
Circuit to decide whether the subject lease-sale contracts are
sales of natural gas for resale in interstate commerce as defined
* Brooklyn Union Gas Co. v. F.E.R.C., 627 F.2d 462 (D.C. Cir.
1980), at 7.
* Nantahala Power and Light Co. v. F.P.C., 384 F.2d 200 (4th Cir.
1967); Connecticut Light and Power Co. v. F.P.C., 557 F.2d 349 (2nd
Cir. 1977).
30a
by the Natural Gas Act.” For these reasons, the res judicata
and collateral estoppel arguments cannot stand.
The royalty owners have requested oral argument. They
point to the magnitude of the briefs, the lengthy record, and
the factual and legal complexity of the issues as reason for oral
argument. The case has been well briefed and we feel that oral
argument is unnecessary for a thorough review and resolution
of the case. Therefore, oral argument will be denied.
[5] Having found that the subject lease-sale agreements are
sales of natural gas as defined by the Natural Gas Act, the
remains to be decided what remedies should be adopted for
past and future periods. Numerous questions remain as to
what remedies are available and what action or combination of
actions should be taken to insure that consumers are afforded
the “complete, permanent and effective bond of protection
from excessive rates and charges”"’ contemplated by the Natu-
ral Gas Act. These issues were previously discussed by the
FPC in its order issued in these dockets on June 3, 1977 58
FPC. However, the FPC later phased the proceeding and
deferred the remedy issues until the jurisdictional issue had
been decided. This case shall be remanded for hearing and
decision of the remaining issues including those set forth in the
order of June 3, 1977. The basic issues to be addressed on
remand are (1) whether and if so to what extent were the
payments made by E] Paso, Northwest and PNW to the
overriding royalty owners excessive and therefore unlawful,
(2) what if any amounts should be required to be refunded by
the royalty owners to El] Paso and Northwest and flowed
through by them to their jurisdictional customers, and (3) what
level of royalties should be approved for the future?
*Tenneco Oil Co. v. F.E.R.C., 580 F.2d 722, 724 (5th Cir. 1978).
” Atlantic Refining Co. v. P.S.C. of New York (“CATCO") 360
U.S. 378, 388 (1959).
3la
THE COMMISSION ORDERS:
(A) The initial decision of the administrative law judge is
affirmed and adopted.
(B) The motion for oral argument is denied.
(C) A hearing shall be held to determine proper remedies
for past and future periods in accordance with the terms of this
order.
(D) A presiding administrative law judge to be designated
by the chief administrative law judge shall preside at the
hearing in this proceeding, with authority to establish and
change all procedural dates, and to rule on all motions as
provided in the rules of practice and procedure.
3. ALJ’S INITIAL DECISION ON
JURISDICTIONAL STATUS OF LEASE SALE
AGREEMENTS, EL PASO NATURAL GAS CO.,
6 FERC { 63,037 (February 20, 1979)
33a
6 FERC © 63,037
El Paso Natural Gas Company, Docket No. CP74-314;
Northwest Pipeline Corporation, Docket No. CP76-327; Sun >
Oil Company, et al., Docket No. CI77-526
Presiding Administrative Law Judge's Initial Decision on
Jurisdictional Status of Lease-Sale Agreements
(Issued February 20, 1979)
{[Note: Order affirming Initial Decision and initiating fur-
ther hearing was issued September 25, 1980, and appears at
12 FERC * 61,297.)
Appearances
Paul R. Connolly, J. Alan Galbraith and Arthur R. For-
manek for E] Paso Natural Gas Company
David K. Watkiss, Jack W. Hanks and Joseph T. Casey for
Northwest Pipeline Corporation
Gordon Gooch and Charles M. Darling, [V for Tenneco Oil
Company, Continental Oil Company, American Petrofina
Company of Texas, Crown Central Petroleum Corpora-
tion, Delta Drilling Company, and Mr. & Mrs. Morris
Mizel
Michael J. Henke and Mary Jane Reynolds for Union Oil
Company of California
Craig W. Hulvey for Mobil Oil Corporation and Getty Oil
Company
George Mickum, Steven H. Brose and Edward Leahy for
Atlantic Richfield Company
Leo J. Hoffman for Sun Oil Company (Delaware)
John L. Williford and Larry Pain for Phillips Petroleum
Company
R.H. Landt for Amoco Production Company
34a
Terry R. Barrett and Stanley L. Cunningham for F.H.N..,
Ltd.
William B. Browder, Jr. for W. Watson LaForce, Jr., et
al,
J. O. Terrell Couch for Robert Beamon, et al.
Sherman S. Poland and Bernard A. Foster, III for William
G. Webb, et al.
John S. Fick and Thomas D. Clarke for Southern Califor-
nia Gas Company
Shirley A. Woo, Malcolm Furbush, and Peter Hanson for
Pacific Gas and Electric Company
Edwyn R. Sherwood, Henry E. Brown, and Joel L. Greene
for Colorado Interstate Gas Company
Bruce R. Debolt and John H. Socolofsky for the Oregon
Public Utility Commissioner
Radovan Z. Pinto for the People of the State of California
and the California Public Utilities Commission
Richard E. Kelly for the Staff of the Federal Power Com-
mission and the Staff of the Federal Energy Regulatory
Commission.
BENKIN, Presiding Administrative Law Judge:
These three cases have been consolidated for investigation
under Section 5 of the Natural Gas Act.
The focus of the inquiry is a series of “lease-sale agreements”
contracts which transferred ownership of the natural gas re-
serves underlying a vast amount of acreage in the San Juan
Basin.
Most of the San Juan Basin lies in northwestern New Mex-
ico, but a part of it extends northward into Colorado. It is high,
semiarid country. The land appears to be unpromising; one
35a
witness described it as “a lot of scenery [and] goat pasture.”
There was a time when so little was thought of the prospects
for the San Juan Basin that most of the land was given to the
Indians. Today, we know better: the bowl-shaped sandstone
formations that underlie the Basin are permeated by enormous
volumes of natural gas. Nearby in the “Four Corners” area are
some of the Nation’s most abundant deposits of coal.* So the
Basin, despite its unprepossessing appearance and its isolation
from major population centers, is rich.
More than two decades ago, the independent producers who
owned the working interests in oil and gas leases covering
large tracts of land in the San Juan Basin entered into a series
of contracts by which they transferred their leasehold rights to
the gas reserves underlying the acreage. The transferees were
two corporations. One was E] Paso Natural Gas Company (E]
Paso), a jurisdictional interstate natural gas pipeline. The
other, Pacific Northwest Pipeline Corporation (PNW), was
soon to become a jurisdictional natural gas pipeline. Under the
so-called lease-sale agreements, the interest owners reserved
the right to receive certain payments — termed “overriding
royalties” — determined by multiplying a specified unit sum by
the volume of gas (in Mcf) that the pipelines extracted from the
acreage.’ In time, wach royalty would escalate until it would be
set at a figure approximating the fair market value of the gas
produced.
The question for decision in this proceeding, aspects of which
have previously been litigated before a Federal District Court,
is whether the lease-sale agreements constituted sales of natu-
ral gas for resale in interstate commerce. If, as a matter of law,
'Tr. 337.
* See Chemehuevi Tribe of Indians v. F .P.C., 420 U.S. 395, 397 n.3
(1975).
*In some of the agreements, the overriding royalty payments
defrayed the pipeline’s obligation to make a “production payment”
for gas extracted.
36a
they were, it follows that the agreements have been subject to
the regulatory jurisdiction of the Commission under the Natu-
ral Gas Act.‘ The principal consequence of a determination that
the lease-sale agreements were jurisdictional sales of natural
gas would be a holding that the provisions of the agreements
which purported to obligate the pipeline-buyers to pay the
producer-interest owners amounts (whether or not denomin-
ated royalties) exceeding the FPC/FERC-established ceiling
prices for gas of the vintages involved were, to that extent,
illegal. From such a holding it might also follow that a large
portion of the huge sums paid for gas produced under the
agreements may have to be refunded and may eventually find
its way back into the pockets of ratepayers in California andthe
Pacific Northwest from whom the funds were exacted in the
first place.’
‘See § l(b) of the Act, 15’ ».C. 717(b). At the time this proceed-
ing was begun, the “Commission” in question was the Federal Power
Commission. The Federa! Power Commission was abolished and was
replaced by the Federal Energy Regulatory Commission, which
assumed mosi of the FPC’s jurisdiction, under the Department of
Energy Organization Act, 42 U.S.C. 7101-7352. The DOE Organiza-
tion Act took effect on October 1, 1977. This proceeding is continued
before the new Federal Energy Reguliory Commission pursuant to
$§ 402(a) and 705(b) of the DOE Orgar.zation Act, 42 U.S.C. 7172(a),
and 7295(b).
*The parties have not had the opportunity to submit briefs or
arguments on the effect of a holding that the agreements are jurisdic-
tional upon the pricing of the gas vader the Natural Gas Policy Act of
1978. Hence, that question will not be dealt with in this decision.
Another question that will not be considered in this decision is the
matter of criminal liability under Section 21 of the Natural Gas Act,
15 U.S.C. 717t, in the event the Commission determines that the
lease-sale agreements constituted unlawful (because uncertificated)
jurisdictional sales at above-ceiling prices. Early in the proceeding,
Commission Staff Counsel expressly disclaimed any intention on the
Staff's part to consider this case for reference to the Department of
Justice. Tr. 69.
37a
In order to dispose of the issues, the Commission must
necessarily undertake a substantial exercise in historical
detective work. In addition, despite the existence of several
definitive judicial pronouncements on the subject, from the
Supreme Court and elsewhere, the Commission must apply
some still-nascent legal principles.
This investigation proceeding was instituted by an order of
the Federal Power Commission issued on June 3, 1977, 58 FPC
2181, exactly three years after El Paso had filed a complaint
asking the Commission to undertake the investigation." Part of
the three-year delay was occasioned by the Commission’s deci-
sion, announced on April 8, 1976, 55 FPC 1677, to defer action
upon the complaint pending disposition of litigation then going
forward in the United States District Court in Midland, Texas,
involving issues identical to those raised by El Paso’s com-
plaint to the Commission.’ The District Court suit came to an
end on January 27, 1977."
According to the Commission, the primary question to be
determined in this investigation proceeding is whether the
“lease-sale” agreements between the pipelines and various
owners of working interests in acreage in the San Juan Basin
constitute jurisdictional sales of natural gas for resale within
“El Paso Natural Gas Co., Docket No. CP74-314, et al., Order
Instituting Show Cause Proceeding, Ordering Filing of Evidence and
Ordering Hearing, issued June 3, 1977 (hereinafter cited as Order
Instituting Proceeding).
* See El Paso Natural Gas Co., Docket No. CP74-314, et al, Order
Deferring Action on Request to Show Cause, Denying Motions and
Permitting Intervention, issued April 8, 1976. There is, so far as the
record shows, no explanation for the almost two-year delay between
the filing of the complaint and issuance of the April 8, 1976 order.
*See n. 19, infra.
38a
the meaning of Section 1(b) of the Natural Gas Act as it was
construed in Rayne Field*and the progeny of that case.
After El Paso filed its complaint, Northwest Pipeline
Corporation (Northwest) filed a petition for leave to intervene
in the proceeding. Northwest, like El] Paso a jurisdictional
interstate natural gas pipeline, is the successor in interest to
the lease-sale agreements that were executed by PNW in the
1950's and that eventually came into Northwest's hands by
virtue of a court-ordered divestiture."’ In its April 8, 1976
order, the Commission directed that Northwest's intervention
petition would be treated as a § 5 complaint and would be given
its own docket number. Thereafter, in the June 3, 1977 order
instituting this proceeding, the Commission joined as respon-
dents in the proceeding the interest owners who were parties
to the E] Paso lease-sale agreements (sometimes called GLAs)
and the interest owners who were parties to the lease-sale
agreements (denominated PLAs) that had made their way into
the hands of Northwest. ''
* United Gas Improvement Co. v. Continental Oil Co., 381 U.S.
