APTD-1459
AN ANALYSIS
OF THE
REGULATORY ASPECTS
OF NATURAL GAS SUPPLY
US. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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APTD-1459
AN ANALYSIS
OF THE
REGULATORY ASPECTS
OF NATURAL GAS SUPPLY
by
Foster Associates, Inc.
1101 Seventeenth Street, N.W.
Washington, Dr C. 20036
Contract No. 68-02-0640
EPA Project Officer: Frank Collins
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1973
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The APTD (Air Pollution Technical Data) series of reports is issued by
the Office of Air Quality Planning and Standards, Office of Air and
Water Programs, Environmental Protection Agency, to report technical
data of interest to a limited number of readers. Copies of APTD reports
are available free of charge to Federal employees, current contractors
and grantees, and non-profit organizations - as supplies permit - from
the Air Pollution Technical Information Center, Environmental Protection
Agency, Research Triangle Park, North Carolina 27711 or may be obtained,
for a nominal cost, from the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22151.
This report was furnished to the Environmental Protection Agency by
Foster Associates, Inc., Washington, D.C. in fulfillment of Contract
No. 68-02-0640. The contents of this report are reproduced herein
as received from the contractor. The opinions, findings, and con-
clusions expressed are those of the author and not necessarily
those of the Environmental Protection Agency. Mention of company
or product names is not to be considered as an endorsement by the
Environmental Protection Agency.
Publication No. APTD-1459
11
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TABLE OF CONTENTS
CHAPTER I
CHAPTER II
Page
INTRODUCTION 1-1
CONCLUSIONS AND REOMENTATIONS 11-1
Regulatory Strategies for Increasing Gas Supply 1L-2
1. Sanctity of Contract Legislation [1-5
2. Decontrol Legislation 11-6
3. Legislation to Expand Federal Regulation 11-8
4. Modification of Producer Regulation 11-9
5. Acceleration of Offshore Leasing 11-14
6. Encouragement of Supplemental Gas Supplies 11-16
Optimal Strategy and Cost Effectiveness Estimates 11-25
CHAPTER III - REGULATORY BODIES AFFECTING SUPPLY OF GAS
A. State Regulation
1. Conservation Regulation
2. Leasing Authority
3. Rate Regulation
4. Actions Directed to Gas Shortage
B. Interior Department
1. Leasing of Public Lands
2. Office of Coal Research
C. Federal Power Commission
1. Background of the Natural Gas Act
2. Scope of FPC Powers Under Natural Gas Act
D. Other Federal Bodies
1. Departments of State, Defense and Commerce
2. Price Commission
3. Atomic Energy Commission
FEDERAL POWER COMMISSION REGULATION OF NATURAL GAS
A. Producer Sales at the Wellhead
1. 1954 Through 1960
2. 1961 Through 1968
3. 1969 to Date
B. Pipeline Rates
C. Pipeline Certificates
D. Abandonments
E. Interconnection of Facilities
F. End-Use Regulation
CHAPTER IV -
III-l
III-l
111-6
111-11
111-12
111-24
111-24
111-33
111-34
111-34
111-36
111-40
111-40
111-41
IIJ-45
IV-1
IV-2
IV-3
IV-9
IV-21
IV-26
IV-32
IV-5 7
rv-58
1V-40
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TABLE OF CONTENTS
Pat
CHAPTER V
CHAPTER VI
G. Curtailments
H. Imports and Exports
1. Pipeline Imports from Canada
2. LNG Imports by Tanker
I. Synthetic Gas
REGULATORY MEANS OF INCREASING GAS SUPPLY
A.
B.
C.
D.
E.
Supply-Demand Picture: Background Data
1. Trends In Gas Exploration and Reserves
2. Trends in Gas Prices
3. Extent of Gas Shortage
4. Potential Gas Reserves
Proposed Sanctity of Contract Legislation
Legislation to Decontrol Wellhead Prices
Legislation to Expand Federal Regulation
FPC Modification of Producer Regulation
1. Optional Certificate Procedure
Increase in Area Rate Ceilings
2.
3.
4.
Other Measures
What EPA Can Do
F.
G.
Acceleration of Offshore Leasing
Encouragement of Supplemental Gas Supply Projects
1. Gas from Alaska
Pipeline Imports from Canada
LNG Imports
2.
3.
4.
5.
IV-45
1V-55
IV-56
IV-60
IV-71
V-l
V-6
V-6
V-12
V-16
V-21
V-25
V-32
V-37
V-42
V-45
V-48
V-51
V-55
V-56
V-62
V-66
V-70
V-75
Synthetic Gas Reformed from Liquid Hydrocarbons V-79
Synthetic Gas from Coal V-86
THE COST EFFECTIVENESS AND TIME REQUIREMENTS FOR
ALTERNATIVE REGULATORY STRATEGIES REGARDING GAS
SUPPLIES
A.
B.
C.
D.
The Cost Effectiveness of Increased Field Prices
of Gas in the Lower 48 States
VI-1
VI-3
The Current Commodity Value of Gas in U.S. Markets VI-4
The Increase in Gas Production that Would Result
from Commodity Value Pricing VI-11
The Benefits Compared with the Cost of Incremental
Domestic Gas Supplies, 1972-1982 VI-17
E. The Benefit of Increased Gas Supplies Resulting
from a Reduction of Sulfur Emissions
VI-22
11
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INDEX OF TABLES AND CHARTS
Page
Table Forecast of Gas Production in the Lower 48 States 11-24
Table Estimated Benefit of an Increased Gas Supply in the
United States with Respect to Reduction in Sulfur
Emissions 11-25
Table NARUC Survey of 42 States and the District of Columbia,
Action by Regulatory Agencies and Natural Gas
Distribution Companies to Meet Existing or Possible
Future Natural Gas Shortages, February 29, 1972 111-14
Table Summary of State Actions Respecting Restrictions and/or
Curtailments of Gas Service II1-17
Table Outer Continental Shelf Lease Sales of Oil and Gas III-28
Table Area Guideline Prices Established by Statement of
General Policy No. 61-1, Issued September 28, 1960 IV-8
Table Firm Requirement Deficiencies Reported by Interstate
. Pipelines to FPC Staff IV-48
Table Curtailment Provisions and Plans Filed by Interstate
Pipelines with FPC IV-51
Table Trends in Gas Reserves and Production, United States
Excluding Alaska, 1958-1971 V-8
Chart Reserve-Production Ratios, Annual Additions of New
Reserves, Production, and Consumption of Natural Gas
in the United States (Excluding Alaska) V-9
Table Trends in Gas Well Drilling, United States Excluding
Alaska, 1958-1971 V-10
Table Exploration Indicators, United States, 1958-1971 V-ll
Table Trends in Wellhead Prices of Natural Gas and Comparison
with Other Hydrocarbon Fuel Prices at Points of
Production, United States, 1958-1971 V-13
Table Trend in Prices of Gas and Fuel Oil for Residential
Heating, United States, 1959-1971 V-14
Table Current Rates for Interstate and Intrastate Sales of
New Gas V-15
Table U.S. (Excluding Alaska) Gas Supply Gap as Projected by
FPC Staff V-18
Table U.S. (Excluding Alaska) Gas Supply Gap as Projected by
National Petroleum Council • V-19
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INDEX OF TABLES AND CHARTS
Page
Chart United States Gas Supply-Demand Balance, Contiguous
48 States V-20
Table U.S. Potential Gas Supply by Area as of December 31, 1970 V-23
Table Estimated Proved World Gas Reserves and Production by
Country, 1971 V-26
Table Filed and Prospective LNG Import Projects V-75
Table Announced Reformer Gas Projects V-81
Table The Differential by Which Natural Gas Is Priced Below
Its Commodity Value Level in Consumer Markets, First
Quarter 1972 VI-5
Table The Commodity Value of Natural Gas Produced in the
Lower 48 States, First Quarter 1972 VI-9
Table Alternative Structures for Pricing Gas at Its Commodity
Value Level in the Field, Based on the Vintage Concept:
First Quarter 1972 VI-10
Table Natural Gas Production Based on the Bureau of Natural
Gas Forecast VI-12
Table A Forecast of the Production of Gas in the Lower 48
States Based on Commodity Value Pricing VI-13
Chart Projected Production Compared with Latent Demand in the
Lower 48 States • VI-15
Chart Effect of Elasticity of Supply on Projected Production
of Gas in the Lower 48 States Vl-16
Chart The Unit Cost of Incremental Domestic Supplies VI-18
Table Field Prices of Natural Gas Projected to 1977 and 1982 VI-19
Table Forecast of Gas Production in the Lower 48 States VI-24
Table Estimated Unit Benefit of an Increased Gas Supply in
the United States with Respect to Reduction in
Sulfur Emissions VI-26
Table Estimated Total Benefit of an Increased Gas Supply in
the United States with Respect to Reduction in
Sulfur Emissions VI-27
Table Estimated Benefit of an Increased Gas Supply in the
United States with Respect to Reduction in Sulfur
Dioxide Emissions VI-27
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BIBLIOGRAPHY
See Bibliography at end of Chapters III, IV, V and VI.
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CHAPTER I - IOTRODUCTION
The fundamental objective of this study is to assist the .
Environmental Protection Agency in finding ways to increase the nation's
supply of pipeline quality gas and low sulfur fuel oil for stationary
utilization, by reference to government regulation which attend these
fuels.
This report is limited to the analysis of regulatory aspects
attending the supply of gas. The fuel oil portion of the study will
be submitted separately to EPA.
For gas, Foster Associates first developed a comprehensive picture
of the current situation as it relates to the regulation of supply and dis-
tribution of gas in the United States. This included (a) identification
of regulatory authorities and their function, (b) a definition of existing
procedures available for bringing about changes in the supply and distribu-
tion of gas, and (c) suggestions as to how EPA may participate to bring
about changes defined in (b) above. After setting out the current situa-
tion, Foster Associates identifies future changes foreseen in the regula-
tion of gas. Possible strategies for bringing about future changes are
suggested, and estimates have been made respecting cost effectiveness and
time requirements for optimal strategies.
The contents of this report are current as of December 15, 1972.
1-1
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CHAPTER II - CONCLUSIONS AND RECOMMENDATIONS
That the United States today faces a critical shortage of gas is
undisputed. Seven interstate pipelines in the past year have been compelled
to reduce deliveries to customers below firm contract levels, and 15 pipe-
lines have predicted the necessity to curtail customers in the current
winter season. Moreover, for most pipelines, there has been no supply
available to permit new or expanded service for some time. Carried through
to the retail level, gas distributors in many areas of the nation have been
forced either to refuse or sharply restrict the attachment of new and
increased loads. Industrial users of gas are being increasingly forced to
seek out alternative fuels which are generally available, if at all, only
at higher prices.
Another alarming indicator of supply is the steady decline in the
nation's gas reserve inventory picture. For example, as contrasted with a
92% overall increase in production over the 1958-1971 period, total proved
gas reserves in the Lower 48 States of the U.S. in 1971 were 2% below their
1958 level. More significantly, during the past four years when production
rose more than 131, total proved reserves dropped by some 40 trillion cubic
feet (from 289.3 trillion cubic feet at the beginning of 1968 to 247.4 tril-
lion at the end of 1971), or nearly 151. This drop reflects the fact that
reserve additions in the Lower 48 States averaged only about 50% of produc-
tion over the 1968-1971 period. The worsening supply trends also reflect
a steady decline in exploratory gas well drilling for more than a decade.
Still a further manifestation of the current gas shortage is the
proliferation of projects announced in the past few years for the importation
II-l
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of foreign LNG and development of synthetic gas supplies. In addition,
many U.S. pipelines and distributors are contributing large sums to gas
exploration efforts in frontier areas of Canada and Alaska as well as to
feasibility studies of pipeline projects to bring such gas to U.S. markets.
Increasing attention is also being given to coal gasification projects,
with one such proposal already filed with the FPC and others under active
consideration.— All of these supplemental supply sources are projected
to entail substantially higher unit costs of gas supply than domestic pro-
duction. But the anomaly is that the bulk of the projects are an outgrowth
of the decline in available domestic gas which, in turn, has been brought
about to a considerable degree by inadequate prices for wellhead production.
Regulatory Strategies for Increasing Gas Supply
This study suggests several possible regulatory strategies for
increasing the supply of gas. Most of these strategies pertain to legis-
lative action or FPC action to stimulate domestic production which, despite
the publicity given to LNG, SNG and other such "glamor" sources of gas,
will continue to provide the bulk of the nation's supply through at least
this decade.— At the same time, current projections indicate that domestic
production will fall increasingly short of meeting demand in the years
ahead. Therefore, it is also necessary to formulate regulatory policies
I/ These projects are in addition to coal gasification research, jointly
funded by industry and the Federal Government, aimed at development of
a commercial process for converting coal to high-Btu pipeline quality
gas by 1980.
2/ According to FPC Staff projections (shown on page V-18), production in
, the Lower 48 States will account for 94% of the estimated total U.S.
gas supply (excluding Alaska) in 1975, 82V in 1980 and 711 in 1985.
11-2
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at the earliest possible date to encourage development of supplemental gas
projects meeting national interest and economic feasibility criteria.
Even though gas imports and synthetic gas production will not be available
in any important degree to augment domestic sources until the latter part
of this decade or the early 1980's, the criteria and policies laid down in
the next year or so will be instrumental in influencing future development.
It should also be noted that none of the more likely means for
increasing gas supply will result in any substantial expansion of supply
overnight. With respect to domestic gas, the results of any significant
modifications of regulatory policy would take some time to perceive because
of the time lag between exploration for new reserves and the date production
commences to flow to markets. This lag is variously estimated at between
three to seven years depending upon the producing area and distance from
established market outlets. Nor, as indicated, do supplemental sources of
gas supply offer much hope of supply alleviation for the immediate future.
An exception could be the reforming of gas from naphtha and other light
hydrocarbon feedstocks since reforming plants can be built within a period
of two years or less. However, the bulk of naphtha feedstocks for such
plants would have to be imported, thus raising questions concerning inter-
fuel relationships and the direction of the nation's overall import policies
in the years ahead.
1. Sanctity of Contract Legislation
One means of encouraging increased domestic production would be
passage of legislation to assure contract sanctity, i.e., certainty of
II-3
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price and other contract terms. So-called "sanctity of contract" bills
were the subject of hearings before both House and Senate Committees in
the last session of Congress, but were never reported out of those com-
mittees. These bills are not aimed at decontrol of producer prices.
Rather, their purpose would be to immunize new producer contracts -- after
a one-time review and approval by the FPC -- from subsequent regulatory
change. The FPC review would extend to the entire pricing structure
(initial price plus provisions for fixed escalations), the length of the
contract and other contract terms. In passing on the contracts, the
Commission would be prohibited from using the cost of service, public
utility rate base method and instead would look to supply and demand
factors, price levels deemed required to elicit adequate supplies for
the interstate market, and economic and cost trends.
A major benefit, of the sanctity of contract legislation would be
the avoidance of the price confusion and risk which characterized FPC pro-
ducer regulation in the 1960's. In South Louisiana, for example, the FPC
rolled back price levels three times between 1960 and 1968. Such action
was hardly inducive to producers to commit new reserves to the interstate
market as opposed to the intrastate market where contract terms were
binding. Another principal benefit would be to free the FPC from the cost
of service ratemaking method. Although there are some (e.g., the American
Public Gas Association and certain other consumer groups) who maintain
that the cost of service approach is the only means of protecting consumers
against unjust and unreasonable rates, it is our view that experience in
the area rate proceedings over the past decade has shown application of the
II-4
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cost method to producers on an area basis to present nearly as many
difficulties as its application on an individual company basis.
Significantly, in two recent area rate decisions, the FPC recognized
that cost calculations cannot be mathematically precise, but rather
reflect arbitrary judgments as to allocation procedures and a wide
margin of error as to both data and methods used. (FPC Opinion No. 595
issued May 6, 1971 in the Texas Gulf Coast Area Proceeding; FPC Opinion
No. 598 issued July 16, 1971 in the Southern Louisiana Area Rate
Proceeding.) Relieved from any precedents or pressures to attempt to
apply the cost method further for new gas supplies, the FPC could proceed
to develop more rational regulatory standards giving greater recognition
to market forces and the incentives necessary to elicit greater supply
additions.
Generally speaking, there is little opposition to the concept of
contract sanctity. However, various provisions of the proposed bills have
been criticized on the ground that they go far beyond what is necessary to
accomplish that goal. These criticisms reflect a fear of departing very
far from the past regulatory scheme. However, it is now generally acknow-
ledged that this past scheme was a factor which contributed in significant
degree to the development of the present gas shortage.
Assuming reintroduction of the sanctity of contract bills which
died in the last Congress, it is recommended that EPA join with other
Federal Government bodies -- including the Departments of Interior and
Commerce, and the Office of Management and Budget -- which supported this
legislation in the past. Passage of these bills, in essentially the same
II-5
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form as previously proposed, would appear to be a minimum step toward
ameliorating the domestic supply situation. While dedication of addi-
tional gas reserves to the interstate market would not be guaranteed,
the price and other assurance provided by sanctity of contract legis-
lation would remove some present disincentives to interstate sales by
producers. The sanctity of contract step, however, is unlikely to prove
effective unless coupled with FPC action to increase producer prices to
more realistic market levels. (See pages V-25 and V-28 through V-32 for
a further discussion of the sanctity of contract matter.)
2. Decontrol Legislation
Another regulatory strategy requiring Congressional action is
decontrol of wellhead prices. This approach is urged by those who believe
that sanctity of contract legislation would not go far enough in restoring
the ability of gas prices in the field to react to market forces and hence
in stimulating the needed turnaround in domestic supply.
As discussed further on pages V-32 through V-37, deregulation
proposals take three general forms: decontrol of all gas, decontrol of
gas under new contracts only, and decontrol of new gas contracts subject
to certain safeguards.— Decontrol of producer prices for new gas are
If In the last category, bills were introduced in the last two sessions of
Congress by Senator Tower and Rep. Price (both of Texas) to eliminate
FPC rate control over future contracts, provided that (a) the acreage
involved had not previously been dedicated to the interstate market,
(b) contract prices, including any escalations, are expressed in terms
of a definite charge per unit, with indefinite price escalations pro-
hibited, and (c) all other contractual provisions (such as quality,
rate of take, prepayment arrangements, and abandonment of service),
regardless of their effect upon contract prices, continue to be subject
to Commission approval and review.
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known to be under active consideration by the Administration at this
time. Support for legislation of this nature has been expressed by
officials of the Interior, Commerce and State Departments; the
Director of the Office of Emergency Preparedness; and the President's
Council of Economic Advisers, among others. In addition, two current
FPC members - - Pinkney Walker and Rush Moody - - favor immediate decon-
trol of domestic wellhead prices.
On the other hand, efforts to deregulate producers will probably
be opposed by consumer and other interests as well. FPC Chairman Nassikas,
for example, has come out against deregulation on the principal ground that
the results would be chaotic in a time of supply shortage. He and others
question whether producer markets are sufficiently competitive to permit
adjustment to realistic price levels and whether, once gas price ceilings
are removed, interfuel competition could provide any meaningful restraints
on increasing gas prices. Another major question is the extent to which
the price of gas would rise and the degree to which supply would respond
if FPC wellhead regulation were eliminated.
Further, the reaction of Congress to any decontrol proposals is
problematical at best.
Despite the uncertainties and reservations concerning the effects
of decontrol, legislation in this direction would assuredly spur greater
exploratory efforts and lead to increased gas supply additions. Should EPA
desire to support the decontrol route, probably the type of proposal most
likely of passage by Congress (and the one least disruptive to present con-
sumer markets) would be legislation along the lines proposed by Senator
II-7
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Tower. In other words, deregulation would be limited to new gas contracts
only, with safeguards to preserve some measure of FPC control.
3. Legislation to Expand Federal Regulation
Another general approach advocated by some to meet the current
gas shortage is the expansion, not the reduction, of federal regulation.
This approach includes proposals to establish national end-use controls on
consumption of gas, together with extension of FPC jurisdiction over intra-
state and direct sales in order to prevent unregulated markets from siphoning
off new gas supplies for low priority uses.
Pressures for federal end-use controls over all gas markets
reflect growing concern respecting the potential consequences of gas supply
curtailments. If the present gas situation continues to deteriorate, some
sort of controls may be needed to avoid curtailment of service to existing
residential and commercial customers who have no feasible alternative to
the use of gas. However, determination of priorities for other classes of
customers presents difficulties and especially so on a nationwide basis
because of the considerable variation in patterns of gas usage in different
regions of the country.—
Above all, proposals for end-use control and/or intrastate sales
regulation constitute measures for coping with the gas shortage, not for
I/ Even so, the FPC has recently acted to establish eight end-use
priorities to be applied by all interstate pipelines in the nation
during periods when insufficient gas supply necessitates curtailment
of service (FPC Order No. 467, issued January 8, 1973), and has
advanced a proposal to adopt the same priorities on a national basis
respecting use of new gas supplies (Docket No. R-467).
II-8
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relieving it. On the other hand, if wellhead prices were permitted to
rise to realistic market levels, purchasers of gas for interstate markets
should again be able to compete with intrastate purchasers, and the tendency
for newly available gas supplies to be committed to intrastate markets
should diminish.
In short, we do not see expansion of federal regulation over
wellhead sales as a promising regulatory strategy for increasing gas supply. —'
(See further discussion on pages V-37 through V-42.)
4. Modification of Producer Regulation
Leaving aside remedial legislation, the FPC can itself take
regulatory actions designed to alleviate the gas shortage. In fact, it has
already adopted several measures towards this end. However, there is a
limit to how far the Commission can go within the present statutory scheme,
and its actions are always subject to appeal and the possibility of court
reversal.
A case in point is the FPC's recent adoption on August 3, 1972
of an optional procedure for certificating new gas sales, clearly its most
innovative supply-inducement step to date. The new procedure is intended
to provide two incentives to domestic production: authorization of sales
of gas not previously available to the interstate market at prices in
excess of area rates (specifically, at prices "shown to be in the public
\j No consideration has been given in this report to any additional
regulation of transmission or distribution of gas.
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interest"), and reduction of future rate uncertainty to the extent possible
within the FPC's present statutory powers. The optional procedure -- con-
trary to some press reports and other pronouncements --is not a decontrol
measure. Not only must all contracts be submitted for FPC review and
approval, but use of the procedure is also subject to several restrictions.
Moreover, while the FPC proclaimed the intent to provide certainty of rates
to the extent of its authority, it recognized that it cannot bind future
Commissions not to modify those rates prospectively in the future. Never-
theless, the measure has been vehemently challenged by at least 15 Senators
and 20 House members --as well as certain consumer interest groups -- as a
usurpation of the legislative function by seeking to effect, through
administrative action, both contract sanctity and deregulation of new gas
sales. A group of "Concerned Congressmen" and the American Public Gas
Association immediately appealed the FPC's action to the courts. A final
decision may be a year or more in the future.
The FPC apparently intends to rely to a considerable extent on
the new optional certificate procedure as a vehicle for allowing higher
prices. However, in the four months since its adoption, the optional pro-
cedure has not generated much response. To date, only four applications
have been filed. While one of these applications was certificated rela-
tively promptly, no protest was filed and the rate involved did not exceed
the level already approved for sales in an adjacent producing area. The
other three applications propose 45<£ rates -- nearly 20t higher than the
current area rate level -- for sales in South Louisiana. Various parties
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have petitioned in opposition, so that more protracted processing will be
required. (See pages V-42 through V-48 for further discussion of the
optional certificate procedure.)
Another course of action open to the FPC is to raise area rates
-- either for new gas sales, or for both new and existing sales --in order
to give greater recognition to market value factors, including prices
negotiated for intrastate sales, prices of competitive fuels, and cost and
economic trends. This might be done through a reopening of the area pro-
ceedings, consideration of petitions to amend the area ceilings, or possibly
through the establishment of some type of index permitting periodic price
adjustments in accordance with changes in specific economic or cost
indicators. However, adjustments within the present area pricing framework
are not without drawbacks, and the FPC recently indicated reluctance to
proceed in this direction.—
I/ In Opinion No. 639 issued December 12, 1972, the Commission denied an
unopposed petition to raise the new gas ceiling rate for Appalachian
Area sales in the view that neither perpetuation of the present system
of area pricing by contract vintage nor the initiation of a new round
of area proceedings offered much hope for alleviating the natural gas
shortage. Instead, the Commission urged wider use of the optional
certificate procedure. The FPC also commented as follows to criticisms
of the present area rate method on grounds of its failure to achieve
a workable relationship between supply and demand and its dependence
on the use of noncurrent cost data:
"We appreciate that a uniform national rate for gas sold in
interstate commerce, arrived at through rulemaking and tending
toward recognition of the commodity value of gas, would not be
subject to these infirmities, but before considering this course
of action, as an alternative to area rate proceedings, we await
the guidance of reviewing courts now hearing appeals of [three
area rate decisions]." (Opinion No. 639, Mimeo, ppll-12.)
11-11
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Given the present area rate system, an increase in rates for
existing sales deserves serious consideration since net revenues from
such sales provide an important source of cash for undertaking additional
exploration and development. Some have opposed any price increases for
presently flowing gas without assurance that the additional revenues will
actually be devoted to a search for new gas supplies and not diverted to
other types of investment. In certain recent decisions, the FPC has
responded to this position by providing for increases in flowing gas rates
only after specified commitments of new gas reserves to interstate pipe-
lines. Alternatively, in one case, it granted an increase subject to the
requirement that the resultant additional revenues be expended in an
exploratory program over and above the normal level of expenditures for
such activities.
Various other measures could be taken by the FPC to increase the
supply of funds available for exploration and development. For example, in
a few major cases in the past 18 months, the Commission has adopted a pro-
cedure under which refunds determined to be owing by producers to pipelines
for excess charges in the past can be worked off by dedicating additional
gas reserves to the interstate market. This procedure, or some other type
of refund relief conditioned on further exploration, could be applied by
the Commission in other cases as well. While waiver of refunds involves a
number of equitable considerations, refund monies nevertheless are a poten-
tial source of supplemental funds to be directed to exploratory ventures
holding promise for future supplies. Consumers could benefit far more by
application of the funds in question to a search for additional gas reserves
11-12
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than by receiving the refund monies either in cash or as a credit to their
gas bill.
Still additional funds for gas exploration could be made avail-
able by extension and expansion of the FPC's program which permits pipe-
lines to make advance payments to producers for development and production
activities and to recover such advances in their rates. This program is
presently scheduled to expire on December 31, 1972 but is now under review
by the FPC with a view toward its extension and enlargement to include
exploratory activities. Also, the Commission could provide encouragement
to gas distributors -- as it has to small producers and pipelines --to
search for gas. Several large distributors have established exploration
subsidiaries, and some have discovered reserves which they seek to have
transported by an interstate pipeline to their service area. One case
presenting this situation is now before the Commission.
At some point in the future, EPA might consider a statement of
position regarding various regulatory approaches which could be taken by
the FPC in an effort to increase wellhead supplies of gas. As identified
above and described further in Chapter V (pp. V-42 through V-56), some of
the possible means open to the FPC at this time include (a) establishment
of higher gas prices reflecting market value and other pertinent economic
considerations; (b) flexibility in applying the optional certificate pro-
cedure; (c) relief from refunds, subject to use of refund monies in exploration
for gas; (d) expansion of the advance payment program; and (e) distributor
participation in gas exploration operations. However, in the event EPA
should decide to support any of these measures -- all of which involve
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higher prices to consumers to increase supply -- this should not be done
without thorough prior evaluation of their impact on transportation,
distribution and consumption of gas.
5. Acceleration of Offshore Leasing
Clearly, one of the most obvious means for encouraging expan-
sion of natural gas supply is to accelerate, and regularize, the leasing
of lands on the Outer Continental Shelf. OCS lands are estimated to con-
tain at least 201 of total U.S. potential gas reserves excluding Alaska
(and 40% including Alaska), yet only about 1% of the federal offshore
area has been leased to date. The Interior Department has recognized the
need for accelerated leasing and is currently going forward with a plan
to hold two general lease sales annually over a five-year period in the
Gulf of Mexico. Some delay in this schedule has already occurred due to
court litigation over the adequacy of Interior's environmental impact
statement. At a minimum, all possible efforts should be made to see
that the 10 projected lease sales are conducted without further delay.
Interior's current leasing plan has its principal focus in the
Gulf of Mexico, which is reasonable since potential gas reserves in OCS
lands off Louisiana and Texas are estimated together to comprise 152 tril-
lion cubic feet, or well over 601 of the total offshore potential (excluding
Alaska). Offshore Louisiana, in addition, is already a prolific producing
area. However, it is imperative that efforts also go forward to enable
leasing in the Atlantic and Pacific OCS areas, and in the Gulf of Alaska,
at the earliest possible time. The Atlantic OCS -- estimated by the
Potential Gas Committee to contain 36 trillion cubic feet of potential
11-14
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gas reserves -- is a nearby and geologically promising source of increased
domestic supply for the East Coast, already heavily dependent on imports
of foreign oil and likely to become also dependent on imports of foreign
gas (LNG) in the future. Similarly, the Pacific DCS, with estimated
potential gas reserves of some 11 trillion cubic feet, represents an
obvious source of additional clean-burning fuel for West Coast states,
especially California. Yet, leasing of either the Atlantic OCS, or
further leasing of the Pacific OCS, can be expected to encounter sub-
stantial opposition on environmental grounds.
It is, of course, understood that OCS leasing should go forward
only under stringent environmental safeguards. The danger of oil spills
can never be entirely eliminated. However, regulations and enforcement
of standards to prevent oil spills are stronger today than ever before
and also are under constant review to identify possible improvements.
The efforts being taken by the Interior Department to require and enforce
strict precautionary measures, and the fact that reasonably safe drilling
operations can be conducted on offshore lands, need repeated emphasis to
the public. The fact that the petroleum potential in the Atlantic OCS is
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deemed to be at least 30 miles from shore should also be stressed.— EPA
could make a contribution in this regard.
6. Encouragement of Supplemental Gas Supplies
The most likely sources of nonconventional gas on the horizon
at this time for increasing U.S. supply over at least the next decade are:
ra-j gas from Alaska, primarily the North Slope\U (b) gas imported by
pipeline from Canadian frontier areas;— (c) LNG imported by tanker from
overseas nations; (d) synthetic gas reformed from liquid hydrocarbons;
I/ While there is some question under international law as to the outer
limit of the DCS area subject to U.S. jurisdiction, the 1958 Geneva
Convention on the Continental Shelf clearly grants the U.S. sovereign
rights to explore and exploit the natural resources of the Continental
Shelf to a depth of 200 meters (about 656 feet). The width of the OCS
at this depth varies widely in different offshore regions of the
United States.
With respect to the Atlantic OCS, the U.S. Geological Survey has
described the continental shelf as a submerged platform extending
from mean low tide to the break marking the beginning of the
continental rise -- with a width varying from less than three miles
off southern Florida to about 285 miles off Newfoundland, and some-
what less than 600 feet in depth at most places. (Geological Survey
Professional Paper No. 659, "Geologic Framework and Petroleum
Potential of the Atlantic Coastal Plain and Continental Shelf,"
1971.)
2/ Substantial gas potential is also believed to exist in the southern
part of Alaska, primarily the Kenai Peninsula, where proved reserves
were estimated at slightly more than 5 trillion cubic feet at the end
of 1971. Gas from this area is now being liquefied and shipped to
Japan.. At least one West Coast distributor is considering the possi-
bility of a project to bring LNG from the Kenai Peninsula to California.
V Assuming continuation of present export policies of the Canadian
National Energy Board (which requires retention of sufficient proved
reserves in Canada to meet Canadian market requirements for approxi-
mately 30 years in the future before permitting exportation of gas),
as exemplified by its recent denial of all pending export licenses
for lack of exportable surplus, there seems little likelihood of any
substantial increase in imports from Canada until sufficient reserves
are developed in frontier regions to support new gas export projects.
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and (e) synthetic gas from domestic coal. Other possibilities have also
been mentioned -- such as nuclear fracturing of tight gas-bearing forma-
tions, oil shale gasification and tar sand gasification -- but these
appear speculative for some years to come for technological reasons,
among others.
Unlike wellhead production of domestic gas, the nonconventional
supplemental sources involve a number of different facets of national
policy. These considerations include national security questions con-
cerning sources of supply, balance of payments problems, and oil import
restrictions. In addition, nonconventional supply projects promise to be
very costly to consumers -- certainly far more so than the cost of domestic
gas now and probably still more so for the most part even with an increase
in domestic gas rates to market clearing price levels. In short, the
regulatory encouragement to be given to supplemental supply sources --
which ones, to what degree, and when - - requires a careful evaluation of
a mix of interrelated factors.
From the standpoint of national security, coal gasification
and Alaskan gas are the most advantageous. Assuming transportation of
Alaskan gas via Canada, various Canadian controls would be exercised,
but, once gas was flowing, the danger of interruption of supply seems
remote. The same observation pertains with respect to Canadian gas trans-
ported from such frontier areas as the Mackenzie Delta in the Northwest
Territories, the Arctic Islands and eastern Canada offshore. As to
importation of LNG from overseas, the bulk of the world's estimated gas
reserves -- exclusive of North America -- are located in the Soviet Union,
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the Middle East and North Africa. Each of these area sources could be
interrupted in the event of international political or military problems.
While the consequences of such interruptions could be mitigated over time
by achieving a maximum diversity of LNG sources, nevertheless, a cutoff of
supply for any significant period could cause severe problems for particular
pipelines or distributors which became heavily dependent on imported LNG.
Coal gasification presents little or no balance of payments prob-
lems , nor does Alaskan gas if transported by pipeline in Alaska and by tanker
to the West Coast (assuming tanker construction in domestic shipyards). Some
balance of payments considerations would be involved in the pipelining
of Alaskan gas through Canada. Projects based on importation of gas (or
LNG) or liquids for purposes of manufacturing gas raise greater problems
in this regard. However, in the case of gas imports, these problems would
be diminished to the extent that underlying foreign facilities utilized
equipment and materials purchased in the United States.
Considered from a capital requirements standpoint, reformer gas
projects based on naphtha feedstocks would appear to be the least costly
of the various alternatives at this time.— For example, the Gas Arctic-
Northwest Project under study to transport North Slope gas to the Manitoba-
Minnesota border is currently estimated to cost $5 billion for a capacity
of 3.5 billion cubic feet per day -- or more than $1.40 per cubic foot per
day. The El Paso Algeria project to import 1 billion cubic feet per day
\j Such projects also offer the advantage of a shorter lead time than
other supplemental sources of supply. Reformer plants using naphtha
can be built in two years or less, as compared with roughly four years
for large-scale LNG import and coal gasification projects and still
longer for a project to connect North Slope gas.
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is estimated to involve a total capital investment of over $1.6 billion
(including facilities in Algeria, LNG tankers, and related regasification,
storage and pipeline facilities in the U.S.) -- or about $1.60 per cubic
foot per day. A coal gasification project recently submitted by El Paso
to the FPC contemplates an even higher capital cost -- approximately $1.70
per cubic foot per day of capacity. By contrast, various gas reformer
plant proposals filed with the FPC to date indicate a capital investment
ranging between about 15
-------
imports. While some synthetic gas projects now under consideration con-
template use of domestic feedstock, most naphtha produced in domestic
refineries today is consumed in the manufacture of gasoline and military
jet fuels. Therefore, the naphtha reforming route would require substan-
tial imports of a refined crude oil product to produce gas which would
doubtless exceed the energy equivalent cost of crude oil. In addition,
tiiis route would result in increased reliance on foreign refining"
capacity.
An alternative and probably more desirable route is the importa-
tion of crude oil to produce naphtha in domestic refineries, for subsequent
conversion to synthetic gas, and low sulfur residual fuel oil. Several
proposals of this nature have been outlined. In general, lead times for
such projects are estimated to be somewhat longer and capital costs
higher than for projects based on gasification of naphtha or lighter
liquid hydrocarbons. However, the advantages of this course of action,
compared with the importation of naphtha, include (a) encouragement,
rather than discouragement, of domestic refining capacity; (b) procure-
ment of two needed fuels rather than only one, with concomitant benefits
of interfuel competition; and (c) the ability to use high sulfur crude
oil as the basic refinery input.
The above discussion is intended to illustrate the myriad of
policy issues which bear on supplemental supply projects. These issues
must be resolved within a national policy context and cannot be viewed
from the standpoint of gas supply maximization alone.
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Still another issue has recently come into prominence with the
FPC's decision last June approving the importation of 1 billion cubic feet
per day of Algerian LNG by three major interstate pipelines serving the
East Coast. This issue -- which affects not only imported LNG but also
all other high-cost nonconventional supply supplements (and conceivably
new high-cost domestic production as well) --is whether such supplements
should be sold at incremental prices (i.e., at the full cost of the
incremental supply) or at rolled-in rates (i.e., at the average cost of
all supplies).- Traditionally, pipelines in the U.S. have followed the
practice of rolled-in pricing. Over the years, this has resulted in
efficient use of capacity, avoided complex problems of allocating particular
supplies to particular customers and also avoided abrupt changes in prices
for new supply acquisitions at higher costs. Continuation of this system,
however, has now been placed in doubt by the FPC's decision requiring that
the three pipeline importers of the Algerian LNG sell this supply only at
incremental rates.
The basic rationale in favor of incremental pricing is that a
new supply which cannot be sold at its full economic cost is economically
infeasible. While this argument has appeal from a theoretical standpoint,
it presents serious difficulties when considered in light of pipeline
I/ Actually, two levels of sales are involved. First are sales to custo-
mers -- distributors and direct industrial customers --of pipeline
companies proposing to import LNG or obtain other high-cost increments
of supply. Second are sales by distributors to their customers, i.e.,
ultimate consumers. For the moment at least, the controversy has
narrowed to the method of pricing by pipeline companies to distributor
and direct customers.
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market realities today. Specifically, a consistent application of incre-
mental pricing principles to all new gas supply sources costing in excess
of the rolled-in average cost of a pipeline's existing systemwide supplies
would create a host of administrative problems but, even more important,
could limit and reduce the amount of new gas supplies for U.S. markets.
This is because there are only limited markets at this time prepared to
incur the risk of contracting for and then selling supplemental gas sup-
plies at a multiple of historically prevailing gas prices. Thus, incre-
mental pricing threatens the overall marketability of nonconventional
gas supplements and thereby could be detrimental to EPA's pursuit of an
enhanced supply of gas.
It might be argued that incremental pricing of new supplies
would be justified under certain conditions and in certain situations in
the future. However, the issue is complex and requires a thorough
evaluation by the FPC of the nature of individual pipeline markets,
whether supplemental gas is sought to maintain deliveries to existing
markets or expand deliveries, alternative sources of supply, and load
balancing means.—' it is recommended that EPA take no position on
any widespread application of incremental pricing until such an evaluation
is made and subjected to critical review.
_!/ No such evaluation was attempted in the one case where the incremental
principle was adopted. In fact, no evidence was even submitted on the
subject in that case.
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Optimal Strategy and Cost Effectiveness Estimates
While a number of alternative strategies are available to EPA,
the optimal strategy is found to be an incentive structure which would
allow the price of new gas contracts to be fixed by reference to the
marketplace. This would best be achieved by amending the Natural Gas Act
to deregulate field prices of gas produced in the United States and sold
under new contracts. The objective could also be attained, with lesser
effectiveness and a greater time lag, by amending the Natural Gas Act to
instruct the FPC in its continuing regulation of field prices of gas to
grant "contract sanctity" and to determine reasonable new gas prices by
reference to economic factors in the marketplace, not by reference to cost
of service.