392 (1965).
In 1957, after PNW entered into various lease-sale agreements,
El Paso acquired all of the outstanding stock of PNW. Two years
later, PNW was merged into E] Paso, and all of PNW’s assets,
including its interests under the lease-sale agreements, became part
of the Northwest Division of E] Paso. After a decade of antitrust
litigation, necessitating five separate opinions by the Supreme Court
of the United States, E] Paso was forceti to divest itself of the PNW.
assets. (California-Pacific Utilities Co. v. United States, 410 U.S.
962 (1973), aff'g United States v. El Paso Natural Gas Co., 358 F.
Supp. 820 (D. Col. 1972); Utah Public Service Comm'n. v. El Paso
Natural Gas Co., 395 U.S. 464 (1969); Cascade Natural Gas Corp. v.
El Paso Natural Gas Co., 386 U.S. 129 (1967); United States v. El
Paso Natural Gas Co., 376 U.S. 651 (1964); California v. F.P.C., 369
U.S. 482 (1962).
“GLA” means “Gas Lease Agreement” and is the designation
given by El Paso to the lease-sale agreements made with E] Paso. E]
Paso designated each of the lease-sale agreements it acquired fron
39a
3
The Commission also noted that some four years earlier it
had issued an opinion which dealt with the question whether
certain of the lease-sale agreements were jurisdictional sales of
natural gas. In that case, William G. Webb, et al. (Opinion No.
642),"* the Commission had authorized certain of the interest
owners—known as the Webb-Turner parties—to abandon con-
ventional sales to the interstate market in order to con-
summate their contracts to make lease-sales of their acreage to
E] Paso. Both the Commission Staff and the State of California
had argued that the lease-sales themselves were jurisdictional
under the Rayne Field doctrine. The Commission had distin-
guished Rayne Field and rejected that argument." The June 3,
1977 order initiating the instant proceeding expressly made
the interest owners who were parties to the Webb, et al.,
Opinion No. 642 case parties to this case. The Commission said
that it wanted to review the holding in Opinion No. 642 in light
of today’s changed circumstances, holding that the doctrine of
res judicata did not preclude relitigation of the jurisdictional
issue decided in that Opinion."
PNW asa“PLA,” which stands for “Pacific Lease Agreement.” The
PLAs are now owned by Northwest, of course, and Northwest has
continued to use the E] Paso terminology to designate the contracts.
"49 FPC 17 (1973).
“Id. at 25-26.
“In its Order Instituting Proceeding, the Commission said that
the Webb decision “did not consider at that time whether the continu-
ing production payment itself was a sale.” 59 FPC 1209 at 1214-1215.
As the Commission acknowledged in its July 29, 1977 order on
rehearing, however, that statement was incorrect. Nevertheless,
the Commission on rehearing adhered to its determination to recon-
sider the jurisdictional holding in Webd in light of “the changed
circumstances of today” and to its conclusion that “The doctrine of res
judicata does not apply where changed circumstances appear.” E/
Paso Natural Gas Co., Docket No. CP74-314, et al., Order on
Rehearing, Ruling on Motions for Deferral of Proceedings, Granting
Motion to Designate Additional Parties, Granting Late Interven-
tions and Granting Motion to Delete Respondent, issued July 29,
1977, 59 FPC 1214-1215 (hereinafter cited as Order on Rehearing).
40a
The event which precipitated the entire controversy Was a
dispute between E] Paso and Sun Oil Company, the owner of
the “overriding royalty” interest under GLA 61. That agree-
ment provided for redetermination of the rate of the per-Mcf
overriding royalty payable to the interest owner at specified
intervals; after 15 years, the royalty was to be a rate fixed by
mutual agreement of the parties (but not less than ten cents per
Mcf). In the absence of agreement between the parties, the
contract provided for determination of the royalty rate by a
board of arbitrators who “shall base their decision on the then
value of such gas at the well head.”"* In 1973, after the 20-year
price-redetermination point arrived, E] Paso and Sun were
unable to agree on a mutually-acceptable royalty rate. At Sun’s
insistence, the dispute was submitted to a board of arbitrators.
The board agreed with Sun’s contention that, under GLA 61. it
was entitled to the full market value of the gas at the wellhead.
and that the operative standard for establishing market value
was the going wellhead price for natural gas in the intrastate
market. The board's decision, issued in 1973, rejected the
contention that the market value of the GLA 61 gas should be
equal to the lower F PC-established rate for interstate sales of
gas of the same vintage. The board set the royalty rate for E!
Paso’s payments to Sun at 40 cents per Mcf.""
Upon learning of the Sun award, other GLA and PLA in-
terest owners demanded redetermination of the rates applica-
ble to their per-Mcf overriding royalties, under either rate
redetermination or favored nations clauses in their lease-sale
Exh. 22, p. 9.
The respondents assert that the arbitrators’ award of 40 cents
per Mcf was substantially less than the prevailing intrastate price in
the vicinity; 55-60 cents per Mcf. See Respondents’ Initial Brief, p.
25. It is nonetheless conceded that the F PC-regulated interstate
price for flowing gas of similar vintage was 24 cents per Mef. See
Complainants’ Proposed Findings of Fact (hereinafter “CPFF”) No.
193, p. 61; Responses of Designated Respondents to Complainants
Proposed Findings of Fact (hereinafter “RCPFF”), No. 193. p. 101.
dla
agreements." E] Paso’s response to these demands was to file
four separate lawsuits in U.S. District Court against some
interest owners under the GLAs. The actions, which were
eventually consolidated and transferred for trial to the District
Court for the Western District of Texas, sought declaratory
judgments that the lease-sale transactions were in reality
jurisdictional natural gas sales which had to be the subjects of
FPC-issued certificates of public convenience and necessity
before any overriding royalties could lawfully be collected. In
addition, El Paso sought to enjoin any interest owner from
following Sun's lead and seeking an arbitration award. OnJune
3, 1974, having filed its complaint with the Commission, E]
Paso moved in the District Court for a stay of proceedings and
for reference of the suit to the Commission. The Court with-
held decision on the motion (and, in fact, simply never ruled on
it). The District Court did, however, issue an order on August
1, 1974, permitting Northwest to intervene in the litigation. It
did so because after the suits were instituted, Northwest suc-
ceeded to El Paso’s interest in one of the lease-sale agreements
on which E] Paso had sued."
The typical favored nations clause provided that the interest
owner would receive the highest overriding royalty rate paid by the
pipeline-producer for gas produced under any lease-sale agreement
covering acreage located within 200 miles of the interest owner's
acreage.
* See n. 10, supra. The lease-sale agreement was PLA 13 with
Mobil Oil Corporation as the interest owner. Northwest acquired El
Paso’s rights under PLA 13 on February 1, 1974. After having made
the acquisition, Northwest not only intervened in El Paso’s suit in
order to assert its interests under PLA 13, but also sought to join as
parties to the suit the interest owners who were parties to the
remaining PLAs which were not involved in E) Paso’s action, so that
it could obtain an adjudication of its rights and liabilities under the
PLAs. The District Court, however, refused to permit joinder of the
remaining independent producers.
42a
On January 27, 1977, after a 26-day trial and four days of oral
argument, the District Court issued its decision.'* The Court
- held that the lease-sale transactions were not sales of natural
gas for resale within the meaning of Section 1(b) of the Natural
Gas Act and, consequently, were not subject to the regulatory
jurisdiction of the Commission.” The District Court thereupon
dismissed the suits for lack of subject-matter jurisdiction.”
The judgment of the District Court was appealed to the United
States Court of Appeals for the Fifth Circuit.~ The Fifth
Circuit was also the venue of petitions filed by a number of
respondents, seeking immediate judicial review of the Com-
mission’s order of June 3, 1977 sending this case to hearing and
its July 29, 1977 order denying rehearing of the June 3 order.”
The Court of Appeals consolidated the various cases for argu-
ment and, on September 6, 1978, issued an order deferring its
ruling on all of the appeals pending the Commission's decision
in this proceeding.*'
“ El Paso Natural Gas Co. v. Sun Oil Co., 426 F. Supp. 963 (W.D.
Tex. 1977).
“Td. at 970.
“1 Id. at 971.
= El Paso Natural Gas Co. v. Sun Oil Co., No. 77-1762.
*Tenneco Oil Co. v. F.E.R.C., No. 77-2613, et al., 580 F.2d 722
(5th Cir. 1978).
“ Shortly after the District Court rendered its decision, Northwest
entered into settlement agreements with the PLA interest owners.
The agreements mirrored the terms of settlement agreements which
E] Paso and the GLA interest owners had executed in October 1974.
Both pipelines agreed, during the pendency of litigation about the
jurisdicational status of the lease-sale contracts, to pay overriding
royalties at a rate keyed to, but slightly less than, the regulated
ceiling price for new San Juan Basin gas. The outcome of this
proceeding (including judicial review of the Commission's action) is to
control the rights of the interest owners to retain the funds. In an
order issued February 16, 1977, 57 FPC 989, the Commission permit-
ted El Paso to pass through to its customers the cost of the higher
43a
Meanwhile, the administrative hearing went forward. At
first, plans were made for trial of all issues, including the
question of the remedy that would be appropriate if the lease-
sale agreements were ultimately held to constitute jurisdic-
tional wellhead sales of natural gas. In an order issued Febru-
ary 13, 1978, 2 FERC © 61,124, however, the Commission
directed that the proceeding should be phased, so that the
question of the Commission's jurisdiction over the agreements
would be litigated and decided first, with the remedial issue
pretermitted until after the jurisdictional question was
decided.”
The hearings on the jurisdictional issue got underway on
May 2, 1977. At an early stage of the proceedings. all parties
concerned agreed to stipulate that issues once litigated in the
District Court in Midland would not be retried, and that the
evidentiary record in the District Court case would be received
in evidence in this proceeding and would be the basis for the
Commission's disposition of the jurisditional issues between
the parties to this proceeding who were also parties to the
Midland case. This stipulation saved a great deal of time and
effort. Nevertheless, the hearing into the disputes which were
not the subject of the Midland litigation consumed 19 days of
hearing sessions beginning on May 2, 1978 and ending on June
6, 1978. All parties filed proposed findings of fact and re-
sponses to proposed findings of fact on July 3, 1978 and July 25,
1978, respectively. Simultaneous initial briefs were filed on
September 11, 1978, and reply briefs were filed on September
29, 1978.
overriding royalty payments. As of the date this record closed,
Northwest had heen authorized two rate increases, of $27 million and
$34 million, to recover its expenditures for increased overriding
royalties.
= El Paso Natural Gas Co., Docket No. CP74-314, ef a/., Order
Granting Motion for Phasing of Proceedings and Deferral of Proce-
dures Concerning Remedy, issued February 13, 1978.
ae
doa
The first of the lease-sale agreements in the San Juan Basin
was GLA 32, entered into in 1950 between E] Paso and Delhi
Oil Corporation (Delhi). Examination of the history of that
transaction is basic to an understanding of why the parties to
that agreement, and the balance of the lease-sale agreements,
chose to do business in the hybrid lease-sale format rather than
through conventional wellhead-sale contracts.
E] Paso had been interested in the San Juan Basin as a source
of gas supply for several years before GLA 32 was con-
summated. To supply its first pipeline to California, E] Paso
had relied almost exclusively on casinghead gas produced in
the Permian Basin. This source of supply proved to be
unsatisfactory. Casinghead gas, being a by-product of oil pro-
duction, was produced only as oil was produced. The schedule
for oil production was, to a large extent, a function of state
prorationing orders and the market’s demand for petroleum
products, chiefly motor vehicle gasoline. Oil production tended
to be most plentiful at the beginning of each month, when
producers sought to meet their “allowables” and during the
warm weather months, when highway travel was heaviest.
These peak periods of oil—and casinghead gas—production did
not coincide with the times when demand for natural gas was
high in E] Paso’s markets.
In addition, there simply was not enough natural gas avail-
able to E] Paso from its Permian Basin sources. In the mid-
1940’s, it became clear to the pipeline and the California utili-
ties it served that the rapidly expanding California market’s
demand would soon outstrip E] Paso’s existing dedicated re-
serves. The Federal Power Commission, too, was putting
pressure on E] Paso to secure dedication of new and substantial
reserves of dry gas, free from the vagaries of oil production.
As a result of these factors, E] Paso undertook a search for a
large dry gas supply. The search eventually centered in the
San Juan Basin, where gas had first been produced, though not
in commercial quantities, as early as the 1920’s. The San Juan
tee
45a
Basin’s relative proximity to E] Paso’s California market made
it particularly attractive to the pipeline.
Delhi, an independent producer, owned substantial reserves
of natural gas in the Barker Dome Field of the San Juan Basin.
Like other independent producers operating in the Basin, Del-
hi was unable to market its gas because no interstate pipeline
had reached the Basin, and local demand could not absorb the
existing potential supply. El Paso proposed to fill the need for
an interstate pipeline connecting the Basin to major metropoli-
tan areas. On August 25, 1947, it filed an application with the
FPC, seeking a certificate of public convenience and necessity
for construction and operation of a pipeline from the San Juan
Basin to a point on the Arizona-California border near Nee-
dles, California.
Delhi and E] Paso executed a gas-purchase contract dated
May 1, 1948. Under the contract, Delhi was to sell and E] Paso
agreed to purchase up to 100,000 Mef of natural gas per day for
a period of 25 years, and from year to year thereafter, at a base
price of ten cents, with a specified escalation of the price of each
two and one-half years for the first 15 years of the contract.”
After the first 15 years, and at five-year intervals thereafter,
the price would be set at the fair market value of the gas at the
wellhead. It is a measure of the times that the parties set a
13-cent-per-Mef floor on the fair-market-value figure to be
employed under this redetermination clause.”
By its terms, the contract would not become operative until
two events occurred. Both involved the Federal Power Com-
mission. First, E] Paso would have to obtain favorable action
from the FPC upon its application for certification of its pipe-
line project, an application which it had filed nearly nine
months earlier. Second, Delhi would have to obtain from the
* Exh. 40 EP 2, pp. 15, 17, 25. For the first ten years of the
contract, the price was to escalate one-half cent per year; the price
was to escalate one cent per year during the remaining five years.
7 Id. at 25.
46a
Commission a ruling that its performance under the contract *
would not make the company a jurisdictional natural-gas
company.*
On May 19, 1948, E] Paso and Delhi entered into a second
contract which called for both of them jointly to construct,
own, and operate the pipeline from the Basin to California that
was the subject of El Paso’s pending application to the FPC.
Thereafter, on June 30, 1948, the San Juan Pipe Line Com-
pany, anewly-formed corporation owned by El Paso and Delhi,
filed an application with the Commission for a certificate
authorizing it to construct, own, and operate a pipeline from
the San Juan Basin to California.
The plan, under which the parties would jointly own and
operate the pipeline that would, in turn, enable them to market
a supply of natural gas to be sold under a relatively con-
ventional gas sale contract, came a cropper, however. The
critical problem was Delhi’s inability to secure from the Com-
mission a declaratory order, ruling that its performance under
the contracts would not subject it to regulation by the Commis-
sion under the Natural Gas Act. Three times it sought such a
ruling, and three times the Commission refused to issue one.”
* Id. at 3-5. The contract also required Delhi, inter alia, to commit
its Barker Dome acreage to the substantial performance of its con-
tractual obligations, to drill wells (within the limits of state spacing
restrictions) sufficient to supply the contract volumes of gas, to
gather and treat the gas (reserving to Delhi the right to remove
hydrocarbons other than methane), and to deliver pipeline-quality
gas to a central point on the proposed pipeline. In addition to the
above-described pricing provisions, the contract had a favored na-
tions clause.
*” Dethi Oil Corp., 8 FPC 613 (1949); Delhi Oil Corp., 7 FPC 1025
(1948); Delhi Oil Corp., 7 FPC 958 (1948). The problem, in those
pre-Phillips days, evidently inhered in Delhi's participation in the
pipeline-ownership-and-operation project. In the two later applica-
tions, Dethi proposed to restrict, though not completely terminate,
its participation and interest in the San Juan Pipe Line Company.
The Commission, nevertheless, apparently felt that an independent
47a
As a result, El Paso and Delhi abrogated their contract to
construct the pipeline and entered into a new and substantially
modified gas-purchase contract. Under the new gas-purchase
contract, dated February 4, 1949, E] Paso was entitled to call
upon Delhi to supply up to 150,000 Mef of gas per day to meet
its peak loads. The second contract, like the first, was con-
ditioned upon an F PC determination that Delhi would be free
of regulation under the Natural Gas Act.” This time the pipe-
line to California was to be constructed, owned, and operated
by El] Paso, without any participation or assistance from Delhi.
These terms were evidently satisfactory to the Commission,
for on March 10, 1949, it issued an order in which it determined
that Delhi would not become a regulated natural gas company
by virtue of its performance under the second gas-purchase
contract."
While all of this was going on, the larger question of the
amenability of independent producers to regulation under the
Natural Gas Act was being loudly debated in several forums.
There is no doubt about the fact that Delhi, like many other
independents, was concerned about the prospect of FPC
regulation and was anxious to take whatever steps were feasi-
ble to avoid the spectre of jurisdictional status.
In June of 1947, the Supreme Court of the United States,
noting that the Commission had not asserted jurisdiction over
wellhead sales per se, had commented: “We express no opinion
producer’s affiliation with, and co-ownership of, a jurisdictional pipe-
line could render the producer jurisdictional. To Delhi, a holding that
it was jurisdictional would bring down upon it two undesirable con-
sequences: cost-of-service treatment of its gas sales and a regulated
rate of return. Once Delhi divested itself of all interest in the pipeline
company, however, the law as it then existed placed no impediment
in the path of the Commission's issuance of a nenjurisdictional status
determination.
” Exh. 40 EP 6, pp. 7-8, 22-23.
" Dethi Oil Corp., 8 FPC 750 (1949).
48a
as to the validity of the jurisdictional tests employed by the
Commission in these cases.” Since the issue in the /nterstate
case was the Commission’s jurisdiction over a sale by a pipe-
line, not its jurisdiction over an independent producer’s sale, it
was unusual and ominous for the Court to reach out tocomment
on the jurisdictional status of wellhead sales by such produc-
ers. Soon thereafter, the Commission issued Order No. 139,"
adding to its General Rules a new Section 2.54, which pur-
ported to exempt wellhead sales by independent producers to
interstate pipelines from FPC jurisdiction.
Presumably, the Commission's issuance of the new Section
2.54 was designed to eliminate any doubt about the status of
independent producers that may have been engendered by the
Supreme Court’s comment in the /nterstate case. The matter
would not die that readily, however: On October 28, 1948, the
Commission launched an investigation to determine whether
Phillips Petroleum Company, an independent producer, had
become a jurisdictional natural-gas company by virtue of its
wellhead sales of natural gas to an interstate pipeline.” In
addition, on May 11, 1949, two months after Delhi received its
favorable ruling from the Commission, Chairman Nelson Lee
Smith of the FPC sent a letter to Arizona Senator Carl
Hayden, in which Smith indicated that Delhi’s proposed well-
head sale of natural gas to El Paso might subject Delhi to
regulation by the Commission.” At this time, there was pend-
ing in Congress a bill which would have amended the Natural
Gas Act to grant independent producers specific legislative
® Tnterstate Natural Gas Co. v. F.P.C., 331 U.S. 682, 690 n.18
(1947). |
12 F.R. 5585 (1947).
4 Phillips Petroluem Co., 7 FPC 983 (1948). Between the date
Section 2.54 was issued and the date the Phillips investigation be-
gan, Commissioner Richard Sachse had resigned and had been re-
placed by Commissioner Thomas C. Buchanan.
® Exh. 40 EP 1720.
=
49a
exemptions for their wellhead sales to interstate pipelines, in
effect enacting as a statute Section 2.54 of the Commission's
General Rules.
After it became aware of Chairman Smith's letter to Senator
Hayden, Delhi sought clarification of its status from the
Commission.” The Commission replied that, inasmuch as De-
lhi’s status turned on the answer to a question of law, /.e., the
legal effect of Order No. 139, promulgating Section 2.54 of the
Commission's Rules, “The Commission is unable, in the cir-
cumstances, to express a conclusive opinion as to whether you
will or will not be subject to regulation under the Natural Gas
Act by virtue of proposed sale of natural gas to E] Paso.”"
Chilling words indeed!—indicating that the Commission's con-
fidence in the legal validity of § 2.54 was beginning to ebb. This
development, coupled with other rapidly moving events on the
jurisdictional front (e.g., the ongoing Phillips investigation),
caused Delhi to seek the advice of counsel on other ways to
carry out the objectives of its agreement with E] Paso without
subjecting itself to the risk of regulation under the Natural Gas
Act.
Delhi’s counsel in Dallas sought the advice of Charles V.
Shannon, a Washington lawyer specializing in FPC law and the
Commission's one-time General Counsel. In a letter of Decem-
ber 1, 1949, Shannon expressed the opinion that if Delhi,
instead of g»ing through with its then-pending wellhead sale
contract with El] Paso, were to transfer its Barker Dome re-
serves through a sale of the underlying leases, the transaction
would be non-jurisdictional and would not make Delhi subject
to regulation by the Federal Power Commission.” In light of
"Id.
“ Exh. 40 EP 1721.
“Exh. 40 EP 22. Shannon's opinion was based upon the then-
recent decision of the Supreme Court in F.P.C. v. Panhandle East-
ern Pipe Line Co., 337 U.S. 498 (1949), holding that the Natural Gas
Act did not apply to the transfer of leases by an interstate pipeline to
a production company. It should be noted that Shannon's opinion was
Wa
Shannon's opinion and the confusion surrounding the legal
status of independent producers, the parties decided to re-
negotiate and recast the second gas-purchase contract in the
form of a lease-sale agreement. Under the lease-sale format,
Delhi would sell its gas leases covering the Barker Dome
acreage to E] Paso, and E] Paso would undertake the produc-
tion of natural gas from the acreage. Delhi would receive
compensation for the gas in an amount roughly equivalent to
the per-Mcf price it would have received under the gas-
purchase contract, minus E] Paso’s production costs.
The most significant factor in the arrangement was this: the
lease-sale format was developed specifically for the purpose of
putting the independent producer and the pipeline in about the
same economic positions they would have enjoyed under a
conventional wellhead gas sale contract. From the standpoint
of the parties to the first lease-sale agreement, the primary
purpose—and perhaps the sole purpose—of using that format
rather than a conventional wellhead gas sale contract)was to
avoid the possibility that independent producers who sold their
gas to interstate pipelines under such a contract would be held
to be natural-gas companies subject to the Federal Power
Commission's regulatory jurisdiction.
E] Paso and Delhi abrogated the second gas-purchase con-
tract on January 27, 1950. On the same day, they entered intc «
lease-sale agreement, which E] Paso later designated GLA 32.
The agreement provided that E] Paso would pay to Delhi an
“overriding royalty” on all gas produced from the Barker Dome
acreage. The amount of the payment was to be five cents per
Mcf for the first five years, six cents per Mef for the next five
years, and seven cents per Mcf for the ensuing five years;
rendered five years before the Supreme Court held, in Phillips
Petroleum Co. v. Wisconsin, 347 U.S. 672 (1954), that wellhead sales
by independent producers were jurisdictional and 16 years before the
Rayne Field case, supra, held that the sale of a lease may be the legal
equivalent of a jurisdictional sale of natural gas.