Under either alternative, the objective would be to allow new gas
prices to reach a "market clearing level," the commodity value level. But,
at the same time, increased cash flow would be needed in each case to sup-
port the expansion of exploration and well drilling activity which would
result from increased incentives provided by allowing new gas prices to
reach commodity value levels. One method of increasing cash flow for
this purpose would be to raise prices for flowing (old) gas. However,
the extent to which higher flowing gas prices would actually generate the
funds needed to expand exploration (i.e. , be channelled to this end) would
largely depend on producing companies' evaluation of the prospective
return offered by the new gas prices compared with those offered by
alternative outlets for investment capital.
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The contrast between the projected production of gas in the
Lower 48 States under existing FPC area price ceilings, and the optimal
solution afforded by commodity value pricing of gas in the field, is esti-
mated on the following table.
FORECAST OF GAS PRODUCTION IN THE LOWER 48 STATES^
(Trillion Cubic Feet at 1000 Btu/cf)
Based on Commodity Value Pricing
Based on Current Assuming Elasticity of Supply at
1977
1982
Area Prices b/
21.4
19.3
+0.45
23.1
24.1
+0.75
24.2
27.5
+ 1.0
25.2
30.1
a/ After exclusion of field use.
F/ Based on the Federal Power Commission estimate set out in National
Gas Supply and Demand, 1971-1990, February 1972.
This increased production of gas will directly offset the pro-
jected deficiencies in low sulfur coal and oil availability, and doubly so,
if additional supplies of fuel oil will be required in the future to ful-
fill shortfalls in gas demand caused by declining gas production projected
on the assumption of a continuation of current FPC area price ceilings.
There is thus a volumetric benefit of increased gas production from the
point of view of reducing sulfur emissions in the United States. An
equivalent expression in dollars can be estimated by reference to the
sulfur tax proposed by bills submitted in 1972 to Congress, summarized
on the next page.
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ESTIMATED BENEFIT OF AN INCREASED GAS SUPPLY IN THE ,
UNITED STATES WITH RESPECT TO REDUCTION IN SULFUR EMISSIONS *'
Increase in 1982 Gas Supply Cost Benefit in 1982 if the
Resulting from Commodity Increased Gas Supply Replaces
Value Pricing Commencing High SulfurHigh Sulfur
January 1, 1973 b/ Coal Oil
(Trillion Cubic Feet](Million Dollars)
Maximum 10.8 $3,100-4,147 $2,236-2,970
Minimum 4.8 1,382-1,843 994-1,320
a/ Benefit based only on dollar value of sulfur tax. Other factors such
as price of fuel and equipment costs will also affect costs to con-
sumers. National considerations, such as balance of payments and
security of supply, are also relevant.
b_/ Supply range reflects alternative elasticity of supply assumption
ranging from +0.45 to +1.0.
There would also be other benefits. The gas pipeline and dis-
tribution industry would benefit from increased throughput or utilization
of existing capacity. Without allowing gas prices to achieve commodity
value levels, natural gas production in the U.S. will decline. The high
proportion of total cost represented by fixed costs (costs which do not
vary with output) in pipeline and distribution operations results in dis-
economies of scale with declining throughput. Cost per unit of through-
put increases as utilization of capacity declines.
In addition, natural gas prices fixed by reference to the
market would benefit the energy industry because of the interrelationship
of gas with oil, both in terms of exploration effort and corporate struc-
ture. The search for gas has become increasingly directional in recent
years. Notwithstanding this fact, the price of gas, like the price of
11-25
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oil, makes a contribution to the search for hydrocarbons. To a non-
quantifiable degree, commodity value prices will act to increase sup-
plies of associated-dissolved gas resulting from increased domestic crude
oil production.
Another direct benefit of commodity value pricing for gas would
be the contribution to the U.S. balance of payments. Each Mcf of gas dis-
covered due to the greater exploration effort under commodity value pricing
would accordingly reduce the need to import oil or gas from other countries.
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CHAPTER III - REGULATORY BODIES AFFECTING SUPPLY OF GAS
The purpose of this chapter is to identify, and briefly describe
the role of, the principal state and federal regulatory agencies which
affect the supply of gas in the United States.
A. State Regulation
Gas supply is affected by three basic types of state controls:
conservation regulation (applicable in greater degree to oil, but also to
gas), leasing of lands (again applicable to both oil and gas), and regula-
tion of local sales. In general, none of these areas of regulation are
deemed at this time to present any material barrier to the development of
supply. However, the extent to which public opposition in coastal states
is able to block leasing or drilling of potential petroleum-bearing lands
on environmental grounds could prove to be a major exception.
Also reviewed here are some measures being taken by state regu-
latory bodies with respect to restrictions on new and expanded gas service
by distributors, ordering of service priorities in the event of curtail-
ment, and other measures designed to both reduce demand and encourage
supply -- all in response to the developing natural gas shortage.
1. Conservation Regulation
Virtually all producing states exercise a variety of conserva-
tion regulations aimed primarily at preventing physical waste of oil and
gas. Another purpose is to protect correlative rights of property owners,
i.e., rights to an equitable and fair share of oil and gas produced (such
share being based generally on the proportion of recoverable reserves
III-l
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underlying each owner's property to total recoverable reserves in a pool).
The regulations relate, among other things, to well completion techniques
and equipment; spacing of wells; pooling of tracts; unitization of reservoirs
and portions thereof; limitation of production to resonable market demand;
allocation of allowable production to pools and among wells in a pool;
secondary recovery operations; and protection against land and water pollu-
tion as a result of oil and gas drilling and production.—
State conservation laws date from 1878 when Pennsylvania passed
the first statute dealing with the casing and plugging of individual
wells. More comprehensive regulation developed in the early 1930's when
excess supply became a chronic problem in the major oil producing states
and crude prices dropped sharply. Large new discoveries, especially in
Oklahoma and Texas, aggravated the marketing chaos. Voluntary agreements
among operators in some of the more prolific fields met with little suc-
cess, and martial law had to be imposed on occasion in Texas and Oklahoma
I/ The coordination of state conservation regulations is provided by the
~~ Interstate Oil Compact Commission (IOCC), created in 1935 pursuant to
the Interstate Compact to Conserve Oil and Gas. The Compact came into
being through a Joint Congressional Resolution which provided for a two-
year term. The Compact has been regularly extended by Congressional
action for two or four-year periods ever since. The U.S. Attorney
General is required to report annually on the effects of oil conserva-
tion controls on oil industry competition and price behavior.
The IOCC consists of the Governors of 29 member producing states plus a
number of standing committees. The work of the IOCC is largely carried
on at its semi-annual meetings, with meetings of the Executive Committee
in the intervals. Action is most often taken in the form of resolutions
adopted at meetings of the full Commission or the Executive Committee.
Those of significance are usually concerned with aspects of federal
policy affecting oil and gas which are deemed to involve the conserva-
tion interests of the states.
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to control the deteriorating situation. In 1931, for example, Texas
deployed the state militia to close all wells in the state.
This situation led to the formulation of rules in the various
states for limiting production to reasonable market demand. The various
state prorationing laws received federal sanction in 1935 with the passage
of the Connally Hot Oil Act which prohibited the interstate shipment of
oil in violation of any state law (i.e., in excess of state allowable
production).
State regulation of production through market demand proration-
ing has primarily affected the production of oil. Twelve states have
statutes defining waste as the production of oil in excess of reasonable
market demand, and authorizing limitation of production to demand. But,
only six of the states -- Kansas, Louisiana, New Mexico, North Dakota,
Oklahoma and Texas -- have ever enjoyed a productive capacity materially
in excess of market demand for any substantial period of time. Thus,
it is in these states where market demand prorationing has been applied.
in past decades. Today, however, there is little or no excess oil
producing capacity in any of these states. In the two principal producing
states, Texas and Louisiana, monthly allowable production of oil has
been authorized at maximum efficient producing rates of the wells for
several months (with the exception of a few fields held to lower rates
because of reservoir problems or limitations on downstream facilities).
Three other states (Oklahoma, Kansas and New Mexico) have been producing
essentially at 100% --or more --of maximum efficient well rates for
two or more years.
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With respect to natural gas, production is of two principal
types: (a) casinghead, solution or gas cap gas which is associated with
oil and produced from oil reservoirs; and (b) gas produced from "non-
associated" reservoirs. The production of associated gas depends on the
rate of oil production^ and is affected by any market demand restrictions
applied to oil. The production of nonassociated gas -- which has accounted
for an increasing proportion of total gas production over the years (77%
in 1971) -- is primarily controlled by the rate at which gas is purchased.
Most state regulatory agencies do not attempt to determine state-
wide market demand for gas. (Only two have procedures for doing so, Kansas
and Oklahoma.) However, some states in the past have periodically required
gas nominations .on a reservoir basis from purchasers or producers, or both,
and then used these nominated volumes to determine allowable production by
reservoir.
A few states have attempted in the past to set minimum rates for
wellhead sales of gas -- purportedly in an attempt to prevent flaring and
waste of gas. The most notable examples are Oklahoma and Kansas. In each
case, however, the U.S. Supreme Court reversed the minimum price laws as
an invalid interference with the exclusive jurisdiction of the FPC to
regulate the price of gas sold by producers for resale in interstate
commerce.—
I/ However, over the years, the states have adopted increasingly stringent
regulations against the flaring of casinghead gas.
2/ Natural Gas Pipeline Co. v. Panoma Corp., 349 U.S. 44 (1955); Cities
Service Gas Co. v. State Corporation Commission of Kansas, 355 U.S.
391 (1958).
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Recently, this controversy has been revived with an order issued
on October 5, 1972 by the Oklahoma Corporation Commission prohibiting the
production of gas at prices less than 20$ as wasteful.— (For gas pro-
duced at depths greater than 15,000 feet, the Oklahoma Commission declared
production at prices less than 25$, 35$ and 50$ -- depending on depth --
to be wasteful.) In the order, the Oklahoma Commission asserted that it
was not fixing a minimum price or ordering the purchase or sale of gas at
any price. Rather, it was merely exercising its authority to enforce
rules for the prevention of waste. Hearings were said to have shown
that an unreasonably low price for sale of gas encourages production at
progressively higher rates to offset rising operating costs, thus causing
damage to reservoirs and a consequent loss of recoverable reserves. Fur-
ther, according to the State Commission, wells are being plugged and
abandoned in Oklahoma while they are still capable of producing substantial
volumes due to uneconomical prices. For these reasons, the State Commission
said it will order wells to be shut in if gas production therefrom is sold
at prices considered "wasteful."
The above action of the Oklahoma Commission has already been
appealed to the State Supreme Court by several gas producers and gas pur-
chasers. Also, a confrontation with the FPC is inevitable. Relying on
previous Supreme Court holdings, the FPC recently rejected some 35 rate
increases to 20$ or higher filed in compliance with the state order. It
has also filed suit in a Federal District Court to enjoin enforcement of
the order. The FPC takes the position that, although the Oklahoma order
I/ Oklahoma Corporation Commission, Order No. 93381, Cause CD No. 34596,
~ issued October 5, 1972.
III-5
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is framed in terms of waste prevention and seeks to avoid the "minimum
price" stigma, its essential effect is the establishment of minimum
prices and hence an unlawful burden on interstate commerce. Given the
past judicial precedent, the ultimate outcome of the measure would
seem very much in doubt.
2. Leasing Authority
Producing states all have authority to lease state lands. In
general, leases are awarded at public auction to parties offering the
highest cash bonus, and provide for a fixed royalty to the state on all
oil and gas produced. Otherwise, state leas.inp regulations and require-
ments vary greatly from state to state, precluding any meaningful gen-
eralization.
In some states, royalties from production on state lands are a
significant source of state revenue. During the 1960's, both Texas and
New Mexico sponsored testimony in various area rate proceedings in the
FPC stressing the importance of such revenues to the respective states --
as well as revenues from taxes imposed on the production of oil and gas.
In Texas, for example, certain state agencies own substantial producing
acreage -- over 10 million acres in the Permian Basin and Gulf Coast
areas alone -- the income from which is used to support the educational
system of the state. The same is true in New Mexico which owns approxi-
mately 9 million surface and 13 million mineral acres of lands, generating
about $4 million of gas royalty income in fiscal 1971.
The State of Alaska represents a somewhat special situation.
Among other things, the amount of state-owned lands in known petroleum
III-6
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producing basins is many times larger than that of any other state. In
addition to offshore lands covered by the Submerged Lands Act of 1953,
Alaska was granted the right to select about 103 million onshore acres
of land from the Federal Domain by the Alaska Statehood Act of 1959.
During the early and mid-1960's, Alaska selected about 28 million acres,
including that portion of the Arctic Slope where the Prudhoe Bay Field
was subsequently discovered in 1968. Selection of the remaining 75 million
acres is presently in abeyance due to a freeze imposed by Federal Govern-
ment in 1966 on further cessions of land to the state (and further leasing
of federal lands) pending settlement of Alaskan native land claims.
In September 1969, the State of Alaska held the largest lease
sale in U.S. history, receiving nearly $900 million in bonus money for
450,000 acres in the Prudhoe Bay area. A large part of this acreage had
previously been offered for sale by Alaska in 1964 and 1965 -- prior to
the Atlantic Richfield-Humble Oil $ Refining discovery in 1968 -- but
received no bids at that time. A drawback to immediate further leasing
of North Slope acreage is the continuing uncertainty over the proposed
Alyeska pipeline and the lack of market outlets until that or some other
pipeline is built.
Also, until Prudhoe Bay oil can be produced and marketed, no gas
can be made available from the North Slope since all proven gas reserves
discovered to date in the area are associated with oil. Aside from
problems involved in the construction of an oil pipeline, additional
problems and uncertainties exist with respect to the construction of a
gas pipeline. These uncertainties are discussed further in Chapter V.
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In general, a basic objective of the states in the past has
been to lease lands in order to maximize revenues. Except perhaps for
local situations, there has been little pressure to restrict leasing and
development of potential oil and gas lands. Recently, however, environ-
mental considerations -- the threat of oil spills in particular -- have
caused various state legislatures to seek to halt or ban leasing and
drilling activities on certain offshore lands.
Environmental concern in California dates back to 1955 when,
as a result of conservationist pressure, the state created an offshore
marine sanctuary out to the three-mile limit and for 16 miles along the
Santa Barbara coast.— However, in the ensuing years, California leased
nearly all state offshore lands outside the sanctuary between the Ventura
County line and Point Conception, as well as other submerged lands off
its coast.
In early 1969, after a major oil spill on a federal lease in
the Santa Barbara Channel, the State of California declared a moratorium
on well drilling in all waters under its jurisdiction; Several operators
have applied in recent months to conduct further drilling on state leases
in an attempt to end the ban. In support, they stress major improvements
during the previous two years in techniques and equipment to contain and
clean up any oil spill which might occur, as well as a greatly improved
capability to drill in offshore areas with little risk of accident. Given
I/ Cunningham-Shell Tideland Act, Section 6871.2, California Public
Resources Code (1955).
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the development of these techniques, they contend that further prohibi-
tion of offshore drilling is indefensible, especially in view of
California's critical need for oil and gas supplies. Nevertheless, the
State Lands Commission -- while permitting some sidetracks (wells bottomed
less than 100 feet from the original hole) and some redrills (wells
bottomed more than 100 feet from the original hole) -- has thus far granted
permits for the drilling of only two new wells (both infill development
wells).
Moreover, in the City and County of Los Angeles, which overlie
large oil and gas pools (both offshore and onshore), public opposition
to recent applications for drilling permits in coastal areas has been
intense. For example, it took many months of effort before Occidental
Petroleum finally won permission from the Los Angeles City Council in
October 1972 to drill a well in the Pacific Palisades area near the
coastline -- this permission having first been denied in an action
reversed by Mayor Yorty.
On the East Coast, similar pressures are now building up against
offshore leasing and drilling. For example, in New York, several bills
were introduced in the State Legislature this past year to ban oil and
gas well drilling in the Atlantic Ocean off Long Island and/or adopt other
measures aimed at environmental protection of offshore lands. From a
geological standpoint, the sedimentary structures of greatest interest in
the Atlantic offshore area are substantially seaward of the three-mile
limit generally applied to state lands. However, the Original Thirteen
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States presently have a suit pending in the U.S. Supreme Court before a
Special Master— claiming that, under their original charters from England,
their marine boundaries extend as far as 100-200 miles from their coastline.
Two bills were passed last spring by both houses of the New York
Legislature but subsequently vetoed by Governor Nelson Rockefeller. One
bill would have prohibited the leasing of any offshore lands for oil or
gas extraction within three miles of the New York coastline (or such other
boundary as may be ultimately determined to be subject to state jurisdic-
tion) . In vetoing this bill, Governor Rockefeller stated that the nation's
growing energy needs may make it desirable to permit drilling off New York
shores at some future time, and that the State Commissioner of Environmental
Conservation has adequate powers to insure that any such drilling will be
consistent with the need to protect the state's marine sanctuaries and
recreational areas. Further, he added:
"A large share of potential domestic oil reserves are thought
to lie in offshore deposits. If every coastal state were to
react automatically and negatively by placing outright prohibi-
tions on the development of these potential reserves, our nation
might face severe energy shortages in the not too distant future.
This bill represents that kind of automatic and negative reaction.
It could well lead to similar action elsewhere and seriously
inhibit attempts to achieve a balance between environmental
interests and the need for legitimate gas and oil exploration.
The bill should, therefore, be disapproved."
The second bill passed by the New York Legislature authorized
the adoption of regulations for the protection of marine fishery resources
within a distance of 200 miles from the New York coastline or to a depth of
I/ A Special Master is an individual designated as a special officer or
representative of the Court with power to take testimony and determine
facts in particular situations.
111-10
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100 fathoms, whichever is the greater. This bill was vetoed by the Governor
in view of current litigation concerning the reach of national and state
jurisdiction over territorial waters.
As indicated in another section, environmental opposition to
federal sales of offshore oil and gas lease sales has been a significant
cause of delay in petroleum development in the past few years. Opposition
of the more vocal conservationist groups has been widely publicized. The
above-described recent experiences in California and New York illustrate
that, on a state level as well, public opposition on environmental grounds
poses a significant barrier to the development of offshore hydrocarbon
supplies.
3. Rate Regulation
The rates and terms of sales by privately owned gas utilities
are regulated by state authorities in all but three states. The three
exceptions are Minnesota, Nebraska and South Dakota where municipalities
grant permits and set rates for sales of gas. In Texas, municipalities
or counties have primary rate jurisdiction, but the state commission has
appellate jurisdiction.
Rate regulation by the states is based on the cost of service
approach, with the objective of permitting each utility to recover prudently
incurred costs plus a fair return on investment. Utility regulation in
general is surrounded by a long history, and differences exist between the
states as to allowable costs and determination of the investment base (rate
base). Thus far, however, neither this history nor the type of present
III-ll
-------
regulation by the states has any appreciable effect on the total supply of
gas.
In addition to rate regulation, most state commissions exercise
authority over the initiation of service (37 states), construction of
additional facilities (26 states) and abandonment of facilities (43 states).
Further, virtually all state commissions have authority to establish safety
and service standards and to require line extensions in service areas.
4. Actions Directed to Gas Shortage
During the past few years, state regulatory agencies have become
increasingly involved in actions designed to respond to existing or
expected natural gas shortages. These shortages have developed over wide
areas of the nation due to inability of an increasing number of interstate
pipeline suppliers to maintain existing levels of gas delivery to customers,
coupled with the inability of nearly all interstate pipelines to expand
deliveries to meet demand growth in market areas. (Curtailments by interstate
pipelines are discussed in Chapter Iv, pages IV-45 through IV-54.)
For the most part, the state actions take the form of considering
limitations on new and increased service by local distributors and, in the
event of insufficient supply to meet existing gas requirements, priorities
of service to govern curtailments. However, a number of states have also
taken other measures both to conserve existing supplies of gas and to
encourage expansion of gas supply. Such measures include orders banning
promotional advertising; approval of higher rates to interruptible and large
industrial customers; encouragement to use alternate fuels; efforts to
111-12
-------
augment domestic gas production by permitting distributors to invest in
exploration and development; support for coal gasification and other
R§D projects; directives to expand underground storage or other peak
shaving facilities; participation in hearings and/or proceedings before
the Federal Power Commission, other federal regulatory agencies and
Congress; and requirement of periodic supply reports by natural gas
companies within the state.
The various actions already taken, or under consideration, by
the different states are summarized in Table III-l on the following pages.
The summary is based on a survey undertaken in late 1971 by the National
Association of Regulatory Utility Commissioners (NARUC) of responses by
state agencies and intrastate distributors to gas shortage problems. The
NARUC report was published on February 29, 1972.-'
Table III-2 describes the approaches adopted in different
states with respect to restrictions on new and additional service by
distributors and curtailment priorities. The summary here rests on the
NARUC study noted above, as supplemented by independent surveys conducted
by Foster Associates and the Gas Appliance Manufacturers Association.
I/ NARUC "Survey of Actions by State and Federal Regulatory Agencies and
Intrastate Natural Gas Distributors to Meet Natural Gas Shortages,"
February 29, 1972.
A subsequent survey of state regulatory actions by Foster Associates
does not permit updating of the NARUC on a comparable basis. Con-
sequently, Table III-l should not be regarded as a totally up-to-date
compilation but rather as an indication of the broad variety of
measures which the states are implementing to cope with the growing
shortage of gas supply.
111-13
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Table III-l
Page 1 of 2
NARUC SURVEY OF 42 STATES AND THE DISTRICT OF COLUMBIA
Action by Regulatory Agencies and Natural Gas Distribution Companies
To Meet Existing or Possible Future Natural Gas Shortages
February 29, 1972
Action
Number of States
February
1972
Future^'
Names of States-'
2/
To Conserve Natural Gas Supply
1. Curtailment in time of shortage
a. Curtailment of new or added service 13
b. Priorities for new or added service 8
3.
c. Priorities for curtailment of
existing service
Industrial
Coimercial
Steam-electric
Residential
Interruptible
16
13
1
4
12
d. Incorporation of curtailment or 7
service priorities in utility tariffs
2. Fjcpanded use of alternate fuels
a. LNG 7
b. Nuclear energy 1
c. Oil, liquefied petroleum, liquefied 8
propane, synthetic gas
d. Coal gasification research and 5
development
Advertising and promotion
a. Advertising to inform the public on 1
conservation of gas
b. Prohibition of specified promotional 6
practices
Conn., Del., (D.C.), (Fla.), 111.
Ind. Md., Mich., Mo., N.H.,
N.Y.
Wis.
Calif.
N.H.
N.C., Ohio, (Tenn.) , Va. ,
CWyo.)
111. , Mich., Mo., (Nev.),
(N.J.), N.Y., N.C., (S.C.),
4. Higher rates to interruptible or large
industrial and commercial customers
(Tenn.), Wyo.
4 Ariz., Ark., Calif., Conn., (D.C.),
Iowa, Mich., Md., Mo., (Mont.),
Nev., (N.J.), N.Y., N.C., Ohio,
(Pa.), S.C., Vt., W.Va.
3 Calif., Conn., (D.C.), Iowa, Mich.,
Md., Mo. , (Nev.), N.J., N.Y.,
N.C., Ohio, (Pa.), S.C., Vt.,
W.Va.
1 Calif., (Nev.)
1 Conn., (D.C.), Mich., N.C. , Ohio
4 Ariz. , Calif. , Colo. , 111. , Kan., Md.
Mo., N.H., (Nev.), (N.J.), (S.C.)
Term., (W.Va.), N.Y., N.C., Wyo.
1 Ark., Calif., Iowa, Mo., N.C.,
Pa., S.C., (Tenn.)
Calif., Conn., Del., 111. , Mass.,
Mich. , Ohio
Calif.
Ariz., Calif., Conn., 111., Mass.,
N.Y., N.C., Ohio
Calif., 111., Mich., N.Y., Ohio
(N.J.), Okla., (S.C.)
Conn., Del. , 111. , Mich., Ore.,
Pa.
Kan., (Okla.) , (Utah)
111-14
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Table III-l
Page 2 of 2
NARUC SURVEY OF 42 STATES AND THE DISTRICT OF COLUMBIA
Action by Regulatory Agencies and Natural Gas Distribution Companies
To Meet Existing or Possible Future Natural Gas Shortages
February 29, 1972
Number of States
Action
February 1 ,
1972 Future^'
Names of States-
To Increase Available Natural Gas Supply
1. Exploration for natural gas
a. Intrastate for domestic U.S.A. and 6
offshore
b. Foreign 3
c. Investment or loan authorization 2
for exploration for gas
2. Expanded underground storage or other 3
facilities for peak shaving
3. Increased gas production allowables 2
Other Measures to Conserve and/or
Increase Natural Gas Supply
1. Gas supply reports by natural gas com- 7
panies to regulatory agencies
2. Intervention and participation in FPC 9
proceedings affecting gas
3. Regulatory agency policy orders prescrib- 6
ing conservation and curtailment procedures
4. Regulatory agency appeals to or appear- 2
ances before U.S. Congress and federal
agencies
Calif., Mich., N.Y., Ohio, Okla. ,
Wyo.
Calif., Mich., Ohio
Calif., 111.
Calif., 111., Ind.
Okla., Tex.
Ark., Calif., Del., 111., Mich.,
N.C., (N.JO, Pa., (Wis.)
Ark., Calif., Ga., Ind., La.,
Mich., N.Y., Tex., Utah
Calif. , Del., Nev. , N.J., N.Y.,
N.C.
Mich., N.Y.
V Contingency plan, pending application, or possible future action.
2/ Names of states in parenthesis are those planning future action.
111-15
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Certain states have approached these matters on a statewide
basis. For example, in 1970 or 1971, the regulatory agencies in four
East Coast states -- New York, New Jersey, Pennsylvania and North
Carolina -- initiated investigations into the adequacy of gas supplies
in the respective states, the desirability of promulgating general rules
concerning the attachment of new and expanded loads, and curtailment pro-
cedures. These investigations ended with the issuance of rules generally
applicable to all utilities in the state. Regulatory bodies in other
states -- including Illinois, Ohio and Nevada, among others -- have also
held statewide hearings.
In a larger number of states, particularly those confronted
with the expectation of growing curtailments by interstate pipeline
suppliers, authorization has been granted to numerous individual gas
utilities to restrict new connections and, if necessary, cut back
existing service according to specified plans.
Generally speaking, as Table III-2 indicates, activities of
state regulatory agencies in the area of service restrictions and curtail-
ments have been particularly intense in certain eastern and midwestern
states with large gas consuming populations and little or no gas produc-
tion. Notable examples are New York, Pennsylvania, Illinois and Michigan.
In the western part of the country, California is unique in having had a
formal program concerning gas supplies and curtailments of service for
over 20 years.
However, major producing states are also being affected by the
gas shortage. In Louisiana, one of the two principal sources of domestic
111-16
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SUNMARY OF STATE ACTIONS RESPECTING RESTRICTIONS
'AND/OR CURTAILMENTS OF GAS SERVICE
Table III-2
Page 1 of 6
ALABAMA
ALASKA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
CONNECTICUT
DELAWARE
DISTRICT OF
COLUMBIA
The Alabama Public Service Commission has ordered distributors to submit plans
governing the conservation of available gas supply.
(No information available.)
The Arizona Corporation Coimission, in 1972, issued a comprehensive set of rules
respecting load additions and increases, and curtailment of service priorities.
Service to new industrial or commercial customers requesting over 7,000 Mcf per
month or 70,000 Mcf per year are prohibited, and increases in service to present
industrial and commercial customers above these limits may not be made except on
an interruptible basis. Curtailment priorities provide for cutoff first of inter-
ruptible deliveries, large industrial users and smaller industrial users.
Some gas operators have curtailed or stopped service to large industrial users
under interruptible clauses in their service contracts during periods of extreme
gas shortage. Several large electric utilities have installed large oil reserves
to supplement natural gas when gas is in short supply.
The Arkansas Public Service Commission held hearings in 1971 to determine curtail-
ment priorities for Arkansas Louisiana Gas Co., the major gas distributor in the
state. An order of priorities was established by the Commission on August 9, 1971.
The priorities (from lowest to highest) are: large industries curtailed at Arkla's
discretion; industrial boiler fuel users able to use alternate fuels (subject to
certain limitations); other industrial deliveries where an alternate fuel cannot be
used (except service to prevent plant damage); remaining industrial and all com-
mercial uses; residential and other human needs customers .
The California Public Utilities Commission has long had a comprehensive program to
assure adequate gas supply and has also taken a number of actions recently to meet
the threat of a future natural gas shortage. Since the 1940's, California has
required distributors to include curtailment plans for industrial sales in utility
tariffs in order to avoid jeopardizing firm service to domestic customers in periods
of shortage. In addition, since 1961, the PUC has required all distributors within
the state to submit an annual report on existing and estimated future gas supply.
The California Commission has also sought to encourage exploration for new natural
gas supplies both in the United States and abroad (including distributor investment
in exploration ventures), and has supported the development of use of alternate
fuels to supplant or supplement natural gas.
The Colorado Public Utilities Commission has not yet taken any specific action to
relieve gas shortages or to stretch existing gas supplies.
The Connecticut Public Utilities Commission has not issued a general order regarding
gas curtailment. However, on August 19, 1971, it approved a plan filed by
Connecticut Power 5 Light Co. for refusing new customers or added loads from existing
customers. Specifically, Connecticut P5L was directed to supply minimum additional
load requirements of customers in the future according to a system of priorities
setting maximum allowable volumes and specifying type of use. Residential and small
commercial customers, medium commercial, large commercial and small industrial, and
large industrial customers were to be served, in that order, with maximum volumes
ranging from up to 500,000 Btu per hour for residential customers to 2,000,000 Btu
per hour for large industrial customers.
The Delaware Public Service Commission, in December 1971, ordered Delmarva Power 6
Light Co. not to provide any additional or increased service to any building,
structure or other installation not then receiving gas service -- except to honor
contracts entered into prior to that date. However, this additional service is
limited to 200,000 Mcf, with the allocation thereof to consider the location of
existing lines, the extent to which the structure has been completed and gas bum-
ing equipment installed, and certain other factors. Delmarva was also ordered to
prohibit any home, building, installation or other structure presently connected
to its supply lines to be converted to gas for heating purposes and to cease
advertising of gas-fired heating systems and appliances of any kind (except replace-
ments or others which could assist in reducing the summertime valley in gas con-
sumption) .
The Public Service Commission of the District of Columbia, in November 1971, issued
interim authority to Washington Gas Light Co. to limit sales growth to residential
use. However, the PUC denied WG§L's request to restrict new gas sales to single-
family residences and instead ordered the company to also serve individually metered
apartment house uses. In March 1972, WG§L ceased all new service even to residential
customers.
111-17
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Table 111-2
Page 2 of 6
SUMMARY OF STATE ACTIONS RESPECTING RESTRICTIONS
AND/OR CURTAILMENTS OF GAS SERVICE
FLORIDA TTie Florida Public Service Commission has taken no action respecting service
restrictions or curtailments.
GEORGIA The State of Georgia has not yet experienced any gas shortage and therefore has
approved no curtailment plan, service priorities, or end-use priorities. However,
the Georgia Commission has intervened in an FPC proceeding concerning curtailments
by Southern Natural Gas Co. which could affect service to Atlanta Gas Light Co.
HAWAII Hawaii is presently self-sufficient with respect to its gas supply. Its only gas
utility company manufactures gas for use on the island of Oahu, and propane is
distributed in rural areas from Standard Oil of California's refinery on Oahu.
IDAHO The Idaho Public Utilities Commission is presently drawing up a policy outlining
end-use priorities. Recently, the Idaho Commission met with the Oregon and
Washington Commissions, and with El Paso Natural Gas Co. and seven natural gas
distribution companies serving the area, to discuss present and future supply of
natural gas for the region. A possibility now under study is the development of
common peak shaving facilities by distributors in the area.
ILLINOIS Illinois has a comprehensive program for dealing with the problems of adequacy of
gas supply. Among other things, the Illinois Commerce Commission considers: cur-
tailment policies of distributors, programs for restricting new or increased service;
expansion of underground storage and peak shaving; prohibition of specified promo-
tional practices; and encouragement of construction of dual-fuel facilities. In
addition, the Illinois Commission has authorized investment by utilities in
activities to explore for gas, and encouraged the formation of a Coal Gasification
Group by seven utilities to conduct research and development work towards a coal
gasification plant.
New and additional service by Peoples Gas Light § Coke Co. and Northern Illinois
Gas Co. , two of the largest distributors in the state, has been restricted for
some time.
INDIANA The Indiana Public Service Commission does not hold hearings on curtailment plans
of distributors as many other states do. Rather, state approval is automatic if
no objection to a curtailment proposal is filed within 30 days of its submission.
Several distributors in the state have volumetric limits on new service, and
some have established priorities for curtailing existing service.
IOWA The Iowa Commerce Commission has issued no orders but maintains contact with local
gas utilities which have procedures in their filed tariffs for protecting service
to presently attached firm gas customers.
KANSAS Kansas apparently has given little formal attention to gas service restrictions
and curtailments. (A letter to Foster Associates indicated that Kansas relies on
FPC regulation of Kansas-Nebraska Natural Gas Co. to control gas supply in the
state.) However, Kansas distribution companies have begun to curtail the use of
gas not only during the coldest weather, but also at other seasons of the year.
KENTUCKY The Kentucky Public Service Commission is currently investigating curtailment pro-
cedures. At least five distributors have filed curtailment programs.
LOUISIANA The Louisiana Public Service Commission has issued no general directives on the
subject of curtailments. The majority of its gas companies are served by inter-
state pipelines subject to FPC jurisdiction. The Louisiana Conmission has, how-
ever, intervened in various proceedings involving the gas supply of United Gas
Pipe Line Co. with the objective of obtaining a greater proportion of United's
supply for customers in Louisiana.
MAINE Maine has formulated no plans for curtailment or service priorities with respect
to natural gas use. Although the state is now adequately supplied, the Maine
Public Utijities Commission is examining future sources of pipeline natural gas,
LNG and other alternate gas sources.
MARYLAND The Maryland Public Service Commission has not developed a statewide program with
respect to natural gas shortages, curtailments or priorities, but has issued
orders approving curtailment proposals by specific distributors.
111-18
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Table II1-2
Page 3 of 6
SUMMARY OF STATE ACTIONS RESPECTING RESTRICTIONS
AND/OR CURTAILMENTS OF GAS SERVICE
MASSACHUSETTS The Massachusetts Department of Public Utilities plans to review the status of each
utility company's gas supply after the spring of 1972 when the extensive program of
construction of storage and processing facilities for liquid natural gas and for
LPG, which has been under way for several years, is expected to be completed. If
the review indicates the need for any curtailment or priorities for gas service,
they will be made at that time.
MICHIGAN The Michigan Public Service Commission has considered and approved applications
dealing with limitations on new service and curtailment of existing service by
several distributors. One order, for example, provided that no new commercial or
industrial customers could be added to the utility's system and restricted addi-
tional residential customers under a priority system. Another order forbid new
residential, commercial or industrial customers in the Southern Division system of
Michigan Gas Utilities Co., and also denied a priority petition of the Michigan
State Housing Development Authority for priority of gas service for low and medium
income housing customers. A third order established a "Controlled Service Program"
under which natural gas available to Michigan Consolidated Gas Co. in excess of
existing requirements of firm customers will be sold in a manner to ensure satis-
faction of its most essential end uses, i.e., according to a schedule of priorities.
The Michigan Commission retains jurisdiction to consider gas service for any cus-
tomer with a pollution problem which presents an unusual threat to the public
health and welfare.
MINNESOTA Minnesota has no agency with authority to control gas supply.
MISSISSIPPI The Mississippi Public Service Commission has issued no orders nor adopted any
plan with respect to curtailment of service or end-use priorities during periods
of natural gas shortage. Mississippi's natural gas distribution companies have
filed no specific overall formalized plans for meeting gas shortages with the
Commission, but several major gas companies have included curtailment provisions
in their revised tariff rate schedules during 1971.
MISSOURI^ The Missouri Public Service Commission has issued no general orders relating to
curtailment of service, or end-use priorities for natural gas service during
periods of gas shortages. However, the Commission has approved tariff provisions
for several individual companies establishing priorities for curtailment during
periods of short supply, as well as priorities for connection of new service as
additional supplies of gas become available.
MONTANA The Montana Public Service Commission has issued no orders regarding curtailment.
NEBRASKA Nebraska has no agency with authority to control gas supply.
NEVADA The Nevada Public Service Commission has held public hearings on a proposed
General Order 18, "Natural Gas Service Curtailment Priorities," but a final order
has not yet been issued. The proposed general order includes provision for
priorities of service in the event of gas shortage in the following sequence:
domestic service; commercial firm service; public utility steam-electric generating
plant firm service; industrial firm service; commercial interruptible service;
public utility steam-electric generating plants interruptible service; and indus-
trial interruptible service.
NEW HAMPSHIRE The Public Utilities Commission of New Hampshire issued no orders and formulated
no plans for curtailment of gas service. It has been a standard practice in the
state that interruptible loads have the lowest priority and space-heating customers
highest priority.
NEW JERSEY The New Jersey Department of Public Utilities Board of Public Utility Commissioners
issued Executive Order No. 71-3 (December 23, 1971) establishing standard curtail-
ment rules for distributors in the event of a gas shortage. The order provides for
the curtailment of non-residential services in the following order: (1) inter-
ruptible customers and customers having dual-fuel capacity, after suitable advance
notice; (2) industrial and commercial customers being served under special con-
tracts; (3) firm industrial and commercial customers who have agreed to curtail-
ments, under prior arrangements; (4) distributors' own facilities, to a minimum
level; (5) industrial and commercial customers on an involuntary basis under an
established priority list, assigned by the utility; and (6) all remaining non-
residential customers. The distributors were also ordered to file curtailment
plans and to substitute advertising of an "educational" nature in lieu of promo-
tional advertising.
111-19
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Table III-2
Page 4 of 6
SIW1ARY OF STATE ACTIONS RESPECTING RESTRICTIONS
AND/or CURTAILMENTS OF GAS SERVICE
In January 1972, the New Jersey Board scheduled hearings to investigate priorities
for curtailment, sales and advertising practices, and the effect of gas curtail-
ments on the industrial life of the state.
NEW MEXICO New Mexico is reportedly investigating gas supply and curtailment matters.
NEW YORK The New York Public Service Commission initiated an investigation in mid-1970 to
~determine whether any restrictions should be placed on attachment of new customers
by gas distributors in view of potential gas supply shortages. On October 26,
1971, the New York Commission issued a decision restricting attachment of all new
customers other than residential. Analyzing the supply-demand situation of each
of the state's 23 gas distributors in light of supply cutbacks by interstate pipe-
lines serving New York, the PSC concluded that all but two would be unable to
secure sufficient gas to meet the reasonable needs of its customers and of persons
or corporations applying for new or additional gas service. Accordingly, the New
York Commission ordered that (1) no new customers (except one- and two-family homes,
and individually metered apartments) be attached unless the utility has a sufficient
firm supply of gas to meet all firm customer needs for at least two years following
attachment, the customer has facilities to burn an alternate fuel, or the gas is to
be used for a commercial or industrial process for which there is no practical or
economically feasible alternative fuel; (2) increased service to existing firm cus-
tomers (other than one- and two-family homes and other individually metered domestic
consumers) taking less than 12,000 Mcf annually be limited to a maximum of three
years, whichever is less, unless the customer has dual-fuel capacity at least equal
to the increment above such ceiling; and (3) increased service to existing custo-
mers taking 12,000 Mcf or more annually is to be limited to their highest annual
consumption in the last three years in the absence of newly installed dual-fuel
capacity at least equal to the increment above such consumption level.
In addition, the New York Commission established a schedule of priorities in the
event curtailments are necessary, ordered an end to all promotional activities
aimed at attracting new or additional gas load, and directed all gas distribution
companies to submit within 60 days detailed plans for new or increased peak-shaving
facilities (or advise why no such facilities are being planned).
NORTH The North Carolina Utilities Commission instituted a rulemaking proceeding in July
CAROLINA 1970 to consider service limitations by gas utilities within the state. By order
dated July 27, 1971, the North Carolina Commission directed that any gas company
placing limitations either on sales to new customers or additional sales to
existing customers provide service according to the following priorities (highest
to lowest); residential customers who can be feasibly served; small commercial
and industrial users with requirements not exceeding 20 Mcf/d; industrial customers
using gas as a raw material; large commercial and industrial customers with require-
ments exceeding 20 Mcf/d; preferred interruptible customers; interruptible customers;
dump schedule customers.
The North Carolina Commission also ordered all distributors to install or maintain
sufficient peak shaving equipment to meet residential customer needs.
NORTH DAKOTA (No information available.)
OHIO
OKLAHOMA
OREGON
PENNSYLVANIA
The Ohio Public Utilities Commission held hearings in December 1971 respecting
possible restrictions on new and increased service. In February 1972, the PUC
issued an interim order directing all distributors delivering over 2,000 Mcf/d
to cease promotional advertising, submit plans for acquiring or increasing peak
shaving and storage facilities, submit curtailment proposals, and report monthly
to the state. Several distributors in the state are refusing service to new non-
residential customers, and at least two have been authorized to restrict service
to new residential customers.
The Oklahoma Corporation Commission has apparently issued no curtailment orders.
However, the Commission is considering the establishment of long-range priorities
for natural gas use.
The Public Utility Commissioner of Oregon has issued an order curbing sales pro-
motion activities by gas utilities, as well as by electric utilities.
The Pennsylvania Public Utility Commission instituted an investigation in March
1971 into the adequacy of natural gas supplies in Pennsylvania. In February
1972, the PUC ordered all gas utilities to (1) file reports on gas deliveries
and available supplies immediately and henceforth whenever an estimate in an
earlier report changes by 5%; (2) submit curtailment procedures as part of their
111-20
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Table III-2
Page 5 of 6
SUMMARY OF STATE ACTIONS RESPECTING RESTRICTIONS
AND/OR CURTAILMENTS OF GAS SERVICE
tariffs; (3) refrain from contracting to serve any gas-burning equipment installed
after February 15, 1972, except under certain conditions; (4) cease all promo-
tional advertising; and (5) submit proposals for intercompany cooperation to
insure reliability of service during periods when demand exceeds supply.
PUERTO RICO Gas use at present time is limited to propane and butane gas produced by island
petroleum refineries.
RHODE ISLAND The Division of Public Utilities has taken no action requiring utilities to cur-
tail gas sales. Distributors have undertaken voluntary curtailments. Providence
requires advance approval for new commercial and industrial hookups.
SOUTH The South Carolina Public Service Commission has not issued orders relating to
CAROLINA curtailment or end-use priorities for natural gas service, nor has there been a
statewide program regarding existing or potential natural gas shortages. How-
ever, the PSC has approved curtailment policies and/or service priorities for at
least two utilities: Piedmont Natural Gas Co. and Carolina Pipeline Co.
SOUTH DAKOTA South Dakota has no agency with authority to control gas supply.
TENNESSEE The Tennessee Public Service Commission has not yet taken action on utility com-
pany applications for inclusion of curtailment rules and limitations on gas sales
in rate schedules. Three companies have proposed priorities for curtailment and
service limitations in the event of insufficient gas supply to meet demand.
Emergency curtailment plans have been approved for two companies.
TEXAS The Texas Railroad Commission set a hearing for November 30, 1972 to consider all
matters relating to the promulgation of curtailment priorities for gas transported,
delivered and sold in the State of Texas.
UTAH The Utah Public Service Commission is not presently contemplating any action with
respect to conserving existing supplies or increasing available gas reserves.
Utah's principal supplier recently asked authorization, however, for rate increases
to large industrial and commercial consumers, but not for residential service, as a
means of effecting restriction of gas sales.
VERMONT The Vermont Public Service Board has not approved any gas curtailment plans, nor
have any been filed with it. The Board, however, has imposed restrictions on
advertising and promotional practices by gas and electric utilities.
VIRGINIA The Virginia State Corporation Commission has wide-ranging powers permitting
almost instant curtailment of gas usage when necessary. During 1971, limitations
on new customers were ordered for 10 distributors, most limitations permitting new
residential customers only. In addition, Virginia is studying the possibility of
ordering alternate fuel use by large industries.
WASHINGTON The Washington Utilities and Transportation Commission has taken no formal action
directed toward conserving or enlarging Washington's gas supplies. However, the
Commission has met with other Pacific Northwest regulatory agencies, together with
the region's gas distribution companies and suppliers, to discuss measures for
attempting to solve the gas supply problem beyond 1972.
WEST VIRGINIA The West Virginia Public Service Commission is presently considering requests by
gas distribution companies to approve restrictions on new industrial customers and
new commercial customers (other than multi-family structures) and curtailments of
deliveries to industrial customers if necessary to protect service to residential
customers. New service restrictions and curtailment programs have been authorized
for at least two companies.
WISCONSIN The Wisconsin Public Service Commission deals with gas shortage on an individual
company basis. A number of utilities in Wisconsin have filed formal petitions
for authority to limit the sale of gas to new customers and additional gas to
existing customers, and to curtail deliveries in the event of insufficient supply.
In these cases, formal hearings have been held and orders issued granting sales
limitation and curtailment authority. In all cases, the company involved is
required to submit a periodic report as to its gas supply situation and an analysis
of future developments.
111-21
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Table III-2
Page 6 of 6
SUMMARY OF STATE ACTIONS RESPECTING RESTRICTIONS
AND/OR CURTAILMENTS OF GAS SERVICE
WYOMING Wyoming at present has no general natural gas shortage and does not foresee one.
However, established policy of the Wyoming Commission in times of gas shortage
is to discontinue service to interruptible customers first, and to firm industrial
or commercial users second, with a view to maintaining service to the residential
customer as long as possible. Should Wyoming's industrial progress be impeded by
a natural gas shortage in the future, it is thought possible that the legislature
might take action to curtail the amount of gas exported from the state.
Source: (1) Foster Associates survey of state actions regarding curtailments and supplies;
(2] NARUC survey of state agency and distributor actions to meet gas shortages, report
issued February 29, 1972;
(3) Survey of curtailment plans and agency actions by Gas Appliance Manufacturers
Association; and
(4) Press reports.
111-22
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gas, power plant and other industrial customers dependent on gas supplies
from United Gas Pipe Line Co. (an interstate pipeline) have been substan-
tially curtailed over the past few years. Further, plans for a number of
new industrial plants in the state have been halted because of the lack
of an available gas supply. The Louisiana Commission is taking an
increasingly active role in various Federal Power Commission proceedings
in an effort to retain a greater proportion of United Gas Pipe Line's
supplies within the state.
In Texas, an action of particular significance was the recent
scheduling of hearings by the Texas Railroad Commission for November 30,
1972 to consider the establishment of curtailment priorities for gas
transported, delivered and sold in the State of Texas. The notice setting
the hearing declared: "There is an immediate and urgent need for the
development of a statewide standard of priorities for the curtailment of
transportation, delivery and/or sale of gas to assure effective control
of the flow of gas to the proper destinations to avoid suffering and hard-
ship of domestic consumers, yet to make available to all gas consumers on
a reasonable but limited basis during times of.Jieeded curtailment to the
end that the public will be best served."—
I/ Notice (dated November 16, 1972) of Hearing Relating to the Promulga-
~~ tion of Curtailment Priorities for Gas Transported and Sold in the
State of Texas, Oil and Gas Docket No. 20-62,505.
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B. Interior Department
1. Leasing of Public Lands
a. Leasing Statutes and Administering Agencies
The authority of the Interior Department to lease federal lands
derives from the Mineral Lands Leasing Act of 1920 (onshore lands) and the
Outer Continental Shelf Lands Act of 1953 (offshore lands).
The OCS Act provided for federal jurisdiction over the submerged
lands lying seaward of those granted to the states. The latter had been
generally determined by the Submerged Lands Act of May 22, 1953, which gave
the coastal states jurisdiction over such lands to a distance of three
miles from their coast lines into the Atlantic and Pacific Oceans and up
to nine miles into the Gulf of Mexico if a state's historic boundary prior
to joining the Union had been more than three miles from shore or if such
a boundary had previously been approved by Congress. The states of
Florida and Texas are in this category.
The boundaries of the federal and state segments of the DCS, and
hence of the respective jurisdictions, have not yet been precisely defined.
The seaward limits remain imprecise, and even the location of the shoreward
boundaries is, in some cases (such as off Louisiana), still in dispute.
Litigation is currently pending with respect to the jurisdiction limits
of the Atlantic States, Florida, Louisiana,- California and Alaska.
I/ See Footnote on following page.
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Within the Department of the Interior, the Bureau of Land
Management is responsible for the leasing of public lands, while the
Geological Survey regulates operating practices. The Geological Survey
is also responsible for geological and geophysical exploration on OCS
lands. Information provided by the Geological Survey, along with other
information, is evaluated prior to leasing in order to identify promising
acreage and appraise potential resources. In large part, the Geological
Survey purchases geological and geophysical data from private surveyors.
The Interior Department's basic objectives with respect to the
leasing and management of publicly owned mineral resources are threefold:
to assure orderly and timely resource development, to assure a fair market
value return on disposition of public resources, and to protect the
environment.
I/ To permit mineral development to proceed pending resolution of
conflicting claijns, -Louisiana and the Federal Government signed an
agreement in 1956 whereby the area off Louisiana was divided into
four zones extending seaward from the Chapman Line, which is a line
generally following the Louisiana coastline established for adminis-
trative convenience. Zone 1 extends three miles seaward from the
Chapman Line, and Zone 2 continues seaward to a point nine miles from
the Chapman Line. Zone 3 includes the area seaward of Zone 2 to a
line nine miles seaward of the "Coast Guard Line," and Zone 4 includes
all submerged lands seaward of Zone 3. Louisiana has exclusive juris-
diction within Zone 1. Zone 4 and undisputed portions of Zones 2 and 3
are managed by the Federal Government. The portions of Zones 2 and 3
in dispute are controlled by a joint committee with members from the
Interior Department and the Louisiana Mineral Board. All revenue from
leases in the disputed areas is placed in escrow for distribution at
such time as the ownership is finally resolved.
111-25
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b. Leasing of Onshore Lands
Under the Mineral Lands Leasing Act of 1920, leases are granted
both by competitive bidding and by a simultaneous filing system. In the
latter case, with a number of applications for the same lease filed
simultaneously, the right of priority is resolved by public drawing.
When land is within the known geologic structure of a producing
oil or gas field prior to the issuance of a lease, it may be leased only
by competitive bidding and in units of not more than 640 acres to the
qualified applicant offering the highest lease bonus. Royalty payments
are usually 12.51. The simultaneous filing system, is used in areas where
research or exploration is required before the presence of minerals
can be anticipated. Such non-competitive leases may be as large as 2,560
acres, and the royalty is fixed at 12.5%.
Competitive and non-competitive leases involve primary terms of
five and ten years, respectively, with production of oil or gas in paying
quantities holding either type of lease thereafter.
Recently, a Department spokesman expressed the opinion that a
system of all competitive leasing, with appropriate requirements for
exploration and development, would be more responsive to supply and demand
and would lead to less holding of leases primarily for speculation.—
Interior has proposed reforms to the mineral leasing laws towards this end.
I/ Statement of Harrison Loesch, Assistant Secretary of Interior, to
Senate Committee on Interior and Insular Affairs, June 19, 1972.
111-26
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c. Leasing of PCS Lands
Under the OCS Lands Act, all oil and gas leases are issued on a
competitive bidding basis. The present system involves cash bonus bidding
by sealed bids, plus payment of a fixed royalty. The acreage of a single
lease block may not exceed 5,760 acres, and leases are issued for a
primary term of five years and may be held thereafter as long as oil or
gas are produced in paying quantities. The Act specifies that in no event
shall the royalty on oil and gas be less than 12.51; actually, all OCS
leases issued to date have required a royalty rate of 16-2/31. Annual
rentals are set at $3 per acre for leases offered at general lease sales
(unproven areas) and $10 per acre for leases obtained at drainage sales
(proven areas).
Since passage of the OCS Act, BLM has conducted 25 sales of off-
shore oil and gas leases, including 11 drainage sales (in proven areas)
and 14 general sales (in unproven areas). The acreage and bonus figures
for these sales are shown on Table III-3 on the following page. The
pattern of sales has been erratic, with no general lease sales held in
eight of the last 19 years and one or two general sales held in the
remaining years. In the aggregate, the sales have netted the United States
Government cash bonuses in excess of $5 billion. On an acreage basis, two-
thirds of the lease sales have involved lands adjacent to Louisiana. Thus
far, the only other states involved to any significant extent have been
Texas and California.
A measure of the importance of the nation's offshore oil and
gas development is the fact that, between 1958 and 1971, production from
111-27
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Table III- 3
OUTER CONTINENTAL SHELF LEASE SALES OF OIL AVD GAS
Date
10/13/54
11/09/54
07/12/55
07/12/55
02/26/59
08/11/59
02/26/60
02/26/60
03/13/62
03/16/62
03/16/62
10/09/62
05/14/63
04/28/64
10/01/64
10/01/64
03/29/66
10/18/66
12/15/66
06/13/67
02/06/68
05/21/68
11/19/68
01/14/69
12/16/69
07/21/70
12/15/70
11/04/71
09/12/72
Type
Sale
(G)
(G)
(G)
(G)
(G)
(D)
(G)
(G)
(G)
(G)
(G)
CD)
(G)
CD)
(G)
(G)
(D)
(D)
(D)
(G)
(G)
(G)
(D)
(D)
CD)
CD)
(G)
(D)
(G)
(D) = Drainage
(G) = General
Source :
U.S.
1971;
Offered
State
La.
Tex.
Tex.
La.
Fla.
La.
Tex.
La.
La.
Tex.
La.
La.
Cal.
La.
Ore.
Wash
La.
La.
Cal.
La.
Cal.
Tex.
La.
La.
La.
La.
La.
La.
La.
Tracts Acres
199
38
39
171
80
38
97
288
401
30
380
19
129
28
149
47
18
52
1
206
110
169
26
38
27
34
127
18
78
3,037
748,000
111,788
216,000
458,095
458,000
81,813
437,760
1,173,223
1,808,276
90,720
1,780,265
33,855
669,777
34 ,028
836,134
253,940
35,993
227,898
1,995
971,489
540,609
728,551
46,824
96,389
93,764
73,360
593,485
55,872
366,682
13,324,585
Leased
Tracts
90
19
27
94
23
19
48
99
206
10
195
9
57
23
74
27
17
24
1
158
71
110
16
20
16
19
116
11
62
1,661
Acres
394
67
149
252
132
38
240
464
951
28
927
16
312
32
425
155
35
104
1
744
363
541
29
48
60
44
543
37
290
7,436
,721
,149
,760
,807
,480
,820
,480
,046
,811
,800
,746
,178
,945
,673
,433
,420
,056
,717
,995
,456
,181
,304
,682
,505
,153
,642
,898
,222
,521
,601
Total
$ 116
23
8
100
1
88
35
246
177
267
43
12
60
27
7
88
99
21
510
602
593
149
44
66
97
845
96
585
$5,021
Bonus
,378,476
,357,029
,437,462
,091,263
,711,872
,035,121
,732,031
,909,784
,260,305
557,720
,775,727
,887,359
,807,587
,340,626
,768,772
,764,928
,845,963
,164,930
,189,000
,079,178
,719,262
,899,046
,868,789
,037,339
,908,196
,769,013
,832,785
,304,522
,827,925
,262,010
Average
Bid per
Acre
$ 295
348
56
396
13
2,268
149
532
186
19
289
2,713
41
1,847
65
50
2,534
947
10,621
685
1,660
1,097
5,049
908
1,112
2,190
1,555
2,587
2,016
$ 675
Highest
Bid per
Acre
$ 1,220
2,209
177
2,077
16
10,442
1,026
2,502
3,201
26
3,081
8,480
455
10,490
376
310
6,112
3,128
10,621
6,500
11,374
7,602
27,401
2,161
6,600
8,201
12,875
18,005
21,870
sales (proven areas)
sales (unproven areas)
Department of
data provided
Interior, Geological Survey,
by Bureau of Mines on lease
Outer Continental Shelf Statistics,
sale
held Septenber
12, 1972.
111-28
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OCS lands rose from about 1% to over 121 of total U.S. production of both
natural gas and crude oil and condensate.— (Including state offshore
lands, the respective proportions are about 181 and 16%.) Even more
important is the fact that only about 1% of OCS lands, or 7.4 million
2/
acres out of a total of 682 million acres,— has been leased to date
by the Federal Government.
In President Nixon's Clean Energy Message to Congress on June 4,
1971, the Secretary of Interior was directed to accelerate oil and gas
leasing on the Outer Continental Shelf both in the Gulf of Mexico and in
other promising areas, and to publish a five-year schedule of lease offer-
ings. Pursuant to this mandate, Interior released a tentative five-year
schedule for OCS leasing contemplating 10 sales in the Gulf of Mexico
through 1975 and public hearings on possible leasing in the Gulf of Alaska
I/ The bulk of the OCS production is from offshore Louisiana. The break-
down for 1971 is as follows.
Crude and Condensate Natural Gas
OCS
OCS
OCS
- Louisiana
- Texas
- California
Total OCS
Total U.S.
(Bil lions of Barrels)
386
2
31
419
3,478
(Billions of
Cubic Feet)
2,634
127
16
2,777
22,493
Source: Interior Department submission to Senate Committee on
Interior and Insular Affairs in connection with over-
sight hearing held March 23, 1972 on administration of
Outer Continental Shelf Lands Act, Table 55.
2/ Includes OCS areas of the Gulf of Mexico, and the Atlantic, Pacific
and Arctic Oceans, heyond state jurisdiction to the 200 meter depth
limit.
111-29
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and Atlantic Ocean sometime prior to 1976. The tentative schedule was as
follows:
Date Area and Type of Sale
10/71 Gulf of Mexico (Drainage)
12/71 East Louisiana (General) and Gulf of Mexico (Drainage)
5/72 Louisiana (General) and Gulf of Mexico (Drainage)
11/72 Texas (General) and Gulf of Mexico (Drainage)
5/73 Alabama, Mississippi and Florida (General) and Gulf of Mexico
(Drainage)
11/73 Louisiana and Texas (General) and Gulf of Mexico (Drainage)
5/74 Gulf of Mexico (Drainage)
11/74 Louisiana and Texas (General) and Gulf of Mexico (Drainage)
5/75 Gulf of Mexico (Drainage)
11/75 Gulf of Mexico (General and Drainage)
In regard to the above schedule, the first proposed drainage
sale was held in November 1971, but further sales have been delayed. The
general lease sale in offshore eastern Louisiana -- originally set for
December 1971 -- was blocked by environmental groups which claimed that
the Final Environmental Impact Statement of the Interior Department did
not comply with the National Environmental Policy Act in failing to
adequately discuss alternatives to the sale. A U.S. District Court
granted an injunction barring the sale on this ground. After Interior
filed a supplemental Environmental Impact Statement, the sale was finally
held in September 1972. Another offshore Louisiana lease sale, encom-
passing over 600,000 acres of DCS lands, is presently scheduled for late
December 1972.
The Bureau of Land Management is currently updating and revising
the leasing schedule. Present plans call for two general sales of 300,000
- 600,000 acres each per year over a five-year period in the Gulf of
111-30
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Mexico. Development of the acreage involved is estimated to require the
drilling of 3,500 to 4,500 wells which, in turn, are estimated by Interior
to result in an increase in crude oil reserves of 2.5 to 5.0 billion
barrels and an increase in gas reserves of 20 to 40 trillion cubic feet. BLM
also contemplates offering further leases in the Gulf of Mexico if no sales
of OCS lands in the Gulf of Alaska and the Atlantic region are held by 1976.
Sales of leases in these areas must be preceded by considerably more study
of environmental and other factors.
TVo major roadblocks could possibly delay or, in certain areas,
actually prevent future OCS oil and gas leasing: (1) federal-state juris -
dictional disputes, and (2) opposition by environmentalist and conserva-
tion groups.
Jurisdictional limits will be determined by future court cases,
or statutues, since application of the terms of previous legal decisions
to unsurveyed landrsea margins to define seaward boundaries is virtually
impossible. As noted, the question of federal versus state jurisdiction
in the Gulf of Alaska and Atlantic Coast offshore areas is currently in
litigation. Either resolution of these conflicts, or negotiation of
interim zone arrangements as in Louisiana, is necessary before major
leasing actions can be undertaken.
Due to environmental considerations, leasing of OCS lands has
already been,delayed, and court suits to block further sales could cause addi-
tional delay. In California, moreover, there is presently a moratorium
on all offshore leasing, the result of public reaction following the oil
spill in the Santa Barbara Channel in January 1969. In April 1971, the
Interior Department suspended further operations in 35 federal leases
111-31
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in the Santa Barbara Channel until January 1973 to permit Congress to
consider a pending bill for termination of the leases and for establish-
ment of a national energy reserve. This suspension order was reversed
by a U.S. District Court in California (as to 11 leases of four companies
which challenged the action) and is now on appeal to the U.S. Court of
Appeals for the Ninth Circuit in San Francisco. (Gulf Oil Corp. et al.
v. Rogers C. B. Morton, No. 72-2449)
Finally, in Atlantic Coast offshore areas, any leasing of DCS
lands faces considerable opposition from the adjacent states.— Several
bills sponsored by Senators or Representatives of Eastern Seaboard states
were introduced in the last session of Congress to bar any federal sale
of leases for at least two or three years pending thorough study of all
environmental factors and/or adoption of a program of marine sanctuaries.
The Interior Department is going forward with collection of information
regarding the oil and gas potential of the Atlantic Outer Continental
Shelf area and the environmental implications of lease sales in this
area, but Secretary Morton has indicated that any decision to lease and
permit exploratory drilling is still a few years in the future.-'
I/ For example, a special commission on marine boundaries and resources
of the Massachusetts Legislature recently issued a report recommending
against any Atlantic OCS development until (a) the present oil import
quota system had been abolished, (b) national policies respecting
energy and marine resources had been developed, and (c) spill preven-
tion technology and oil spill cleanup techniques had been considerably
improved. The report followed hearings on the possible development of
oil and gas in the George's Bank region off Massachusetts.
2/ Statement of Secretary of the Interior Rogers C. B. Morton. November 11,
1971.
111-32
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2. Office of Coal Research
The Office of Coal Research administers the Federal Government's
coal gasification program. This program was accelerated during the latter
half of 1971 following President Nixon's Clean Energy Message of June 4,
1971 calling for expedited development of coal gasification technology.
Subsequently, OCR signed an agreement with the American Gas Association
providing for joint government-industry funding of expanded research efforts
to produce pipeline-quality synthetic gas from coal. The agreement contem-
plates joint funding of $30 million annually over a four-year period, two-
thirds to be provided by the Federal Government and one-third by industry.
The current OCR gasification program includes four ongoing
pilot plant projects based on: (a) the HYGAS process (hydrogasification
of bituminous coal) -- undergoing testing by the Institute of Gas
Technology at a pilot plant in Chicago; (b>) the CO- Acceptor Process --
undergoing testing by Consolidation Coal Co. at a lignite gasification pilot
plant recently completed at Rapid City, South Dakota; (c) the BIGAS process
-- to be tested by Bituminous Coal Research, Inc. at a pilot plant under
construction near Homer City, Pennsylvania; and (d) the SYNTHANE process
developed by the Bureau of Mines -- to be tested at a pilot plant scheduled
to begin construction in the fall of 1972 near Pittsburgh, Pennsylvania.
The pilot plant program is intended to aid the design of a
demonstration plant to be built, largely through industry financing, within
five or six years. It is hoped that operation of the demonstration plant
will provide, by the end of the decade, a sound commercial basis for the
construction and operation of large coal-based synthetic pipeline gas
plants. OCR's target date for coal gasification on a commercial scale is 1980.
111-33
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C. Federal Power Commission—
The Federal Power Commission has extensive power to regulate
the transportation and sale for resale of natural gas in interstate com-
merce. These powers stem from the Natural Gas Act, passed in 1938 but
considerably broadened in scope by the Supreme Court in 1954 in Phillips
Petroleum Co. v. Wisconsin, 347 U.S. 672.
1. Background of the Natural Gas Act
Passage of the Natural Gas Act was the result in large part of
pressures arising from diminishing production in the Appalachian area
after 1917 and the inability of particular states to control sharply in-
creased prices of gas imported from other states. In 1928, the Senate
adopted a Resolution directing the Federal Trade Conmission to investigate
public utility corporations doing an interstate business in electricity and
gas, as well as the activities of holding companies controlling such
corporations, and to make reports and recommend legislation necessary to
correct any practices tending to create a monopoly or other abuses. In
1935, the FTC issued a report emphasizing, among other things, problems
created by the unregulated control of pipeline transmission, the concentra-
tion of control of interstate pipelines in a few holding companies, and the
need for conservation of gas. A principal conclusion of the report was
that the business of transporting and selling natural gas for ultimate
distribution to the public was a matter affected with the public interest
V Because of the critical impact which the FPC has had and will continue
to have on gas supply, its activities and policies to date are described
in a separate chapter, which follows.
111-34
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and should be subjected to federal regulation. It was largely on the
basis of the FTC report that Congress led to pass the Natural Gas Act
three years later.
At the time of enactment, the Natural Gas Act was widely thought
to apply only to interstate pipelines. The legislative history gives no
indication of any intent that it also cover independent producers. This
interpretation was also believed to flow from Section l(b) which specifically
provides that the Act not apply to the "production or gathering of gas."—
The Section l(b) proviso, however, proved to be ambiguous and
the source of considerable controversy over the following decade and a
half. In essence, the advocates of greater regulation contended that
regulation of sales by pipelines was ineffective without regulation of sales
to pipelines by producers. During this period, the FPC consistently
declined to assume jurisdiction over sales by producers (except producers
affiliated with interstate pipelines).
In 1951, following an investigation to determine whether Phillips
Petroleum Co. was a natural gas company subject to its jurisdiction, the
FPC reaffirmed its position that producer sales were so closely related
to "production and gathering" as to be exempt from Federal regulation. This
I/ Section l(b) of the Natural Gas Act reads as follows:
"The provisions of this act shall apply to the transportation
of natural gas in interstate commerce, to the sale in interstate
commerce of natural gas for resale for ultimate public consump-
tion for domestic, commercial, industrial, or any other use, and
to natural-gas companies engaged in such transportation or sale,
but shall not apply to any other transportation or sale of natural
gas or to the local distribution of natural gas or to the facili-
ties used for such distribution or to the production or gathering
of natural gas." [52 Stat. 821 (1938); 15 U.S.C. Section 717(b)]
111-35
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decision was reversed by the U.S. Court of Appeals for the District of
Columbia Circuit which, in 1954, was upheld by the Supreme Court. A
majority of the Supreme Court interpreted the Section l(b) proviso ex-
empting production and gathering to mean '"physical activities, facilities
and properties used in the production and gathering of gas,'" but not to
sales after production and gathering. Rather, the Court concluded that
"'the legislative history indicates a congressional intent to give the
Commission jurisdiction over the rates of all wholesale of natural gas
in interstate commerce, whether by a pipeline company or not and whether
occurring before, during, or after transmission by an interstate pipeline
company.'" (347 U.S. at 682)
Thus, FPC jurisdiction over wellhead sales by independent pro-
producers for resale in interstate commerce was established by the Supreme
Court. Various legislative efforts were made in the next few years to
remove this jurisdiction or to lessen the extent of the FPC's authority
over independent producers, but none were successful.—
2. Scope of FPC Powers Under Natural Gas Act
Pursuant to various sections of the Act, the FPC exercises rate,
certificate and abandonment authority over sales, transportation and
facilities constructed by natural gas companies for such purposes. The
FPC also has jurisdiction over gas imports and exports, as well as broad
I/ For example, one bill (the Harris Fulbright bill) was passed by
Congress in 1956 but vetoed by President. Eisenhower because of dis-
closure of a campaign contribution by a registered lobbyist for an
oil company. Another amendatory bill (the Harris-O'Hara bill) was
introduced in the following Congress but was dropped after a further
campaign contribution episode.
111-36
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power to issue rules considered necessary to carry out the functions under
the Act.
As noted, the FPC's jurisdiction is limited to transportation in
interstate commerce and sales for resale in interstate commerce. Section
l(b) of the Act specifically excludes any other transportation or sale, as
well as the "local distribution" of gas and related facilities. Further,
Section l(c) -- added to the Act in 1954 -- exempts essentially local
companies receiving gas from an interstate source, provided (a) the sale
takes place within or at the boundary of the state; (b) all of the gas
is ultimately consumed within the state; and (c) a state commission
certifies to the FPC that it is exercising regulatory jurisdiction over
the rates, services and facilities of the company involved.—
Rate authority is exercised under Sections 4 and 5 of the Act.
Section 4 requires 'that rates and charges for the transportation or sale
of jurisdictional gas shall be "just and reasonable" and not unduly discrim-
inatory. Any increase (or other change) in rates must be filed with the FPC
at least 30 days in advance of the proposed effective date. The FPC may
allow the increase without formal hearing; or it may hold a hearing and,
pending decision, suspend the increase for a maximum of five months --
I/ Section l(c) is .known as the Hinshaw Amendment. It was passed to
counteract initial efforts by the FPC -- notwithstanding Section l(b)
--to exercise jurisdiction over companies which received gas from
interstate pipelines for subsequent transportation and/or distribu-
tion wholly within one state. The FPC was affirmed in its position
by the Supreme Court in 1950. Regarding this as too broad an intru-
sion into state regulatory authority, Congress amended the Act in
1954. Thus far, seme 180 companies have applied for and been granted
an exemption under the Hinshaw Amendment.
111-37
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after which the change.may go into effect subject to refund of any portion
of the increased rate ultimately found not just and reasonable. Section
5 gives the FPC power to institute an investigation into the rates and
charges of a jurisdictional natural gas company -- either on its own motion
or on complaint by another party -- and to prescribe just and reasonable
rates to be collected prospectively by such company.
Certificate authority is exercised under Section 7(c) of the Act
which requires that natural gas companies obtain certificates of "public
convenience and necessity" to transport and sell natural gas, and to
construct, extend or acquire facilities for such purposes. The FPC may
attach conditions to the issuance of such certificates, and it may issue
temporary certificates in cases of emergency (again with conditions)
without notice or hearing.
Under Section 7(a), the Commission also has power to direct
natural gas companies subject to its jurisdiction to interconnect with and
sell gas to municipalities and others engaged in distribution of gas for
public consumption, provided such interconnection and sale will not impair
the company's ability to render adequate service to its customers.
Abandonment authority is exercised under Section 7(b) which pro-
vides that jurisdictional facilities and service may not be abandoned
without a finding by the Commission "that the available supply of natural
gas is depleted to the extent that the continuance of service is unwarranted,
or that the present or future public convenience or necessity permit such
abandonment."
111-38
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Exportation and importation of gas must be authorized by the
FPC under Section 3 of the Act.— The statutory standard is that authority
shall be granted unless the Commission finds that the proposed exporta-
tion or importation "will not be consistent with the public interest."
The Commission may grant authority with conditions. It may also, "...
from time to time and . . . for good cause shown, make such supplemental
order in the premises as it may find necessary to appropriate." (In
effect, this provision gives the FPC power to modify the terms of any im-
port authority at any time in the future.)
Section 16 of the Act grants the FPC broad rulemaking authority.
Under this Section, the Commission may "perform any and all acts" and
"prescribe, issue, make, amend, and rescind such orders, rules, and
regulations as it may find necessary or appropriate to carry out the pro-
visions of this act." Procedurally, before adopting a new rule or
regulation under Section 16, the FPC must publish notice of the proposal
and provide an opportunity for comment by interested persons. However,
no hearings are required (although they may be held). Further, while the
FPC must state reasons for any rulemaking action, it need not amass and
analyze voluminous evidence in support of its action. In this way, rule-
making differs importantly from contested rate and certificate proceedings
I/ Pursuant to Executive Order No. 10485, issued September 8, 1953, the
FPC.. is also required to issue permits for the construction and opera-
tion of border facilities for the exportation and importation of
natural gas to or from a foreign country. Before issuing such permits,
the FPC must obtain favorable recommendations from the Secretaries of
State and Defense.
111-39
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(wherein the Commission must hold hearings before reaching a decision)
and hence affords a vehicle for the Commission to implement new regula-
tory policies in a relatively expeditious manner. In recent years, the
FPC has used its rulemaking authority to an increasing degree to promul-
gate major policy changes.
D. Other Federal Bodies
1. Departments of State, Defense and Commerce
The Departments of State and Defense both have an important voice
in policy matters affecting the supply of petroleum in the United States.
In the past, the activities of the two Departments have been directed
largely to oil. However, in light of the probability of increasing imports
of gas (and/or liquids as feedstock for the manufacture of gas), the degree
of interfuel substitutability possible in many markets and the need for a
coordinated interfuel approach to current energy questions, both State and
Defense seem likely to become increasingly involved in formulation of
policies affecting the supply of gas in the future.
To date, the State and Defense Departments have been consistently
asked by the FPC for their position concerning both pipeline imports from
Canada and, more recently, LNG imports from Algeria and Libya.— There has
been no opposition by the State Department to any announced gas import
I/ Under Executive Order No. 10485, the FPC is required to obtain the
favorable recommendations of the Departments of State and Defense
for the construction and operation of border facilities for the ex-
portation and importation of gas.
111-40
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project thus far. Nor has the Defense Department recommended denial
of any gas import project, although it has expressed concern in some
instances that individual pipelines and gas distribution companies not
become overly dependent on imported LNG.
Similarly, the Commerce Department has not played a significant
role in policies affecting gas supply in past years. However, during
1972, it participated in trade negotiations with the Soviet Union involving,
among other things, the possibility of joint ventures to bring Soviet
gas in liquefied form to the U.S. by the end of this decade. But the
Secretary of Commerce recently advised that an early agreement concerning
any such venture was not imminent.— In any event, even if some form of
tentative agreement were signed in the near future, the importation of
Soviet LNG faces so many policy and regulatory considerations as to render
it a highly speculative source of supply at this time.
2. Price Commission
The Price Commission was established under Executive Order No.
11627 of October 15, 1971 and is composed of seven public members appointed
by the President on October 22, 1971. The Price Commission was directed to
prescribe specific standards, criteria and regulations to carry out the
goals of the Cost of Living Council to stabilize prices and rents.
Speech of Peter G. Peterson, Secretary of Commerce, before the
American Petroleum Institute in Chicago, November 14, 1972.
111-41
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Sales of gas subject to regulation -- including wellhead sales
under FPC jurisdiction -- are governed by Price Commission rules issued
for regulated public utilities. These rules have undergone several revisions
over the past year with respect to requirements for notifying the Price
Commission of requested rate increases and those approved by regulatory
agencies, provisions for further review by the Price Commission of agency-
authorized increases, and guidelines applicable to utility increases.
Since its inception, however, the Price Commission has generally accepted
the rulings of state and federal commissions in regard to rate increases
for regulated companies.
Initially, the Price Commission required federal and state regu-
latory agencies to review all price increases for consistency with the
purposes of the Economic Stabilization Act and to certify all approved
increases as consistent with such purpose. However, the Price Commission
retained the power to further review -- and modify -- such increases within
a specified period. Several criteria were later issued by the Price Com-
mission for use by regulatory bodies in appraising permissible increases,
including that the increase (a) is cost-justified and does not reflect
future inflationary expectations; (b) is the minimum required to assure
continued, adequate and safe service, or provide for necessary expansion
to meet future requirements; (c) will achieve the minimum rate of return
needed to attract capital at reasonable costs and avoid impairment of
credit; , (d) does not reflect labor costs in excess of those allowed under
Price Commission policies; and (e) takes into account expected and obtain-
able productivity gains.
111-42
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Effective March 20, 1972, the Price Commission provided for the
issuance of Certificates of Compliance to regulatory agencies whose pro-
posed procedures for dealing with utility rate increases were deemed
satisfactory to the Price Commission. Agencies receiving such Certificates
thereafter assume final responsibility for all approved increases, with the
Price Commission reserving only the right to monitor their decisions. As
of the end of October 1972, the Price Commission had issued Certificates
of Compliance to 27 state commissions and 2 federal agencies (the Civil
Aeronautics Board and the Interstate Commerce Commission).
The Federal Power Commission has not received a Certificate of
Compliance from the Price Commission. However, to date, the Price Com-
mission has not blocked any rate increase approved by the FPC for either
pipeline companies or producers. With respect to each such approval, the
FPC has certified that its actions are consistent with the economic goals
of Administration's wage-price stabilization program and meet other re-
quirements of Price Commission regulations. In one order (Order No. 437A-4,
issued November 29, 1971) pertaining to increased rates allowed for producer
sales in South Louisiana and three other areas, the FPC explained its
position as follows:
"This Commission has been confronted with conclusive evidence
demonstrating a gas supply shortage. Every indication is that
such a shortage will continue into the near future. The actions
which we have taken in these recent opinions are designed to
reverse this trend and to augment the Nation's dwindling gas re-
serves. To this extent the rates and other provisions in those
determinations have used price as a tool to bring gas to the
marketplace; in other words, to obtain for the public service the
needed amount of gas. We have attempted to provide the proper
economic climate to stimulate exploratory and developmental efforts
in order to provide adequate service to the consumer at the lowest
reasonable rate. An important policy consideration which we cannot
111-43
-------
ignore is the substantial burden which would fall upon the
consumer if higher priced alternative energy supplies are re-
quired to alleviate the gas shortage. It is imperative that
adequate sources of energy, including natural gas, be available
to sustain the Nation's economic growth. Thus, we have balanced
our regulatory responsibilities under the Natural Gas Act with
the President's economic goals, and find they are not inconsistent."
In sum, other than adding another tier of regulation, Price Com-
mission controls have had little impact on the price of gas sold in inter-
state commerce for resale. However, with respect to intrastate gas sales
which are not subject to FPC regulation, the Price Commission in several
instances has denied rate increases because they exceeded base period
prices or profit margins, or for certain other reasons. The result has
been the diversion of considerable quantities of intrastate gas, particularly
in Louisiana and Texas, to interstate sales under emergency procedures. As
explained in Chapter IV (p. IV-25), the FPC has adopted measures in the past
few years to permit emergency sales of gas to interstate pipelines for 60-day
periods without certificate authorization and for periods exceeding 60
days under limited-term certificates. The purpose of these emergency
procedures is to alleviate curtailment problems of pipelines which are un-
able to purchase sufficient supply to maintain existing delivery levels to
their customers. The price level for limited-term emergency sales has
been restricted by the FPC to about 35<£, but this is higher than contract
prices for many intrastate sales. Thus, because the Price Commission has
so far not interfered with prices of regulated sales, gas which might
otherwise be committed to intrastate buyers is transferred to interstate
purchasers on an emergency basis.