5la
thereafter, the seven-cents-per-Mef price would remain in ef-
fect until cumulative production taken from the acreage by El
Paso reached 600 Bef, after which the “royalty” would be equal
to the fair market value of the gas (but not less than 7¢ per
Mcf).” Delhi reserved all rights to any oil production. The
agreement called for E] Paso to make a substantial cash down
payment, which could be increased or decreased in the future
depending upon the parties’ recalculation of the ges reserves
underlying the acreage. E] Paso was entitled to take a max-
imum of 110,000 Mcf per day; under the take-or-pay clause, it
was obligated to take a minimum of 60,000 Mef per day.“ The
lease-sale agreement, like its predecessor contracts, was con-
tingent upon FPC issuance of the certificate to construct a
pipeline and transport San Juan Basin gas to California mar-
kets. That contingency was satisfied on July 4, 1950, when the
Commission issued the certificate to E] Paso.’ One vear later,
in July 1951, El Paso began the transportation to California of
natural gas produced from the Barker Dome Field.“
"Exh. 40 EP 29.
“ Id. at 9-10. Under a “take-or-pay” clause, the putative lessee was
obligated to pay for a specified minimum volume “f gas production
from the acreage, regardless of whether that volume of gas was
actually produced and taken into the pipeline. The effect of the
clause, in the context of a lease-sale agreement, is to prevent the
lessee from shutting in production from the acreage covered by the
agreement, thereby limiting its financial obligation and depriving the
lessor of revenue.
"San Juan Pipe Line Co., 9 FPC 170 (1950).
“ Congress eventually passed the bill exempting well-head sales
by independent producers from Federa! regulation under the Natu-
ral Gas Act. On April 15, 1950, President Truman vetoed the meas-
ure. Shortly thereafter, on July 11, 1950, the Commission issued
Order No. 154, 15 F.R. 4633 (1950), rescinding Section 2.54 of its
inconsistent with the Natural Gad Act.
52a
IV
One of the most bitterly contested issues in this case con-
cerns the extent to which the gas-producing potential of the
San Juan Basin was fully known at the time E] Paso began its
program of acquiring leases in the Basin. Although a great deal
of time and attention has been devoted to the geology of the
San Juan Basin and its prospects from a business and economic
standpoint, the essential facts can be summarized in relatively
brief compass.
Large volumes of natural gas underlie the San Juan Basin,
and geologists and petroleum engineers were generaly aware
of this fact as early as 1950, when GLA 32 was signed. *' The gas
occurs principally in three sandstone formations: 1. The Pic-
tured Cliffs formation, the shallowest of the three; 2. The
Mesaverde formation, the primary focus of developmental
activities, consisting of two distinct pay sands, the Cliff House
and the Point Lookout, separated by the non-gas-bearing
Menafee formation; and 3. The Dakota formation, the deepest
of the three." The three formations share certain similarities.
All are of varying depths and thicknesses. Each of the forma-
tions consists of blanket, gas-bearing sands which are deepest
towards the center of the Basin and outcrop progressively at
the Basin’s perimeter. All of the gas-bearing formations are
characterized by relatively low porosity and permeability.”
Because of the low porosity and permeability of the pay sands,
it was well known that the gas of the San Juan Basin would be
relatively expensive to extract, and that a producer would
have to wait longer to recover his investment in a San Juan
* See ¢.g., Exh. 40 EP 1920.
* Exh. 38, III J.A. 552a-554a, 557a.
“Exh. 38, III J.A. 554a; Exh. 40 EP 1905(AX2), p. 3; 40 EP
1905(F (1), pp. 3-4; 40 EP 1905(FX1), pp. 4-5.
* Exhs. 38, III J.A. 553a-554a, 576a; 40 EP 1905(A\(2), p. 4; 40 EP
1920, p. 119.
58a
Basin well than he would have to wait for payout from a well
drilled elsewhere. Counterbalancing these factors was the
blanket nature of the sands, a phenomenon which tended to
assure that gas would be encountered at virtually any
location.”
In the early 1950's, DeGolyer & MacNaughton (D&M), a
respected, well-known firm of oil and gas geologists, made
numerous studies and evaluations of the natural gas reserves
of the San Juan Basin. D&M concluded that reserves of natural
gas were available in sufficient quantities to warrant commer-
cial production activities.“ Using the volumetric method of
estimating, D&M expressed great confidence that large
volumes of natural gas were available for extraction from
virtually all of the San Juan Basin acreage that the firm stu-
died. For example, in a January 1, 1950 report presenting “an
estimate of the proved recoverable reserves from the lower
Paradox limestone formation in the Barker Creek Gas Field
* * * and certain acreage under dedication to El Paso Natural
Gas Company,”” D&M concluded that—
This reservoir is estimated to contain 2 trillion 294 bil-
lion 272 million cubic feet of gas in place within an area of
45,000 acres.
~ - * * «
The indicated original reserve in place per acre for the entire
field is 50 million 983 thousand cubic feet per acre.
“ 7. - . “ -
“ A witness for Northwest testified that, having drilled several
hundred wells in the Basin, the pipeline had never had a dry hole. Tr.
765.
“See, ¢.g., Exhs. 40 EP 1905(A\(1), (AX(2), (C2), (C9), (E2),
(EX4), (F1), (F 2).
* Exh. 40 EP 1905(A\(1), p. 1.
5da
The remaining gas reserves of the field recoverable to a
terminal pressure of 250 psig shut-in wellhead after
deducting the cumulative production to January.1, 1950 is
2 trillion 88 billion 743 ion cubic feet.
The gas reserve available for pipeline sale after makin
allowances for miscellaneous field use, treating losses an
fuel, recoverable to a terminal pressure of 250 psig shut-in
wellhead is 1 trillion 531 billion cubic feet.”
This language, it should be noted, pertains to only one set of
leaseholds in the Basin. D&M was similarly sanguine about the
abundance of proved reserves underlying other acreage that it
studied.
The respondents now claim that D&M’s use of the
“volumetric” method of calculating reserves in place, rather
than the more precise “pressure decline” method, resulted in
gross overestimates on D&M’s part. They also quibble about
D&M’s use of the term “proved reserves” in the firm's several
reports; respondents claim there is a difference between that
term as D&M used it and the “proved reserves” that must be
present before a sale of a leasehold will be construed as a sale of
gas in place under the teachings of Rayne Field and its prog-
eny. Both of these contentions are rejected. In the first place,
respondents’ criticisms are palpably the product of litigation-
inspired 20/20 hindsight. So far as this record shows, all of the
contemporaneous, knowledgeable, interested persons who re-
viewed the D&M reports placed complete confidence in their
accuracy for the purpose for which they were made; the FPC,
for instance, certificated a major new pipeline system based
upon the reserve estimates produced by D&M.
In the second place, it is doubtful that either Rayne Field or
any of the cases that have expounded upon the Rayne Field
doctrine demand that proven reserves be defined with the
hairsplitting nicety upon which the respondents seem to insist.
All that Rayne Field requires is that the parties know and
* Id. at 4-5.
00a
believe there is at least a specified quantity of gas in place upon
which they can rely for the purpose of transacting business.
Thirdly, while the volumetric method is admittedly less
accurate than the pressure decline method, the difference is
not substantial when we are dealing with an area as great, and
volumes as large, as those the San Juan Basin presented.
Furthermore, the volumetric method of estimating reserves is
today, and was then, a sound, generally-accepted technique for
estimating gas reserves, especially in a field with little or no
production history." This is not, moreover, a case of preferring
a faulty methodology over an exact and precise one. As counsel
for Atlantic Richfield, one of the respondents, pointed out
during the Midland trial, “reserve estimating is at best an
inexact science.”
Finally, as noted above, the record shows that. con-
temporaneously with the D&M studies and thereafter, all of
the parties acted on the assumption that there were massive
quantities of proved reserves underlying the San Juan Basin.
The most persuasive point is that, notwithstanding the above-
average costs of extracting the San Juan Basin’s gas reserves, ™
experienced and knowledgeable businessmen were willing to
expend huge sums of money to obtain rights to the gas reserves
of the Basin.
“See Exh. 38, IV J.A. 121] §a-19a.
“Id. at 1219a. To which the witness responded, “I think that's a
good classification, yes, sir.”
™“ Several of the factors that caused the cost of extracting gas from
the Basin to exceed the cost of comparable development activities
elsewhere in the Southwest have been noted above, There was the
low permeability and porosity of its gas-bearing sandstone forma-
tions, coupled with the unusually low pressure of the gas reserves. In
addition, the relative isolation of the Basin and the lack of a local
gas-technology infrastructure, ¢.g.. skilled drillers and equipment
suppliers, made the cost of development operations higher than
would have been the case in, say, the Permian or Hugoton Basins,
56a
Delhi and other independent producers (some of whom are
now before the Commission in this case, taking the view that
the Basin was a risky speculation), all successful and profit-
oriented business concerns, acquired leases on much of the
Basin’s acreage and were willing to agree to delay-rental
obligations for failure to develop the leases. Delhi had in fact
executed two contracts with El] Paso, under which it was
obligated to make wellhead sales of the reserves underlying its
acreage. Although the contracts were aborted, the problem
was not a lack of confidence in the estimates of the Delhi
reserves. Similarly, E] Paso risked the vast sums that went
into the construction of the San Juan pipeline on the belief that
its acquisitions in the Basin included enough reserves to sup-
port that investment. The Commission, too, must have been
convinced of the virtual certainty of the reserves; it certifi-
cated the pipeline on that basis. And D&M, then as now one of
the most prestigious engineering consulting firms in the na-
tion, had staked its professional reputation on its evaluation.
At that time, before the significance of the question for
purposes of litigation became known, all of the knowledgeable
persons in the field acted upon the assumption that large
volumes of proved reserves could be produced from the San
Juan Basin. It is too late now to suggest that the contrary was
true.
Vv
As we have seen, use of the lease-sale format as the mechan-
ism for transferring reserves began with GLA 32, which was
executed early in 1950. GLA 32, however, is not involved in
this proceeding, and is substantially different in content from
the El Paso lease-sale contracts that were executed later. The
basic terms and conditions that recur again and again in the
lease-sale contracts involved in this proceeding first appeared
in GLA 47, signed in January of 1952. It seems clear that the
contents of GLA 47 set the pattern for the rest of the San Juan
Basin GLA contracts. For this reason, it is worthwhile to look
into the reasons why GLA 47 came into being.
57a
Once again, the fundamental stimulus was California's seem-
ingly insatiable hunger for natura! gas. As the demands of the
to maintain its position as California's primary gas supplier. On
March 6, 1951, El Paso had filed an application with the Feder-
al Power Commission, seeking a certificate authorizing the
transportation of an additional 100,000 Mcf of gas per day from
the San Juan Basin to the California border.
By early 1951, Delhi had acquired huge reserves of natural
gas in the Blanco-Largo and Kutz Canyon-Angel’s Peak Fields
of the San Juan Basin. both of which were located to the
Southeast of the Barker Dome Field. It was clear to E] Paso
that, in order to Support its pending FPC application to in-
crease its natural gas service, it would have to obtain dedica-
tion of the vast Delhi reserves to the El Paso system. This was
the case for two reasons. F irst, the Delhi reserves were
uniquely large enough to provide the volumes needed to sup-
port the application. Second, the unique strategic location of
the Delhi reserves permitted them to be rapidly introduced
into El Paso’s pipeline system, thereby providing the deliver-
ability that E! Paso needed to demonstrate to the Commission.