111-44
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The present wage-price stabilization program is scheduled to
expire on April 30, 1973. The Secretary of the Treasury recently
indicated that the Administration will ask for an extension of controls
beyond that date. Such extension must be approved by Congress.
3. Atomic Energy Commission
Through its Plowshare Program, the Atomic Energy Commission is
responsible for research aimed at the development of peaceful nuclear
explosives to improve utilization of natural resources, especially stimu-
lation of production from natural gas fields. Much of this research is
conducted jointly with industry.
Two jointly sponsored experiments involving underground nuclear
explosives to stimulate gas production from tight formations have been
conducted to date: (a) Project Gasbuggy with El Paso Natural Gas Co. in
1967; and (b) Project Rulison with Austral Oil Co. and CER Geonuclear
Corp. in 1969.
Project Gasbuggy involved the firing of a 29 kiloton explosive
on December 10, 1967, at a depth of 4,240 feet in the San Juan Basin of
New Mexico. Project Rulison detonated a 43 kiloton explosive on September
10, 1969, at a depth of 8,426 feet in the Mesaverde formation, about six
miles southeast of Grand Valley, Colorado. Both projects are now under-
going testing with respect to production capabilities and pressure buildup.
Two additional potential projects partly sponsored by AEC offer
possibilities for extending gas stimulation technology. One -- Project Rio
Blanco -- contemplates the simultaneous detonation of multiple explosives
with an aggregate yield of about 90 Kt, spaced vertically at gas-bearing
111-45
-------
depths between 5,000 and 7,000 feet, at a location in Rio Blanco County,
Colorado, utilizing land rights obtained by the CER Geonuclear Corp. under
a joint venture agreement with Equity Oil Co. The other project -*- Wagon
Wheel -- involves the sequential detonation of five nuclear explosives,
each with a yield of about 100 Kt vertically spaced in the same well
at depths between 9,000 and 12,000 feet, at a location in the Pinedale
Field in Wyoming. Wagon Wheel would demonstrate the feasibility of
sequential firing and its effects on fracturing, stimulation and
chimney interactions at greater depths than previously attempted.
AEC is also currently engaged in studies directed toward develop-
ing a small diameter, minimum residual tritium, nuclear explosive called
DIAMOND, for particular use in gas stimulation. The diameter factor is
important because of limitations of drilling technology and drilling
costs. The diameter of the DIAMOND explosive is less than the 8-inch
diameter of the Rulison explosive and can therefore be emplaced in a
9-5/8-inch well casing. The DIAMOND design was successfully tested when
a device called Miniata was test fired at the AEC's Nevada Test Site on
July 8, 1971.
It is believed by some that very substantial gas reserves in
the Rocky Mountain area can be "unlocked" from tight formations by under-
ground nuclear explosions. However, the outlook for this supply of gas
is quite uncertain. While AEC has announced its intent to pursue the
Plowshare Program, future scheduling has been placed in abeyance pending
study of environmentalist protestations as well as the results of the
first tests (e.g., the level of radioactivity in the gas reserve).
111-46
-------
Bibliography
Colorado Scliool of Mines, State and Federal Regulations Pertaining to the
Petroleum Industry, Volume 65, July 1970
i3ole, Hollis M. , Speech (as Assistant Secretary of Interior) to Petroleum
Landmen's Association in New Orleans, Louisiana on October 16, 1969
Economic Stabilization Regulations, Code of Federal Regulations, Special
Edition of Federal Register (Revised as of October 1, 1972)
Federal Power Commission, Federal and State Commission Jurisdiction and
Regulation, 1967
Gas Appliance Manufacturers Association, Survey of Curtailment Plans, 1972
Lawrence Livermore Laboratory, An Analysis of Gas Stimulation Using Nuclear
Explosives, May 15, 1972 (Prepared for U.S. Atomic Energy Commission)
Loesch, Harrison (Assistant Secretary of Interior), Statement before Senate
Committee on Interior and Insular Affairs, June 19, 1972.
Interstate Oil Compact Commission, A Study of Oil and Gas in tne United
States, 1964
National Association of Regulatory Utility Commissioners, Survey of Actions
by State and Federal Regulatory Agencies and Intrastate Natural Gas
Distributors to Meet Natural Gas Shortages, February 29, 1972
New York Public Service Commission, Opinion and Order Establishing Restric-
tions on Attachments of New Gas Customers, etc., Case iNo. 25766,
October 26, 1971
New York State, Executive Chamber, Memoranda dated June 8, 1972 filed with
Assembly Bills 838 and 12062 (vetoed by Governor Nelson Rockefeller)
Oil and Gas Journal, various issues 1971 and 1972
Oklahoma Corporation Commission, Order No. 93381, issued October 5, 1972
Peterson, Peter G. (Secretary of Commerce), Speech before American Petroleum
Institute in Chicago, Illinois, November 14, 1972
Stone, Oliver L., Continental Shelf Natural Gas, Including a Comparison of
Significant Features of the Systems of the United States and the United
Kingdom, Natural Resources Lawyer, November 1971
Texas, Notice of Hearing Relating to the Promulgation of Curtailment
Priorities for Gas Transported and Sold in the State of Texas, issued
November 16, 1972
111-47
-------
U.S. Atomic Energy Commission, Annual Report 1972
U.S. Department of Interior, Brief submitted for Secretary of Interior to
U.S. Court of Appeals for the Ninth Circuit, Gulf Oil Corp. et al. v.
Rogers C. B. Morton et al. (No. 72-2449), September 1972
U.S. Department of Interior, Bureau of Land Management, Draft and Final
Environmental Statements re Proposed 1972 Outer Continental Shelf Oil
and Gas General Lease Sale, Offshore Louisiana, July 25, 1972 and
October 13, 1972
U.S. Department of Interior, Office of Coal Research, Annual Report 1972
U.S. Department of Interior, Geological Survey, Geologic Framework and
Petroleum Potential of the Atlantic Coastal Plain and Continental Shelf,
1971 (Geological Survey Professional Paper 659)
U.S. Department of Interior, Geological Survey, Leasing and Operating
Regulations for tne Submerged Lands of the Outer Continental Shelf,
Reprint of October 1967
U.S. Department of Interior, Geological Survey, Outer Continental Shelf
Statistics, April 1972
U.S. Department of Interior, News Release (issued June 15, 1971) on Tentative
Offshore Leasing Schedule Througn 1975
U.S. Department of Interior, Submission to Senate Committee on Interior and
Insular Affairs on Administration of Outer Continental Shelf Lands Act,
March 23, 1972
U.S. Statutes
Mineral Lands Leasing Act of 1920 (30 U.S.C. Section 185)
Outer Continental Shelf Lands Act of 1953 (67 Stat. 462)
Natural Gas Act of 1938 (52 Stat. 821)
University of Missouri-Rolla Journal, State Regulatory Controls on Oil and
Gas (Alaska), June 1971, pp. 93-98
111-48
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CHAPTER W - FEDERAL POWER CCMMISSION REGULATION OF NATURAL GAS
Regulation by the Federal Power Commission has clearly been a
dominant factor affecting the supply of natural gas for the past 15 years.
This is not to say, however, that other factors have not also had an
important influence on industry motivation to explore for and produce
gas. Some of the more important include federal taxation of oil and gas,
the oil import program, and the availability of alternative outlets for
capital investment by U.S. companies both at home and abroad.
This chapter seeks to review highlights of FPC regulation
pertinent to an understanding of the present supply situation. Before
proceeding with this review a brief chronology of the major events of
FPC regulation is set forth below.
1928 - FTC directed by Senate to investigate public utility corporations
engaging in interstate electric and gas business
1935 - FTC recommends federal regulation of transportation and sales of
gas in interstate commerce
1938 - Natural Gas Act passed, giving FPC authority over transportation
and sales of gas for resale in interstate commerce
1954 - Supreme Court holds Natural Gas Act applies to wellhead sales by
producers for resale in interstate commerce
1960 - FPC adopts area rate approach for producer sales
1965 - FPC issues first area rate decision (Opinion No. 468 for Permian
Basin area)
1968 (May) - Supreme Court affirms FPC Opinion No. 468
1968 (September) - FPC issues second area rate decision (Opinion No. 546
for South Louisiana area)
IV-1
-------
1970 - U.S. Court of Appeals upholds FPC Opinion No. 546, but with invita-
tion for upward price adjustments
1971 (April) - FPC orders interstate pipelines to file curtailment of
service plans
1971 (July) - FPC issues second decision in South Louisiana area decision,
approving higher rates (Opinion No. 598)
1972 (June) - Supreme Court upholds FPC authority to control curtailments
of service by interstate pipelines to all customers
1972 (June) - FPC authorizes first base load importation of LNG from
Algeria over long term
A. Producer Sales at the Wellhead
Without question, the most difficult and controversial aspect of
FPC regulation has been its regulation of producer sales of natural gas at
the wellhead. Various regulatory methods have been attempted -- based for
the most part on cost computations for individual producers or for groups
of producers in particular producing areas of the nation. In terms of
eliciting supply sufficient to meet demand, these attempts must be pro-
nounced a failure. For well over a decade, the FPC virtually froze the
price of gas at levels fixed according to criteria bearing little or no
relationship to marketplace realities. The effect was twofold: to dis-
courage investment by producers in gas exploration and production, while
at the same time (through low prices for gas) artifically inflating the
demand for gas in relation to other fossil fuels.
The history of area rate regulation, coupled with the history of
certification of new gas at so-called "in-line" and "guideline" rates, is com-
plex but crucial to an appreciation of the present gas supply picture and the
IV-2
-------
current pressures for amendment of the Natural Gas Act to remove or relax
FPC control over producer prices.
Producer rate regulation may conveniently be described in
three periods: 1954 through 1960, 1961 through 1968, and 1969 to date.
1. 1954 Through 1960
Upon issuance of the Supreme Court's decision in the Phillips
case in 1954, the FPC was suddenly faced with the unwanted task of regu-
lating literally thousands of producers. It was soon deluged with a flood
of rate filings under Section 4 and applications for certificates to
initiate (or continue) sales under Section 7. The first six years of its
regulation -- ending with the adoption of an area approach to producer
rates -- proved to be an administrative chaos, as the Commission struggled
to handle matters on an individual company basis and fell farther and
farther behind in coping with a continually rising backlog.— The 1954-
1960 period was also characterized by court reversal of higher rates
approved by the Commission for new gas sales. These rates reflected at
least in part a rapid growth in demand for gas as interstate pipelines
expanded their systems to many unserved parts of the country and to pro-
vide additional gas to existing markets.
With respect to the certification of producer sales in this early
period, the Commission -- except in rare instances -- approved the prices
contained in the contracts. This practice, however, came to an end in 1959
with the Supreme Court's decision in the CATCO case. The CATCO case
\j In 1960, the FPC was described as the "outstanding example in the
Federal Government of the breakdown of the administrative process."
Landis, Report on Regulatory Agencies to the President-Elect, printed
for use of the Senate Committee on the Judiciary, 86th Congress,
Second Session, 54.
IV-3
-------
involved large volumes sales by a group of four producing companies— in
South Louisiana at a proposed initial rate of 21.4<£ (plus Itf tax where
applicable). This price was the highest ever negotiated at the time the
contract was signed in 1956. The FPC twice refused to certificate the sale
at the contract price (imposing various conditions instead) but, faced with
the threat of contract cancellation by the producers and dedication of the
gas to intrastate markets, backed down and approved the sale as proposed.
The Supreme Court reversed,— holding that the Commission was obligated to
attach conditions to prices deemed "out-of-line" or otherwise not in the
public interest. The Court said:
"[The] inordinate delay presently existing in the processing
of Section 5 proceedings requires a most careful scrutiny and
responsible reaction to initial price proposals of producers
under Section 7 .... The fact that prices have leaped
from one plateau to the higher levels of another . . . [makes]
price a consideration of prime importance .... Where the
proposed price is not in keeping with the public interest
because it is out of line or because its approval might result
in a triggering of general price rises or an increase in the
applicant's existing rates by reason of 'favored nation'
clauses or otherwise . . . the Commission in the exercise
of its discretion might attach such conditions as it
believes necessary." (360 U.S. at 391)
Subsequent to the Supreme Court's decision in CATCO, several other
FPC certificate orders approving contract rates for South Louisiana sales
at rates equal to or higher than the CATCO level were set aside and remanded
I/ The initials of the four companies -- Cities Service Co., Atlantic
Refining Co. (now Atlantic Richfield), Tidewater Oil Co. (now Getty Oil
Co.), and Continental Oil Co. -- account for the term "CATCO."
2j Atlantic Refining Co. v. Public Service Commission of New York, 360 U.S,
378.
IV-4
-------
by four different U.S. Courts of Appeal on the ground that the prices in
question were "out-of-line."—
As to rate regulation under Sections 4 and 5, the FPC approached
the problem of determining just and reasonable rates in the initial years
by looking to the cost of service of each individual producer, the same
approach followed for natural gas pipelines and electric utilities.
Generally, the FPC's procedure was to consolidate into company-wide
proceedings all of a company's rate increase applications together with
investigations instituted under Section 5 into all of the company's rates.
These proceedings proved to be exceedingly complex and time consuming,
primarily because of difficulties in attempting to adapt the cost of
service method to regulation of producers. The Commission's backlog
of rate increase cases mounted rapidly. By 1960, only 11 such cases had
been decided after full hearings, while 3,278 producer rate increase
filings involving 570 companies were awaiting hearing and decision. (24
FPC at 545)
On September 28, 1960, in its first decision in a major company-
wide rate proceeding (the original Phillips case which led to the Supreme
I/ United Gas Improvement Co. v. FPC, 283 F.2d 817 (CA 9), certiorari
denied sub nom. California Co. v. United Gas Improvement Co., 365 U.S.
881, and Superior Oil Co. v. United Gas Improvement Co., 365 U.S. 879;
Public Service Commission v. FPC, 287 F.2d 146 (CADC). certiorari
denied sub nom. Hope Natural (5? Co. v. Public Service Commission, 365
U.S. 88U, and Shell Oil Co. v. Public Service Commission, 365 U.S. 882;
United Gas Improvement Co. v. FPC, 287 F.2d 159 (CA 10); United Gas
Improvement Co. v. FPC, 290 F.2d 135 (CA 5), certiorari denied sub~~nom.
Sun Oil Co. v. United Gas Improvement Co., 368 U.S. 823 (October 9,
1961); United Gas Improvement Co. v. FPC, 290 F.2d 147 (CA 5),
certiorari denied sub nom. Superior Oil Co. v. United Gas Improvement
Co., 366 U.S. 965.
IV-5
-------
Court's 1954 decision holding the Natural Gas Act to apply to sales by pro-
ducers for resale in interstate commerce), the FPC concluded, on the basis
of its experience to that time, "that the traditional original cost,
prudent investment rate base method of regulating utilities is not a sensible
or even a workable method of fixing the rates of independent producers of
natural gas."— In support of this conclusion, the Commission pointed out
that producers, for whom the results of exploration are highly uncertain,
are not like public utilities which have a reasonably predictable relation-
ship between investment and output. Further, the Commission reasoned, the
necessity of allocating joint costs, i.e., costs incurred in producing oil
and gas jointly (which typically account for about two-thirds or more of all
costs incurred by producers), between gas and oil greatly complicates the
costing process and can lead to widely divergent results, depending on the
allocation methods used. Moreover, when an unrealistic result is reached, then
the allocation formulae must be changed in order to bring about a reasonable
result. The Commission also stressed the administrative impossibility of making
separate cost of service determinations for each of the producers under its
jurisdiction. Faced with a huge and ever-growing backlog of cases, the FPC pre-
dicted that it would be unable to become current in its producer rate work until
the year 2043 even if its Staff of some 800 employees were tripled.
For these and other reasons, the FPC declared its intention to
henceforth determine producer rates for the industry on an area basis .
". . .[I]t appears that the ultimate solution to producer regulation will
I/ FPC Opinion No. 338, issued September 28, 1960 in re Phillips Petroleum
Co. (G-1148 et al.); 24 FPC 537, 542.
IV-6
-------
be in the determination of fair prices for gas, based on reasonable
financial requirements of the industry and not on the particular rate
base and expenses of each company." (24 FPC at 547)
Simultaneously with its decision in the Phillips case, the FPC
issued Statement of General Policy No. 61-1 establishing two sets of guide-
line prices for 23 different producing areas -- one set applicable to
initial prices for certificating new sales and the other applicable to
increased rates for existing sales. The Commission stressed that the
guidelines did not constitute determinations of just and reasonable rates
but rather were intended to facilitate producer regulation during the
interim pending the completion of area rate proceedings. The specific
guidelines were said to be based on all "relevant facts available"
(including cost information from decided and pending cases, historical
and existing price structures, area price trends over a number of years,
production and exploratory trends, trends in demand, and others), but the
weight given to any of these factors was not explained.
Nevertheless, an obvious objective of the Commission in Statement
of General Policy No. 61-1 was to "hold the line" on producer prices then
in effect. As shown by Table IV-1 on the following page, the initial
guideline levels established by the Commission were below the highest
rates at which gas was then being committed to the interstate market
except in two areas (one a single field in Oklahoma). Moreover, in some
areas, the initial guideline rates were well below previously authorized
sales. The guideline levels for rate increase purposes were still lower
than the initial rate guidelines in nearly all areas.
IV-7
-------
AREA GUIDELINE PRICES ESTABLISHED BY
STATEMENT OF GENERAL POLICY NO. 61-1
Issued September 28, 1960*
TABLE IV-1
Area
Texas
District
District
District
District
District
District
District
District
District
*2)
#3)
#4)
#5)
#6)
#7B)
#7C)
08 )
South Central
Texas
Texas Gulf
Coast
Northeast
Texas
West Texas
District 09 - North Central
Texas
District #10 -
Louisiana
Southern
Northern
Mississippi
Oklahoma
Panhandle Area
Other
Carter-Knox
Kansas
New Mexico
Permian Basin
San Juan Basin
Colorado
Wyoming
West Virginia
Texas
Panhandle
FPC Increased
Rate Level a/
14.0
14.0
14.0
14.0
14.0
14.0
11.0
11.0
11.0
14.0
11.0
14.0 (plus tax)
14.0 (plus tax)
14.0
11.0
11.0
11.0
11.0
11.0
13.0
13.0
13.0
25.0
FPC Initial
Rate Level
-(Cents per Mcf) -
Highest
Price Filed
15.0
18.0
18.0
18.0
14.0
15.0
14.0
16.0
16.0
14.0
17.0
21.5 (plus tax)-/
17.0 (plus tax)
17.0
15.0
16.8
16.0
16.0
13.0
15.0
15.384
28.0
20.00
22.00
20.00
20.00
17.00
15.50
16.00
21.80
14.49
23.00
24.8 (including tax)
20.2 (including tax)
22.88
23.00
20.50
16.80
23.00
21.26
17.0
16.4
17.5
29.7
a/ The increased rate guidelines in most areas were subsequently raised by l.Otf for con-
tracts from which all price escalation provisions had been eliminated and by 0.6
-------
The guideline levels were amended several times over the next
five years -- mostly downward. Also, many of the areas set forth in the
Policy Statement (reflecting in some instances, as in the State of Texas,
merely administrative subdivisions) were later adjusted and combined for
area rate proceeding purposes.
2. 1961 Through 1968
The next broad period of FPC regulation extends from the initia-
tion in December 1960 of the first area rate proceeding -- the Permian
Basin Area Rate Proceeding -- through late 1968. During this period the
FPC completed two major area cases, establishing rates for the Permian
Basin area only slightly higher than the guidelines fixed at the begin-
ning of the decade and establishing rates for the South Louisiana area
lower than the 1960 guidelines. The FPC decision in the Permian Basin case
was upheld by the Supreme Court in 1968. The 1961-1968 period, particu-
larly the earlier years, was also dominated by a series of certificate
proceedings in which the Commission established "in-line" prices at or
below the guideline initial price levels promulgated in 1960 and gen-
erally froze all new producer sales to those levels. The FPC's "in-line"
policy developed as a result of the Supreme Court's CATCO decision and
subsequent court decisions reversing and remanding FPC certificate orders
because the prices were "out-of-line."
a. "In-Line" Regulation
During the first half of the 1960's, the Commission conducted
numerous certificate proceedings to determine the maximum price at which
IV-9
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it would issue permanent certificates for new gas sales. The majority of
these proceedings involved sales in the South Louisiana and Texas Gulf
Coast areas, both major sources of gas supply for interstate pipelines.
Some of the earlier South Louisiana proceedings included sales which had
been remanded by the courts. The later cases primarily dealt with the
large numbers of sales which had commenced under temporary certificates --
generally issued at guideline prices in the case of sales executed after
September 28, 1960 (the date of the Statement of General Policy No. 61-1),
although often with some type of refund condition— -- pending hearings
and grant of permanent certificates. In the Texas Gulf Coast cases, the
Commission severed its consideration of pre-Policy Statement sales and
post-Policy Statement sales in some instances.
The method generally applied by the FPC in these proceedings
was to examine the prices at which sales in the area had previously been
certificated, excluding "suspect" prices (those under certificates which
had been set aside by the courts or were under court review, and all
"like" prices), and then to select the "in-line" price level from the
remaining sales. The effect of this technique was to substantially
narrow the range of prices to be considered, since nearly all certifi-
_!/ The FPC's policy regarding the issuance of temporary certificates --
which permit producers to begin sales on a temporary basis pending a
determination of whether permanent authorization should be granted on
the terms proposed -- underwent several changes of direction during
the early 1960's and must be characterized as indecisive at best.
Some temporaries were issued with no conditions, others were condi-
tioned to require refund of amounts collected in excess of the ulti-
mately determined initial rate (but not below a certain floor level),
and still others were conditioned to require refund of all excess
amounts collected above the ultimately approved initial rate with no
floor.
IV-10
-------
cates issued at prices higher than the guidelines (and, in some cases,
at prices at or below the guidelines) were subject to litigation. As
to the remaining sales, the process of selecting an "in-line" price was
imprecise; considerable controversy developed over what sales should or
should not be considered and over the weight to be accorded to those
given consideration.
Using the above procedure, the Commission first determined in
January 1962 an "in-line" price of 20.(H (including tax) for South
Louisiana sales subject to state taxing jurisdiction and 18.5<£ for off-
shore Louisiana sales in the Federal Domain.— This determination
pertained to the original CATCO contracts executed in 1956. The same
"in-line" prices were confirmed by the FPC in two subsequent decisions
relating to later contracts.— At the same time, a large number of
South Louisiana sales were severed from the contested proceedings and
granted certificates pursuant to settlement agreements providing for
prices of 20.625
-------
which pipeline buyers could make up purchases that they had been obli-
gated to pay for under contractual terms but could not physically take
at the time.
In the Texas Gulf Coast certificate proceedings, the FPC deter-
mined "in-line" prices of 15.0$, 16.0$ and 17.0$ depending on the date
of contract and the particular subarea of the sales. However, in all sub-
areas, the "in-line" determinations in the initial cases were below the
applicable guideline levels which were accordingly lowered to the "in-line"
levels (or, in one case, to a level 1$ higher than the "in-line" price).
Virtually all of the FPC "in-line" price decisions were attacked
on multiple grounds and appealed to the courts. The principal issues con-
cerned the prices which the Commission should take into account in reaching
its '"'in-line" determinations (including whether any weight should be given
to guideline and temporary certificate prices), whether economic evidence
on supply-demand and cost trends should be considered, whether the FPC had
power to prohibit the producers from increasing rates above the levels
which could trigger widespread increases in the areas involved; and the
extent of the Commission's authority to order refunds of amounts collected
above the in-line rates under both judicially invalidated certificates and
temporary certificates. All of these questions eventually reached the
Supreme Court, in part because of conflicting decisions by the courts below.
In two different decisions,— the Supreme Court affirmed the
FPC's approach in all significant respects. Specifically, the Court ruled
I/ United Gas Improvement Co. v. Gallery Properties, Inc., 382 U.S. 223
(1965J ; FPC v. Sunray DX Oil Co., 591 U.S. 9 (1968).
IV-12
-------
that the Commission correctly refused to hear economic trend and cost
evidence in in-line proceedings because of the delays which consideration
of such evidence would entail; that the imposition of moratoria on price
increases above specified "triggering" levels was a justifiable measure
to keep the general price level relatively constant pending determination
of just and reasonable rates in area proceedings; that the FPC did not
abuse its discretion in giving "some weight" to guideline and temporarily
certificated prices; that the Commission could require refunds of revenues
collected above the in-line rates pursuant to previously issued certifi-
cates which had been overturned by the courts; and, finally, that the
Commission could order refunds of amounts collected in excess of in-line
rates under temporary certificates which did not include an express refund
condition.
The Court's holding on this last issue, namely, the ordering
of refunds in the case of sales under temporary certificates which were
granted without refund condition, is of particular interest in terms of
its effect on producer expectations. The FPC had first ruled that it
would be inequitable to require refunds in such situations because the
temporaries contained no explicit language to warn the producers of the
possibility of a refund and because the imposition of a refund condition
retroactively would "so denature the value of a Commission authorization
as to place any reliance on [its] actions in this area in serious jeopardy."
(29 FPC 225). On appeal, the B.C. Circuit held that the FPC had power to
order retroactive refunds and should undertake a "more penetrating"
analysis of the equities involved. (PSC of New York v. FPC, 329 F.2d 242)
IV-13
-------
The FPC thereafter reversed its previous position and ordered refunds in
several cases. Certain of these cases were appealed to the Tenth Circuit
which agreed with the producers that the FPC did not have power to order
refunds of amounts collected under unconditioned temporary certificates
and that to require refunds retroactively would deny price assurance and
undermine producer confidence. The Supreme Court rejected this reasoning.
"When a producer has requested permission to begin delivery
of gas prior to completion of normal certification pro-
cedures , due to an emergency, we think it not unfair that
in return for that permission it accept the risk that at
the termination of those procedures, the terms proposed
by it may be retroactively altered to conform to the public
interest." (391 U.S. at 50)
In sum, the overall effect of the FPC's "in-line" price policies
developed during the early and mid-1960's was to freeze prices at pre-
existing or lower levels.
b. Area Rate Proceedings
The second principal focus of FPC activity during the 1960's was
the initiation and conduct of several area rate proceedings. The Commission
chose the Permian Basin area of West Texas and Southeast New Mexico as the
first producing region in which to test the area rate method. The Permian
Basin proceeding was instituted on December 23, 1960. This was followed by
the initiation of proceedings for the South Louisiana area on May 10, 1961,
for the Hugoton-Anadarko and Texas Gulf Coast areas on November 27, 1963
(these two proceedings were conducted jointly for the most part during the
hearing phase, although were decided separately), and for the Other Southwest
area (consisting of Mississippi, Northern Louisiana, and parts of Oklahoma,
IV-14
-------
Texas, Kansas and Arkansas) on December 28, 1967. The first two area
cases -- for the Permian Basin and South Louisiana areas -- dominated the
scene and set the precedents.
The evidence introduced in the area rate hearings was voluminous
and fell into two broad categories: economic (including industry structure,
nature of the exploratory effort, supply and demand, pricing history, and
financial requirements) and cost. The cost evidence related to composite
industry costs computed both on a national and an area basis. The area
cost data were collected via a questionnaire sent to all major producers
in the area. The nationwide cost data were derived primarily from industry
publications. The Commission outlawed cost evidence pertaining to operations
of individual companies.
Hearings in the Permian Basin case began in October 1961 and
lasted nearly two years. The total transcript comprised over 30,000 pages.
On August 5, 1965, the FPC issued Opinion No. 468 deciding the case. (34
FPC 159) Opinion No. 468 adopted a two-price system of rates according to
the contract vintage (and type) of gas. The contract dividing date was
established at January 1, 1961. Thus, for "new" gas well gas sold under
contracts dated since January 1, 1961, rates were fixed at 16.5
-------
The rationale for the two-price system was that a higher price based on
current costs was needed to encourage producers to engage in further
exploration and development directed specifically toward gas, while such
a price for "flowing" gas discovered and developed in the past primarily
in the course of searching for oil would only result in windfall profits.
In addition, the FPC ordered refunds in full of all amounts collected
under refund obligation (in Section 4(e) proceedings) in excess of area
rates; imposed a moratorium or ban on rate increase filings above the area
ceilings for about 2-1/2 years (until January 1, 1968); prescribed
various pipeline quality standards and price adjustments for sales not
meeting these standards; and established a procedure (although failed to
spell out the qualifying circumstances) whereby producers could seek
relief from area rates or refund requirements.
The FPC's Permian Basin decision, which represented the culmina-
tion of mammoth efforts by the participants in the case and by the Commis-
sion itself, has been the subject of extensive analysis. To producers it
was a grave disappointment. To some others as well, the procedures used
to arrive at the results seemed as illogical as the individual company
cost approach rejected by the Commission in 1960. Two aspects of the
decision bear emphasis here. The first is that the so-called "new" gas
ceiling of 16.5$ was only a half-cent higher than the guideline price
established in 1960 for initial sales. The second is that the area
ceilings fixed for both "new" and "flowing" gas- were based solely on
_!/ The latter is frequently referred to as "old" gas.
IV-16
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average cost determinations. The Commission said: ". . .A composite
cost determination is the bedrock on which a regulated price must be estab-
lished.11 (34 FPC at 189-190) The "new" gas ceiling rested on a composite
cost computation of 16.43
-------
opinion in the Permian case was upheld by the Supreme Court in all
respects.— The Supreme Court concluded that the FPC decision did not
violate any legal requirements and generally represented a permissible
exercise of discretion. At the same time, the Supreme Court made clear
that its affirmation was influenced by the fact that the Permian case
was the first area rate proceeding and that it expected the FPC to deal
with issues more precisely as the agency gained greater experience with
area rate regulation.
The second area case initiated by the FPC -- the South Louisiana
Area Rate Proceeding (AR61-2) -- was decided in Opinion 546 (40 FPC 530),
issued on September 25, 1968 (about five months after the Supreme Court's
affirmation of Opinion No. 468 in the Permian case). The time elapsed
between the commencement of this case (in May 1961) and the Commission's
decision was over seven years. Hearings spanned a 28-month period between
August 1963 and November 1965, resulting in a transcript totalling over
34,000 pages. The evidence introduced during these hearings followed
essentially the same lines as in the Permian case and included voluminous
cost studies, generating seemingly endless controversy over cost alloca-
tion methods and other costing techniques, as well as over many suggested
adjustments to these methods and techniques. Similarly, the Commission's
decision essentially conformed to the format established in the earlier
area case, although with some differences.
Opinion No. 546 established a three-price system for South
Louisiana sales. Regarding sales subject to state taxing jurisdiction,
I/ Permian Basin Area Rate Cases, 390 U.S. 747 (1968).
IV-18
-------
the ceilings were fixed at 18.5<£ for contracts dated prior to January 1,
1961; at 19.5
-------
declining trends since 1958 in reserve-production and finding-production ratios
for the South Louisiana area. In a decision issued March 20, 1969 on rehear-
ing (Opinion No. 546-A; 41 FPC 378) , the FPC modified somewhat the moratorium
provisions for contracts dated after October 1, 1968 but essentially adhered
to its earlier decision. However, at the same time, the Commission initi-
ated a new proceeding (AR69-1) to determine whether higher ceiling rates
should be prescribed for offshore sales contracted since October 1, 1968.
FPC Opinion No. 546 was ultimately upheld in 1970 by the Fifth
Circuit Court of Appeals which, however, expressed "serious misgivings"
particularly as to the adequacy of the Commission's findings respecting
supply, demand and the impact of the prescribed rates.— Further, although
affirming the FPC, the Court suggested that the Commission might wish to
modify its earlier decision. On rehearing a few months later, the Court
reiterated this suggestion and clarified the Commission's power to make
whatever adjustments it deemed necessary.
"Under Section 19(b) of the Natural Gas Act, this Court
has the broad remedial powers that inhere in a court of
equity, and pursuant to our equitable powers, we make it
part of the remedy in this case that the authority of the
Commission to reopen any part of its orders, including
those affecting revenues from gas already delivered, is
left intact. The Commission can make retrospective as
well as prospective adjustments in this case if it finds
that it is in the public interest to do so." (444 F.2d
125)
I/ Austral Oil Co. et al. v. FPC, 428 F.2d 407 (1970)
IV-20
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3. 1969 to Date
By late 1968 and the first part of 1969, there were growing
signs of a gas supply shortage. One of the first indications was a letter
dated December 16, 1968 from the President of the American Gas Association
to the Chairman of the FPC requesting the Commission to reexamine its area
rate policies because of an impending shortage of gas and the inability of
many distribution companies to obtain long-term commitments of additional
gas supply from interstate pipelines. This letter was noteworthy because
of the active role played by several distributor groups during the 1960's
in seeking to prevent increased price levels for producers. A few months
later, the American Gas Association announced an absolute drop in U.S.
proved gas reserves in 1968 for the first time in the nearly two decades
during which the Association had compiled statistics, together with the
lowest level of new supply additions since 1954.- Speeches of various
FPC members commenced to note these trends and to describe the gas supply
situation as "critical." An FPC Staff report, released in September 1969,
referred to mounting evidence that the nation's gas supply "is diminishing
to critical levels in relation to demand" and predicted "only a few years
remain before demand will outrun supply" on the basis of then prevailing
trends.-
\l Excluding Alaska, gas reserve additions in the U.S. have been even
lower than in 1968 in each succeeding year, while total proven gas
reserves have fallen by nearly 15% since their peak level of 289 tril-
lion cubic feet at the end of 1967.
2f A Staff Report on National Gas Supply and Demand, FPC Bureau of Natural
"~ Gas, September 1969, pi.
IV-21
-------
Thus, since 1968, the FPC's regulation of producers has increas-
ingly shifted toward the adoption of remedial measures aimed at reversing
the downward trends in gas supply and encouraging higher levels of explora-
tion for gas.
Among other things, a number of actions have been taken by the
Commission in the past three years to increase the level of area rates.
Significantly, in the South Louisiana area, the FPC reopened the earlier
proceeding in its entirety for reconsideration and, on July 16, 1971,
issued Opinion No. 598 superseding Opinion No. 546 and establishing sub-
stantially higher rates. Opinion No. 598 accepted, with certain modifica-
tions, a Settlement Proposal supported by nearly all parties -- including
producers, pipelines, distributors and the FPC Staff.— Pursuant to the
Settlement, the FPC approved a 26<£ ceiling rate for all so-called "new"
gas sold under contracts dated since October 1, 1968 and a 22.375
-------
additional new gas reserves in the area (beyond those required to work off
refund obligations) committed by the producing industry as a whole to
interstate pipelines in the following six years. The escalations are 0.5
-------
ranging up to 26.0<£ and "flowing" gas ceiling rates ranging up to 20.0
-------
October 2, 1970, amended by Order No. 441, issued November 10, 1971); and
(3) adoption of a policy to suspend producer rate increases for one day
only, rather than the full five-month statutory period permitted under the
Natural Gas Act (Order No. 423, issued February 18, 1971).
In addition, the FPC has sought to relieve curtailment problems
for individual pipelines— by permitting the purchase of gas on an emergency
basis at rates considerably above the area ceilings. Specifically, the
Commission adopted rules to (1) permit emergency sales by independent pro-
ducers for 60-day periods without certificate authorization (Order No. 418,
issued December 10, 1970); and (2) to permit limited-term sales by pro-
ducers for longer than 60 days, at rates above the area ceilings, to inter-
state pipelines demonstrating an emergency need for gas (Order No. 431,
issued April 15, 1971) .-^
Many of the above actions designed to stimulate increased supply
have been appealed to the court, and their validity remains uncertain at
this date. In one decided case involving the ratemaking treatment provided
by the Commission for advance payments by pipelines to producers to develop
additional gas, the U.S. Court of Appeals for the B.C. Circuit held that the
I/ In 1970, the shortage of gas supply led two major interstate pipelines
to seek FPC approval of procedures proposed for curtailing deliveries
to their customers. In the following two years, eight pipelines have
been forced to curtail firm sales --by increasing amounts. These
curtailments, and the FPC's response to the problem, are discussed at
a later point in this Chapter.
2/ As of September 21, 1972, the FPC had issued 87 certificates for limited-
term sales by producers -- mostly at rates of 35
-------
FPC's action constituted a justifiable experiment in its search for
solutions to alleviate the gas shortage.— However, in a more recent
decision, the same Court overturned the FPC's exemption of small producer
sales from rate regulation, holding that such action constituted an abdica-
tion of the Commission's responsibility to insure that all rates of all
natural gas companies are just and reasonable and hence was beyond the
2/
Commission's statutory power.—
The most recent, and perhaps most far-reaching, measure taken
by the FPC in response to the growing shortage of domestic gas supply was
its adoption last summer of a new optional procedure for certificating new
gas sales by producers at rates in excess of area ceilings (Order No. 455,
issued August 3, 1972). The new procedure, which is subject to several
restrictions as to its use, essentially contemplates a one-time review of
new gas sales contracts in an effort to reduce uncertainty respecting
future rates. The FPC action was immediately appealed to the courts as
tantamount to deregulation, and the outcome of this litigation is undoubtedly
a year or more in the future.
The optional certificate procedure established in FPC Order No.
455 is discussed further in Chapter V (pages V-43 through V-48).
B. Pipeline Rates
Pipeline rates have been determined by the FPC from the outset
by the traditional utility rate base method which involves calculation of
a total cost of service for a specified test period and translation of
I/ PSC of New York v. FPC. CADC, No. 71-1161, decided March 29, 1972,
rehearing denied May 19, 1972.
2/ Texaco Inc. et al. v. FPC, CADC, Nos. 71-1560 et al., decided
December 12, 1972. It is probable that the FPC may appeal this decision
to the Supreme Court.
IV-2 6
-------
that cost of service into jurisdictional rates through various cost alloca-
tion and rate design techniques.
The costs to be recovered through rates include all operating
and maintenance expenses, depreciation and depletion, and taxes, plus a
fair rate of return on rate base. The rate base consists of investment
at original cost (less accrued depreciation) plus an allowance for working
capital. Determination of rate of return is governed by certain well-
established criteria in public utility regulation, namely, a fair return is
commensurate with returns on investment in other enterprises with corresponding
risks, sufficient to attract capital and adequate to assure financial integrity.
Use of the cost of service approach for determining pipeline rates
is widely accepted, although the computation of individual cost components
and determination of the rate of return level are frequently heavily con-
tested in pipeline rate proceedings. However, with one exception, these
disputed costing matters generally have no bearing on whether more or less
gas will be available and hence are beyond the supply focus of this study.—
The one exception relates to gas produced by a pipeline itself
or purchased by a pipeline from an affiliated producing company. The
pricing of such gas has had a long history in the FPC and in the courts.
In 1954, the Commission granted Panhandle Eastern Pipe Line Co. a commodity
value allowance (essentially, the average field price of comparable gas
I/ It may be noted, however, that in recent years, several pipelines
have sought higher depreciation rates for plant and other investment
because of declining gas supply. This situation, the pipelines
allege, results in reducing the number of years existing facilities
can be expected to remain in use, thereby requiring a higher rate of
annual depreciation in order to recover investment. One pipeline,
for example, recently requested an increase in depreciation rate from
4% (implying an average plant investment life of 25 years) to 8.33%
(implying an average life of 12 years). The pipeline claims the
8.33% rate is justified by an expected 12-year period of deliverability
from its dedicated recoverable gas reserves.
IV-27
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sold in the same producing areas) for its own gas production. This
decision, however, was overturned in 1956 by the Court of Appeals for
the District of Columbia Circuit which ruled that the FPC was required
to apply the cost of service rate base approach to pipeline-produced
gas at least as a point of departure and to show any allowance higher
than a cost-based amount to be no more than needed to encourage pipeline
exploration and development of its own production.— As a result of this
court opinion, the FPC --up until the last few years -- followed the
traditional cost of service approach for pipeline-produced (and affiliate-
produced) gas, i.e., it permitted pipelines to include in their cost of
service an allowance no greater than the estimated costs of producing
that gas. For most pipelines, such allowances were considerably lower
than the prices paid to independent producers for gas purchases in the
same producing areas.
In 1966 the FPC initiated a proceeding to determine the proper
method to be used for pricing gas produced by pipeline companies and/or
obtained from affiliated producers. The first phase of the proceeding
was directed to the pricing of such gas in the future, specifically, gas
produced from leases acquired after the date of an FPC decision. Evidence
submitted in the proceeding indicated, among other things, that reserves
owned by pipelines engaged in production operations declined both absolutely
(by close to 30% between the period 1958-1966) and as a proportion of
national gas reserves (from 251 to 131). On October 7, 1969, the FPC
I/ City of Detroit v. FPC, 230 F. 2d 810 (1955); certiorari denied,
352 U.S. 829 (1956).
IV-28
-------
decided that gas produced by pipelines from leases acquired thereafter
could be reflected in pipeline rates at the area price levels allowed
independent producers for comparable gas.— This change to an area method,
the FPC made clear, was intended to encourage pipelines to increase their
search for and production of gas.
The FPC was judicially affirmed in this new ratemaking approach
to pipeline-produced gas. Thus far, however, the approach has not resulted
in any increase in pipeline production. In part, insufficient time has
elapsed for a fair appraisal, considering the lead time needed to lease,
explore and develop gas reserves before production can commence. Probably
a more important reason, however, is that current area rates do not provide
sufficient incentive for either independent producers or pipeline producers
to step up their search for and production of gas.
Once a pipeline's cost of service has been established, the next
steps in the rate fixing process are allocation of that cost of service to
different classes of service and rate design. Here, the methods applied by
the FPC over the years have played a role in the overall background leading
to the gas demand-supply picture today.
In general, most pipeline companies sell the major portion of
their gas under firm rates to distributors for resale to residential, com-
mercial and industrial consumers and the remainder as direct sales to
industrial customers (including power plants) under firm or interruptible
_!/ FPC Opinion No. 586, issued October 7, 1969 in re Pipeline Production
Area Rate Proceeding (RP66-24, Phase I); affirmed by D.C. Circuit in
City of Chicago et al. v. FPC (No. 23740) issued December 2, 1971;
certiorari denied April 17, 1972.
IV-29
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rates. Firm rates are typically comprised of two parts: a demand charge
consisting of a flat monthly payment based on the amount the customer
nominates to take and the pipeline promises to deliver, and a commodity
charge consisting of a unit price per Mcf based on the actual volume
taken by the customer. Demand and commodity charges may vary among
different types of customers purchasing from the same pipeline. Inter-
ruptible rates typically include only the commodity charge.
How to allocate a pipeline's overall cost of service between
its jurisdictional and nonjurisdictional (direct industrial) customers,
and between the demand and commodity portions of its rates, has been a
major function of rate design. In 1952 the FPC adopted what is known as
the Atlantic Seaboard formula.— Under this method, 501 of fixed overhead
costs are classified as demand and allocated among different classes of
sales according to peak load demand; the remaining 501 of fixed costs --
plus all costs varying with volume (principally gas purchase costs) --
are classified as commodity and allocated to all sales on a volumetric
basis.
The Commission applied the Atlantic Seaboard method without sub-
stantial change for several years. However, in the late 1950's and early
1960's, a number of pipelines pressed for modifications which would assign
a larger proportion of costs to the demand portion of rates, thereby lower-
ing the commodity portion and encouraging greater sales to interruptible
industrial customers. With gas plentiful in those years, the FPC permitted
I/ Atlantic Seaboard Corp. et al., 11 FPC 43 (1952).
IV-30
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a "tilting" of costs to the demand charge in several cases in an effort to
improve pipeline load balances through encouraging lower-priced industrial
sales in summer or valley periods when residential and commercial heating
demand is low. The result was to greatly accelerate the industrial demand
for gas. Many of the Commission's "tilting" decisions were bitterly
opposed by the coal interests which stood to lose, and did lose, boiler
fuel markets to cheaper-priced gas. There is no question that the FPC's
past rate design policies contributed -- along with restrictions on well-
head prices -- to an enormous growth in the burning of gas for electric
power generation and other industrial uses, which today account for over
half of total U.S. gas consumption.
Now, with gas in short supply, the FPC is taking another look at
its rate design precedents. Several events in the last year and a half
portend a new direction in the FPC's approach. In April 1971, the Commis-
sion announced that it proposed to reexamine existing commodity rate levels
and, to the extent necessary, redesign commodity-demand rate relationships
in present and future pipeline rate cases.— More recently, in an opinion
involving rates of El Paso Natural Gas Co., the Commission reversed a pre-
viously approved procedure and instead shifted back to the Atlantic Seaboard
approach without modification so as to load greater costs onto the commodity
portion of the rates. At the same time the Commission stated its resolve to
thoroughly review cost classification and techniques in light of the current
gas shortage.
I/ Order No. 431, dated April 15, 1971.
IV-31
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"Our purpose will be to arrive at a method of cost classification
and allocation and rate design which will produce a strong economic
pressure toward a more efficient allocation of our fuel reserves.
This will be directed particularly to conserving gas for residen-
tial , commercial and other uses for which this clear fuel is
greatly needed and discouraging the use of gas for large volume
industrial and boiler fuel purposes." I/
Tangible evidence of the FPC's change of direction came a few
months later when the FPC Staff, in a pending pipeline rate proceeding,
proposed a new rate design approach which would scrap the Atlantic Seaboard
method entirely (with or without modifications) and instead allocate over-
II
all cost of service on a volumetric basis.— In the case involved, the
result would be to shift over $4 million to the pipeline's direct indus-
trial sales and away from its jurisdictional sales for resale.
While major rate design changes seem certain to be adopted by
the FPC in the near future, it should be noted that such changes will
be directed towards reducing gas demand rather than increasing overall
supply.—
C. Pipeline Certificates
Pipeline applications for certificates to construct and operate
facilities for new or expanded service are appraised by the FPC in terms of
four basic criteria: existence of a market for the service proposed,
I/ Opinion No. 600-A, issued May 8, 1972 in re El Paso Natural Gas Co.
(RP69-6, Phase II et al.).
2J Testimony of Staff witness Robert Scarborough, served July 1972 in
United Gas Pipe Line Co. (PJV2-75).
V Another indicated change in FPC policy regarding pipeline rates is
the requirement of incremental pricing for high-cost supplemental
sources of nonconventional supply. This change is described in a
later section of this chapter concerning FPC regulation of imported
gas.
IV-32
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adequacy of reserves to support the proposed service, economic feasibility
of the project, and financeability. In many cases, these criteria are
satisfied with little difficulty, and certificates are issued without
opposition or hearing.— In some cases, the FPC has delayed certification
until the pipeline applicants have perfected their evidence with respect
to markets and reserves. In other cases, however, problems have arisen,
and major projects have been denied by the Commission. Also, where there
are competing proposals to serve the same markets, the FPC must choose
between them.
Some examples of major pipeline proposals which have failed to
receive FPC approval are: (1) a $151 million joint project ("Rock Springs"
project) of El Paso Natural Gas Co. and Colorado Interstate Gas Co. to
transport gas from the Rocky Mountain area to Southern California --
rejected by the Commission in 1963 because of the lack of immediate need
for much of the gas and the desirability of exploring more economical
means for increasing service to the Southern California market;- (2) a
$62 million project (the Oklahoma-Illinois project) sponsored by certain
large integrated petroleum companies to transport gas from northwest and
southeast Oklahoma to serve primarily industrial users in the St. Louis
area -- rejected by the Commission in 1965 because of a potentially adverse
I/ The FPC also has a procedure for granting "budget-type" certificates
~~ to pipelines for the routine construction of unspecified facilities
over a 12-month period. At present, construction under such certi-
ficates is limited to $1 million for each single project ($1.75 mil-
lion for offshore projects) and to a total of $7 million over the
12-month period.
IJ FPC Opinion No. 393 issued July 12, 1963 in re El Paso Natural Gas Co.
et al. (G-16235 et al.); 30 FPC 77.
IV-33
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ijnpact on the existing pipeline supplying that area and a too expensive
duplication of existing facilities;— (3) a $314 million project sponsored
by a newly created subsidiary of Tennessee Gas Pipeline Co. (the Gulf Pacific
project) to carry nearly 865 million cubic feet a day from the Texas Gulf
Coast area for direct sale to Southern California Edison Co. and the Los
Angeles Department of Water and Power for boiler fuel use -- rejected by
the Commission in 1966 in favor of an alternative proposal (by the two
existing interstate pipelines serving the Southern California area) which
was found to better match the market needs of the area, involve lesser
expense, provide a greater flexibility in end-use of the gas and avoid
2/
certain other problems;— and (4) a $127 million common carrier pipeline
(the "Red Snapper" project) sponsored by some 30 companies engaged in off-
shore Louisiana exploration to provide large volume transportation of off-
shore gas to onshore buyers -- rejected by the Commission in 1967 because
of the refusal of the producing company sponsors to disclose offshore
reserve data to support either the route or the capacity of the proposed
line.A/
Notwithstanding these examples of rejected pipeline projects,
an essential fact to be kept in mind is that no area of this country within
economic reach of a pipeline (with the possible exception of isolated com-
munities) has gone without gas for lack of pipeline facilities to transport
I/ FPC Opinion No. 474 issued September 9, 1965 in re Natural Gas Pipeline
Co. of America (CP62-243 et al.), 34 FPC 771.
y FPC Opinion No. 500 issued July 26, 1966 in re Transwestern Pipeline
Co. et al. (CP63-204 et al.), 36 FPC 176.
V FPC Opinion No. 528 issued September 26, 1967 in re Tennessee Gas
Pipeline Co. et al. (CP65-356 et al.), 38 FPC 691.
IV-34
-------
the supply. As a general rule, the cost of service ratemaking method gives
pipelines a built-in motivation to expand their facilities, whenever economi-
cally feasible, since the added investment enlarges the rate base on which
they earn a return. The FPC, in turn, was strongly motivated throughout
the 1950's and 1960's to allow pipeline expansions because of the lower
unit costs to ultimate consumers resulting from increased throughput and
thereby, higher load factor.
In recent years, the FPC has tended to relax its supply standard
for pipelines seeking to connect new sources of reserves. Initially, during
the 1950's, the Commission required that a pipeline, in order to obtain a
certificate of public convenience and necessity, show sufficient committed
gas reserves to deliver annual market requirements for a period of 12 years.
In ensuing years, this so-called 12-year deliverability rule was protested
by various pipelines on the ground that it forced them to contract for
excess supplies and to pay for gas they could not take.- In 1964, the
Commission modified the 12-year rule to provide for greater flexibility in
the case of established pipelines with active gas procurement organizations
and with systems extending into production areas of continuing exploration.
At the same time, however, the FPC continued to require that new pipelines,
and existing pipelines proposing to serve new or expanded markets with new
sources of supply over new routes, show a minimum deliverability life of
12 years for the incremental supply.
V Gas purchase contracts between pipelines and producers typically con-
tain 100% take-or-pay provisions requiring the buyers to pay for daily
quantities specified in the contracts irrespective of whether these
quantities can in fact be physically taken and sold by the buyer.
IV-35
-------
With a drying up of uncommitted reserves available for purchase
by interstate pipelines in the past few years, the 12-year deliverability
standard has become increasingly difficult to meet. In 1972 the FPC certi-
ficated two projects to attach new sources of supply, neither of which
came even close to satisfying the 12-year requirement.— One project pro-
posed by Arkansas Louisiana Gas Co. involving a 300-mile line to attach
new reserves in the Anadarko Basin of Oklahoma and Texas reflected a
deliverability life of seven to eight years; the other --a proposal by
Northern Natural Gas Co. to acquire new reserves in Montana via exporta-
tion and importation through Canada -- reflected a deliverability life of
from four to ten years, depending on assumptions as to estimated under-
lying reserves. In each case, the FPC stated that the 12-year rule did
not apply because the new supplies were sought to serve existing markets,
not new or expanded markets. Leaving aside this distinction, the FPC actions
reveal a willingness to reshape or modify past criteria and to certificate
new projects backed by a lesser showing of supply adequacy than in earlier
years.
In addition, the Commission has recently certificated certain
other construction projects to permit increased sales where the pipeline
involved has shown a deliverability life of only about four years. In at
least one case, however, the certificate was conditioned to require elimina-
tion of the cost of the new facilities from the pipeline's cost of service
I/ FPC Opinion No. 612, issued February 18, 1972 in re Arkansas Louisiana
Gas Co. (CP70-267); FPC Opinion No. 618, issued May 11, 1972 in re
Northern Natural Gas Co. et al. (CP70-69 et al.).
IV-36
-------
if the increase in deliveries turned out to be less than projected due to
inadequate supply.—
In short, the history of pipeline certificate regulation to date
does not indicate any major problems arising from lack of capacity to move
supplies to market.
D. Abandonments
With respect to abandonments, the Supreme Court in 1960 affirmed
an FPC decision that producers may not terminate sales upon expiration of
their contracts but rather are obliged to continue deliveries unless cessa-
2/
tion thereof can be justified in a Section 7(b) proceeding.— (The Court
also ruled, however, that a producer may file a unilateral rate increase
for a sale continuing after the contract termination date.) The effect of
the Court's decision was to require the continued flow of produced gas,
once dedicated to the interstate market, irrespective of contract term.
Armed with this judicial precedent, the FPC over the years has routinely
permitted abandonment of producer sales for reasons of depletion of supply
or uneconomical production, but generally not for other reasons. In addi-
tion, the FPC has required pipelines to continue purchasing gas -- even at
I/ E.g., (1) FPC Opinion No. 574-A issued May 8, 1970 in re Transwestern
Pipeline Co. et al. (CP*7-22Q et al.); FPC order issued January 6,
1971 in re Columbia Gulf Transmission Co. et al. (CP71-77 et al.).
2/ Sunray Mid-Continent Oil Co. v. FPC, 364 U.S. 137 (1960).
TV-37
-------
higher rates filed unilaterally by the sellers upon contract expiration --
which the producers must continue to sell.—
During the past year, the FPC has granted substantial rate
increases to one producer to continue sales which the producer had sought
2/
to abandon because of economic infeasibility.— Certain other abandon-
ment applications have been set for formal hearing to determine what
prices might be necessary to permit continuation of sales on an economic
basis.
In addition, the FPC is now considering a proposal to grant
relief from area rate ceilings for sales from reservoirs where a reduction
in pressure, a need to recondition wells or a need for deeper drilling
makes further production uneconomic at existing prices. The objective
of the proposal is to provide producers with an alternative to seeking
abandonment for economic reasons under Section 7(b) of the Natural Gas Act.
E. Interconnection of Facilities
As previously indicated, Section 7(a) of the Act empowers the
FPC to direct a pipeline company to extend or improve its transportation
facilities, and to establish physical connection with and sell gas to any
I/ A case involving this issue arose in the early 1960's, a time of more
abundant supply, when an interstate pipeline sought to discontinue
purchases at a unilaterally increased rate filed by the producer-seller
after expiration of their contract. The FPC held that the power to
compel continuation of sales would be meaningless without the correla-
tive power to compel the continuation of purchases. FPC Opinion No.
426, in re Continental Oil Co. (CI63-979), issued May 5, 1964;
affirmed by U.S. Supreme Court on 11/14/66 in United Gas Pipe Line Co.
v. FPC, Oct. Term 1966, No. 49.
2/ FPC order dated June 14, 1972 in re Banquete Gas Co. (CI68-703).
IV-38
-------
company or municipality legally authorized to engage in the local distribu-
tion of gas. However, it is expressly provided that the Commission does
not have authority to compel the "enlargement" of transportation facilities
or the establishment of physical connections and sales if the result would
be to impair a pipeline's ability to render adequate service to its cus-
tomers .
Over the years, the FPC has granted numerous requests by munici-
palities and other distributors for orders directing service by an
adjacent or nearby pipeline. Until the last few years, many of these
requests were unopposed by the pipeline involved. Where there was opposi-
tion by the pipeline or some other party, the FPC considered the extent of
the facilities required by the pipeline to establish connection, the
economic feasibility of the proposal, and the impact of the requested
service on the pipeline's operations in determining whether to order
physical connection and sale of gas.
In the past two years or so, greater opposition has developed
to the granting of Section 7(a) requests for allocations of gas, particu-
larly where the gas would be used to service industrial customers, because
of the shortage of supply. Several pipelines have contended that they
should not be required to attach new loads under Section 7(a) when they
have insufficient gas to meet incremental needs of existing customers.
The FPC has accepted this argument in certain recent cases, ruling that
approval of Section 7(a) requests would impair the pipeline's ability to
render adequate service to existing markets.
IV-39
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F. End-Use Regulation
In view of the increasing shortage of gas supply and suggestions
that the FPC allocate available supply by end-use, a brief review of the
Commission's powers and past policies in this area may be useful.
Generally, questions of end-use have arisen in connection with
direct industrial sales by pipelines (or by producers, with transportation
provided by an interstate pipeline to the ultimate user) for boiler fuel.—
The FPC has no authority directly over direct industrial sales. However,
it does have certificate authority over the transportation of gas in inter-
state commerce, whether for direct sale or sale for resale, and over the
construction of facilities to transport gas in interstate commerce. Thus,
through this means, the Commission may prevent -- and has done so on a
number of occasions -- the direct sale of gas by pipelines for industrial
uses deemed contrary to the public interest.
Over the years, the FPC has had no uniform policy concerning the
usage of gas for boiler fuel or other industrial purposes --to the extent
it could control such usage through its certificate authority. Many
certificates have been issued to pipelines for the construction of facili-
ties to transport gas destined for sale to electric utilities and others
for the generation of electricity. For example, much of the pipeline
capacity serving the Florida market was authorized for the purpose of
transporting gas purchased directly in Texas and Louisiana by the two major
electric utilities in Florida, their usage of capacity being considered the
I/ Pipelines also make sales on both a firm and interruptible basis to
distributors for resale to industrial users.
IV-40
-------
only means of rendering gas service economically feasible to residential
and commercial customers in the State of Florida. In other instances,
however, certificates have been denied by the FPC for transportation of
boiler fuel gas.
Four examples of such denial are notable.
(1) In 1959, in a decision eventually upheld by the Supreme
Court, the FPC denied a certificate to Transcontinental Gas Pipe Line Corp.
for construction of facilities to transport 50,000 Mcf/d of gas purchased
in Texas by Consolidated Edison Co. of New York for exclusive use as boiler
fuel in New York City. The Commission concluded that the contemplated use
of gas for boiler fuel constituted an "inferior usage," that the project
would preempt pipeline capacity otherwise available to serve "more urgent
and widely beneficial public needs," and that the direct purchase-sale type
of proposal would tend to exert an upward pressure on the price of gas in
the field.— After considerable litigation, including reversal by the
Third Circuit Court of Appeals, the Supreme Court held that the FPC had
discretion to consider all of these factors in determining whether or not
to issue a certificate.—'
(2) Also in 1959, the FPC denied authorization to El Paso
Natural Gas Co. to transport 100,000 Mcf/d for direct sale to Southern
California Edison Co. for boiler fuel use. Instead, El Paso was directed
to sell the gas to the two major distributors serving Southern California
V FPC Opinion No. 315, issued January 30, 1959 in re Transcontinental
Gas Pipe Line Corp. (G-13143 et al.) ; 21 FPC 138.
2/ FPC v. Transcontinental Gas Pipe Line Corp., 365 U.S. 1 (1961).
IV-41
-------
for resale. The FPC held that the proposed direct sale would result in
committing too large a portion of El Paso's pipeline capacity to one
type of use, would tend to exert upward pressures on field gas, and
would preclude state and local authorities from determining how the gas
could best be used in the Southern California area as a whole.—
(3) In 1966, the FPC rejected a proposal by Gulf Pacific
Pipeline Co. to build a new 1400-mile large diameter line, estimated to
cost over $300 million, in order to transport 865,000 Mcf/d from the Texas
Gulf Coast area to Los Angeles for use as boiler fuel by Southern California
Edison Co. and the Los Angeles Department of Water and Power.— At the same
time, however, the Commission authorized a competing proposal by the two
existing pipelines serving the Southern California market to increase
deliveries to the local distributor. The Gulf Pacific project was rejected
on the grounds that it would impede the conversion of present gas burning
electric generating plants in the Los Angeles area to nuclear and other
fuels; result in detrimental competition for the local gas distributor;
and encourage producers to withhold large blocks of gas from the interstate
market in order to make nonjurisdictional sales at higher prices. The FPC
also concluded that use of the entire Gulf Pacific volume for boiler fuel
would have no appreciable effect in alleviating Los Angeles' air pollution
problem. Subsequently, virtually all of the gas dedicated to Gulf Pacific
-- over 6 trillion cubic feet -- was sold intrastate; the bulk of this gas
I/ FPC Opinion No. 333 issued November 27, 1959 in re El Paso Natural Gas
Co. (G-12580); 22 FPC 900.
2/ FPC Opinion No. 500 issued July 26, 1966 in re Transwestern Pipeline
Co. et al. (CP63-204 et al.) ; 36 FPC 176.
IV-4 2
-------
is probably now being consumed under steam-electric plant boilers or in
other industrial operations in the State of Texas.
(4) In 1972, the FPC denied an application by El Paso Natural
Gas Co. to transport 32,000 Mcf/d of gas purchased by Arizona Public
Service Co. for use as boiler fuel in certain electric generating plants
in the Phoenix area. As in the cases above, the Commission stressed
that the project, if approved, would encourage producers to reserve
large packages of gas for direct sale to the highest bidder, with an
adverse impact on both the amount and price of gas available for inter-
state resale markets. The FPC also cited the proposed usage of the gas
as a factor against certification.—
The above decisions reveal some inclination on the part of the
FPC to regard the use of gas for boiler fuel as inferior compared with
residential and commercial use. In no case, however, did the FPC find
that boiler fuel usage in the situations involved would make any signifi-
cant contribution toward reducing air pollution. Rather, as indicated,
other factors entered into the Commission's decisions, in particular the
impact of direct sales on prices of gas in the field.
Recently, the end-use question has arisen again in connection
with federal offshore gas which producers seek to have transported by
interstate pipelines for use in onshore refineries and chemical plants,
partly as boiler fuel and partly as feedstock or fuel in processing
operations. While pipeline transportation arrangements for producers
I/ FPC Opinion No. 615 issued March 22, 1972 in re El Paso Natural Gas
Co. (CP71-234).
IV-4 3
-------
are not new and have been approved in the past, the gas shortage situation
has led distributors (and certain state commissions) in Eastern Seaboard
states to claim that federal offshore supply should be reserved for inter-
state resale markets and not diverted to local industrial use.
In the first contested case where this claim was advanced, the
FPC decided to approve the proposed transportation of offshore gas to a
producer refinery in Mississippi on the ground that the ability of a pro-
ducer to use its own gas in refinery and chemical plant operations would
provide incentive to explore for and develop additional gas reserves,
part of which will be excess to the producer's requirements and hence
will become available for sale to the interstate market.— This decision
was upheld last May by the Court of Appeals for the D.C. Circuit which
agreed that the desirability of providing incentive to seek additional
2/
supplies outweighed any considerations of end use.—
The same issue is now pending in another FPC proceeding where
three pipelines are seeking authority to transport Federal Domain gas
reserved by certain producers for their own use in onshore facilities.
Questions to be resolved by the FPC include: whether the proposed use of
the gas in producer refineries and petrochemical complexes is superior or
inferior to the use which would be made of the gas by interstate pipeline
customers (many of whom resell large volumes to industrial users); the
degree to which the proposed use actually creates incentive for further
V FPC Opinion No. 560-A, issued December 31, 1970 in re Chandeleur
Pipeline Co. (CP69-76), 44 FPC 1747.
2/ PSC of New York v. FPC, CADC, No. 71-1197, issued May 16, 1972.
IV-44
-------
exploration and development; and whether denial of the transportation
certificates would impede the development of offshore sources of supply
by other producing interests. These questions involve both the stimula-
tion of additional supply and the allocation of existing supply.
G. Curtailments
A corollary to end-use regulation is the authority of the FPC to
control curtailments and allocation of supplies available to pipeline com-
panies . These matters have cropped up on various occasions in the past,
but they have assumed critical importance in the last few years as a
result of plans submitted by nearly all major pipelines for curtailing
deliveries in the event of insufficient supply to meet contractual obliga-
tions. The basic problem presented to the FPC is to provide for a fair
allocation of supplies among all customers of an interstate pipeline in
times of gas shortage.
The scope of the FPC's jurisdiction was contested in the first
curtailment proceeding -- involving United Gas Pipe Line Co. -- to come
before it in recent years. As noted in the previous section, the FPC has
no authority directly over sales by pipelines to direct industrial customers.
Citing this absence of authority, a group of United's direct industrial cus-
tomers contended that the FPC had no power to approve plans for reducing
sales to direct customers below contract quantities. The Commission claimed,
on the other hand, that it had authority to control curtailments, and hence
allocation of supplies, to both direct and resale customers by virtue of its
jurisdiction over transportation of gas in interstate commerce and its power
IV-4 5
-------
under Sections 4 and 5 of the Natural Gas Act to prohibit discriminatory
practices. The FPC's position was rejected by the Fifth Circuit Court of
Appeals which held that the Commission's jurisdiction was confined to
initial certification and to abandonment of facilities used to make
direct sales, with no continuing jurisdiction between these two functions.—
Because of the importance of this issue, the FPC requested --
and was granted -- expedited review of the Fifth Circuit decision by the
Supreme Court. In an opinion handed down on June 7, 1972, the Supreme
2/
Court ruled in favor of the Commission.— Specifically, the Court held
that the FPC's authority over gas transportation gives it power to approve
curtailment of deliveries to direct sales customers, and that language in
the Natural Gas Act exempting direct sales from regulation applies only to
rate authority and not to transportation authority. Among other things,
the Supreme Court pointed out that if a pipeline's direct industrial sales
were wholly exempt from any curtailment plan approved by the FPC, the com-
pany's resale customers would be forced to bear the entire burden of reduced
deliveries. In the case at hand, the Court found the evidence to show that
this burden could not be borne by resale customers alone without jeopardizing
service to homes, schools, hospitals and other such customers. The Supreme
Court further observed that a seriously inequitable system of gas distribu-
tion would result if direct industrial customers could demand full contract
_!/ Louisiana Power 5 Light Co. v. United Gas Pipe Line Co., C.A. 5, No.
71-2550, decided January 14, 1972.
y FPC v. Louisiana Power 5 Light Co., U.S. Supreme Court, No. 71-1016,
Hecided June 7, 1972.
IV-4 6
-------
volumes at the same time that homes, hospitals and schools suffered from
inadequate service.
The significance of the Supreme Court's holding is illustrated
by the fact that, to date, 28 pipelines have filed curtailment plans for
FPC approval.— These pipelines include all major interstate transmis-
sion companies in the U.S. except Tennessee Gas Pipeline and Transwestern
Pipeline Co. Moreover, eight pipelines were forced to curtail sales made
on a firm basis during the year ended March 31, 1972, and 15 pipelines
project firm delivery curtailments in an aggregate amount of about one
trillion cubic feet during the year ending March 31, 1973. The one
trillion cubic feet represents close to 10% of the total annual sales
made by the 15 companies in 1970.
Table IV-2 on the following page depicts the extent of curtail-
ment of firm service experienced and projected by individual pipelines in
reports submitted to the FPC. The company with the most severe supply
deficiency is United Gas Pipe Line. This deficiency, in turn, accounts
for much of supply shortfall experienced by Texas Eastern Transmission,
a major pipeline customer of United, and by Algonquin Gas Transmission
Co., supplied entirely by Texas Eastern. United's difficulties have also
contributed to the supply problems of other pipelines which it serves.
I/ Most of these plans were filed in response to FPC Order No. 431,
issued April 15, 1971, directing jurisdictional pipelines to take
all necessary measures to protect adequate and reliable service,
including (a) consideration of curtailment of all interruptible
and large boiler fuel sales where alternate fuels were available,
and (b) submission of reports regarding present or proposed cur-
tailment procedures.
IV-47
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FIRM REQUIREMENT DEFICIENCIES REPORTED
BY INTERSTATE PIPELINES TO FPC STAFF
TABLE IV-2
Company
Actual Projected
April 1971- April 1972-
March 1972 March 1973
(Bcf)
Algonquin Gas Transmission Co.
Arkansas Louisiana Gas Co.
Cities Service Gas Co.
Colorado Interstate Gas Co.
Consolidated Natural Gas System
Eastern Shore Natural Gas Co.
El Paso Natural Gas Co.
Mississippi River Transmission Corp.
Natural Gas Pipeline Co. of America
Northern Natural Gas Co.
Panhandle Eastern Pipe Line Co.
Texas Eastern Transmission Corp.
Transcontinental Gas Pipe Line Corp.
Trunkline Gas Co.
United Gas Pipe Line Co.
2.1
75.2
38.0^
None
None
None
None
None
83.9^
None
18.7
88.1
43.4
154.3
13.5
149.1
28.0^
1.8
0.1
33.1
2.1
149.8
6.3
25.5
90.9
96.2
97.6
348.4
a/ Described by the company as "normal."
F/ Alternate lower figures were also reported.
£/ Summertime curtailments.
Note: These figures should not be added because of duplications among
companies.
Source: Speech of FPC Chairman John Nassikas to INGAA Convention in
Puerto Rico, October 24, 1972, Table 1.
IV-4 8
-------
Six companies account for over 87% of the total projected
deficiency for the year ending March 31, 1973: United Gas Pipe Line Co. ,
Natural Gas Pipeline Co. of America, Arkansas Louisiana Gas Co. Trunkline
Gas Co., Transcontinental Gas Pipe Line Corp. and Texas Eastern Transmis-
sion Corp. Leaving aside Arkansas Louisiana which primarily serves the
State of Arkansas, the impact of firm delivery curtailments will be felt
largely in Eastern Seaboard and Midwest gas markets.—
Because of sales between pipelines and the chain effect of a
deficiency for one pipeline company in causing a deficiency for others,
the figures in Table IV-2 overstate the total impact of firm sale cutbacks
experienced by pipeline customers. On the other hand, the figures do not
reflect curtailment of interruptible industrial sales which have been
drastically reduced in the case of some companies. For example, Mississippi
I/ The specific geographic areas served by the six pipelines are as follows:
United Gas Pipe Line: Southern Louisiana, Southern Mississippi,
Southern Alabama, Northwest Florida.
Natural Gas Pipeline Co.: primarily the Chicago area, including
nearby communities in Indiana and northern Illinois.
Arkansas Louisiana: Northern Louisiana, Arkansas, northeast
corner of Texas.
Trunkline Gas Co.: A corridor extending northeasterly through
Louisiana, northwestern Mississippi, western Tennessee, south central
Illinois, northwestern Indiana and Michigan.
Transcontinental Gas Pipe Line: A corridor extending north-
easterly from the Texas Gulf Coast across southern Louisiana,
Mississippi, Alabama, and then northward through Atlanta, Winston-Salem,
Washington, B.C., Baltimore, and Philadelphia to New York City.
Texas Eastern Transmission: A corridor extending from the Texas
Gulf Coast across southern Louisiana, Mississippi, central Tennessee
and Kentucky, southeastern Ohio, southern Pennsylvania, New Jersey and
into New York City. Algonquin, a Texas Eastern affiliate serves
southern New England, including the Boston area.
IV-49
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River Transmission Corp., which forecasts a deficiency in firm gas supply of
only about 2.1 billion cubic feet for the year ending March 31, 1973, has
advised that it plans no interruptible sales at all during the 1972-1973
winter months. Historically, more than half of Mississippi's mainline
industrial sales have been interruptible. It should also be kept in mind
that virtually all major interstate pipelines, whether or not they have
found it necessary to invoke curtailments, have instituted partial or com-
plete restrictions on new sales and/or on increased sales to existing custo-
mers.
The substantial impact of the gas shortage on the interruptible
segment of the gas market -- consisting primarily of sales to electric
generating plants and other large industrial customers with facilities to
burn alternate fuels --is further revealed by the curtailment plans which
have been filed by interstate pipelines with the FPC. The nature and
status of these plans are summarized on Table IV-3. While provisions
vary depending upon the composition of the markets served by each pipeline
(interruptible versus firm, direct versus resale, industrial versus residen-
tial and commercial), the plans are generally of two types: those providing
for curtailments according to end-use categories, and those providing for
ratable curtailments of all deliveries. However, most of ratable curtail-
ment plans would be implemented only after cutoff of all interruptible
sales. The majority of the end-use programs similarly accord lowest
priority to interruptible usage and to large volume industrial usage,
particularly where alternate fuels can be used.
IV-50
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CURTAILMENT PROVISIONS AND PLANS FILED BY INTERSTATE PIPELINES WITH FPC
Pipeline
Dace Plan
Filed
Plan Implemented
Description of Curtailment _P_lan _
FPC Status
Algonquin Gas Transmission Co.
(RP7L-131)
May 1971 Curtailments began In Decem- Prorata reduction of deliveries.
her 1971. Rate of curtail-
ment depends on degree of
curtailment by Texas Eastern
Transmission Corp. Antici-
pated curtailment rate in
1972-1973 is 10%.
Settlement conferences to go forward upon resolu-
tion of curtailment procedures of Texas Eastern
Tr ansrolssi on , Algonquin ' s sole suppl ier .
Alabama-Tennessee Natural Gas Co. May 1971
(RP71-138)
Arkansas Louisiana Gas Co.
(RP71-122)
May 1971
Bluefield Gas Co.
(RP72-94)
Cities Service Gas
(RP71-129)
Colorado Interstate Gas Co.
(RP71-135)
October 1971
May 1971
May 1971
(RP72-122)
Columbia Gas Transmission Co,
(RP72-89)
May 1972
No Prorata reduction of deliveries, after curtailment of
all interruptible sales first. (Existing tariff pro-
vision. )
Curtailments began In October End-use curtailment, as follows (from Lowest priority
1971 . Estimated race is
approximately 150 Bcf per
year .
Projects curtailment of 28
Bcf in year ending March
1973.
Projects curtailment of 1.8
Bcf in 1972-1973 winter.
December 1971 No
Under analysis by FPC Staff.
Hearings held In July and August 1971. Rejec-
tion of plan recommended by an FPC Examiner in
October 1971 due to possibility of discrimina-
tory and preferential application. Plan is now
pending FPC decision.
Under analysts by FPC Staff.
to highest):
(a) all Incorruptible sales
(b) large volume industrial sales where alternate
fuels can be used
(c) large volume Industrial sales where alternate
fueIs cannot be used
(d) small industrial and commercial sales
(e) sales to residential and other "human needs"
customers.
End-use curtailments, as follows (from Lowest priority
to highest):
(a) Interruptible service
(b) "curtailable" service
(c) remaining industrial service
(d ) service to domestic and other "human needs"
customers .
End-use curtailment of interrupt ible deliveries (Large
volume sales for electric generation, smaller volume
sales for electric generation, sales to direct con-
sumers and utilities, sales to commercial customers),
followed by "simultaneous and equitable" curtailment
of firm deliveries.
End-use curtailment, as follows (from lowest priority
to highest) :
(a) Interruptible service, direct and resale
(b) firm service to resale customers for Interruptible
industrial use
(c) firm service to direct and resale customers for
firm industrial use
(d) firm service for domestic and commercial use
(Existing tariff provision.)
Curtailment of deliveries for use by or resale Co Inter- Suspended until October L, 1972.
ruptible customers. Plan also provides for meeting of
firm growth needs before allocation of any supply for
Interrupclble requirements.
Under analysis by FPC Staff.
Approved by FPC In September 1971.
Ratable curtailment of all firm deliveries (except to
small general service distributor customer), but with
pre ference to res identlal and coane re la L customers .
Interim settlement agreement provides for exemption of
volumes required to maintain firm non-industrial
customer Loads (subject to certain conditions) with
surcharges up to $L.b5/Mcf for such exempted volumes.
Interim settlement offer approved by FPC in
October 1972.
-------
CURTAILMENT PROVISIONS AND PLANS FILED BY INTERSTATE PIPELINES WITH PPC
Pipeline
Date Plan
Filed
Plan Implemented
Description of Curtailment Plan
FPC Status
Consolidated Gas Supply Corp.
(RP72-67)
October 1971
Eastern Shore Natural Gas Co.
(RP72-21)
El Paso Natural Gas Co.
(RP72-6)
Lone Star Gas Co.
(RP72-15)
Mid-Louisiana Gas Co.
(RP71-139)
August 1971
July 1971
Florida Gas Transmission Co. May 1971
(RP71-128)
Granite State Gas Transmission Hay 1971
(RP71-116)
Great Lakes Gas Transmission Co. May 1971
(RP71-134)
May 1971
Louisiana-Nevada Transit Co. July 1971
(RP72-13)
Michigan Wisconsin Pipe Line Co. May 1971
(RP71-117)
May 1971
Projected curtailment: of
24 Bcf in year ending
March 31, 1973.
Relatively small curtailment
(83 MMcf) anticipated in
1972-1973 winter season,
End-use curtailments, as follows (from lowest to highest Formal hearing reconmended by FPC Staff.
priority):
(a) Indus trial uses which can be converted to alternate
fuel
(b) "critical" industrial uses which cannot be feasibly
converted to alternate fuel
(c) industrial usage less than 60 MMcf per year
(d) domestic and commercial use.
End-use curtailments, as follows (from lowest to highest Approved by FPC In November 1971.
priority):
(a) interruptible service (including sales to resale
customers for Interruptlble use)
(b) firm service to d irec t pipe 1ine custoners
(c) firm service for industrial use (except small
volume industrial use)
(d) firm service to resale and small industrial
customers.
Projects curtailment of 90 End-use curtailments, as follows (from lowest to highest Interim curtailment plan prescribed by FPC in
Bcf during year beginning priority): October 1972 at El Paso's request. Permanent
November 1, 1972, averaging (a) direct industrial sales above firm capacity curtailment plan pending decision.
247,000 Mcf/d. (b) direct and resale sales for industrial use
(c) sales for commercial use
(d) domestic and residential use.
No . End-use curtailment of four classes of interruptlble Under analysis by PPC Staff.
custoners, followed by ratable curtailment of firm
deliver ies . (Existing tariff provision.)
No Ratable curtailments, but with preference to residential Accepted for filing.
and commercial customers.
No Ratable curtailment of deliveries. Under analysis by FPC Staff.
No End-use curtailments, as follows (from lowest to highest Under analysis by FPC Staff.
priority):
(a) oil field sales
(b) direct interruptible sales
(c) residential and commercial service.
No Ratable curtailment of firm deliveries (although with Rejection of plan recommended by FPC Examiner in
priority to domestic users), after curtailment of all February 1972. proceeding remanded by FPC in
Interruptlble deliveries. October 1972.
No
Ratable curtailments, except that seller may first
require buyers to reduce or discontinue interruptible
loads In excess of 200 Mcf/d. (Existing tariff provi-
sion.)
Approved by FPC in September 1971.
End-use curtailments, as follows (from lowest to highest Approved by FPC In April 1972.
priority):
(a) interruptible customers
(b) industrial usage
(c) domestic consumption.