E] Paso at first attempted to purchase the gas from Delhi at
the wellhead. It offered an initial base price of 7.33 cents per
Mcf plus longevity escalations. Delhi rejected the offer on the
ground that the price was too low. E! Paso then approached
other independent producers in the area, seeking to make
wellhead sales contracts. But those producers, aware of E]
Paso’s urgent need for the dedication of new reserves and of
Delhi's strong bargaining position, refused to consummate
sales to E] Paso until the outcome of the negotiations with
Delhi became known. Hence, E! Paso was forced to deal with
Delhi first. Unable to obtain the gas reserves it needed
through the medium of conventional wellhead sale contracts,
El Paso sought to purchase Delhi's leases in a transaction
similar in form to the Barker Dome sale that had taken place in
1950.
58a
After months of hard bargaining, the parties executed the
lease-sale agreement now known as GLA 47 on January 18,
1952.*
GLA 47 covered leases owned by Delhi in the Blanco-Largo
Field of the San Juan Basin. In the contract, Delhi agreed to
assign its entire interest in the leaseholds to El Paso, reserving
an “overriding royalty” on all gas produced and saved from
the subject acreage. The quantum of the “overriding royalty”
was fixed as follows:
5¥e¢ per Mcf for the first 3 1/3 years from date of closing.
6¥¢ per Mef for the next 3 1/3 years thereafter.
7¥e per Mcf for the next 3 1/3 years thereafter.
Not less than 8¢ per Mef for 1 year thereafter.
Not less than 9¢ per Mef for 1 year thereafter.
Not less than 10¢ per Mcf thereafter.”
The agreement also provided for redetermination of the
price after the tenth year and after each ensuing five-year
period. If the parties were unable to reach agreement as to the
new price, the issue would be settled by arbitration, with the
arbitrators fixing the price at the fair market value of the gas at
the wellhead (but not less than the minimum figures set forth
above). The agreement also contained a favored nations clause.
In addition to its “overriding royalties” on gas production,
Delhi also retained substantial rights in other minerals. Delhi
reserved a 33 1/3% interest in all liquid hydrocarbons extracted
from the acreage, and it had the option to require El Paso to
pay the override in kind or in cash at the fair market value of
the liquids. Delhi reserved the rights to any oil recovered from
the leasehold. Delhi also retained the rights to all gas or other
“The negotiations were conducted by two now-legendary figures
in the industry, Clint Murchison, President of Delhi and Paul Kayser,
President of E] Paso.
* S Exh. 24, p. 5.
59a
hydrocarbons taken from any formation deeper than the
Mesaverde.
The agreement also contained a take-or-pay clause, which
required E] Paso to pay for a minimum volume of gas produc-
tion from the leasehold, whether or not it took that quantity.”
It imposed a number of specific drilling and developmental
obligations upon E] Paso, such as the obligation to develop the
acreage fully down through the Mesaverde and all shallower
formations and to drill at least one well on each 320-acre spac-
ing unit during the first five years after execution of the con-
tract. E] Paso also undertook complete responsibility for oper-
ation of the acreage, including the actual production of gas
from it. In the contract, E] Paso agreed to pay Delhi for wells
located on the acreage at the date of closing. The price was
$80,000 for each completed commercial Mesaverde well and
$20,000 for each completed commercial Pictured Cliffs well.
E] Paso was given the right to reassign acreage to Delhi, and
thereby to be relieved of responsibility to develop the acreage,
if it appeared that a specific production unit would not produce
gas in commercial quantities. In addition, E] Paso had the right
to reconvey to Delhi any specific well that proved to be unpro-
fitable to operate; Delhi then had the option to continue pro-
duction from the well, selling the gas to E] Paso at the wellhead
at the highest price prevailing in the field. Finally, the agree-
ment provided that Delhi had the option to purchase, at El
Paso’s cost, any oil well E] Paso might complete.
The question whether the GLA 47 transaction would render
the seller subject to FPC jurisdiction apparently remained
* The clause (Article VII, Section 1) was somewhat ambiguous. It
set the take-or-pay quantity at all gas produced from the acreage
until total production exceeded 100,000 Mef per day. Thereafter, El
Paso was obligated to take or pay for the greater of 25% of the open
flow capacity of all the wells, on the basis of an 80% load factor, but
not more than 150,000 Mcf per day, or 100,000 Mef of gas per day until
the acreage was fully developed and 25% of open flow capacity up to
150,000 Mef per day thereafter. In any event, the minimum daily
takes could be averaged out over a one-year period.
60a
uppermost in the minds of Delhi’s principals, for they sought
another legal opinion on that subject shortly before the agree-
ment was executed. On January 7, 1952, eleven days prior to
the signing of GLA 47, Delhi’s counsel, Charles V. Shannon,
issued another opinion, in which he reiterated his view that
consummation of this particular lease-sale agreement would
not make the transaction jurisdictional under the Natural Gas
Act.”
GLA 47 was closed on March 1, 1952. On that date, Delhi
assigned its leases and wells to El Paso and El Paso paid Delhi
$1,020,941.34 for Mesaverde and Pictured Cliffs wells situated
on the acreage covered by the agreement.” Shortly after the
closing, during March 1952, E] Paso began to transport gas
produced from the GLA-47 acreage through its interstate pipe-
line system.” Three months later, on June 19, 1952, the Feder-
al Power Commission granted E] Paso’s application for a cer-
tificate authorizing the expansion of its facilities.”
* It is significant that Shannon’s opinion was issued about a month
after the parties had signed a memorandum agreement, dated De-
cember 5, 1951, outlining the significant terms of the contemplated
lease-sale agreement. They evidently believed that the deal could
have been aborted if counsel subsequently advised that there had
been a shift in the jurisdictional winds.
* CPFF (Complainants’ Proposed Findings of Fact) No. 116, p. 43;
See also Exh. 24 (Letter from Delhi Oil Corp. to E] Paso Natural Gas
Co., dated February 29, 1952, re: Delhi-E] Paso Trade, pp. 1-4. It
should be noted that the parties considered the wells to be sufficient-
ly commercial to fall within the contract requirement that E] Paso
must pay Delhi only for commercial wells. See Exh. 24, p. 10.
*CPFF No. 118, p. 43.
® El Paso Natural Gas Co., 11 FPC 1071. The Commission also
removed a 34 Bef annual ceiling on volumes transported through El
Paso’s system. The ceiling had been imposed when the E] Paso
pipeline from the San Juan Basin was originally certificated.
6la
At present, the interest owners of GLA 47 (successors to
Delhi’s rights) are Tenneco Oil Company and Continental Oil
Company. Both of these companies have demanded increased
overriding royalty payments from El Paso. Both Tenneco and
Continental were parties to the U.S. District Court suit in
Midland, Texas.
VI
It was as if the execution of GLA 47 had broken a logjam.
After the March 1, 1952 closing of GLA 47, El Paso’s pro-
gram of acquiring gas reserves in the San Juan Basin through
purchases similar to the so-called “Delhi deal” proceeded
rapidly. In all, the pipeline made 36 lease-sale contracts with
the owners of gas leaseholds in the Basin, thereby acquiring
the gas underlying more than a quarter of a million acres.”
Although it took some six and one-half years to consummate
all of the agreements, the large tracts were acquired early in
the program. Almost two-thirds of the acreage (some 65.6% of
it) was under contract by January 1953, a year after execution
of the first GLA, and the contracts for more than 80% (82.5%)
of the acreage had been signed by July 8, 1953, some 18 months
after GLA 47 came into being.
The essential details of the GLA acquisitions are provided in
the following table:
*! Only 35 of the GLA contracts are implicated in this case. The
exception is GLA 153, which is shown on Exhibit 36 as having been
executed on May 10, 1953. Francis I. Harvey is identifed as the
interest owner. For reasons which are not presently apparent, the
Commission did not designate the GLA 153 interest owners as re-
spondents when it initiated this case. See Tr. 412.
Prior Gas
GLA Date Date Origaeal Present Purchase
No. Signed Closed Owner Owner Contract“
47 1/18/52 3/1/52 Delhi Oil Corp. Tenneco Oil Co. & Continental Oil No
Co
51 2/29/52 41/52 J. Glenn Turner Mapeo Production Co. & Hopi Oil Yes
Co
52 4/1952 5/1652 Three States Nat. Gas Co. Tenneco Conoco Yes
60 9/26/52 1/2253 San Juan Drilling Co., ¢f a/ Tenneco Conoco No
61 9/26/52 15538 Sunray Oil Co. Sun Oil Co. : No
62 10/10/52 318/53 Blackwood & Nichols Co. F.HLN., Ltd. No
63 123538 22038 Atlantic Refining Co. Atlantic Richfield Co. No
66 33153 42433 Lucerne Corp. W. Watson LaForce, ef al No
2 6/2/53 71553 J. Glenn Turner Mapeo Hopi Yes
76* 7/6/53 Vi Johnston Oil and Gas Co. Union Oil Co. of Cal. No
=e" 7/653 1354 R. E. Beamon Robert Beamon, ef «/ No
73 Tes T2738 Three States & Albuquerque Ass‘. — Tenneco Conoco, Am. Petrofina, ef No
Oil Co. al
86 12153 12158 J. Glenn Turner Mapco Hopi Yes
101 4254 4201 J. Glenn Turner Mapeo Hopi Yes
106 52554 TH Morris Mizel, ef wr Morris Mizel, ef wr. Yes
122 10/12/54 12/155 White, McMillan & McLane Producing Royalties, Inc., ef al. Yes
125" 11/1054 1130/56 Benson-Montin, ef «/ American Petrofina Co. Yes
127 121 12144 J. Glenn Turner Mapeo Hopi Yes
129 12245041056 Delta Drilling Co. Delta Drilling Co., et al Yes
139 3355 2138 White & McLane Producing Royalties, Inc. ef a/ Yes
152° 4156 4156 Webb & Turner Turner & Webb Yes
157" 61/55 655 Turner & Webb Turner & Webb Yes
160" 7/55 ri ts) Turner & Webb Turner & Webb Yes
172 4/2955" 92453" Beaver Lodge Oil Corp. Crown Central Petroleum Corp. Yes
195° 1956 Lw5G Turner & Webb Turner & Webb Yes
196 12.2855 1272855 Turner & Webb, ef «/ Turner & Webb, ef al. Yes
197 122855 122855 Huerfanito Drilling Co. Huerfanito Drilling Co. No
ae
Prior Gas
GLA Date Date Original Present Purchase
No. Sigued Closed Owner Owner Contract“
193* 12/26/55 1228/55 Turner, Webb & Schultz, ef a/ Turner, Webb & Schultz, ef al. Yes
231° 12/1/55 155 Turner, Webb & Abraham Turner, Webb, ef al, Yes
243" 1/8/57 1657 Turner, Webb & Schultz Turner, Webb & Schultz Yes
249 1/57 1857 Turner & Webb Benson-Montin-Greer Drilling Yes
Corp., et al,
343* 7/2938 41/58 Texas Nat'l Petroleum Co. Union Oil Co. of Cal. No
349°" 7/29/58 72938 Texas Nat'l Petroleum Co. Union Oil Co. of Cal. No
350* 4/5/58 45 5s R. E. Beamon Robert Beamon, ef al No
351** 8/5/58 995s kK. E. Beamon Robert Beamon, ef al. No
*GLAs 76, 77, 348, and 350 related to the same acreage.
**GLAs 349 and 351 related to the same acreage.
“GLAs which were the subject of the case of William G. Webb, ef al. (Op. No. 642), 49 FPC 17 (1973).
“Leases were transferred on September 24, 1953 pursuant to « ‘etter agreement dated July 30, 1953. Formal GLA contract was signed
on April 29, 1955
“Exhibits 42 (Rev.) and 36 show closing date as 94958. CPFF No. 432 gives it as 7/29/58.
“Yes” indicates that, prior to the lease-sale, El Paso purchased yas from the acreage under a wellhead sale.
64a
As the table indicates, the number of separate tracts of land
involved was somewhat less than the number of GLA con-
tracts. Four of the agreements GLAs 76, 77, 348 and 350,
related to the same acreage, with the latter two transactions
transferring to El] Paso the deeper horizons of the tract.
Similarly, both GLA 349 and GLA 351 related to the same
acreage, with the first transferring five-sixths of the working
interest and the second transferring the remainder.
In the case of almost half the contracts—16 of them—we find
that the interest owner who sold the leasehold consisted of J.
Glenn Turner, Delhi’s General Counsel, one of Turner’s part-
ners in the Dallas law firm of Turner, Atwood, White, McLane
and Francis, or both. Whether these corporate lawyers were
acting for themselves or as agents for others is a question upon
which the record offers no enlightenment. Eight of the Webb-
Turner GLAs, plus GLA 125, were the subject of the Federal
Power Commission’s Opinion No. 642."'
As the table above indicates, natural gas from the acreage
involved had been sold to El Paso under conventional wellhead
sale contracts before the Webb-Turner GLA contracts were
signed. In order to transfer the leasehold interests, it was
necessary for the seller, in each case, to obtain the Commis-
sion’s approval; technically, the transmutation of the con-
ventional wellhead sale into a sale of the leasehold and its
underlying reserves constituted an “abandonment” of the con-
ventional sale, for which authorization was required under
Section 7 of the Natural Gas Act.” There is, however, no
explanation of why the 13 other GLA contracts which replaced
prior wellhead sales were not also the subject of abandonment
cases.
® Besides Turner, two the firm’s partners who turned up as sellers,
were William G. Webb and Alfred E. McLane.
* William G. Webb, et al., 49 FPC 17 (1973).
15 U.S.C. 717f.
65a
The following table [see 66a-67a] shows the number of wells
on the acreage covered by each of the GLA contracts as of the
date the contract was signed and as of the date the property
transfer was closed. In some cases, e.g., GLAs 139 and 172, a
substantial period of time elapsed between the two dates,
during which a substantial number of wells were drilled. The
record does not disclose why the lengthy hiatus occurred in
some cases and not others. We may infer that, in those in-
stances where the closing was delayed, the seller found it
financially attractive to “drill up” his acreage and to sell the
wells to E] Paso at the price specified in the contract. The table
also contains an estimate of the size of the parcel transferred
under each of the GLA contracts. In this connection, it should
be noted that, during the period of E] Paso’s lease-sale acquisi-
tions, New Mexico law set a maximum on the number of wells
that could be drilled on a tract of a given size. The maximum
was one Pictured Cliffs well for each 160 acres and one
Mesaverde well for each 320 acres.
The formats of the GLA agreements all followed essentially
the same pattern. In exchange for the lessee’s agreement to
transfer the gas leasehold (either the lessee’s interest in all the
acreage or only his rights in certain horizons), E] Paso agreed
to pay a lump sum at the closing to purchase the wells and
gas-drilling-and-production equipment located on the acreage.
In some cases, there was also a specified lump-sum payment
which was not tied to any particular personalty transfer—a
sort of “bonus” to the owner of the leasehold.”
The principal compensation to the interest owner, however,
took the form of periodic payments which were to be made as
E) Paso produced the gas and other hydrocarbons. The pay-
ment was termed an “overriding royalty.” In about half the
(Text continues on p 68a, after table]
® In two cases, GLA 63 with Atlantic Richfield and GLA 66 with
Lucerne Corporation et a/., there were no wells on the acreage, and
there was no provision for payment of a lump sum at closing.
Wells on Wells on
GLA No. of Date Date
No. Acres Signed Closed Remarks
47 102,400 15MV 16MV Only 11 MV and 7 PC wells purchased as “commercial.”
9PC 9PC
51 841.71 3MV 3MV PC well is not shown on Exh. 41, Tab 1 map.
IPC IPC
52 29,631.21 6MV 7MV E! Paso’s Exh. 42 (Rev.) shows 8 MV wells.
IPC IPC
60 3,500 IMV 7™MV Exh. 42 (Rev.) shows & MV wells. Contra: Exh. 40 EP 40.
61 11,400 3MV 4MV 2 incomplete wells on 1/5/53 closing date.
62 See remarks 2PC 2PC 1,081 acres in initial transfer. 11,520 acres eventually
transferred. 1 well not deemed “commercial.”
63 5,080. 0 0
66 2,480 0 0
72 2,443.69 2MV 2MV Exh. 42 (Rev.) shows 4 MV wells at closing.
13PC Map (Ex. 41, Tab 3) shows only 2 complete.
76 26,687.71 4PC 19PC Same acreage as GLAs 77, 348, 350. 1 incomplete PC well
3MV at ‘closing.
77 do. do. do. Same acreage as GLAs 76, 348, and 350.
78 10,423.49 2MV 2MV
86 320 IMV IMV
101 3800 5PC 5PC
106 1,480 2MV 2MV
122 1,280 0 8PC
125 9,250.25 5PC 49PC Acreage has only 48 wells today.
127 1,760 6MV 6MV
5PC 5PC
129 5,236.31 6PC 31PC
139 3,429.17 0 19PC Map (Exh. 40 EP 40) shows 2 PC wells on 3/3/55
execution date.
351
Total acreage
1,921.36
3,760
320
1,201
1,600
2,885.30
160
960
480
920.69
4,720.81
26,687.71
1,283.48
26,687.71
1,283.48
= 250,226.78
12PC
GLA confirmed 7/30/53 letter agreement.
Fruitland (FR) wells were shallower than PC wells.
Same acreage as GLAs 76, 77, and 350. GLAs 348 and 350
transferred Dakota formation rights.
Exhs. 42 (rev.) and 36 show closing date as 9/9/58. CPFF
(p. 110) says 7/29/58.
Same acreage as GLAs 76, 77, and 348. GLAs 348 and 350
transferred Dakota formation rights.
Same acreage as GLA 349.
B19
68a
cases (17), the royalty was payable as long as gas was produced
from the acreage. In the remainder, the royalty went to li-
quidate E] Paso’s obligation to make a lump-sum “production
payment.” Since the amount of the “production payment” was
usually calculated on the basis of the maximum volume of
reserves thought to underlie the acreage, it made very little
practical difference which form the obligation took.
Under the typical arrangement, E] Paso’s initial payment
was pegged at between five and six cents per Mef. During most
of the period, the wellhead price of gas in the Basin hovered
between ten and twelve cents per Mcf, and the cost of produc-
tion was thought to vary between five and seven cents per Mef.
Hence, the initial price, in many cases, closely approximated a
fair estimate of the profit after production expenses that could
have been anticipated from a wellhead sale. The initial pay-
ment escalated, usually by one cent per Mef, at specified in-
tervals until the agreement was either ten years old (in the case
of the Turner, Webb-Turner, and GLA 47 agreements) or 15
years old (in the case of all the other agreements). Thereafter,
the price was to be the wellhead value of the gas, fixed by
mutual agreement or, failing that, by arbitration at five-year
intervals, but not less than the last specified escalation.
For example, the compensation provisions of one contract
(GLA 52) provide, in Article III, Section 2, that the interest
owner, Three States Natural Gas Company, “reserves and
retains to itself and its successors and assigns, or to person(s)
whom Three States may designate, the following:
Paragraph A. An overriding royalty on Three States’ in-
terest in all gas produced and saved from the said leases and
the subject lands being sold herein as follows:
(1) 5¢ per Mef on all such gas produced and saved
during the first 3 1/3 years after the date of closing.
(2) 6¢ per Mef on all such gas produced and saved
during the next 3 1/3 years thereafter.
(3) 7¢ per Mef on all such gas produced and saved
during the next 3 1/3 years thereafter.
69a
(4) 8¢ per Mef on all such gas produced and saved
during the next one year thereafter.
(5) 9¢ per Mef on all such gas Lead ogame and saved
during the next three years there
(6) 10¢ per Mef on all such gas produced and saved
during the next one year thereafter.
(7) Not less than 10¢ per Mef on all such gas produced
and saved thereafter.”
The GLA 52 contract went on to provide that, when 15 years
have elapsed from the date of the closing, the parties would
attempt to agree on the amount of the overriding royalty for
the ensuing five-year period, and that the agreed figure would
be at least the ten-cents-per-Mef final price specified in the
above-quoted schedule. In the absence of mutual agreement,
the contract said,
such amount shall be determined by a board of arbitra-
tors * * *. The board of arbitrators, in determining the
amount of an overriding royalty, shall base their decision
on the then value of such gas at the well head, considering
only quality and pressure of gas, aggregate quantity of
delivery and the then current field prices (of then newly
negotiated contracts) of gas in other fields connected to or
in the area of any of El Paso’s pipe lines or gathering
systems * * *,
This process of setting the royalty at the wellhead value of
the gas produced from the lease was to be undertaken anew
after the twentieth vear from the date of closing and at in-
tervals of five years thereafter. In any event, however, the
ten-cents-per-Mcf figure was to remain a floor under the
amount of the royalty payment.”
Exh. 25, p. 7. The interest of Three States Natural Gas Company
is now held by Tenneco Oil Company and Continental Oil Company.
* Exh. 25, pp. 7-9. In GLAs 348, 349, 350, and 351, the initial
price-redetermination date was fixed at January 1, 1969 and was not
measured from the date of contract closing. These exceptions to the
general pattern may be related to the fact that those four contracts
70a
In all but one of the agreements (GLA 153), the interest
owner reserved an overriding royalty interest in any liquid
hydrocarbons (except oil) that E] Paso might produce from the
horizons transferred to the pipeline. Typically, the overriding
royalty was one-third of the seller’s interest in the liquids,
payable either in cash or in kind at the interest owner’s option.
The interest owner also specifically reserved all rights to any
oil that might underlie the acreage and to all gas or other
hydrocarbons in formations not conveyed.
Each of the agreements obligated El Paso to develop the
acreage in a manner which would avoid forfeiture of the
underlying lease. Also, the agreements expressly or by
implication imposed on the pipeline certain minimum require-
ments to drill new wells and to take gas from existing wells.
For example, in GLA 77 and GLA 76, both of which covered
the same acreage, E] Paso was bound to drill, within seven and
one-half years from the date of closing, at least one Mesaverde
well on each 320-acre Mesaverde drilling unit and one Pictured
Cliffs well on each of the 160-acre Pictured Cliffs drilling units
authorized by the New Mexico Oil and Gas Commission. In
agreements where there was no specific obligation to drill and
produce from new wells to be made at E] Paso’s expense, the
pipeline’s obligation to develop was a function of the take-or-
pay clause. As is indicated above, that clause required E] Paso
to take or pay for an annual average of 25% of the aggregate
open flow capacity of all the wells on the acreage on the basis of
an 80% load factor. This type of clause was generally found in
agreements pertaining to acreage that had, at the time of
closing, about the maximum amount of wells allowed by State
law—so that it was thought unnecessary or futile to provide for
additional drilling.
GLA 198, for example, involved the transfer of rights to the
gas in the Pictured Cliffs formation underlying one and one-
involved acreage that had been transferred in prior GLAs. In any
event, the interval between redetermination dates provided for in
GLAs 348, 349, 350, and 351 was the standard period of five years.