*g
ro
o 3
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CURTAILMENT PROVISIONS AND PLANS FILED BY INTERSTATE PIPELINES WITH FPC
Pipeline
Date Plan
Piled
Plan Implemented
Descr ipc ion of Curtailment Plan
FPC Status
Mississippi. River Transmiss ion
(RP73-6)
July 1972
Natural Gas Pipeline of America
(RP70-42)
Northern Natural Gas Co.
(RP71-107)
June 1*70
April 1971
Panhandle Eastern Pipe Line Co.
(RP71-119)
Shenandoah Gas Co.
(RP71-UI)
Southern Natural Gas Co.
(RP72-74)
Texas Eastern Transmission Corp.
(RP71-130)
Texas Gas Transmission Corp.
May 1971
Projects firm cur tailments
of 6.5 Bef during year
ending March 1973.
Voluntary curtailments of
11.3 Bcf in 1970 . Curtail-
ment of 183 Bcf for 12
months ended August 1971.
Total curtailment of 167 Bcf
forecast for following year.
Projected curtailments of
2.3 Bcf in summer of 1971
and 6.3 Bcf in summer of
1972.
End-use curtailments, as follows(from lowest to highest Hearings began in October 1972.
priority):
(a) sales for electric generation
(b) direct interruptible industrial sales
resale interruptible industrial sales
Projected curtailments of
16,6 Bcf through March 1972
and 25.5 Bcf for year
ending March 1973.
June 1971
November 1971 No
May 1971 Curtailments conroenced at
rate of 100,000 Mcf/d in
December 1971. Beginning
in May 1972, anticipated
curtailment rate is
250,000 Mcf/d (or 10%).
May 1971 No
(c)
(d)
(e)
(f)
firm industrial deliveries exceeding 1 ,000 Mcf /d
firm industrial deliveries less than 1,000 Mcf /d
remaining resale service.
Ratable curta llments , after voluntary relinquishnents
by larger cus comers .
Discontinuation of interruptible deliveries for large
volume consumers (specifically, 12 electric generating
plants) using over 25,000 Mcf/d equivalent, with ratable
curtailment thereafter up to 15% of contract demand in
April and October and up to 30% of contract demand in
months of May through September. Subsequent settlement
offer provides for end-use curtailment of sales for
electric generation and large volume Interruptible
sales in winter months, and ratable curtailment up to
15% of contract demand in summer months -- with any
further curtailments to be made according to winter plan.
Ratable curtailment of industrial sales and sales for
electric generation, d irect and resale. "Human needs"
and small resale customers are exempt.
End-use curtailments, with highest priority to domestic
customers. (Existing tariff provision.)
End-use curtailments, as follows from lowest to highest
priority):
(a) sales to electric generating plants with alternate
facilities
(b) interruptible sales
(c) firm industrial sales
(d) remaining sales.
Ratable curtailment of all deliveries. Interim settle-
ment proposal exempts small customers and provides for
exemptions for other buyers to extent required to pro-
tect residential and commercial loads.
Ratable curtailment of all sales in proportion to
quantity entitlements determined for each customer in
winter and summer periods. Interim settlement agree-
ment provides for 100% curtailment of Interruptible
requirements before any curtailment of firm require-
ments .
Settlement approved by FPC in November 1971.
Settlement offer approved by FPC in October
1972.
Interim curtailment plan (essentially apportion-
ing two-thirds of curtailment volumes to resale
customers and one-third to direct industrial cus-
tomers) approved by FPC in November 1971. Exten-
ings on permanent curtailment plan held from
November 1971 to August 1972. Plan awaiting
Examiner's decision.
Under analysis by FPC Staff.
Hearings began in March 1972.
Interim settlement proposal (extending to September
1973) pending before FPC.
Interim settlement agreement (extending through
April 1973) approved by FPC in June 1972.
-------
CURTAILMENT PROVISIONS AND PLANS FILED BY INTERSTATE PIPELINES WITH FPC
Pipeline
Dace Plan
Filed
Plan Implemented
Description of Curtailment Plan
FPC Status
Transcontinental Gas Pipe Line
(RP71-H8)
(RP72-99)
May 1971 Curtailments commenced in
June 1971 and have ranged up
to 121 or more of firm
deliveries at various tines.
Trunkline Gas Co.
(RP71-100)
United Gas Pipe Line Co.
(RP71-29,
RP71-120)
January 1972 Projected curtailments of
95 Bcf in year ending March
1973.
April 1971 Curtailments began in winter
1971. Projected total cur-
tailment of 50 Bcf through
March 1972 and 98 Bcf in
year ending March 1973.
October 1970 Curtailments began in Novera-
(revised in ber 1970. Curtailments
Moy 1971) totalled 156 Bcf In year
ending March 1972. Pro-
jected curtailments of 348
Bcf In year ending March
1973.
Curtailment of all Interruptible sales , followed by
ratable curtailment of firm deliveries (except small
volume customers). Interim one-year settlement plan
provided for par c la I or complete exemptions from cur-
tailments In winter months to extent required to pro-
tect firm markets, with such exemptions to be balanced
out by reduced takes on other days.
Curtailment of all Interruptible sales, followed by
ratable curtailment of firm deliveries (except small
volume cus toners) but with exemptions from curtail-
ments In winter months if required for protection of
firm markets. Supplemental procedure provides for
end-use curtailments (oil Interruptible markets first)
in winter months.
End-use curtailments, as follows (from lowest to highest
priority):
(a) interruptiblc sales
(b) large volume firm sales
(c) Email volume firm sales
End-use curtailments, as follows (from lowest to highest
priority):
(a) direct Industrial and power plant sales at rates
lower than applicable city gate zone rates at 100%
load factor
(b) sales for Indus trial end-use (except "process use") ,
including gas used to generate electricity for
industrial purposes
(c) gas used to generate electricity for domestic con-
sumers
(d) sales to Industrial customers for "process use"
(e) gas used by domestic consumers.
InterIm settlement (extending to November 1972)
approved by FPC in November 1971.
Further interim settlement (extending to
November 1973) approved by FPC in November 1972.
Under analysis by FPC Staff.
Various interim curtailment plans approved by
FPC. FPC asserted Jurisdiction over pipeline
curtailments In October 1971 (Opinion 606).
Jurisdiction upheld by Supreme Court In June
1972. FPC rejected lowest priority category
proposed by United and remanded other Issues
concerning implementation of plan to Examiner
for initial decision. Examiner approved plan
in July 1972 subject to subdivision of d ones tic
consumer category Into residential and commer-
cial groups, and higher priority for gas used
to generate electricity for domestic loads than
for "process use" Industrie I gas.
£g
X) &
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H. Imports and Exports
Exportation and importation of gas into the United States require
FPC approval under Section 3 of the Act.
At the present time, exports of gas from this country are rela-
tively insignificant, amounting only to 30 billion cubic feet in 1971 (com-
pared with imports of 932 billion cubic feet). This figure does not
include exportation of approximately 50 billion cubic feet annually of LNG,
begun in 1969, by Phillips Petroleum Co. and Marathon Oil Co. from Alaska
to Japan.
Imported gas is derived from two principal sources: by overland
pipeline from Canada, and by tanker in liquefied form from overseas nations.
In addition, some LNG has been imported on a spot basis via tanker trailer
from Canada. However, the volumes involved here are extremely small, and
such shipments are not considered to constitute anything more than sporadic
supplies available from time to time to meet peak day needs in certain
localized markets (principally in New England). The U.S. also currently
imports some gas from Mexico but, here again, the volumes are now, and are
expected to remain, insignificant.
Pipeline imports of gas from Canada commenced in the early 1950's
but were exceeded by exports to Canada until 1958. Since that time, net
imports from Canada have risen from about 56 billion cubic feet to 897
billion cubic feet in 1971, representing about 3.91 of total U.S. consump-
tion (excluding Alaska) in that year. Substantially increased imports from
Canada would be a highly desirable means of supplementing U.S. gas supply.
However, the extent of any further increase is subject to two major
IV-55
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uncertainties: the current export policy of the Canadian National Energy
Board (which will approve export of only those surplus volumes determined
to exceed the reserves needed to maintain the level of current Canadian
market requirements for almost 30 years in the future), and the magnitude
of future discoveries in Canada.
LNG imports by tanker commenced on a spot basis for peak shaving
(extreme cold day) needs in 1968. To date, the import volumes have been
very small. However, two long-term projects have been authorized by the
FPC in the past year. Several more projects are proposed. The degree to
which such projects will supplement U.S. gas supplies in the coming years
will depend both on the regulatory approach followed by the FPC and on
policies adopted by other regulatory bodies.
1. Pipeline Imports from Canada
Gas moved across the international border into the U.S. requires
not only import authorization from the FPC but also export authorization
from the Canadian National Energy Board.— Also, authorization must be
obtained from the Alberta Energy Resources Conservation Board for the
removal of gas from the Province of Alberta, the major producing region
in Canada to date.
Beginning in 1955 with the issuance of authority to Pacific
Northwest Pipeline Co. (subsequently merged by El Paso Natural Gas Co.)
to import and authority to Westcoast Transmission Co. Ltd. to export
300,000 Mcf/d at a point on the United States-Canadian boundary near
V All export licenses granted by the National Energy Board are subject
to the approval of the Governor-in-Council.
IV-56
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Sumas, Washington, several major blocks of gas have been licensed for
import and export. The volumes involved have been largely for consump-
tion in U.S. markets in Northern California, the Pacific Northwest and
the Upper Midwest area (Minnesota, Wisconsin and Michigan). Some volumes
also flow to Montana, New York and Vermont.
While different considerations were apparent on the two sides
of the border, no serious conflict between the FPC and NEB in regard to
export-import policies developed until 1967. In that year, the two regula-
tory bodies were presented with a proposal involving an increase in imports
by El Paso from Westcoast Transmission at the Sumas border point from the
300,000 Mcf/d level authorized in 1955 to 500,000 Mcf/d. In addition,
Westcoast and El Paso agreed to a contract price of 27.0<£/Mcf for the
entire volume, thus representing a 5<£ increase over the previously author-
ized 22$ rate for the initial import volume of 300,000 Mcf/d. The 22f
rate was said to have been negotiated under distress conditions in 1954
and to be no longer realistic in view of current market conditions. The
NEB approved the new contract in April 1967. Thereafter, on August 10,
1967, the FPC approved the additional imports -- but subject to the condi-
tion that the existing imports of 300,000 Mcf/d continue at 22<£ and the
incremental imports of 200,000 Mcf/d be priced at 29.5
-------
"The importance of price scrutiny takes on added signifi-
cance in view of the possible availability of additional
volumes of Canadian gas for U.S. markets. It is only fair
to alert both United States and Canadian interests at an
early time that gas imports into the United States will not
be approved at unjustifiably high prices." (38 FPC 319)
The FPC decision necessitated reapplication by Westcoast to the
NEB for export authority under the conditions imposed by the Commission.
The NEB denied this authority on December 22, 1967. In so doing, the NEB
announced three criteria for determining whether a proposed price for
export of gas is in the public interest, namely, the price must (a)
recover the appropriate share of costs incurred by the Canadian transmis-
sion company, (b) not be less than the price to Canadian customers in the
general area of the proposed export, after allowance for variations in the
terms of delivery, and (c) approximate the least cost alternative for
energy from indigenous sources in the United States market area. In applying
the third test, the NEB found the price of the export gas to be at least 4.5$
below domestic U.S. gas available to El Paso from the San Juan Basin, and
hence unacceptable. The NEB also made clear its position that the so-called
"in-line" pricing theory applied by the FPC for evaluating border prices was
totally inconsistent with the Canadian public interest.
The impasse created by the above decisions was resolved a few
months later when both the FPC and Canadian Government accepted a proposed
settlement providing for sale of the incremental import volume of 200,000
Mcf/d at 30.5
-------
More recently, the price issue has assumed a secondary role with
Canadian denial of several export licenses due to a lack of surplus gas.
The NEB's policy is to approve for export only those volumes
which are deemed excess to the quantities required to meet the estimated
level of Canadian consumption four years ahead for 25 years. Such excess
volumes are designated as "current surplus" available for export. In
September 1970, the NEB calculated an insufficient current surplus to meet
all then pending export applications. As a result, it granted export
requests by four existing transmission companies -- although with reduced
terms and other conditions -- and dismissed entirely a new export project
mounted by Northern Natural Gas Co. to bring Alberta gas to its system in
Minnesota. The NEB explained as follows:
"In the present circumstances where surplus is not adequate
to support all the applications before the Board, nor the whole
of the applications of already established transmission systems,
the establishment of a new transmission project oriented wholly
to export, founded on the cost of service concept, and so
devised that its future development would almost inevitably
result in decreasing border prices in a period when such gas
as may become surplus to Canadian requirements will be increas-
ingly valuable, would not appear to the Board to serve the
public interest of Canada."
Subsequently, on November 19, 1971, the National Energy Board
rejected a renewed bid by Northern Natural for export authority, together
with two other export requests then pending. Together, the rejected
applications involved an export total of close to a half billion cubic
feet a day and over two and a half trillion cubic feet over the projected
license terms of 15 and 20 years. The NEB cited the lack of any current
surplus available for export. In fact, in view of rapidly increasing
IV-59
-------
Canadian demand for gas, the NEB calculated a current deficiency of
nearly 1.1 trillion cubic feet for purposes of satisfying its 25- to 30-
year protection standard for Canadian requirements.
The NEB's current surplus calculation did not take into account
reserves in Canadian frontier areas where estimates of potential reserves
are relatively large. Several of these areas are under active exploration
at the present time, although there is little definitive information to
date respecting the magnitude of announced reserve discoveries. Without
substantial new reserve additions in Canada, it appears highly unlikely --
given the NEB's current approach to determining exportable surplus -- that
there will be any appreciable increase in U.S. imports of Canadian gas in
the future. In fact, as current export license terms expire, the quantities
of imported gas could decrease from established Canadian producing areas.
The prospects for increased supplies of Canadian gas will be
discussed further in Chapter V.
2. LNG Imports by Tanker
FPC regulation of imported gas in liquefied form from overseas
nations is presently in an unsettled state. An initial question concerns
the extent of the Commission's jurisdiction in this area. A second ques-
tion involves the standards to be applied in evaluating LNG projects, while
a third issue concerns the terms on which the ijnported supply is to be made
available to U.S. markets. In 1972, the Commission dealt with these ques-
tions for the first time in decisions approving two long-term import pro-
posals. In at least one case, however, the Commission's conclusions have
IV-60
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raised considerable uncertainty respecting the future of both imported
LNG and other high cost non-conventional sources of gas supply.
Beginning in 1968, the FPC has authorized several short-term
imports of LNG -- one or two shiploads per project -- from Algeria or
Libya for peak shaving or emergency needs. The prices for these supplies
have ranged from approximately 81<£ to $1.70/Mcf in the port of delivery.
The FPC simply assumed jurisdiction in approving the various short-term
projects, none of which were questioned by any party.
(a) Distrigas Project
The first long-term project considered by the Commission
involved a proposal by Distrigas Corp. -- a largely-owned subsidiary of
Cabot Corp. --to import the LNG equivalent of 15.4 billion cubic feet
annually from Algeria over a 20-year period. The purpose of the project
is to help meet peak shaving needs of distributors in the New England and
New York City areas. The LNG supply will be derived from natural gas pro-
duced and liquefied by Sonatrach (the Algerian national oil company) and
then transported by cryogenic tanker to Distrigas receiving terminals in
Boston, Massachusetts and on Staten Island, New York. Distrigas will pay
68<£ per million Btu (plus annual escalations of 0.6<£ per million Btu) at
the point of delivery and will sell the imported supply to several distribu-
tors at prices ranging from $1.04 to $1.74 per million Btu depending on
the extent of storage, vaporization and transportation service provided.—
_!/ On November 17, 1972, Distrigas applied for authority to import an
additional 45 billion cubic feet of LNG annually from Algeria at
a price of 73.9tf per million Btu, plus escalations and adjustments.
IV-61
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The FPC approved the Distrigas project on March 9, 1972.— In
that decision, the Commission held -- on a first jurisdictional question --
that LNG is natural gas and subject to its jurisdiction in the same manner
as other natural gas. On a second question respecting the scope of its
jurisdiction, a majority of the Commission concluded that it had authority
over the importation of the Distrigas supply and over its transportation
and sale for resale in interstate commerce. At the same time, however,
the Majority concluded that Distrigas' facilities to receive, store and
regasify the LNG -- and the transportation and sale of LNG in the states
of importation -- were not in interstate commerce and, hence, were outside
its jurisdiction.
The last conclusion was the subject of disagreement among the mem-
bers of the Commission at that time. The Majority (Commissioners Carver,
2/
Brooke and Walker)— conceded that it could have taken jurisdiction over all
of Distrigas' operations at the point of receipt of the LNG into the United
States (i.e., the ship's flange) as a condition to approving importation
under Section 3. However, the Majority chose not to do so because of a
desire to encourage the development of new and supplemental sources of
natural gas, including the importation of foreign LNG, at least so long
as these supplemental sources remain competitive with other available sup-
plies of gas or alternative fossil fuels. As the Majority explained:
I/ FPC Opinion 613, issued March 9, 1972 in re Distrigas Corp. (CP70-196).
2f Commissioners Carver and Walker both resigned from the FPC later in 1972.
Therefore, with new appointments, the Majority position of the Commission
on this matter may change.
IV-62
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"We are, in effect, inviting venture capital into the development
of LNG import projects and, to the extent that these projects are
intrastate in nature, we are expressing our intention not to
regulate them. We are firmly of the opinion that the exemption
of these projects from the federal regulatory umbrella will make
them more attractive to private investors and lead to more gas
at a lower price to the consumer, and effect this result sooner,
than if we controlled every detail and decision related thereto."
(FPC Opinion No. 613, Mimeo, p. 11.)
The two dissenting Commissioners (Chairman Nassikas and Commis-
sioner Moody) took an opposite view. Both contended that the FPC should
exercise comprehensive jurisdiction over LNG importation projects,
including the transportation, sale and price of the delivered LNG whether
or not sold in interstate commerce or for resale. It was further argued
that the Majority's decision created a "regulatory gap" and in effect
sanctioned a "what the traffic will bear" approach to LNG prices, thereby
ignoring both the impact on domestic gas supplies and the need to protect
ultimate consumers. As Chairman Nassikas put it: "When the price and
volume of imported LNG have such a direct impact on the price, volume,
and exploration activity for domestic gas, this Commission, as a resource
allocating agency, must exercise its authority over alternative gas sup-
plies." .
A further contention of the FPC Chairman was that the regulatory
gap created by the majority placed an impossible burden on state regula-
tory commissions and could encourage the emergence of a "vast network" of
unregulated intrastate distributors of LNG along the Atlantic Seaboard,
contrary to the public interest in securing commitment of gas supplies to
jurisdictional markets.
IV-63
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The divided decision of the FPC in the Distrigas case reflects
both differing legal rationale and differing policy conclusions which
could have an impact on the encouragement of imported LNG supplies for
U.S. markets. These differences will be resolved by the courts. The
Commission decision is now pending before the Court of Appeals for the
D.C. Circuit on an appeal brought by the Public Service Commission of
New York. However, in appraising the future of LNG imports from the point
of view of FPC regulation, the questions raised by the Distrigas case have
been largely transcended by the Commission's later actions in the El Paso
Algeria case, described below.
(b) El Paso Algeria Project
The second major LNG project considered by the FPC in 1972
involves the importation of one billion cubic feet per day from Algeria
by subsidiaries of three major interstate pipeline companies -- Columbia
Gas Transmission Co., Consolidated Gas Supply Corp. and Southern Natural
Gas Co. The project was put together by El Paso Natural Gas Co. which
formed a new company -- El Paso Algeria Corp. --to buy LNG from Sonatrach
and arrange for its transportation to the East Coast of the United States.
The three importing pipelines will use the LNG for base load purposes,
i.e., to augment supplies available from other sources to meet system
requirements the year around. Assuming the project is still viable after
court litigation, Columbia and Consolidated will import aggregate volumes
of 650,000 Mcf/d at a terminal to be constructed on the Chesapeake Bay at
Cove Point, Maryland and, after regasification, will transport the gas to
IV-64
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their market areas in Mid-Atlantic states. Southern Natural will import
350,000 Mcf/d at a terminal near Savannah, Georgia for delivery to its
market areas primarily in the states of Georgia and Alabama. Deliveries
are not expected to commence until late 1975 or 1976.
The El Paso Algeria project is substantially larger than the
Distrigas project -- primarily as a result of the fact that the three
importing pipelines seek the LNG as a base load supply on a year-round
basis, as opposed to merely season heating supply to be furnished by
Distrigas. The size difference is manifested in several ways: (1) the
El Paso Algeria import volumes are 365 billion cubic feet a year compared
with Distrigas volumes of approximately 15 billion per year; (2) the con-
struction expenditures involved in the El Paso Algeria project total more
than $1.6 million -- including expenditures of $628 million by Sonatrach
for liquefaction and other facilities in Algeria, $742 million by El Paso
Algeria for tanker construction and $270 million by the three importing
pipelines for terminal, storage, regasification and pipeline facilities
in the United States -- compared with an estimated $20 million outlay for
the Distrigas project; and (3) effectuation of the El Paso project requires
nine tankers (three of which are on order from a French yard and the remain-
ing six, under present plans, are to be built in U.S. shipyards with
subsidies from the Maritime Administration) compared with only one tanker
required by the Distrigas project. Another major difference is that most
of the LNG involved in the El Paso Algeria project is destined for sale
in interstate commerce for resale, while much of the Distrigas supply will
be consumed in the states of importation.
IV-6 5
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Despite these differences, the two projects raise similar ques-
tions respecting the reach of FPC jurisdiction, the cost of foreign LNG in
relation to domestic supplies, reliance on foreign sources of supply, and
means of encouraging supplemental non-conventional supply projects.
In an essentially unanimous decision issued June 28, 1972,— the
FPC authorized the El Paso Algeria project -- but subject to several
unexpected and controversial conditions. Five conditions are of particu-
lar significance:
(1) The FPC directed that the three importing pipelines sell
the LNG to their customers at incremental rates instead of at rolled-tn
rates, as proposed. (Incremental rates are based on the cost of the incre-
mental source of supply alone -- which, in this case, is higher than the
cost of the pipelines' other supplies -- while rolled-in rates reflect an
averaging of the costs of all supplies.) The Commission reasoned that
"rolled-in" pricing of the more expensive LNG would disguise its true
economic cost. Moreover, to assure that incremental LNG prices would be
passed through to ultimate consumers, the FPC prohibited the three importing
pipelines from selling to distributors which did not have separate rate
schedules for reselling the LNG at incremental rates.
(2) The FPC ordered El Paso Algeria to obtain a certificate
under Section 7(c) of the Natural Gas Act to sell LNG to the three importing
I/ FPC Opinion No. 622, issued June 28, 1972 in re Columbia LNG Corp. et al.
(CP71-68 et al.).
IV-66
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companies.— In a reversal of its position respecting the status of
Distrigas, the Commission found El Paso Algeria to be engaged in the sale
of LNG in interstate commerce for resale and hence a natural gas company
subject to its jurisdiction. Again, unlike Distrigas, the Commission con-
cluded that the terminal facilities proposed by the pipeline importing
companies at Cove Point and Savannah were subject to its jurisdiction and
required certification. (The status of these facilities was not contested
in this case, since the pipelines applied for certification.)
(3) The FPC imposed a fixed limit on the import prices to be
paid to El Paso Algeria -- 77
-------
(5] The FPC outlawed provisions for the recovery of project
costs by the three importing pipelines in the event of an interruption in
the LNG supply.
These conditions were not only denounced by all the participants
in the El Paso Algeria project, but they also evoked a considerable outcry
from many other companies and interests.— It was widely argued that one
or more of the conditions would kill this project as well as jeopardize
other high cost supplemental supply proposals. With very few exceptions,
pipelines and distributors agreed that incremental pricing of individual
sources of supply would create overwhelming administrative and practical
problems, particularly for distributors, and hence would be unworkable.
The Commission's conclusion that El Paso Algeria was a jurisdictional
natural gas company was attacked as legal error (the argument being that
El Paso Algeria is engaged in the sale of gas in foreign commerce for
resale in interstate commerce, not in the sale of gas in interstate com-
merce for resale). Conditions restricting import prices to fixed levels
and prohibiting pipeline recovery of project costs in the event of a supply
interruption were condemned from many sides as totally unacceptable. More-
over, these conditions, coupled with the possible adjustment of project
prices and other terms by the FPC at some future date if cheaper alternative
\l Because of the precedent-setting nature of Opinion No. 622, a large
number of companies or groups not previously parties to the proceeding
-- including gas pipeline and gas distributor associations, several
individual pipelines and distributors, Interior Department, Maritime
Administration, AFL-CIO, National Association of Regulatory Utility
Commissioners, and others -- asked to intervene and filed petitions
for rehearing.
IV-68
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supplies became available, were said to render project risks so great and
project costs so uncertain as to preclude financing.
Faced with such overwhelming opposition, the FPC modified its
decision on October 5, 1972 (Opinion No. 622-A) so as to delete or substan-
tially revise most of the contested conditions. The modifications were
conceded to be necessary to assure financing of the project. Specifically,
the Commission (1) retained the requirement that the importing pipelines
sell LNG on an incremental rate basis, but eliminated the further condition
in effect requiring distributor customers to sell also on that basis; (2)
reversed its jurisdictional holding respecting El Paso Algeria, concluding
on reconsideration that the company's operations would be wholly in foreign
commerce and hence outside FPC jurisdiction; (3) retained the fixed import
ceilings, but indicated price adjustments would be allowed for additional
costs shown to be justified; (4) clarified that language referring to
the possible adjustment of imported LNG terms, if cheaper alternative
supplies become available, did not indicate an intent to alter the terms
of the instant project but was meant to apply to consideration of future
projects; and (5) relaxed the prohibition against pipeline recovery of
project costs in the event of a supply interruption so as to permit the
recovery of out-of-pocket expenses but no depreciation or return on
equity capital.
The above-described decisions illustrate the FPC's dilemma in
approving high-priced supplemental gas supply projects badly needed to
augment domestic gas supplies which have declined because of too low well-
head prices allowed by regulation in the past, among other reasons. With
IV-69
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the conditions originally imposed in Opinion No. 622, the Commission was
obviously seeking to hold the lid on supplemental project costs and prices
to the extent possible. These conditions, however, were considerably more
onerous than any ever imposed on a domestic supply project. Given this
fact, together with the risks and uncertainties inherent in the El Paso
Algeria project, the project would have collapsed if the original condi-
tions had been retained, according to the applicants.—
To the extent Opinion Nos. 622 and 622-A can be considered a
regulatory precedent, their most significant impact for the future of
supplemental supply projects lies in the adoption of incremental pricing
principles.—' Essentially, the arguments in favor of this approach are:
(1) an incremental supply of gas which cannot be sold at its full cost is
economically indefensible; (2) rolled-in pricing of high cost supplies will
merely permit the continued use of gas for low priority uses and hence a
continued misallocation of energy resources through distorted prices; and
(3) incremental pricing will permit distributor customers of pipelines to
I/ The El Paso Algeria case is not yet over. Appeals have been filed
~~ in the courts by all of the project participants, as well as by environ-
mental groups which contest the location of the proposed LNG terminal
site at Cove Point, Maryland. These groups, however, recently agreed
to drop their opposition to the Cove Point terminal subject to the
laying of pipelines from the ship's docking platform to shore in an
underwater tunnel, as well as certain land use changes.
2/ In Opinion No. 622-A, Commissioner Brooke dissented to the retention
~ of incremental pricing for pipelines, and Chairman Nassikas con-
curred only for the purpose of certificating the project without fur-
ther delay. Nfore important in terms of court review, the incremental
approach was promulgated in the El Paso Algeria case in the absence
of any record evidence on the subject.
IV-70
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evaluate whether other alternatives for meeting system needs are more
economical.
On the other hand, the entire pattern of gas sales throughout
the country is predicated on rolled-in pricing. New supplies are typically
acquired by pipelines on a systemwide basis to serve all markets. Over the
years, this has resulted in efficient use of capacity and avoided complex
problems of allocating particular supplies to particular customers.
Furthermore, in the El Paso Algeria case, the supply involved will not be
directed to expand existing markets or attach new loads but rather is
required to maintain existing service to present customers. Under these
conditions, the economic rationale for incremental pricing is questionable.
It is assumed that the FPC will give substantial study to the
incremental pricing issue in the future.
Further discussion of incremental pricing appears in Chapter V
N
(pages V-62 through V-66).
I. Synthetic Gas.
FPC regulation of synthetic gas (SNG), alternatively called
substitute natural gas or substitute pipeline gas, raises essentially
the same issues as base load LNG importation. The chief questions include:
the extent of FPC jurisdiction, the source and cost of the feedstock sup-
ply, the cost of the final gas product, and incremental versus rolled-in
pricing of SNG sales by pipelines.
A sizeable number of SNG projects (some 40 or more) based on
reforming of naphtha or lighter liquid hydrocarbons, or on refining of
crude oil into naphtha (for subsequent gasification) and low sulfur residual
IV-71
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fuel oil, have been announced in the past 18 months. Some of these are
wholly intrastate and so may proceed without application to the FPC. Thus
far, five proposals have been filed with the Commission, hearings have been
held on three, and one has been authorized by the FPC.
In addition, an application was filed in November 1972 in the
FPC by El Paso Natural Gas Co. for authority to construct facilities to
connect synthetic gas to be produced by a coal gasification plant which
El Paso proposes to build in northwestern New Mexico.
The five liquid gasification projects filed with the FPC are
as follows:
(1) Columbia LNG Corp. proposes to reform 250,000 Mcf/d from imported
Canadian light hydrocarbon liquids (principally, ethane and propane) at a
$32 million plant to be built near Green Springs, Ohio. The company's
application to the Commission did not seek authority to construct the plant
but only to sell SNG at the plant tailgate to its parent, Columbia Gas
Transmission Co., at an estimated cost of service rate of $1.12/Mcf. Hearings
were held in October 1971. Columbia originally expected to have the plant
in operation by mid-1973; however, delays have occurred because of failure
of Columbia's feedstock supplier to receive the necessary Canadian authori-
zations for export of ethane. Columbia is now revising the project to use
only propane as feedstock, and further hearings before the FPC are likely.
(2) Algonquin SNG Inc. has requested FPC authority to construct a
$40 million plant near Freetown, Massachusetts to produce a maximum of
120,000 Mcf/d for sale to Algonquin Gas Transmission Co., with initial
output of 57,336 Mcf/d. The feedstock for the initial volumes would be
IV-72
-------
domestic naphtha purchased'from Humble Oil § Refining Co. f.o.b. its
Bayway, New Jersey refinery at 10.5<£ per gallon (plus escalations), equiva-
lent to $3.417 per barrel. At full plant output of 120,000 Mcf/d, the
estimated cost of service rate to Algonquin Gas Transmission is $1.41/Mcf
assuming year-round deliveries (335 days) and $1.80/Mcf assuming winter
month deliveries only (151 days). On December 7, 1972, the FPC issued a
decision— disclaiming jurisdiction over the SNG plant but authorizing the
receipt and resale of synthetic gas by Algonquin Gas Transmission.
(3) Tecon Gasification Corp. has applied for authority to construct
a $140 million plant in order to produce 500,000 Mcf/d of SNG from foreign
and domestic naphtha. The original plan proposed construction of the plant
in South Plainfield, New Jersey as a joint venture of Texas Eastern Trans-
mission Corp. and Consolidated Gas Supply Corp. Texas Eastern was to
have supplied 60% and Consolidated 401 of the capital funds, with the final
plant output to have been split in similar proportions. Several days
of hearings were held on this project in the spring of 1972. Subsequently,
the town council of South Plainfield voted to deny a permit for installation
of the plant at South Plainfield. Tecon now seeks to build the plant at a
site near Baton Rouge in Ascension Parish, Louisiana. The revised project
would be sponsored solely by Texas Eastern. The naphtha feedstock would
continue to be derived from foreign and domestic sources, including two-
thirds of the total (about 104,000 barrels per day) from foreign suppliers.
I/ FPC Opinion No. 637, issued December 7, 1972 in re Algonquin SNG Corp.
(CP72-35).
IV-7 3
-------
The estimated cost of SNG to Texas Eastern in the first full year of plant
operation (1975 according to present plans) is $1.27/Mcf.
(4) Transco Energy Co. proposes to build an $85 million naphtha
gasification plant near Chester, Pennsylvania in order to reform approxi-
mately 250,000 Mcf/d from domestic and foreign naphtha for sale to
Transcontinental Gas Pipe Line Corp. Feedstock requirements for the plant
are estimated at 53,500 barrels per day of naphtha (plus 4,200 barrels
per day of propane for enrichment purposes) which is expected to cost $4.50
per barrel on average during the first three years of plant operation
(1975-1977). The projected cost of SNG to Transcontinental Gas Pipe Line
is $1.40/Mcf in 1975. While Transco Energy applied for a certificate to
construct the plant, it has now asked the FPC to disclaim jurisdiction
over the SNG facility.
(5) Coastal Energy Corp. proposes to build a $33 million plant near
Corpus Christi, Texas in order to produce about 125,000 Mcf/d of SNG from
primarily domestic liquid feedstocks for sale to Trunkline Gas Co. The
proposed rate to Trunkline is $1.10/Mcf, subject to adjustment upward and
downward according to changes in the wholesale price of domestic crude oil
east-of-California. Trunkline has requested FPC authority to construct
facilities to connect and purchase the SNG, and Coastal Energy has applied
for a disclaimer of FPC jurisdiction over the proposed plant.
As noted, the above five proposals raise questions of jurisdic-
tion, feedstock supply and cost, and method of pricing the high cost SNG
supply. With respect to jurisdiction, Opinion No. 637 appears to have
removed much of the uncertainty --at least at the level of FPC decision
IV-74
-------
(which is always subject to reversal in the courts). The principal question
concerned the extent of the FPC's jurisdiction over the reformer facilities
and the sale of synthetic gas from such facilities. The Commission held
that it had no jurisdiction here in light of language in the Natural Gas
Act defining natural gas as "either natural gas unmixed or any mixture of
natural and artificial gas." Thus, because synthetic gas is artificial gas
and not natural gas, it is not jurisdictional. At the same time, the FPC
made clear its authority over the interstate transportation and sale for
resale of SNG once it is introduced into the system of an interstate pipeline
company and becomes mixed with natural gas. This aspect of jurisdiction was
never in dispute.
The FPC's disclaimer of jurisdiction is an important holding for
companies planning SNG projects from the standpoint of depth of evidence
and procedures required to obtain FPC approval. Any simplification here will
undoubtedly tend to facilitate SNG projects. In a broader sense, however,
the Commission's jurisdictional holding respecting the reformer facilities
is not likely to significantly affect the volume of SNG supply entering
interstate markets in view of the Commission's uncontroverted authority to
deny or condition the transportation of SNG (when mixed with natural gas)
and its sale for resale in interstate commerce.
In regard to feedstock, two of the five projects described above
contemplate use of both foreign and domestic naphtha, one contemplates use
of only domestic naphtha at least initially, one is based on domestic liquids
(unspecified as to type) and the fifth would rely on imported LPG from
Canada. Those projects based on use of foreign naphtha require import liquid
IV-7 5
-------
authorization from the Oil Import Administration which, to date, has granted
no licenses for the import of naphtha for conversion to synthetic gas. Use
of domestic naphtha avoids this problem, but it is presently more expensive
than foreign supplies and also is not generally available today for uses
other than the manufacture of gasoline and military jet fuel. As to LPGs,
any widespread use of domestic supplies for gasification purposes would
cause a considerable upward price effect in various markets, including the
petrochemical market which, in the United States, largely depends on
natural gas liquids for feedstock purposes. Canadian LPGs are not subject
to U.S. import quotas but, as noted in connection with the Columbia LNG
case, are subject to Canadian export restrictions.
In short, the question of feedstocks for SNG projects -- particu-
larly those based on use of foreign liquids -- involves complex considerations
which should be evaluated in the context of overall policy objectives,
rather than in isolated fashion in proceedings before the FPC.
A further major regulatory difficulty is the cost of the SNG
product. With respect to the five proposals submitted to the FPC, the
projected unit costs range from $1.10 to $1.41/Mcf, or higher. With the
exception of Algonquin Gas Transmission Co. which contemplates sale of the
SNG under a separate rate schedule to buyers contracting for the service,
all of the other pipeline purchasers propose to roll in the cost of the
SNG with the cost of overall system supplies. On a rolled-in basis, the
estimated cost impact of the SNG ranges from 5.9{/Mcf in the case of
Columbia Gas Transmission to 15.7
-------
Assuming the precedent established in the FPC Opinion No. 622
respecting LNG imports from El Paso Algeria, the FPC can be expected to
require incremental pricing for SNG supplies. This will cause consider-
able marketing difficulties.
Except for feedstocks, the foregoing considerations also per-
tain to coal gasification projects. For example, the proposal recently
filed by El Paso with the FPC involves an estimated SNG cost of $1.21
per Mcf which the pipeline proposes to pass on to customers through a
purchased gas adjustment provision in its tariff. On this basis, the
projected cost impact of the new supply to El Paso's customers would be
6*/Mcf.
IV-77
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Bibliography
Diener, William P., "Area Price Regulation in the Natural Gas Industry of
Southern Louisiana," Tulane Law Review, April 1972
Dungan, Malcolm T., "Jurisdiction of the Federal Power Commission Over
Importation of Liquefied Natural Gas," Natural Resources Lawyer, April
1971
Federal Power Commission
1. FPC Opinions including, among others:
Opinion No. 315, issued January 30, 1959 in re Transcontinental Gas
Pipe Line Corp. (G-13143 et al.); 21 FPC 138
Opinion No. 333 issued November 27, 1959 in re El Paso Natural Gas Co.
(G-12580); 22 FPC 900
Opinion No. 338, issued September 28, 1960 in re Phillips Petroleum Co.
(G-1148 et al.); 24 FPC 537
Opinion No. 351, issued January 22, 1962 in re Continental Oil Co.
et al. (G-11024 et al.); 27 FPC 96
Opinion No. 393, issued July 12, 1963 in re El Paso Natural Gas Co.
et al. (G-16235 et al.); 30 FPC 77
Opinion No. 398, issued July 17, 1963 in re Placid Oil Co. et al.
(G-13183 et al.); 30 FPC 283
Opinion No. 426, issued May 5, 1964 in re Continental Oil Co. (CI63-979) ;
31 FPC 1079
Opinion No. 436, issued July 23, 1964 in re Union Texas Petroleum et al.
(G-13221 et al.); 32 FPC 254
Opinion No. 468, issued August 5, 1965 in re Permian Basin Area Rate
Proceeding (AR61-1); 34 FPC 159
Opinion No. 474, issued September 9, 1965 in re Natural Gas Pipeline Co.
of America (CP62-243 et al.); 34 FPC 771
Opinion No. 500, issued July 26, 1966 in re Transwestern Pipeline Co.
et al. (CP63-204 et al.); 36 FPC 176
Opinion No. 526, issued August 10, 1967 in re El Paso Natural Gas Co.