Tla
£
half sections. At the time of closing, there were six Pictured
Cliffs wells on the acreage, or one well per 160 acres.” Article
VII, Section 1 of the contract (entitled MINIMUM GAS PRO-
DUCTION AND DEEP GAS PRODUCTION) provided as
follows:
El Paso agrees that it will promptly commence and
continue taking gas from wells now existing or which may
hereafter be completed in the zones and/or formations in
the leases and operating agreements being sold to it
hereunder, subject to the physical capacity of the wells to
produce the quantities hereinafter provided for against
the line pressures of El Paso’s gathering system, and
likewise subject to requisite authorization to produce such
volumes under the rules and regulations of governmental
authorities having jurisdiction thereof, provided, how-
ever, that El Paso shall take gas hereunder at natural well
head flowing pressures and hall have the right to operate
its gathering system at pressures up to, but not exceeding
250 PSIG. * * *
Subject to the regen provisions hereof, E] Paso shall
take from Pictured Cliffs wells now existing or which may
be hereafter completed on the subject lands and leases, an
amount of gas each day equal to twenty-five percent (25%)
of the aggregate open flow capacity of all such wells on the
basis of an eighty percent (80%) load factor, averaged
annually. In lieu of taking the minimum quantities of gas
required by this Agreement, E] Paso may pay to each
Assignor, in cash, all amounts which would have been due
to such Assignor hereunder had such quantities been
taken. * * * Any gas paid for by El Paso but not taken
during any year by virtue of the minimum take or pay
provisions hereof may be taken by E] Paso from the sub-
ject lands at any time thereafter out of any production in
excess of the minimum quantities above provided for dur-
ing the period or periods in which such quantities are
being made up.”
® See Exh. 41, Tab 16.
* Exh. 16, pp. 19-21.
72a
A number of the GLAs contained a so-called reconveyance
clause, a provision which operated to limit E] Paso’s risks.”
The clause gave E] Paso the right to reassign to the interest
owner acreage or wells that proved to be unprofitable or non-
commercial, thereby liquidating its obligation to make good on
the lessee’s duties to the landowner with respect to the acreage
or the wells.
A relatively straightforward example of a reconveyance
clause, one dealing only with the possibility of an unprofitable
well, appears in GLA 106, which E] Paso entered into with Mr.
and Mrs. Morris Mizel on May 15, 1954. A paragraph found in
Article VI, Section 3 of the agreement reads as follows:
In the event the operation of any well now or hereafter
drilled by E] Paso shall become unprofitable, then El Paso
shall have the option upon sixty (60) days’ notice to Mizel
to reassign to Mizel such well and the unit upon which such
well is situated, and in such event Mizel shall have the
option to sell gas produced therefrom to El Paso at the
highest price paid for gas of like kind and quality in the
field by E] Paso or any other bona fide pipeline company,
and E] Paso agrees to purchase such gas at such price."
GLA 106, it should be noted, involved a relatively small
parcel. A more complex reconveyance clause appears in agree-
ments for more substantial blocks of acreage, such as GLA 78
with both Three States Natural Gas Company and Albuquer-
que Associated Oil Company. In that agreement, which con-
veyed drilling rights to both Pictured Cliffs and Mesaverde
horizons underlying more than 15 square miles, the clause™
” The clause tended to appear in the earlier contracts. It is found in
the seminal GLA 47, in GLAs 52, 60, and 61, respectively in the
second, third, and fourth of the GLAs signed, and in GLAs 76, 77, 78,
and 106.
" Exh. 30, p. 8.
* Part of Article VI, Section 2 of Exh. 29 at pp. 14-15.
73a
read as follows (the interest owners are designated as FIRST
PARTIES with E] Paso as SECOND PARTY):
In the event that development hereafter in the area of
or adjacent to any drilling units should evidence that such
drilling unit will not be productive of gas in commercial
quantities in the formation me gesene to such drilling unit
as above specified and for such reason SECOND PARTY
shall not desire to drill such well thereon, then SECOND
PARTY ype! reassign any such drilling unit to
FIRST PARTIES or to any person whom FIRST PAR-
TIES may designate and thereupon shall be relieved of its
obligation to drill a test well thereon to the formation
applicable; provided that SECOND PARTY may retain
any commercial gas well completed therein in a shallower
or deeper formation, together with its rights in such drill-
ing unit down through such shallower or deeper forma-
tion. In the event the operation of any well now or hereaf-
ter drilled shall become unprofitable, then SECOND
PARTY shall have the option upon sixty (60) days’ notice
to FIRST PARTIES to reassign to FIRST PARTIES
such well and the unit upon which such well is situated,
and in such event FIRST PARTIES shall have the option
to sell oe produced therefrom to SECOND PARTY at
the highest price paid for gas of like kind and quality in the
field by SECOND PARTY or “y other bona fide pipeline
company, and SECOND PARTY agrees to purchase such
gas at such price.
All of the GLA agreements featured a favored nations
clause. The standard clause, which is virtually identical in all of
the contracts, obligated El Paso to pay the interest owner any
higher price it might subsequently pay under a lease-sale
agreement involving lands within a 200-mile radius of the
acreage. Since the Basin, at its widest point, was considerably
less than 200 miles across, the provision for payment of the
highest price that E] Paso negotiated for lease-sales within a
radius of 200 miles assured each interest owner that he would
be treated on a par with all other sellers of leases in the San
Juan Basin. In this context, it should be noted that at that time
E] Paso was the only pipeline making lease-sale contracts and
the only one that seemed likely ever to do so.
74a
VII
E] Paso was not to be alone for long, however.
As the United States entered the 1950’s, the Pacific North-
west area of the country remained as the last major untapped
market of the natural gas industry. On June 28, 1950, PNW
asked the Federal Power Commission for authority to serve
that region and local distributors in its major metropolitan
areas, Seattle, Washington and Portland, Oregon with natural
gas. The application contemplated the construction and opera-
tion of a long-distance pipeline commencing in Wharton Coun-
ty, Texas and rooted in the gas fields of the Texas Gulf Coast.
By the Spring of 1952, however, PNW’s focus had shifted
from the Texas Gulf Coast as its gas-supply source to the San
Juan Basin, an area more than a thousand miles closer to the
potential market. On August 27, 1952, PNW amended its
application for a certificate of public convenience and necessity
to specify that the proposed pipeline would be anchored in the
San Juan Basin.”
A major task for PNW was to secure dedication of reserves
to its proposed system. To do so, PNW sought commitments
from independent producers who owned substantial reserves
in the SanJuan Basin. PNW offered a number of the producers
the option of either a conventional wellhead sale of natural gas
or, alternatively, a sale of the gas reserves in place, with the
producers reserving an overriding royalty that would vary
with the quantity of gas produced. Under the “wellhead sale”
option, PNW originally offered to pay ten cents per Mcf for the
first five years, with an escalation of one cent per Mcf every
five years thereafter. Under the “in-place” option, PNW
offered an initial price of five and one-half cents per Mef and
™ The full scope of the proposal was massive, calling for the con-
struction of an entirely new pipeline system consisting of 1,184 miles
of main line and approximately 150 miles of lateral lines. The plans
contemplated that, by the third year of operation, the PNW pipeline
would carry its maximum design capacity: 314,000 Mef of gas per day.
75a
periodic escalations thereafter, with the producer having the
option to price the gas at its fair market after the twelfth year.
Subsequently, PNW raised its offering price under both
options; it offered 12 cents per Mef as the initial price for a
wellhead sale and approximately seven cents per Mef as the
initial price for a gas-in-place sale. The complainants say that
the five-cent-per-Mef difference between the two options re-
flected the costs that would be incurred by one who performed
the functions that fell to the operator of a gas lease, e.g.,
drilling, operation, and payment of production taxes." There is
some indication that contemporaneous computations by per-
sons knowledgeable in the business of extracting gas from San
Juan Basin reservoirs calculated those costs at about 4.5 cents
per Mcf. However, nothing in the record tells us convincingly
whether the close approximation of those two figures was the
result of design or happenstance.
PNW’s first success on the road towards obtaining the re-
serve commitments it needed was achieved on June 12, 1952.
On that date, PNW entered into a “commitment” agreement
with Phillips Petroleum Company. Under the agreement, Phil-
lips conditionally dedicated acreage in the Basin to PNW.
Phillips retained the option of selecting either a conventional
wellhead sale or a sale of gas in place as the ultimate form of the
transaction. Phillips exercised its option on January 9, 1953,
when it formally executed a lease-sale agreement with PNW,
thereby choosing the in-place-sale option. The lease-sale
agreement, which was eventually denominated PLA 5, cov-
ered approximately 202,000 acres located generally in the
northern and eastern portion of the Basin. Under the agree-
ment, PNW acquired rights in the Phillips leases down to, and
including, the Mesaverde formation.
The lease-sale agreement contemplated the transfer to
PNW of 3 Tef of recoverable gas reserves. PNW was obli-
gated, after a period of time, to reassign to Phillips acreage
See CPFF Nos. 476-77, p. 118.
76a
underlaid by any reserves in excess of the 3 Tef figure. Phillips
reserved an “overriding royalty” on all gas produced by PNW
from the PLA 5 acreage. During the first year after gas from
the PNW pipeline was first sold for resale, the royalty pay-
ment was to be seven cents per Mef. After that first year, the
price was to be eight cents per Mef for the next nine years.
During the succeeding year, the eleventh after the pipeline
first began operation, the price was to be nine cents per Mef.
Then, the price was to rise to ten cents per Mcf, where it would
remain until 20 years had elapsed from the opening of the PNW
line. After expiration of those first 20 years, the price was to be
redetermined under a formula: the redetermined price would
be 75% of the average of the three highest wellhead prices
being paid by any pipeline in the Basin for high-volume (20,000
Mcf/d or more) deliveries. In no event, however, could the
redetermined price be less than eleven cents per Mef for the
first five years, plus one cent per Mef for each five years
thereafter.
Under the agreement, Phillips reserved all rights to oil and
casinghead gas in the formations transferred to PNW and all
rights to any hydrocarbons found below those formations.”
PNW agreed to reimburse Phillips at the closing for Phillips’
costs of drilling and completing every well on the acreage as of
the closing, if the well met minimum standards of production.”
PNW was obligated to develop the acreage in such a manner
that there would be at least 250 net wells completed on the
acreage by July 1, 1955. PNW was given the right to reassign
® That is, below the base of the Mesaverde.
™ The standards specified that a well would have to produce at least
750 Mef/d against atmospheric pressure after a three-hour flow to be
eligible. At the time the agreement was made, the estimated cost of
drilling such a well into the Mesaverde formation was $90,000.
™ When acreage is communitized, the production of a well drilled
on that acreage is shared by all working interest owners in proportion
to their contributions to the communitized acreage. See Tr. 305-06.
Hence, if Phillips’ rights applied to one-half of a proration unit, a well
77a
to Phillips any acreage which it decided would be unprofitable
or uneconomical to develop, thereby relieving itself of all
obligations to develop that acreage.
The contract required PNW to acquire from the San Juan
Basin (either by purchase, production, or both) all of its daily
gas requirements up to 350 MMcef per day, except for 20 MMcf
per day, which could be secured from other places. PNW could
fulfill this requirement with gas from the Phillips acreage or
from elsewhere in the Basin. The 350-MMcf/d figure gave
PNW very little leeway to look to sources other than those in
the Basin, in light of the fact that the initial design capacity of
its pipeline was to be 314 MMcf/d.*
Since the contract was executed at a time when the pipeline
did not exist as such, it is not surprising to find that the parties
made the contract's viability contingent upon two events:
First, PNW would have to obtain the requisite certificate of
public convenience and necessity from the Federal Power
Commission. Second, PNW would have to obtain a satisfactory
certificate of financing from a reputable financial institution.
At about this time, other independent producers in the San
Juan Basin were recipients of similar offers from PNW. On
July 21, 1952, PNW made its option proposal to the Stanolind
Oil and Gas Company, which owned substantial reserves of
natural gas in the Basin. At first, Stanolind refused to commit
any acreage to PNW under either branch of the option scheme.
Subsequently, however, Stanolind entered into three “com-
mitment” agreements, dated March 13, 1953, March 10, 1954,
and February 1, 1955, with PNW. Under these agreements,
Stanolind conditionally assigned over 146,000 acres to PNW.”
drilled on the unit would constitute one gross well but only one-half of
a net well. Two such wells would add up to one net well. Consequent-
ly, meeting an obligation to have 250 net wells on the PLA 5 acreage
by July 1, 1955 might well entail drilling many more wells than that.