(G-8932 and CP66-315); 38 FPC 311
IV-78
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Opinion No. 528, issued September 26, 1967 in re Tennessee Gas Pipeline
Co. et al. (CP65-356 et al.); 38 FPC 691
Opinion No. 546, issued September 25, 1968 in re Southern Louisiana
Area Rate Proceeding (AR61-2); 40 FPC 530
Opinion No. 560-A, issued December 31, 1970 in re Chandeleur Pipeline
Co. (CP69-76); 44 FPC 1747
Opinion No. 574-A, issued May 8, 1970 in re Transwestern Pipeline Co.
et al. (CP67-220 et al.); 43 FPC 712
Opinion No. 586, issued October 7, 1969 in re Pipeline Production Area
Rate Proceeding (RP66-24, Phase I); 42 FPC 738
Opinion No. 595, issued May 6, 1971 in re Texas Gulf Coast Area Rate
Proceeding (AR64-2); 45 FPC 674
Opinion No. 598, issued July 16, 1971 in re Southern Louisiana Area
Rate Proceeding (AR61-2 et al.); 46 FPC 86
Opinion No. 6UO-A, issued May 8, 1972 in re HI Paso Natural Gas Co.
(RP69-6, Phase II et al.)
Opinion No. 606, issued October 5, 1971 in re United Gas Pipe Line
Co. (RP71-29); 46 FPC 786
Opinion No. 607, issued October 29, 1971 in re Other Southwest Area
Rate Proceeding (AR67-1); 46 FPC 900
Opinion No. 612, issued February 18, 1972 in re Arkansas Louisiana
Gas Co. (CP70-267)
Opinion No. 613, issued March 9, 1972 in re Distrigas Corp. (CP70-196)
Opinion No. 615, issued March 22, 1972 in re El Paso Natural Gas Co.
(CP71-234)
Opinion No. 618, issued May 11, 1972 in re Northern Natural Gas Co.
et al. (CP70-69 et al.)
Opinion Nos. 622 and 622-A, issued June 28, 1972 and October 5, 1972
in re Columbia LNG Corp. et al. (CP71-68 et al.)
Opinion No. 637, issued December 7, 1972 in re Algonquin SNG Corp.
(CP72-35)
IV-79
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2. FPC Orders including, among others:
Order Nos. 410 and 410-A (R-380), issued October 2, 1970 and
January 8, 1971; 44 FPC 1142 and 45 FPC 135
Order No. 411 (R-371) issued October 2, 1970; 44 FPC 1112
Order No. 418 (R-404), issued December 10, 1970; 44 FPC 1574
Order No. 428 (R-393), issued March 18, 1971; 45 FPC 454
Order Nos. 431 and 431-A (R-418), issued April 15, 1971 and July 31,
1972; 45 FPC 440
Order No. 435 (R-389A), issued July 15, 1971; 46 FPC 68
Order No. 441 (R-411), issued November 10, 1971; 46 FPC 1178
Order No. 455 (R-441), issued August 3, 1972
3. National Gas Supply and Demand
Staff Report No. 1, issued September 1969
Staff Report No. 2, issued February 1972
4. Statement of General Policy No. 61-1, issued September 28, 1960
(and subsequent amendments)
Foster Associates, Inc., Weekly Report (covering federal regulation of
natural gas industry), 1956-1972
Gilliam, Carroll L., "The Permian Basin Area Rate Case: New Landfalls in
Rate Regulation," Natural Resources Lawyer, July 1969
Grove, William J., "Current Concepts Applicable to Exportation-Importation
of Natural Gas," Natural Resources Lawyer, October 1968
Kitch, Edmund W., "The Permian Basin Area Rate Cases and Regulatory
Determination of Price," University of Pennsylvania Law Review,
December 1967
Kitch, Edmund W., "Regulation of the Field Market for Natural Gas by the
Federal Power Commission," Journal of Law and Economics, October 1968
Landis, James, Report on Regulatory Agencies to the President-Elect,
printed for use of the Senate Committee on the Judiciary, 86th Congress,
Second Session, 1960
IV-80
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Morrell, Gene P., Speech to Western Gas Processors and Oil Refiners
Association in Anaheim, California on October 3, 1969
National Energy Board
Report to The Governor in Council in the Matter of Westcoast
Transmission Co. Ltd., December 1967
Report to The Governor in Council in the Matter of Alberta and
Southern Gas Co. Ltd., et al., August 1970
Report to The Governor in Council in the Matter of Consolidated
Natural Gas Ltd., November 1971
Pipeline and Gas Journal, "SNG Report," May 1972, pp. 33-41
Nassikas, John N.
Press interview reported in Oil Daily dated November 22, 1969
Statement before Subcommittee on Flood Control and Internal Develop-
ment, House Committee on Public Works, August 1, 1972
O'Leary, John F.
Statement on behalf of Bureau of Mines before House Committee on
Interior and Insular Affairs, April 14, 1969
Speech to Federal Power Bar Association in Washington, D.C. on April 24,
1969
U.S. Supreme Court
Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672 (1954)
Atlantic Refining Co. v. Public Service Commission of New York,
360 U.S. 378 (1959)
Sunray Mid-Continent Oil Co. v. FPC, 364 U.S. 137 (1960)
FPC v. Transcontinental Gas Pipe Line Corp., 365 U.S. 1 (1961)
United Gas Improvement Co. v. Gallery Properties, Inc., 382 U.S. 223
(1965)
Permian Basin Area Rate Cases, 390 U.S. 747 (1968)
FPC v. Sunray DX Oil Co., 391 U.S. 9 (1968)
FPC v. Louisiana Power § Light Co., 406 U.S. 621 (1972)
White, Lee C. (former FPC Chairman), Speech to Financial Analysts Federation
in Washington, D.C. on May 16, 1969
IV-81
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CHAPTER V - REGULATORY MEANS OF INCREASING GAS SUPPLY
In discussing means by which natural gas supply might be
increased through the regulatory process, it is necessary to distinguish
between (1) domestic natural gas production in the Lower 48 States, (2)
imported natural gas and (3) synthetic pipeline quality gas. The second
category includes pipeline imports from Canada and Alaska, and LNG
imports from overseas foreign nations. The third category includes the
manufacture of synthetic gas from liquid hydrocarbon feedstocks (domestic
or foreign) and from domestic coal.
In the case of domestic supply of natural gas produced in the
Lower 48 States, the greatest hopes for turning around the present
exploratory downtrend, and hence for improving supply, include permitting
the wellhead price for interstate gas to be more responsive to the
market forces of supply and demand, and accelerating and regularizing
the leasing of offshore lands. These measures have broad support both
inside and outside the gas producing industry, although there are some
consumer interest groups which contend that no price increase beyond
current levels should be permitted without a thorough government evalua-
tion of producer reserves to ascertain whether and to what extent a
shortage actually exists. Essentially, their view is that producers
are holding back reserves from commitment to interstate markets -- or
refusing to develop proven reserves -- in anticipation of higher
prices. Once this anticipation is removed, the consumer groups suggest,
greater volumes will be forthcoming to interstate markets. A basic
problem with this position, however, is that the evidence to date
V-l
-------
discloses no significant amount of uncommitted gas reserves available
for sale by producers. While the principal source of proven gas reserves
over the years is the American Gas Association (an industry association
which compiles and publishes gas reserve data annually),—' trends in
these reserves are corroborated by reports on dedicated gas supplies
filed with the FPC each year by interstate pipelines. Moreover, reports
on uncommitted reserves submitted by larger gas producers on various
occasions in the past few years at the Commission's directive do not bear
out the contention of a substantial "sitting on reserves." The most
recent reports of this type showed a total of only 3.8 trillion cubic
feet (excluding Alaska) available for sale at the end of 1971, amounting
to only about 1.5% of the nation's estimated proved gas reserves on that
date (again excluding Alaska).
A competitive market approach to wellhead regulation -- which
will necessarily entail substantial price increases -- can be accomplished
through legislative action to decontrol sales by producers either wholly
or in part, or by a reorientation of the direction of FPC regulation. As
explained in pages V-23 through V-29, the Commission has already taken
steps to respond to the supply crisis, but more is needed.
_!/ The FPC, together with the U.S. Geological Survey and technical
experts from the U.S. Navy, is presently conducting an independent
analysis of the nation's proved natural gas reserves. The results
of this analysis are scheduled to be published at the end of May
1973. In addition, the Federal Trade Commission has been conducting
an investigation of the reporting of gas reserve information by the
American Gas Association since October 1970. No findings have been
issued as yet.
V-2
-------
At the very least, legislative action is necessary to reduce
the uncertainty and time lags which dominated producer regulation through-
out the 1960's. All segments of the gas industry, as well as regulators,
both past and present, agree on the need to avoid the frequent -- and, in
the eyes of the producers, totally arbitrary -- reductions applied by the
FPC to producer prices in the past. Hearings were held before both House
and Senate committees in the last session of Congress on so-called
"sanctity of contract" bills which would assure certainty of price and
other terms. While some consumer groups opposed the need for any such
legislation at all (as indicated on page V-30), most of the criticism
during the hearings was directed to certain provisions of these bills,
but not to the principle of "contract sanctity" itself. However, the
bills were not even reported out of the committees and never came to a
vote. Reactivation and passage of this legislation in essentially similar
form would appear to be a minimum step toward ameliorating the domestic
supply situation. The sanctity of contract step, however, is unlikely to
prove effective unless coupled with FPC action to increase producer prices
to more realistic market levels.
There is now growing opinion, however, that sanctity of contract
legislation would not go far enough in providing the needed turnaround in
domestic supplies and that deregulation of producer sales, at least new
gas sales, is necessary. The petroleum industry supports this course,
and so do an increasing number of government officials. Decontrol offers
substantial hope for raising domestic supply, but it also raises some
substantial problems. As noted on pages V-34 through V-37 not the least
V-3
-------
of these problems is that no one can predict with any degree of certainty
what the supply response will be. Moreover, Congressional passage of any
decontrol measure is problematical.
On the other hand, there are those who advocate the view that
the present shortage of gas necessitates an expansion rather than a
relaxation of FPC regulation. Proposals have been advanced, for example,
to extend the Commission's jurisdiction to intrastate sales and direct
sales, and to establish end-use controls on a nationwide basis. If the
supply of gas available for interstate markets does not improve and new
reserves are largely committed to nonjurisdictional and largely industrial
uses, the pressures for end-use rationing by the FPC or some other regula-
tory authority will undoubtedly increase. A basic difficulty with such
proposals is that they are directed to coping with the crisis as it gets
worse rather than to attacking its cause.
With respect to imported gas supply and synthetic gas supply,
multiple policy problems are involved. Among them are balance of pay-
ments questions, national security, and interrelationships with other
fuels. Also to be considered are the more traditional certificate
criteria of need, adequacy and reliability of supply, economic justifica-
tion, and financeability. There is an obvious need to formulate regulatory
policies at the earliest possible date to encourage development of supple-
mental gas projects meeting national interest and economic feasibility
criteria. At the same time, it should be noted that gas imports and
synthetic gas production will not be available in any important degree
to augment domestic sources until the latter part of this decade or the
V-4
-------
early 1980's. Nevertheless, the criteria and policies laid down in the
next year or so will be instrumental in influencing future development.
It should also be emphasized that none of the more likely means
for increasing gas supply will result in any substantial expansion of sup-
ply overnight. With respect to domestic gas, even if legislation removing
or relaxing part of the FPC's regulatory powers were passed within the
next year -- a highly speculative event at best, the result would take
some time to perceive because of the time lag between exploration for new
reserves and the date production commences to flow to markets. This lag
is variously estimated at between three to seven years depending upon the
producing area and distance from established market outlets. Similarly,
measures taken by the FPC to increase supply are also subject to the time
lag problem and, in addition, will undoubtedly continue to face opposition
from certain quarters, which opposition generally entails court litigation
and the delays associated therewith.
Nor do supplemental sources of gas supply offer much hope of
supply alleviation for the immediate future. An exception could be the
reforming of gas from naphtha and other light hydrocarbon feedstocks.
Reforming plants can be built within a period of two years or less.
Hence, relaxation of import controls respecting naphtha feedstock supplies
-- coupled with expedited FPC review of and favorable action on reformer
gas projects -- is perhaps the measure most capable of stimulating a
noticeable increment of supply in the short term. However, the importa-
tion of naphtha is enmeshed in complex questions concerning interfuel
relationships and the direction of the nation's overall import policies
in the years ahead.
V-5
-------
Possible regulatory strategies for increasing supply are dis-
cussed in greater detail in the following pages, together with some sug-
gestions as to the role which EPA might pursue. First, however, some
background information is reviewed in order to lend perspective to the
problems involved.
A. Supply-Demand Picture: Background Data
In considering regulatory strategies for the future, an under-
standing of some past trends and current relationships is necessary to
appreciate the extent of the corrective measures needed to reverse the
present situation and to accomplish any significant increase in supply.
The following portrays indicators of the declining trend in gas
exploratory efforts and in gas reserve additions in the United States;
trends in natural gas prices related to interstate-intrastate levels,
competitive fuels and inflation; the extent of the supply-demand imbalance
projected by two sources in the years ahead; and the magnitude (and loca-
tion) of estimated reserves which might contribute to overcoming the
supply imbalance.
1. Trends in Gas Exploration and Reserves
The story of the decline in gas well drilling and other explora-
tory activity, increase in depth of wells drilled and increase in cost of
wells drilled over the past decade and longer is by now familiar to all
concerned with energy matters, especially natural gas matters. Also well
known is the declining trend in proved gas reserves in the Lower 48 States
relative to production (R/P ratio) , and the absolute decline in proved
V-6
-------
reserves in the last four years due to reserve additions insufficient to
offset production.
Nevertheless, to lend perspective to the overall picture,
certain trends warrant reiteration.
First, as shown on Table V-l, annual production in the Lower
48 States— has approximately doubled in the last 14 years. The total
increase in production over the 1958-1971 period was 921, representing
an average annual growth rate of 5.1% through 1970 (and only 0.5% between
1970 and 1971). By contrast, proved gas reserves in the Lower 48 reached
a peak in 1967 only 141 above the 1958 level and by 1971 were 23 below
the 1958 level. Moreover, during the past four years, while production
continued to climb (from 19.3 trillion cubic feet in 1968 to 21.9 trillion
in 1971, or over 131) , total proved reserves dropped from 289.3 trillion
cubic feet at the beginning of 1968 to 247.4 trillion at the end of 1971,
or nearly 15%. As a result of these divergent trends in production and
2/
reserves, the R/P ratio fell from 22.1 in 1958 to 11.3 in 1971.-
The drop in proved reserves after 1967 reflects the fact that
reserves added in the Lower 48 were insufficient to offset production --
I/ The reserve and production data described in this section relate to
the Lower 48 States, thereby excluding Alaska. The exclusion of Alaska
reflects the fact that Alaskan gas is presently not available to
markets in the Lower 48 States and can be made available only via
pipeline transportation through Canada or in liquefied form by tanker.
Until such transportation comes about, Alaska is considered as a
separate consuming and producing area.
2/ The R/P ratio is a mere mathematical calculation of the times by which
proved reserves exceed annual production. While sometimes expressed
in terms of years, this ratio does not indicate the actual number of
years proved reserves can sustain a given production level since
reserves are subject to declining deliverability characteristics
with depletion of reservoirs and consequently cannot all be produced.
V-7
-------
Total Reserves
TRENDS IN GAS RESERVES AND PRODUCTION
UNITED STATES EXCLUDING ALASKA
1958 - 1971
(All Volumes at 14.73 Psia)
Year-End
Year-End Reserves
Dedicated to
Interstate
Pipelines
Year
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
Additions
Index
Tcf 1958-1959=100
18-9 ^ 100
20.6 )
13.8 )
16.4 )
18.8 ) "
18.1 )
20.1 )
21.2 )
19.2 ) iUJ
21.1 )
12.0 )
8.3 )
11.1 )
9.4 )
Production
Tcf
11.4
12.4
13.0
13.4
13.6
14.5
15.3
16.2
17.5
18.4
19.3
20.6
21.8
21.9
Index
1958=100
100
109'
114
118
119
127
134
142 .
154
161
169
181
191
192
Find ing -
Production
Ratio
1.65
1.67
1.06
1.22
1.38
1.25
1.31
1.30
1.10
1.15
0.62
0.40
0.51
0.43
Proved
Tcf
252.8
261.1
262.2
265.4
270.6
274.5
279. 4
284.5
286.4
289.3
282.1
269.9
259.6
247.4
_. a/
Reserves-
Index
1958=100
100
103
104
105
107
109
111
113
113
114
112
107
103
98
Reserve-
Production
Ratio
22.1
21.1
20.1
19.8
19.9
18.9
18.2
17.5
16.4
15.8
14.6
13.1
11.9
11.3
Tcf
n.a.
n.a.
n.a.
n.a.
n.a.
188.5
189.2
192.1
195.1
198.1
195.0
187.6
173.6
161.3
Percent
Total
Reserves
n.a.
n.a.
n.a.
n.a.
n.a.
69
68
68
68
68
69
70
67
65
n.a. - Not available.
a/ Includes reserves held in underground storage, which increased from 1.7 Tcf at the end of 1958 to
4.3 Tcf at the end of 1971.
PJ
cr
Source: American Gas Association Committee on Natural Gas Reserves; FPC, Gas Supplies of Interstate Pipeline
Companies, 1970 and Press Release No. 18513.
<
i
-------
in fact, reserve additions averaged only about 501 of production over the
1968-1971 period. Moreover, while reserve additions reflect an erratic
pattern from year to year as a result of the uncertainty of drilling
results and revisions of previous estimates, it is significant that the
level of reserves added in the last four years -- averaging 10.2 trillion
cubic feet -- were barely more than 501 of the average level of additions
in the previous 10 years.
The trends in reserves, reserve additions and production are
portrayed graphically below.
RESERVE-PRODUCTION RATIOS, ANNUAL ADDITIONS OF
NEW RESERVES, PRODUCTION, AND CONSUMPTION OF
NATURAL GAS IN THE UNITED STATES (EXCLUDING ALASKA)
5Or
The reason for the decline in reserve-production and finding-
production trends is the sharp drop in gas well drilling which has occurred
over the past decade. As shown in Table V-2, the number of successful
exploratory gas well completions reached a peak in 1959 and has declined
V-9
-------
TRENDS IN GAS WELL DRILLING
UNITED STATES EXCLUDING ALASKA
1958 - 1971
New Field
Wildcats
Year
1958
1959
1960
1961
1962
1963
• 1964
i_ i
o
1965
1966
1967
1968
1969
1970
1971
Number
of
Wells
268
305
296
314
315
240
250
233
229
178
125
191
183
202
Index
1958=100
100
114
110
117
118
90
93
87
85
66
47
71
68
75
Successful
Exploratory
Wells
Number
of
Wells
822
909
866
808
769
663
575
513
574
553
429
616
480
437
Index
1958=100
100
111
105
98
94
81
70
62
70
67
52
75
58
53
Successful
Developmental
Wells
Number
of
Wells
4,207
3,958
4,280
4,674
4,580
3,902
4,116
3,959
3,743
3,045
2,892
3,021
2,742
2,961
Index
1958=100
100
94
102
111
109
93
98
94
89
72
69
72
65
70
Average Depth of
Gas
Feet
5,462
5,523
5,362
5,362
5,373
5,638
5,548
6,149
6,110
6,173
6,021
6,007
n.a.
Wells
Index
1958=100
100
101
98
98
98
103
102
113
112
113
110
110
n.a.
Average Cost Per
Gas Well Foot
Drilled
$/Ft.
$18.42
18.55
17.60
17.98
17.11
18.10
18.16
21.60
22.90
23.69
24.35
26.62
n.a.
Index
1958=100
100
101
96
98
93
98
99
117
124
129
132
145
n. a.
n.a. - Not available.
Source: New Field Wildcats and Successful Exploratory Wells - American Association of Petroleum Geologists.
Successful Developmental Wells - American Association of Petroleum Geologists and World Oil.
Average Gas Well Depth and Average Cost of Drilling - Joint Association Survey of the U. S. Oil
and Gas Producing Industry.
CD
cr
<
-------
Table V-3
EXPLORATION INDICATORS
UNITED STATES
1958 - 1971
Geophysical Crew Time
Rotary Rigs in Operation
Year
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
Number
of
Months
5,731
5,696
5,207
5,024
4,231
4,174
4,406
4,471
3,835
3,496
3,390
3,259
2,521
n.a.
Index
1958=100
100
99
91
88
74
73
77
78
67
61
59
57
44
n.a.
Average
Number
of Rigs
1,923
2,074
1,750
1,760
1,636
1,501
1,502
1,387
1,273
1,134
1,150
1,194
1,028
975
Index
1958=100
100
108
91
92
85
78
78
72
66
59
60
62
53
51
n.a. - Not available.
Source: Geophysical Crew Time - Society of Exploratory Geophysicists.
Rotary Rigs - Hughes Tool Co.
V-ll
-------
by over 501 since that time, while successful gas developmental wells have
fallen by about 371 since the 1961 peak year. New field wildcats reflect
a similar decline.
Exploratory activity as measured by geophysical prospecting and
by the number of rotary rigs in operation has also been in a long-term
decline, as shown in Table V-3.
2. Trends in Gas Prices
The tables on the following pages illustrate, first, that average
wellhead prices of natural gas, when expressed in dollars of constant pur-
chasing power, have hardly risen over the past 14 years and, in fact, have
declined by about 10% since 1964. (Table V-4) Second, the data reveal
the price of natural gas is significantly lower than substitutable fuels
both at the wellhead and at the point of consumption for residential use.
(Tables V-4 and V-5) Third, the data reflect a substantial disparity
between wellhead prices for gas sold interstate and gas sold intrastate.
(Table V-6) At the present time, this disparity is undoubtedly greater
than in more plentiful supply years when interstate prices constituted
a brake on prices contracted in the intrastate market. This situation
no longer pertains, as indicated by recently negotiated prices for spot
intrastate sales up to 52
-------
Table V-4
TRENDS IN WELLHEAD PRICES OF NATURAL GAS AND
COMPARISON WITH OTHER HYDROCARBON FUEL PRICES
AT POINTS OF PRODUCTION
UNITED STATES
1958 - 1971
Year
Average Wellhead
Prices of Natural
Gas
In
In Constant
Current (1967)
Dollars
Dollars-''
(Cents Per Mcf at
14.73 Psia)
Comparative Prices of Hydrocarbon Fuels
At Points of Production
Gas Price As
Percent of
Natural
Gas
Crude
Oil
Coal
(Cents Per MMBtu)
Crude
Oil
Coal
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
12.0
13.0
14.1
15.1
15.5
15.9
15.4^
15.6
15.7
16.0
16.4
16.7
17.1
18.2
13.9
14.9
15.9
16.9
17.1
17.3
16.6^
16.5
16.2
16.0
15.7
15.2
14.7
15.0
10.8
11.7
12.7
13.6
14.0
14.3
13.9^
14.1
14.2
14.4
14.7
15.1
15.5
16.5
52.1
51.0
50.6
49.8
50.2
50.6
51.1
51.2
51.6
51.8
52.7
55.2
56.5
60.2
18.7
18.6
18.3
17.9
17.5
17.2
17.4
17.5
17.9
18.4
18.6
20.0
25.5
29.0
21%
23
26
27
28
28
27
28
28
28
28
27
27
27
58%
63
69
76
80
83
80
81
79
78
79
76
61
57
a/ Prices in current dollars deflated by the B.L.S. Consumer Price Index.
b_/ Excludes all taxes beginning in 1964. In 1964 taxes excluded amounted
to 2.06 percent of the reported wellhead value.
Source: U. S. Bureau of Mines.
V-13
-------
Table V-5
TREND IN PRICES OF GAS AND FUEL OIL
FOR RESIDENTIAL HEATING
UNITED STATES
1959 - 1971
Year
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
Gas
--(Cents
n.a.
67.2
72.4
72.8
71.9
71.9
81.8
81.6
83.4
83.0
83.9
85.1
89.2
95.7
Fuel Oil
#2
Per MMBtu)--
108.7
110.2
108.3
112.6
112.6
115.1
113.3
115.7
118.5
121.9
125.7
128.5
133.2
141.5
Gas As
Percent of
Fuel Oil
n.a.
61%
67
65
64
62
72
71
70
68
67
66
67
68
n.a. - Not available.
Source: Bureau of Labor Statistics, Retail Prices and
Indexes of Fuels and Utilities; heat value
employed for fuel oil is 5,825,000 Btu per
barrel.
V-14
-------
Table V-6
CURRENT RATES FOR INTERSTATE AND INTRASTATE
SALES OF NEW GAS
Producing Area
South Louisiana
Permian Basin
Texas Gulf Coast
Hugoton-Anadarko
Other Southwest
Rocky Mountain
Appalachian Basin
California
Pressure
Base
(Psia)
15.025
14.65
14.65
14.65
14.65
15.025
15.025
14.73
Interstate
Sales!/
( f on t" c Pe
26.0
25.5
24.0
20.0-21.5
22.5-25.4
22.5-24.0
32.0-34.0
— _
In tra state
Sales^/
\* £\
22.0-35.0
14.0-49.0
17.0-45.4
14.0-40.0
10.3-48.5
15.0-43.1
46. 0-53. 8£/
30.0-37.0
a/ Excluding tax}gathering and Btu adjustments.
b_/ Including tax reimbursement and adjustments for gathering and Btu.
£/ Primarily Michigan.
Source: Rates for interstate sales from FPC Opinion Nos. 468, 586, 595,
598 and 607; FPC Order Nos. 411 and 435; and FPC Staff recommenda-
tion in Docket No. AR70-1.
Rates for intrastate sales from FPC report of 11/14/72 in Docket
No. 389-A.
V-15
-------
some contracts for interstate sales from South Louisiana have recently
been signed at 45
-------
sustained contribution to national supply, and productive capability of
supply sources at different stages of depletion.
The Staff projections assumed existing levels of regulated
prices (i.e., prices in effect or approved at the beginning of 1972).
At these prices -- including increased rates allowed by the FPC during
the previous year for several supply areas, Staff considered an increase
in reserve additions from approximately 10 trillion cubic feet in 1970-
1971 to 17 trillion by 1976 as likely. At the same time, Staff indicated
that annual reserve additions could be higher than forecast if the
industry were to find the regulatory atmosphere more conducive to
increased exploratory and developmental efforts.—
I/ The Staff report acknowledged the imprecision inherent in its forecast,
or any forecast of supply responsiveness to price. Specifically, Staff
explained:
"Our construction of a national supply-demand balance neces-
sarily involves a quantitative estimate of the level of future
reserve additions. Being unable to quantify the increments of
additional reserve additions which may result from specific
increases in gas prices and other recent Commission incentives
to increase findings, we were required to place considerable
reliance upon past trends. However, if the producing industry
finds the present regulatory atmosphere more conducive to increased
exploratory and developmental efforts, such past trends may lose
some of their prognosticative value. If this occurs, our predic-
tion as to annual additions to reserves may prove to be under-
stated. When we establish a schedule of additions of reserves,
we in effect make a projection which the Commission correctly
found could not be made based on a precise quantification of
the future supply response to price. This should not be taken
as a defect in our analysis. Our purpose here is to approxi-
mate a likely supply-demand balance over the period considered
and to establish, at least in our view, the order of magnitude
of the various balance components so that some ideas of the
probable supply-demand posture of the Nation might be generated
along with some notion of the sensitivity of the balance to
modification through changes in the relative contributions
of the various elements." (Staff Report, page 6)
V-17
-------
U. S. (EXCLUDING ALASKA) GAS SUPPLY GAP
AS PROJECTED BY FPC STAFF
(All Volumes in Trillions of Cubic Feet at 14.73 Psia)
Annual
Year Demand
Actual Data
1970
1971
Projections
1971
1972
1973
1974
1975
22.6
22.8
24.6
26.1
27.7
28.8
29.8
Domestic
Production
(Lower 48)
21.8
21.9
22.8
23.8
24.7
24.8
24.7
Net Gas Gas
Pipeline LNG From From
Imports Imports Coal Alaska
0.8
0.9
0.9
1.0
1.1
1.1
1.2 0.3
Gas From Percent
Liquid Total Unsatisfied Demand
Hydrocarbon Supply Demand Unsatisfied
„
--
--
a/
a/
a/
a/
22.6
22.8
23.7 0.9 3.6%
24.8 1.3 5.0
25.8 1.9 6.9
25.9 2.9 10.1
26.2 3.6 12.1
1980
1985
34.5 20.4
39.8
18.5
1.6 2.0 0.3 0.7
1.9 3.0 1.4 1.3
a/
a/
25.0
26.1
9.5
13.7
27.5
34.4
a/ Data considered insufficient for quantitative projection.
Source: FPC, National Gas Supply and Demand. 1971-1990. Staff Report No. 2, February 1972, Table 1.
H
tti
o-
I
-J
-------
U. S. (EXCLUDING ALASKA) GAS SUPPLY GAP
AS PROJECTED BY NATIONAL PETROLEUM COUNCIL
(All Volumes in Trillions of Cubic Feet at 14.73 Psia)
Year
Domestic Net
Annual Production Pipeline
Demand (Lower 48) Imports
North
LNG LPG Slope Synthetic Total ,
Imports Imports Gas Gas Supply— Demand
Percent
Unsatisfied Demand
Unsatisfied
1970 22.6 21.8 0.8 — — — — 22.6
(Actual)
1975 29.8 19.8 1.2 0.2 0.2 — 0.4 21.7 8.1
1980 34.5 16.3 1.2 2.1 0.5 1.2 0.6 21.8 12.7
1985 39.8 13.0 1.2 4.0 0.9 1.5 0.9 21.5 18.3
27.2
36.8
46.0
a/ Detail may not add to total due to rounding.
Source: NPC, U.S. Energy Outlook. An Initial Appraisal, 1971-1985, Volume Two, November 1971.
H
CD
cr
oo
-------
In addition, the Staff's supply projections include supplemental
supplies, based essentially on projects now in prospect, including pipe-
line imports, LNG imports, gas from coal, and gas from Alaska. (Synthetic
gas production from liquid hydrocarbons was considered by the Staff to be
subject to such rapidly changing trends as to preclude any meaningful
estimate at this time.) Even with these sources, the forecast is for a
substantial and growing supply gap.
Graphically, the picture portrayed by Staff looks as follows:
UNITED STATES GAS SUPPLY-DEMAND BALANCE
(Contiguous 48 States)
Percent of
Domestic Undi scovered Potential
Potential Recoverable Recoverable
Reserve* Reserves
(Tnll.on Cubic Feet) Discovered by 1990
Unsatisfied Demand
Production From
Potential Natural
Gas Reserves*
Production From
1970 Proven Reserves
1966 1970 1975 1980
'U.S. Natural Gas Reserve Additions (1971-1990) Total 325 Trillion Cubic Feet.
1985
1990
V-20
-------
The potential supply gap indicated by projections of the National
Petroleum Council— are even greater. This is primarily because of more pessi-
mistic estimates of domestic production. Assuming wellhead prices based
on FPC Staff recommendations in 1971, NPC saw little or no incentive for
increased reserve additions, particularly in view of substantially
2i
higher costs of deeper drilling and of drilling offshore and in Alaska.—
Estimates of energy supply and demand necessarily depend on a
variety of assumptions, which are subject to change in the future. As a
result of such changes, many past estimates have missed the mark by wide
margins in terms of accuracy of prediction. Notwithstanding this caveat,
the above projections illustrate responsible current estimates as to the
degree by which supply -- assuming the price and other relevant conditions
of today -- will fall short of satisfying expected demand.
4. Potential Gas Reserves
The United States is not short of potential gas supply. The
Potential Gas Committee estimated potential reserves as of December 31,
\l National Petroleum Council, U.S. Energy Outlook: An Initial Appraisal,
1971-1985, Vol. I, July 1971.
21 Key assumptions reflected in the NPC forecast are as follows: (a) new
gas prices of 26
-------
1970 at 1,178 trillion cubic feet, about four times the level of esti-
mated proven reserves at the end of 1970 (291 trillion cubic feet,
including Alaska). Of this total, 257 trillion are classified as
"probable" (extensions of existing fields), 387 trillion are classified
as "possible" (new field discoveries in formations previously produc-
tive) , and 534 trillion are classified as "speculative" (new field
discoveries in formations or provinces not previously productive).-/
As indicated by Table V-9 on the next page, 613 trillion cubic
feet or 521 of the estimated potential gas supply are located in onshore
areas of the Lower 48 States, 238 trillion or 201 in offshore areas, and
327 trillion or 28% in Alaska. Thus, nearly half of the supply lies in
areas of more costly marine drilling and/or in areas presently, inaccessible
to markets in the Lower 48 States. Moreover, 162 trillion cubic feet of
the onshore potential (or about 13% of the total U.S. potential) are esti-
mated to lie below 15,000 feet in depth.
The U.S. Geological Survey recently estimated undiscovered,
recoverable gas at approximately 2,100 trillion cubic feet (plus another
4,000 trillion of submarginal undiscovered gas not considered recoverable
I/ Potential Gas Committee, Potential Supply of Natural Gas in the United
~~ States, October 1971.
The potential gas supply estimates do not include proved reserves --
defined as all gas estimated to be producible from tested formations
under existing operating and economic conditions without regard as to
size, use, or disposition of any production. Proved reserves in an
undrilled area, however, must be so related to the developed or tested
leases and to known field geology that its productive ability is assured.
Detailed definitions of the "probable," "possible" and "speculative"
categories of potential gas supply are found on page 30 of the above-
cited report of the Potential Gas Committee.
V-22
-------
Table V-9
U. S. POTENTIAL GAS SUPPLY BY AREA
AS OF DECEMBER 31, 1970
(Trillion Cubic Feet at 14.73 Psia)
Area
Probable
Possible Speculative
Total
Onshore (Lower 48 States)
Atlantic Coast and
Appalachian
(excluding Florida)
Florida, Alabama,
Mississippi
Mid-Continent (north
of Arkansas and
Kansas)
Arkansas, North Louisiana,
East Texas
South Louisiana
Texas Gulf Coast,
South Texas
West Texas, Southeast
New Mexico
Kansas, Oklahoma,
Texas Panhandle
New Mexico, Arizona
Rocky Mountain
Pacific Coast, Nevada,
Idaho
Subtotal
Offshore (Lower 48 States)
Atlantic Coast
Florida, Alabama,
Mississippi
South Louisiana
Texas Gulf Coast
Pacific Coast
Subtotal
Total - Lower 48 States
Alaska
Total - United States
25
3
£/
10
18
55
15
27
11
12
1
179
_ _
--
31
7
1
39
218
39
257
7
15
5
25
25
33
32
46
a/
30
7
227
__
—
52
40
7
99
326
61
387
34
14
4
58
3
15
11
23
5
30
3
207
36
39
16
6
3
100
307
227
534 1
66
32
9
93
46
103
58
96
16
72
11
613
36
39
99
53
11
238
851
327
,178
a./ Less than 1 trillion cubic feet.
Source: Potential Supply of
December 31, 1970,
Natural Gas
Potential Gas
in the United
States as of
Committee, October 1971.
V-23
-------
today) .-' The total of 2,100 trillion cubic feet includes 1,000 trillion,
or 481, in the Lower 48 States onshore; 850 trillion, or 401, in offshore
areas (including Alaska); and 480 trillion, or 22%, in Alaska (including
offshore and onshore).
Potential gas reserves in Canada have also been estimated to
21
exist in abundant quantities — -- but again in large part in frontier
areas which are relatively inaccessible and costly for exploration and
drilling. In 1969 the Canadian Petroleum Association published an esti-
mate totalling 725 trillion cubic feet, broken down by area as follows:
Trillion
Area Cubic Feet
Western Canadian Sedimentary Basin (principally includes
Alberta, plus a corridor northwest along the Mackenzie
River to the Arctic Ocean) 270
Arctic Islands 261
Eastern Canada Offshore 150
Hudson Bay 17
Gulf of St. Lawrence 11
British Columbia Offshore 11
Other 5
725
Finally, in view of the expectation of growing LNG imports into
the United States, it is of interest to examine natural gas reserve esti-
mates for different countries of the world. These estimates are shown on
I/ Geological Survey Circular 650, Energy Resources of the United States.
2/ Proved reserves in Canada represent a different situation. According
to the Reserves Committee of the Canadian Petroleum Association,
remaining marketable natural gas reserves in Canada as of December 31,
1971 totalled 55.5 trillion cubic feet -- equivalent to only 201 of
the estimated remaining proved reserves in the United States at the
end of 1971.
V-24
-------
Table V-10. Two facts are particularly noteworthy. One is the discrepancy
between the proportion of proved world reserves controlled by the United
States (only about 16%) and its proportion of world gas production (over
50%). Second is the magnitude of overall proved world reserves controlled
by the USSR (321), the Middle East (20%) and Africa (11%) -- a total of 63%.
Estijnated reserves and production for countries mentioned as
possible sources of LNG for U.S. markets at some future time are com-
pared below.
Reserves Production
(Billion Cubic Feet)
Algeria 106,500 105
Nigeria 40,000 141
Libya 29,500 645
Iran 200,000 1,245
Venezuela 25,400 1,838
Ecuador 6,000 3
Trinidad and Tobago 5,000 117
Australia 24,800 98
Indonesia 4,500 113
USSR 546,000 7,484
B. Proposed Sanctity of Contract Legislation
Assuming reactivation of the sanctity of contract bills before
the last Congress, it is recommended that EPA join with other federal
government bodies -- including the Departments of Interior and Commerce,
and the Office of Management and Budget -- which have supported this
legislation. These bills would not bring about decontrol of producer
prices. Rather, they are intended to remove some of the difficulties
which have hampered effective regulation in the past and have con-
tributed to the drop-off of exploratory efforts.