™ See n. 73, supra.
™*The March 13, 1953 agreement, together with an agreement
dated eleven days earlier, conditionally assigned acreage in which
78a
These “commitment” agreements, like the original Phillips
“commitment” agreement, were not lease-sale agreements.
Their purpose was simply to secure sufficient promise of an
adequate supply of natural gas to demonstrate the viability of
PNW’s pipeline project to both the FPC (in the pending certifi-
cate proceeding) and the financial community (which would be
asked to some up with the capital to construct the project).
Lease-sale agreements were, in fact, executed with Stanolind
in March of 1955.
On July 13, 1953, Sinclair Oil and Gas Corporation and PNW
entered into PLA 2, a lease-sale agreement covering some
3,600 acres located in the northwest corner of the San Juan
Basin. The agreement contained essentially the same provi-
sions as were found in the Phillips agreement (PLA 5), with
only minor variation.” The contract did not contain either a
take-or-pay clause or a favored nations clause.
The next “commitment” agreement was between PNW and
Skelly Oil Company. It was entered into on July 29, 1953 and
covered approximately 19,000 acres scattered throughout the
San Juan Basin.*! The text of the “commitment” agreement
noted that PNW had entered into a lease-sale with Phillips and
simply incorporated the terms of the Phillips lease-sale con-
both Stanolind and Colorado Oil and Gas Company held interests.
CPFF No. 490, p. 122.
“” For example, PLA 2 required PNW to drill at least ten net wells
on the acreage by July 1, 1955, whereas PLA 5 called for PNW to
have 250 net wells by that date on the acreage transferred by Phil-
lips. See Exh. 47, “Contract,” p. 8. Unlike the Phillips contract, PLA
2 did not recite the parties’ intention to assign a specific volume of gas
to PNW. The overriding royalty and redetermination provisions of
the two contracts were, however, markedly similar. As was the case
in the earlier PLA, the contract with Sinclair was conditioned upon
PNW obtaining an FPC certificate to build and operate the pipeline.
“'The Skelly acreage was the subject of PLA 3 and is colored
purple on the map that is Exh. 95. .
79a
tract (PLA 5) by reference. In addition to the terms that
Phillips secured, Skelly demanded, and eventually received, a
favored nations clause, and a ratable-take clause to assure that
its acreage would be developed at the same rate as other San
Juan Basin acreage under contract to PNW. As was the case
with the earlier agreements, the Skelly “commitment” was
conditioned upon issuance of an FPC certificate to PNW.~
On August 5, 1953, the Chicago Corporation (Chicago) and
PNW signed a lease-sale agreement. The agreement, PLA 14,
covered approximately 3,800 acres located generally in the
eastern portion of the Basin.~' PLA 14 was similar in nature to
PLA 2, the Sinclair lease-sale agreement, that had been ex-
ecuted less than a month previously. PLA 14 did not hav
either a take-or-pay clause or a favored nations clause. In this
respect, too, it was like the Sinclair contract. Its pricing provi-
sions were similar to those that would ultimately be incorpo-
rated into the Phillips agreements: a two-tiered pricing sys-
tem, in which Mesaverde gas was priced in accordance with the
well’s deliverability rate, while gas from other formations was
priced in the more conventiona! manner.™ In all other major
respects, however, PLA 14 was substantially identical to the
Sinclair (PLA 2) and Skelly (PLA 3) agreements.
The commitment of gas reserves to PNW under the agree-
ments discussed above was apparently sufficient to carry the
day for PNW in the Federal Power Commission's proceedings.
The Commission had consolidated PNW’s application with
other competing applications for authority to serve the Pacific
= See Exh. 48.
“ PNW had sent Chicago an option proposal by letter dated Janu-
ary 9, 1953. Chicago accepted the proposal, thereby entering into a
“commitment” agreement, four days later. See Exh. 72; Tr. 261-62.
“The Phillips agreement was, in fact, amended to include a
variable-price structure for Mesaverde gas. The amendment took
place on August 4, 1953, only four days after the execution of PLA 14
with Chicago.
80a
Northwest and had conducted a comparative hearing. One of
the issues, which the Commission resolved favorably to PNW,
was whether there were sufficient reserves of natural gas
dedicated to the proposed service.” In Opinion No. 271, issued
on June 18, 1954, the Federal Power Commission granted to
PNW the certificate of public convenience and necessity that it
had sought.”
Only two more “commitment” agreements were signed after
the Commission’s action. The last of them, the February 1,
1955 agreement between PNW and Stanolind, has been dis-
cussed above. The other was an agreement, executed January
25, 1955, between T. H. McElvain and PNW, which commit-
ted gas reserves down to the base of the Mesaverde formation
underlying some 1,500 scattered acres in the San Juan Basin.”
From our standpoint, the most significant feature of the McEl-
vain commitment agreement (which eventually matured into
PLA 4) is that it specifically incorporated by reference the
provisions of the Phillips lease-sale agreement—PLA 5—with
only minor variations.
On February 11, 1955, the Federal Power Commission ap-
proved PNW’s plan of financing for its proposed pipeline. This
step rendered PNW’s certificate final and permitted PNW to
close many of the conditional commitment and lease-sale
agreements into which it had previously entered:
—On February 22, 1955, PLA 14 between PNW and Chica-
go was closed. Leasehold interests in approximately 3,800
acres were conveyed to PNW. There were no wells on the
acreage at the time of the closing. The present interest owner
under PLA 14 is Champlin Petroleum Company.
—PLA 5, between Phillips and PNW, was closed one day
later, on February 23, 1955. Approximately 188,700 acres
were assigned. There were 75 wells, for which PNW paid
~% Northwest Natural Gas Co., 13 FPC 221 (1954).
“Id. at 238-39.
“ See Exh. 95, on which the McElvain acreage is colored yellow.
Sla
approximately $5,600,000, on the acreage at the time of the
closing.” Phillips remains the interest owner under PLA 5
today.
—Skelly and PNW closed on PLA 3 on March 3, 1955. At the
time of closing, there were seven wells on the acreage, and
PNW paid a total of $452,270 for those wells. The present
interest owner under PLA 3 is Getty Oil Company.
—On March 8, 1955, Sinclair and PNW closed on PLA 2,
which transferred Sinclair's rights to about 3,600 acres. PNW
paid $46,615 for the one well that was on the acreage at the time
of the closing. Atlantic Richfield is the present owner.
—Eight separate lease-sale agreements between Stanolind
and PNW were both executed and closed on March 16, 1955.
The agreements covered a total of approximately 146,000 acres
in the San Juan Basin. The eight separate tracts were widely
scattered around the rim of the Basin. Six of the lease-sale
agreements, covering approximately 116,150 acres, are PLAs
6-11, which are involved in this proceeding. The other two
were aborted when PNW reassigned the acreage covered by
the agreements to Stanolind in accordance with its contractual
right to give back any acreage judged unprofitable or unecono-
mical to develop.” The texts of PLAs 6-11 were all essentially
similar, although there were some minor variations. At the
time of the closing, there were 40 wells on the acreage. PNW
paid approximately $1,400,000 for the wells. The present in-
terest owner under PLAs 6-11 is Amoco Production Company.
~ The record does not contain a breakdown of the wells on this, or
any other, PLA acreage as between Mesaverde wells, Pictured Cliffs
wells, or wells in any other formation.
~The PLA contracts covered acreage in the Bondad area (PLA 6),
the Huerfano area (PLA 7), the Ignacio area (PLA 8), the Northwest
Cedar Hill area (PLA 9), the Rosa unit (PLA 10), and the Township
units (PLA 11). The areas covered by the two agreements which
were reassigned were the Arboles and the North Rosa areas. They
are not at issue in this case.
82a
—PLA 4, between PNW and T. H. McElvain, was closed on
September 1, 1955. On that date, there was one well on the
1,500 acres transferred to PNW. McElvain, et al. are the
interest owners under PLA 4 today.
The last of the PLA agreements was PLA 13, executed and
closed on April 23, 1957, some 20 months after the rest of the
PLA agreements. Under PLA 13, General Petroleum
Corporation transferred to PNW leasehold interests in some
13,000 acres located in La Plata County, Colorado, in the
northern portion of the San Juan Basin. The agreement was
similar in nature to the Stanolind agreements (PLAs 6-11) with
only minor variations.” On April 23, 1957, the date of closing,
there were two wells on the acreage subsumed by PLA 13. As
of that date, gas from the PLA 13 acreage had been flowing in
interstate commerce via the PNW pipeline for seven months.
The last step needed to permit PN W to build the pipeline had
been taken in New York City a little less than two years before
PLA 13 was closed. On May 4, 1955, the financing agreements
were closed. Under those agreements, PNW issued
$93,200,000 in First Mortgage Pipeline Bonds; in addition, it
sold bank notes, interim notes, and common stock. With the
money in hand, PNW was able to construct the pipeline rapid-
ly. It was finished the following year, and on September 1,
1956, natural gas began to flow through it from the San Juan
Basin to consumers in Seattle and Portland.
E] Paso’s purchase of PNW, which took place in 1957, and
the merger of the two companies in 1959 touched off more than
a decade of antitrust litigation.” As a result of the lawsuits, E]
” For example, PLA 13 imposed on PNW development obligations
which were somewhat less stringent than those in the Stanolind
agreements. Another provision of PLA 13 gave General Petroleum
the right to require PNW either to drill in any location General
Petroleum might specify or reassign it to General Petroleum. The
Stanolind agreements contained no comparable provision.
" Citations to the litany of cases arising out of the Government’s
suit to compel E] Paso to divest itself of the former PNW assets are
set forth at n. 10, supra.
83a
Paso was compelled to divest itself of the assets once held by
PNW which, after the merger, had become the Northwest
Division of E] Paso. The Northwest Division was acquired by
Northwest Pipeline Corporation on February 1, 1974. In-
cluded among the assets purchased by Northwest in the
transaction were all of the PLA agreements.
In most important respects, the terms of the PLA lease-sale
agreements were similar:
Pricing. There was a basic scheme of compensating the
interest owner, which recurred with few exceptions. All of the
contracts called for PNW to pay the interest owner an overrid-
ing royalty, calculated as a specified sum for each Mef of gas
produced from the acreage, beginning on a specified date.” The
initial price was 7 cents per Mef, except for Mesaverde gas
produced under PLAs 4, 5, and 14. The first increment of
Mesaverde gas under those three contracts was priced at 6
cents per Mcf, but that base rate could be higher, depending on
the rate at which the well produced. The contracts all provided
for periodic escalations of the base rate at specified intervals
for the first 20 years (in the case of PLAs 2, 3, 4, 5, and 14) or for
the first 25 years (in the case of PLAs 6-11 and 13). These
escalator clauses called for increasing the payment by one cent
per Mcf through the end of the tenth year, another cent per Mef
for the eleventh year, another cent per Mef during years 12
through 20, and, in the case of PLAs 6-11 and 13, one more cent
per Mef in the twenty-first through the twenty-fifth years.
After the twentieth year (or the twenty-fifth year under PLAs
6-11 and 13), the interest owner had the option of receiving
either a continuation of the periodic one-cent-per-Mcf
escalations—with the interval between escalation dates heing
set at five years—or being compensated under an “arithmetic
average” formula. It is not necessary to go into all the complex-
* In all of the contracts except PLAs 2 and 13, the date fixed for the
payments to begin was the date of the first sale of gas for resale from
PNW’'s pipeline. As it turned out, that date was September 1, 1956.
84a
ities of the formula; its purpose was to entitle the interest
owner to receive an amount equal to 75% of the average price
being paid for gas sold at the wellhead in the area, if, by doing
so, he would be paid mo
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