V-25
-------
Table V-10
Page 1 of 2
ESTIMATED PROVED WORLD GAS RESERVES AND PRODUCTION BY COUNTRY
1971
(Volumes in Billions of Cubic Feet)
Country
United States
Canada
Total
Argentina
Bolivia
Brazil
Chile
Columbia
Ecuador
Mexico
Peru
Trinidad and Tobago
Venezuela
Total
Austria
Denmark
France
Italy
Netherlands
Norway
Spain
United Kingdom
West Germamy
Yugoslavia
Total
Algeria
Angola
Egypt
Gabon
Libya
Morocco
Nigeria
Tunisia
Total
Total
Production
22,949.1
2,987.8
25,936.9
285.0
100.9
43.6
2-33.4
83.6
3.2
660.9
0.6
117.4
1,837.5
3,366.1
68.1
--
287.4
460.8
1,537.3
--
--
666.9
488.5
45.0
3,554.0
105.1
11.7
39.3
131.0
644.6
1.2
140.8
0.9
1,074.6
Year-End
Proved
Reserves
278,800
55,400
334,200
7,600
5,000
5,000
2,200
2,500
6,000
11,500
2,500
5,000
25,400
72,700
550
500
6,900
6,000
83,000
10,000
500
40,000
14,000
1,800
163,250
106,500
1,500
7,500
6,500
29,500
L8
40 , 000
1,500
193,000
Percent of
R/P World
Ratio Production
North America
12.1
18.5
12.9
Latin America
26.7
49.6
114.7
9.4
29.9
1,875.0
17.4
4,166.7
42.6
13.8
21.6
Europe
8.1
--
24.0
13.0
54.0
--
--
60.0
28.7
40.0
45.9
Africa
1,013.3
128.2
190.8
49.6
45.8
15.0
284.1
1,666.7
179.6
51.2
6.7
57.9
0.6
0.2
0.1
0.5
0.2
--
1.5
--
0.3
4.1
7.5
0.2
--
0.6
1.0
3.4
--
--
1.5
1.1
0.1
7.9
0.2
--
0.1
0.3
1.5
--
0.3
--
2.4
Percent of
World
Reserves
3.2
19.2
0.4
0.4
1.5
4.2
0.4
0.3
4.8
0.6
2.3
0.8
0.1
9.3
6.1
0.1
0.4
0.4
1.7
2.3
0.1
11.1
V-26
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Table V-10
Page 2 of 2
ESTIMATED PROVED WORLD GAS RESERVES AND PRODUCTION BY COUNTRY
1971
(Volumes in Billions of Cubic Feet)
Country
Abu Dhabi
Bahrain
Dubai
Iran
Iraq
Israel
Kuwait
Neutral Zone
Oman
Qatar
Saudi Arabia
Syria
Turkey
Total
Afghanistan
Australia
Bangladesh
Brunei-Malaysia
Burma
India
Indonesia
Japan
New Zealand
Pakistan
Taiwan
Total
Albania
Bulgaria
China
Czechoslovakia
East Germany
Hungary
Poland
Romania
USSR
Total
Total World
Total
Production
16.0
--
1,245.1
18.0
3.1
--
--
--
3.0
--
--
--
1,285.2
91.5
98.0
20.0
--
2.2
16.0
113.2
85.4
1.9
115.1
24.1
567.4
Year-End
Proved
Reserves
10,000
5,000
1,000
200,000
22,000
60
35,000
8,000
2,000
8,000
52,000
700
170
343,930
4,900
24,800
4,000
7,500
100
1,500
4,500
400
6,000
15,500
600
69 , 800
R/P
Ratio
Near East
._
312.5
--
160.6
1,222.2
19.4
--
--
--
2,666.7
--
--
--
267.6
Asia Pacific
53.6
253.1
200.0
--
45.5
93.8
39.8
4.7
3,157.9
134.7
24.9
123.0
Percent of
World
Production
._
--
--
2.8
0.1
--
--
--
--
--
--
--
--
2.9
0.2
0.2
--
--
--
--
0.3
0.2
--
0.3
0.1
1.3
Percent of
World
Reserves
0.3
0.1
11.5
1.3
--
2.0
0.4
0.1
0.4
3.0
--
--
19.7
0.3
1.4
0.2
0.4
--
0.1
0.3
--
0.4
0.9
--
4.0
Soviet Nations
1.8
149.5
31.0
--
127.6
187.3
1,001.2
7,483.6
8,982.0
44,766.2
300
1,000
4,000
500
500
3,000
5,000
6,000
546,000
566,300
1,743,180
„_
555.6
26.8
16.1
--
23.5
26.7
6.0
73.0
63.0
38.9
__
--
0.3
0.1
--
0.3
0.4
2.3
16.7
20.1
LOO.O
__
0.1
0.2
--
--
0.2
0.3
0.4
31.3
32.5
100.0
Source: International Petroleum Encyclopedia, 1972.
V-27
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Hearings were held in September 1971 by the Subcommittee on
Communications and Power of the House Interstate and Foreign Commerce
Committee on H.R. 2513 (introduced by Rep. Murphy of New York) and in
March 1972 by the Senate Commerce Committee on S. 2505 (introduced by
Senator Hansen of Wyoming) and S. 2467 (introduced by Senator Hollings of
South Carolina).- The basic purpose of these bills is to immunize new
producer contracts -- once approved by a final FPC order -- from subsequent
change by the Commission. Such contracts, however, would have to be
submitted to the FPC for initial review to determine whether they are
just and reasonable and required by the public convenience and necessity.
This review would extend to the entire pricing structure (initial price
plus provisions for fixed escalations), the length of the contract and
other contract terms . In passing on the contracts, the Commission would
be prohibited from using the cost of service, public utility rate base
method and instead would look to supply and demand factors, price levels
estimated to be required to elicit adequate supplies for the interstate
market, and economic and cost trends.
The sanctity of contract legislation would permit a producer to
begin deliveries pending FPC review of his contract. If review were com-
pleted within nine months from the date of filing of the contract, the
producer would be required to refund any amounts which the Commission might
determine to be unreasonable, or else could terminate deliveries. However,
If H.R. 2513 and S. 2505 are identical, and S. 2467 differs only with
respect to small producers.
V-28
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if the FPC failed to reach a decision in nine months, no refunds could be
ordered.
Under the bills, the FPC would also be prohibited from reducing
any rate in an existing contract approved after the date of enactment. But
it would retain authority to act on any price increases of an indefinite
nature in both existing and future contracts.
Finally, the sanctity of contract bills would exempt small pro-
ducer contracts (involving daily contract quantities not more than 10,000
Mcf/d) -- or, in the case of S. 2467, small producers (those with annual
jurisdictional sales not more than 10,000,000 Mcf)— -- from FPC regula-
tion.
Introduction of the above bills was preceded by extensive efforts
by distributors, pipelines and producers to work out an acceptable legisla-
tive package to all three branches of the natural gas industry. That such
efforts were successful deserves mention, considering differences which
divided especially distributors and producers in the past.
A major benefit of the sanctity of contract legislation would
be the avoidance of the price confusion and risk which characterized
guideline and in-line pricing policies in the 1960's. In South Louisiana,
for example, the FPC twice rolled back the guideline levels and then, in
1968, set area price levels below these guidelines. Such action was hardly
inducive to producers to commit new reserves to the interstate market as
I/ This version of the small producer exemption would, in effect, codify
action already taken by the FPC to exempt small producers from nearly
all regulatory requirements. The FPC action, however, still faces
judicial review.
V-29
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opposed to the intrastate market where contract terms were binding. While
sanctity of contract assurance would not guarantee commitment of gas to
interstate markets, it would considerably strengthen the competitive
position of purchasers of interstate gas.
Another principal benefit of the proposed sanctity of contract
legislation is that it would free the FPC once and for all from the cost
of service ratemaking method. Although there are some (e.g., the American
Public Gas Association and certain other consumer groups) who maintain
that the cost of service approach is the only means of protecting consumers
against unjust and unreasonable rates, it is our view that experience in
the area rate proceedings over the past decade has demonstrated applica-
tion of the cost method to producers on an area basis to present nearly
as many difficulties as its application on an individual company basis.
Significantly, in two recent area rate decisions, the FPC recognized that
cost calculations cannot be mathematically precise, but rather reflect
arbitrary judgments as to allocation procedures and a wide margin of error
as to both data and methods used.— Relieved from any precedents or
pressures to attempt to apply this method further for new gas supplies,
the FPC could proceed to develop more rational regulatory standards
giving greater recognition to market forces and the incentives necessary
to elicit greater supply additions.
With a few exceptions, critics of the bills do not oppose the
sanctity of contract concept but argue rather that the proposed legislation
I/ FPC Opinion 595 issued May 6, 1971 in the Texas Gulf Coast Area Rate
Proceeding, AR64-2, et al., FPC Opinion No. 598 issued July 16, 1971
in the Southern Louisiana Area Rate Proceeding (AR69-1 et al.).
V-30
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goes beyond what is necessary to accomplish that goal.— For example,
it is claimed that only a relatively simple amendment to the Natural Gas
Act is needed to provide that a rate, once permanently certificated or
found just and reasonable, would not thereafter be subject to reduction.
One of the chief objections to the sanctity of contract bills,
in the form presented to Congress, is that sanctification of contract
termination provisions would destroy the assurance of supply continuity
now provided under the abandonment provisions of the Natural Gas Act— and
would encourage short-term sales contracts, with disastrous price con-
sequences under gas shortage conditions. Other objections are that the
legislation would create as much new confusion as it would eliminate as
the FPC struggled to develop new regulatory standards, that nine months
is far too short a time for FPC review of new contracts, that the cost
of service method of ratemaking should not be outlawed entirely but
rather should be made a factor for consideration at the FPC's discretion,
and that exemption of contracts covering daily volumes up to 10,000 Mcf/d
would result in freeing a substantial portion of sales by large producers
from regulation.
These and other objections reflect a fear of departing very far
from the present regulatory scheme. Without undertaking here to answer
all of the objections, it appears obvious that the supply deficiencies
I/ Joseph Swidler, FPC Chairman from 1961 to the spring of 1966, takes
this position, among others.
2/ As discussed in Chapter IV, no producer may now abandon sales to an
interstate pipeline, even after their contract has expired, without
FPC approval. Such approval is generally not given except in the
case of depletion of supply or uneconomic production.
V-31
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projected for the future are sufficiently great as to warrant at least
the remedies sought by the sanctity of contract legislation. The most
serious reservation relates to the potential for short-term contracts
and decrease in assured continuity of supply. However, the inability of
producers to terminate deliveries upon expiration of a contract is
undoubtedly a factor contributing to the area of uncertainty. Further,
it has been argued that, even if there were a trend toward contracts
shorter in duration than the 20-year term typical in the past, elimina-
tion of the need to provide for contract price escalations for so long
a period in the future could result in lesser price increases than
might otherwise prevail.
C. Legislation to Decontrol Wellhead Prices
Legislation to deregulate wellhead sales is urged by those who
believe that the sanctity of contract proposal does not go far enough in
restoring the ability of gas prices in the field to react to market forces.
Basically, the argument is that in a workably competitive industry, the
balancing of supply and demand is best achieved through the workings of
the market place. Efforts of the FPC to approximate the functioning of
the market place, the argument continues, are beyond its capability --
and, indeed, beyond the capacity of any regulatory body -- and hence are
doomed to failure. Thus, the regulation of the producing industry having
led to a serious imbalance of supply and misallocation of resources, the
market should be allowed to return to its traditional economic function.
As one advocate expressed it:
V-32
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"Whether imposed by statutory amendment or by Commission election
to alter the existing area rate methodology, any approach requiring
the determination of producer prices by the Commission on the basis
of some subjective market standard or criteria would fall far short
of a satisfactory solution. Such standards are extremely difficult
to define and thus are usually couched in general terms and, as
a result, the Commission would be compelled in all likelihood to
define, qualify and quantify the innumerable factors that could
affect the market and might have to be considered in each instance.
To submit market forces to the subjective interpretation of a
regulatory body, regardless of its expertise or good intentions,
can only lead to a distortion of their effect with imprecise and
unresponsive results. In the final analysis, . . . establishment
. . . of a market value as the permissible price level . . . can
be more readily and accurately achieved by the free interplay of
supply and demand dynamics unencumbered by any futile regulatory
attempt to decipher the complicated considerations and the subtle
interrelationships involved in a free market. Inject market forces
into the administrative crucible and no one will recognize the
results." I/
Deregulation proposals take three general forms: decontrol of
all gas (under both new and existing contracts), decontrol of gas under
new contracts only, and decontrol of new gas contracts subject to certain
safeguards. In the third category, bills were introduced in the last two
sessions of Congress by Senator Tower and Rep. Price (both of Texas) to
eliminate FPC rate control over future contracts, provided that (1) the
acreage involved had not previously been dedicated to the interstate
market, (2) contract prices, including any escalations, are expressed
in terms of a definite charge per unit, with indefinite price escalations
prohibited, (3) all other contractual provisions (such as quality, rate of
take, prepayment arrangements, and abandonment of service), regardless of
their effect upon contract prices, continue to be subject to Commission
I/ Address by Carl E. Bagge before the annual meeting of the American
~~ Association of Oilwell Drilling Contractors in Dallas, Texas on
September 24, 1970. Mr. Bagge was then a member of the FPC.
V-33
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approval and review. The form of this legislation was suggested by former
FPC Commissioner Carl E. Bagge.
Decontrol of producer prices for new gas are known to be under
active consideration by the Administration at this time. Support for
legislation of this nature has been expressed by officials of the Interior,
Commerce and State Departments, and by the Director of the Office of
Emergency Preparedness. The President's Council of Economic Advisers has
endorsed action to allow the price of gas, at least new gas not previously
dedicated to interstate purchasers, to approach market-clearing levels.—
In addition, two current FPC members -- Pinkney Walker and Rush Moody --
favor immediate decontrol of domestic wellhead prices. Commissioner
Walker— has taken the position that there was no valid economic basis for
subjecting producer sales to federal regulation in the first place and,
given the present state of affairs, no reason for perpetuating this
regulation. Failure to decontrol, and thereby permit gas producer prices
to reach market-clearing levels, will prevent domestic production and
exploration from competing for investment dollars.—
On the other hand, efforts to deregulate producers are likely
4/
to face opposition from the distributor segment of the industry- and are
1?Annual Report of Council of Economic Advisers, January 30, 1971.
21 Commissioner Walker resigned on December 31, 1972 -- following the
drafting of this report.
3/ Address of FPC Commissioner Pinkney Walker to Pacific Coast Gas
~~ Association, September 21, 1972.
4/ A recent speech by the outgoing President of the American Gas
Association indicates a concern of this approach. In an address
to the AGA annual convention on October 16, 1972, Ralph T. McElvenny
warned against regarding deregulation of producer prices or substan-
tially higher ceilings as the answer to the supply problem.
V-34
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sure to be opposed by many other interests as well. Among others, FPC
Chairman Nassikas and recently resigned Commissioner John A. Carver, Jr.
have come out against deregulation on the principal ground that the results
would be chaotic in a time of supply shortage. They and others question
whether producer markets are sufficiently competitive to permit adjust-
ment to realistic price levels and whether, once gas price ceilings are
removed, interfuel competition could provide any meaningful restraints on
increasing gas prices. The answer, they contend, is not elimination of
regulation but rather more intelligent regulation giving greater weight
to marketplace operations.
Further, the reaction of Congress to any decontrol proposals is
problematical at best. The sanctity of contract bills did not go beyond
committee hearings in the last session. Some 35 members of Congress
attacked the FPC for a recent measure (the "optional certification pro-
cedure") to permit prices higher than area ceilings for new sales under
certain conditions, including 19 House members who have appealed this
action to the courts. Hence, decontrol measures are clearly uncertain
of passage.
Substantively, decontrol proposals raise fundamental questions
affecting policy alternatives. One problem involves the degree to which
producers are competitive, i.e., whether market prices will be set by
competitive forces or will reflect a bargaining edge on the part of pro-
ducers. By traditional measures of concentration of control, the pro-
ducing industry is highly competitive. Large numbers of producers compete
for leases and sell natural gas. On the other hand, it is contended that
V-35
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the bargaining motivation of pipelines is diluted by their ability to pass
on all gas purchase outlays to their customers in resale rates. Therefore,
any inequality which may exist between sellers and buyers is greatly enhanced
in favor of the sellers in a time of supply shortage.
A second problem concerns the extent to which the price of gas
would rise and the degree to which supply would increase if FPC wellhead
regulation were eliminated. The price elasticity of supply is a much
studied topic, both in academic and regulatory circles. No definitive
answers have been reached, and study is complicated by the large number of
variables which must be considered in the overall picture. There is gen-
eral agreement, however, that supply is responsive to price -- although
with reservations as to how much and over what period of time. Some fear
that the response would not come close to matching the public expectations
created by the sharp price rises which would result from decontrol of
either all producer prices or new gas prices only.- This, in turn,
could cause a "backlash" reaction and pressures for even more stringent
price controls than now apply. It is also suggested by some observers
that prices might exceed market-clearing levels in the short term until
producers were able to respond to the new incentives or consumers were
able to either reduce consumption or switch to alternative fuels, thereby
balancing supply and demand.
\l At least one suggestion has been made for decontrol of new gas prices
~ on an experimental basis, for a period of three years, to test the
supply-price relationship. (Statement of John F. O'Leary, former
Interior Department and FPC Staff official, before the Joint Economic
Committee, June 8, 1972.)
V-36
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Despite the uncertainties and reservations concerning the effects
of decontrol, legislation in this direction would assuredly spur greater
exploratory efforts and lead to increased gas supply additions. The need
for development of market-based pricing criteria by the FPC, a task which
would undoubtedly be attended by enormous complexities and litigation,
would be avoided. Presumably, any need for end-use rationing by adminis-
trative decree, again a task entailing subjective judgments, would also
be obviated. These are all desirable objectives.
Should EPA desire to support the decontrol route, perhaps the
type of proposal most likely of passage by Congress-— (and the one least
disruptive to present consumer markets) would be legislation along the
lines proposed by Senator Tower. In other words, deregulation would be
limited to new gas contracts only, with safeguards to preserve some measure
of FPC control or alternatively to provide for some type of arrangements
for monitoring the competitiveness of market behavior. For example, it
might be possible to establish a system of continuing contract surveillance
to signal whether a contract were out of line with expected market
behavior. Investigations could then be launched to determine whether
observed variations from expected values are explained by market conditions.
D. Legislation to Expand Federal Regulation
Another general approach advocated to meet the current gas short-
age is the expansion, not the reduction, of federal regulation. In broad
form, this approach contemplates the establishment of a national system of
I/ As discussed supra, we make no prediction as to the success of a
decontrol bill in any form in the Congress.
V-37
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end-use priorities, with uses at the low end of the scale to be proscribed
to the extent needed to balance sales with deliverable supplies, together
with extension of FPC jurisdiction to cover regulation of intrastate sales
and direct industrial sales by producers and pipelines.—
Among the proponents of this course of action are two former FPC
Chairmen, Joseph C. Swidler (now Chairman of the New York Public Service
Commission) and Lee C. White. (Mr. Swidler served as Chairman from 1961
to 1966 and Mr. White from 1966 to 1969.) Suggestions for the establishment
and implementation of gas rationing plans by the federal government are
being voiced with increasing frequency by others as well.
A major argument advanced in support of FPC regulation of intra-
state and direct industrial sales is the need to prevent unregulated
markets, primarily in producing states, from siphoning off most new gas
production for low priority uses -- such as boiler fuel -- while other
states are experiencing shortages for preferred uses. To illustrate the
extent to which such siphoning off has already occurred, it is pointed
out that the proportion of new gas committed to intrastate markets from
the Permian Basin producing area rose from about 161 in 1966 to over 90?
in the first half of 1970. It is thus argued that regulatory exemption
I/ Last June, Senator Griffin of Michigan introduced a bill (S. 3794) to
grant the FPC authority to regulate intrastate transportation and
sales for resale, as well as direct industrial sales whether in inter-
state or intrastate commerce. No hearings were held, and no action
was taken on this bill in the last Congress.
With respect to direct industrial sales by pipelines, the FPC has
been held by the Supreme Court to have jurisdiction over curtailments
by virtue of its authority over the transportation of gas in inter-
state commerce.
V-38
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which permits the channeling of scarce gas supplies to a few favored areas
should be eliminated.
Pressures for federal end-use controls over all gas markets
reflect growing concern respecting the potential consequences of gas supply
curtailments. If the present gas situation continues to deteriorate, some
sort of controls may be needed to avoid curtailment of service to existing
residential and commercial customers who have no feasible alternative to
use of gas. However, a near insuperable question is what class or classes
of customers should be forced to suffer delivery reductions in order to
enable continued service to other classes. While there is little dispute
that residential and commercial categories deserve the highest priority,
who is to determine the lowest priority? Those advocating end-use con-
trols generally cite boiler fuel as the "most inferior" use. Such a flat
condemnation, however, is subject to controversy in view of the need for
gas -- assuming no other available clean-burning fuels -- to meet air
pollution standards.
Moreover, the experience in pipeline curtailment proceedings
before the FPC has demonstrated the difficulties in formulating acceptable
and equitable priorities for customers of individual pipelines. To attempt
to apply a single set of priorities to all areas of the nation would be
an extraordinarily difficult task. Patterns of gas usage vary consider-
ably in different regions, so that an ordering of equitable priorities in
one area would not necessarily be a reasonable or fair solution in
another area. In short, the problems associated with comprehensive end-
V-39
-------
use regulation by the FPC or any other federal body seem so formidable
as to dictate avoidance of this approach if at all possible. —
Above all, proposals for end-use control and/or intrastate sales
regulation constitute measures for coping with the gas shortage, not for
relieving it. In terms of eliciting additional supplies of gas, their
effect would appear to be nil --or perhaps even counterproductive for
the reason that increased regulation could create a disincentive for
investment. On the other hand, if wellhead prices were permitted to
rise to realistic market levels, purchasers of gas for interstate markets
should again be able to compete with intrastate purchasers, and the
tendency for newly available gas supplies to be committed to intrastate
markets should diminish.
One suggested variation of the end-use control approach would
be to allow a material increase in the price of new gas to encourage greater
resource development and at the same time to impose a national excise tax
on the ultimate sale of gas, with the tax heavier on the less preferred
uses and zero on the "highest" uses.— Receipts from these taxes would be
paid into a "gas supply trust fund" which could be used by the government
for expanded research and development programs, nuclear fracturing,
I/ Even so, the deterioration in the gas supply situation recently caused
the FPC to establish eight end-use priorities for use by all interstate
pipelines throughout the nation during periods when curtailments of
service are necessary (FPC Order No. 467, issued January 8, 1973). In
addition, the FPC has advanced a proposal to adopt the same priorities
nationwide in considering applications for sale of new or increased
gas supplies (Docket No. R-467).
2/ Statement of Charles H. Frazier, independent consultant, before the
Joint Economic Committee, June 7, 1972.
V-40
-------
offshore Atlantic exploration, and numerous other such purposes. A basic
difficulty with this proposal is that it is predicated on the establish-
ment of national end-use priorities which, as discussed above, involves
enormous complexities. It is also difficult to perceive how the proposal
would lead to any significant expansion of supply since a large portion
of any permitted increase would go to the U.S. Treasury rather than to
producers who need incentive to develop domestic gas resources in the
years ahead.
Still another suggestion which has been advanced by others is
the creation of a federal government corporation to explore for oil and
gas on publicly-owned lands. Two particular advantages of such a corpora-
tion are pressed: a singular motivation to expedite maximum development
of resources on federal lands, and the derivation of first-hand data on
costs and other aspects of gas operations which individual producing com-
panies are reluctant to disclose on confidential grounds. One of the
proponents of this proposal is former FPC Chairman Lee White. In hearings
before the Senate Interior Committee in February 1972, Mr. White testified
as follows:
"A government-owned corporation to explore for and develop
petroleum resources on publicly-owned lands could serve to
supplement the privately-owned segment of the petroleum industry,
and, although it should manage the nation's resources in an
efficient manner and on a profit-making basis, it would also
be expected to be strongly motivated by the need to meet national
energy requirements. One of the recurring problems faced by
the FPC and the government generally has been the reluctance
of the natural gas industry to make available data relating to
their gas operations. This has made even more difficult the
FPC's job of establishing area rates .... [T]he existence
of a National Energy Resources Corporation operating in these
areas would be extremely useful in supplying information and
V-41
-------
data on actual costs and operations in a field that has proved
to be most difficult to regulate. This nation has been willing
to use its wealth and its resources in a proprietary manner
when convinced that such an approach was the best solution to a
national problem -- stockpiling of strategic goods, development
and ownership of nuclear devices, and operation of the Alaska
railroad, to name a very few." I/
However, the wisdom of establishing a government corporation to
attain these goals is questionable. From the standpoint of stimulating
greater additions, it is unclear what a federal corporation could do that
private companies could not do with a much shorter time lag, given adequate
price incentives. Also, in the absence of very sizeable appropriations,
a government corporation could explore and develop only a small portion
of public lands. Further, there can be no assurance that a government
corporation would operate efficiently and hence provide any reliable
information for yardstick purposes.
E. FPC Modification of Producer Regulation
As indicated in a previous section, the FPC has recognized the
current shortage of natural gas and acknowledged the role of past pricing
policies in causing the supply situation today. Moreover, the Commission
has taken a number of measures in an attempt to alleviate the shortage,
some more far-reaching than others. In part, the outcome of these measures
is uncertain due to pending judicial review proceedings.
There are two basic types of actions available to the FPC to
induce increased gas supply. The first is allowance of higher field
prices in order to restore incentive for an adequate level of exploratory
I/ Statement of Lee White, former FPC Chairman, before the Senate Committee
on Interior and Insular Affairs, February 25, 1972.
V-42
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and developmental effort. The second is encouragement of gas exploration
and production operations by as broad a segment of companies as possible.
This includes pipelines and distributors.
1. Optional Certificate Procedure
On August 3, 1972 the FPC adopted an optional procedure for
certificating new gas sales (Order No. 455) , clearly its most innovative
supply-inducement step taken to date. The new procedure is intended to
provide two incentives to domestic production: authorization of sales of
gas not previously available to the interstate market at prices in excess
of area prices (specifically, at a price "shown to be in the public
interest"), and reduction of future rate uncertainty to the extent
possible within the FPC's present statutory powers.
The new measure is also intended as a response to the dilemma of
certificating new base load supplies of substitute or supplemental gas at
prices significantly higher than the prices of currently available
domestic wellhead supplies. The Commission explained:
"In summary, if our domestic natural gas resources are not
developed in a timely manner and consumers of natural gas are
forced to satisfy a commensurately larger portion of their energy
requirements by using either substitute or supplemental gas sup-
plies, e.g., imported liquefied natural gas, propane, reformed
hydrocarbons, gasified coal, imported natural gas, or other fossil
fuels, the net effect is higher energy costs throughout the economy,
with resulting inflationary pressures. Higher prices for domestic
gas, if paid for new supplies, will result in a cheaper mix of
energy supplies and thus represent a better alternative.
"In view of these facts, we are unwilling to leave untested the
producing capacity of the United States." (Order No. 455, Mimeo,
p. 3.)
V-43
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The optional certificate procedure is available for both long-
term and short-term contracts covering sales to interstate pipelines of
gas produced from wells commenced after April 6, 1972 (the date the Commis-
sion gave notice of its proposal to adopt the new procedure), and sales of
gas not previously sold in interstate commerce except under emergency pro-
cedures. However, use of the optional procedure is subject to the following
restrictions, among others: (a) the seller under the contract must have
discharged, or be prepared under an acceptable plan to discharge, all refund
obligations owing under past FPC orders for sales in the same geographical
area as the production covered by the contract; (b) the contract must con-
tain no indefinite pricing clauses (with certain limited exceptions),
including provisions for adjustment to any higher area rates which might
subsequently be fixed (so-called area rate clauses); (c) the seller must
agree to waive all rights to contingent future escalation of rates pro-
vided in past area rate decisions for flowing gas produced in the same
geographical area as the production covered by the optional procedure
application;— (d) deliveries may commence pending FPC review but must
be made at applicable area ceiling rates for a period of six months
(although thereafter may be made at contract rates without refund obliga-
tion if the Commission has not acted); and (e) the seller must provide
"factual support" demonstrating why the requested certification is required
by the public convenience and necessity, and the purchaser must provide
I/ This condition would bar producers from claiming any rate escalations
provided in the FPC's area rate decisions for the South Louisiana area
(Opinion No. 598) and Texas Gulf Coast area (Opinion No. 595) contin-
gent upon industry dedication to interstate commerce of specified
quantities of new gas reserves over roughly the next five years.
V-44
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information respecting systemwide supply, deliverability life, implementa-
tion of any curtailment plans, emergency purchases of gas, and purchases
of LNG or other supplemental supplies.
The FPC stressed, and the restrictions imposed so reflect, that
the new procedure is not meant to supplant area rate procedures but rather
to provide an alternative for producers willing to forego certain advantageous
features of the South Louisiana and Texas Gulf Coast area rate opinions in
exchange for greater certainty of certificated prices. As to certainty,
the FPC acknowledged that it cannot bind future Commissions not to modify
rates prospectively under Section 5 of the Act. But, under the optional
procedure, the FPC intends to examine the justness and reasonableness of
the proposed rates at the time of certification in an effort to avoid sub-
sequent rate determinations under either Section 4 or 5. Thus, it is the
Commission's intent to provide certainty of rates to the extent it is able
to do so. However, given the limits of the Commission's ability in this
regard, it is clear that the need for legislation to assure contract
sanctity has not been eliminated.
While Order No. 455 promulgating the optional certificate has
been heralded as a positive step in the direction of encouraging needed
exploration and development of new gas supplies,— it is by no means
I/ In Order No. 455, the FPC called particular attention to comments
expressed by the Departments of Commerce and Interior, and by the
Environmental Protection Agency, in favor of the new procedure. How-
ever, the FPC ignored EPA's further suggestion that pipeline companies
receiving additional gas supplies certificated under the optional pro-
cedure should be required to submit end-use information respecting
the additional volumes.
V-45
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universally accepted or free from reservations respecting its potential
effectiveness.
For example, nearly all producers took the position --in com-
ments filed prior to the adoption of the rule -- that the necessity to
give up contingent escalations of flowing gas rates provided in the South
Louisiana and Texas Gulf Coast area decisions would largely nullify the
incentive offered by the new procedure and defeat its purpose, particularly
for companies with substantial flowing gas production in areas holding the
greatest promise for new gas discoveries. There is little logic, the pro-
ducers contended, in holding out an incentive in the form of above-ceiling
rates for new gas dedications and then reducing or removing it by a penalty
on flowing gas rates.
From the other side, at least 15 Senators and 20 Congressmen --
as well as certain consumer interest groups -- accused the FPC of usurping
the legislative function by seeking to effect, through administrative
action, the "sanctity of contract" proposals then pending before Congress.
The FPC's new procedure was further condemned as tantamount to deregulation
of all new gas sales in defiance of Congressional intent underlying the
Natural Gas Act. Some legislators additionally contended that area rates
permitting the recovery of all expenditures incurred in exploration, develop-
ment and production of gas, plus a 15% return, constitute adequate incentive
to bring forth the necessary supplies. Consequently, they concluded, the
end result of the Commission's actions will be to provide a "multi-billion
dollar windfall" to producers at the expense of the gas consuming public
which the Natural Gas Act is intended to protect. Figures up to $1 trillion
V-46
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were thrown out as estimates of the potential windfall to producers and
cost to consumers.—
More temperate critics question whether the Commission's
optional procedure will be effective in channeling new supplies to the
interstate markets since such markets are likely to be always outbid by
intrastate markets as long as intrastate sales remain unregulated. Hence,
the problem arises as to whether the additional supplies induced by the
procedure will be worth the additional costs to consumers. Further
criticism has been directed to the FPC's decision to allow use of the
optional procedure for short-term as well as long-term contracts, and to
the provision allowing producers to charge contract rates without refund
obligation after six months if the FPC had not acted on an application by
that time. Essentially, these are the same objections raised with respect
to the sanctity of contract bills before the last Congress.
The above described pleadings reflect the political pressures per-
vading the natural gas pricing issue. They also illustrate the difficulties
I/ The derivation of these estimates is of interest in illustrating the
~~ type of political response evoked by the producer pricing issue. For
example, the $1 trillion figure was calculated by applying an assumed
increase of approximately 50
-------
faced by the Commission in seeking to adopt effective measures to stimulate
increased exploratory and development efforts. Despite the severe decline
in overall proven U.S. reserves and in supplies dedicated to interstate
pipelines, opposition persists to abandoning past regulatory procedures
-- however ineffective they may have proved in terms of eliciting supply.
Moreover, opponents take their case to the courts, where litigation leads
to further delay as well as the risk of judicial reversal of any signifi-
cant departures from past precedent.
The ultimate outcome of Order No. 455 is unclear, both because
of court appeals brought by a group of "Concerned Congressmen" and the
American Public Gas Association and because of uncertainty as to the
guidelines and criteria to be applied by the Commission in certificating
new sales under the optional procedure. Moreover, assuming court affirma-
tion and the formulation of reasonable certification standards, it will
be some years before the procedure can be evaluated in terms of supply
response and dedications.—
2. Increase in Area Rate Ceilings
Another course of action open to the FPC is to raise area rates
-- either for new gas, or for both new and old gas -- in order to give
greater recognition to market value factors, including prices negotiated
for intrastate sales, prices of competitive fuels, and cost and economic
I/ Thus far, Order No. 455 has not generated much response. In the four
months since its adoption, only four applications have been filed under
the optional certificate procedure. One application -- for sales in
the Texas Panhandle at a price (26.5
-------
trends. This might be done through a reopening of the area proceedings,
consideration of petitions to amend the area ceilings, or possibly through
the establishment of some type of index (such as the BLS wholesale price
or consumer price indexes) permitting periodic price adjustments in accord-
ance with changes in specific economic or cost indicators.-'
At present, the FPC has under consideration a petition to raise
the ceiling rate for new gas production in the Appalachian Basin area
(specifically, gas under contracts dated after February 1, 1972) from
32(£ and 34^/Mcf to 50
-------
gas are an important source of cash for undertaking additional exploration
and development, activities traditionally financed through internally
generated funds because of the nature of the risks involved.
Some have opposed any price increases for flowing gas without
assurance that the additional revenues will actually be devoted to a search
for new gas supplies and not diverted to other types of investment. The
contingent escalation provisions of the FPC's decisions in the South
Louisiana and Texas Gulf Coast area cases -- providing for specified
increases in flowing gas rates upon specified commitments of new gas
reserves to interstate pipelines -- represent a response to this position.
An alternative response, rather than withholding increased rates until the
reserves are discovered, is to grant the increase subject to the require-
ment that the resultant additional revenues be expended in an exploratory
program over and above the normal level of expenditures for such activities.
This type of approach was recently applied by the FPC in a decision per-
mitting Panhandle Eastern Pipe Line Co. to "spin off" its production
properties to an affiliate and permitting the affiliate to sell Panhandle
the same gas at rates higher than Panhandle's previous cost of service
allowance. The Commission required that the entire revenue difference be
spent on a program to explore and develop new gas reserves for Panhandle's
system over the next five years.—
All of these measures present difficulties, but they all repre-
sent ways for increasing the supply of funds available for exploration and
I/ FPC Opinion No. 626, in re Panhandle Eastern Pipe Line Co. and Pan
Eastern Exploration Co. (CP71-237 et alj, issued September 20, 1972,
V-50
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development. As with other possible regulatory changes, the level of new
reserves which would be forthcoming is impossible to ascertain with any
degree of precision.
3. Other Measures
Still other measures which either have been taken, or could be .
taken, by the FPC to induce the eliciting of new gas supplies include: (a)
permitting advance payments by pipelines to producers for exploration and
development, subject to certain qualifications; (b) waiving refunds of
excess revenue collections determined to be owed by producers to pipe-
lines; and (c) encouraging participation in exploration and development
activities by small producers, pipelines and distributors.
The FPC first adopted a policy of permitting pipelines to make
advance payments to producers (and to recover such advances in their rates)
in October 1970. At that time the Commission authorized advance payments
for purposes of exploration, lease acquisition, development and production
of gas. A year later, the FPC decided to terminate recovery in rates of
advances related to exploration and lease acquisition, on the ground that
such advances seemed merely to be causing increased expenditures without a
proportionate increase in supply, but to continue this treatment for
advances related to development and production through December 31, 1972.
At the present time, the advance payment question is under review to
determine whether the current practice should be terminated, extended
either in its present form or expanded so as again to permit advances for
exploration and lease acquisitions.
V-51
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Data collected by the Commission in connection with the above
review reveal that advance payments during the period October 2, 1970
through November 10, 1971 -- the period when advances were allowed for
exploration and lease acquisition, as well as for development and produc-
tion -- are estimated to have resulted in the commitment of over 18 trillion
cubic feet of proven reserves to the pipelines making the advances, as
compared with only about 800 billion cubic feet during the subsequent
period of more restricted rate treatment.— These data appear to indicate
that the advance payment program has made substantial additional reserves
available to interstate pipelines. However, some pipelines and producers
question whether the program has elicited any new reserves which would
not have been brought forth in any event, whether the payments are not
merely a circuitous method of responding to supply and demand factors
(rather than raising the field price), whether the financial resources
of pipelines are sufficient to permit advance payments plus the construc-
tion of necessary transmission capacity and the development of supple-
mental supplies, and whether the effect of the program has not merely
been to raise rates to consumers by millions of dollars without any assured
benefit. As to the last point, it should be pointed out that the FPC now
requires repayment of the advances either from production or through other
means if no production results. On balance, while the efficacy of the
advance payment program is difficult to assess, it has provided funds to
I/ Over the period October 2, 1970 through August 31, 1972, some 22 pipe-
lines made advance payment commitments totalling $1.25 billion [431
for activities in Canada and Alaska) and actually advanced $720 million
during that time.
V-52
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spur exploration and development beyond the level which might have other-
wise occurred.
Waiver of refunds has also been employed by the FPC to encourage
additional funds to be plowed into exploratory efforts.— The most notable
examples were in the South Louisiana and Texas Gulf Coast area proceedings
where the Commission provided that producers would receive a credit of l
-------
for new gas reserves in that area over a five-year period. The FPC has not
acted on this petition, nor has it adopted any general policy respecting
petitions of this type.
While the waiver of refunds involves a number of equitable con-
siderations, refund monies nevertheless are a potential source of supple-
mental funds to be directed to exploratory ventures holding promise for
future supplies. It would seem that, on balance, consumers would benefit
far more by application of the funds in question to a search for addi-
tional gas reserves than by receiving the refund monies either in cash or
as a credit to their gas bill. Under the second alternative, the amount
received by each customer would be minimal.
With respect to wider participation in gas exploration and pro-
duction, the FPC has already largely exempted small producers from regula-
tory requirements (except certain limited filings) in an effort to stimulate
greater activities by this group i/ (FPC Order No. 428, issued March 18, 1971.)
It has also sought to encourage greater pipeline production by allowing area
rates to pipelines and pipeline affiliates for gas produced from leases
acquired after October 7, 1969. (FPC Opinion No. 568, issued October 7,
1969.) The fact that pipeline production has not increased since this
decision undoubtedly reflects in part the inadequate incentive provided
by present area rates for all producers.
The question of distributor participation in gas exploration
and development has not yet been ruled on by the FPC. Several large
distributors have established subsidiaries to search for gas, and some
I/ As noted in Chapter IV, this exemption was reversed by the U.S. Court
~~ of Appeals for the D.C. Circuit on December 12, 1972.
V-54
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have discovered reserves which they seek to have transported by an inter-
state pipeline to their service area. One case presenting this situa-
tion is now before the Commission .
Unquestionably, distributor investment in exploration activities
represents an additional source of risk capital beyond that which pipe-
lines and producers appear willing to commit at the present time. More-
over, because of vested interests of distributors in maintaining service to
retail markets, their motivation to develop gas for interstate consumption
is perhaps more immediate than that of independent producers who will sell
to intrastate markets if that alternative is more rewarding economically.
On the other hand, there is opposition by those who fear that a proliferation
of efforts by large distributors to explore for, and thereby to preempt
gas supplies for their own use, would lead to an inequitable distribution
of gas among different regions and consumers of the nation. Another
opposing argument is that distributor participation in the production
business would result in widespread integration of these two traditionally
separate segments of the gas industry, thereby reducing the motivation of
distributors to check unreasonable attempts to increase the price of gas
at the wellhead. On balance, at least at the present time, these possible
disadvantages may not outweigh the positive benefit of increased funds
available for exploration and the consequent promise of expanded gas
supplies.
4. What EPA Can Do
At some point in the future, EPA might consider a statement of
position regarding various regulatory approaches which could be taken by
V-55
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the FPC in an effort to increase wellhead supplies of gas. As identified
above, some of the possible means open to the FPC at this time include
(a) establishment of higher gas prices reflecting market value and other
pertinent economic considerations; (b) flexibility in applying the
optional certificate procedure; (c) relief from refunds, subject to use
of refund monies in exploration for gas; (d) expansion of the advance
payment program; and (e) distributor participation in gas exploration
operations. However, in the event EPA should decide to support any of
these measures -- all of which involve higher prices to consumers to
increase supply -- this should not be done without thorough prior evalua-
tion of their impact on transportation, distribution and consumption of
gas.
In adjudicatory proceedings at the FPC, any expression of views
by EPA would require formal intervention. The degree to which EPA might
wish to participate in such proceedings will depend on budgetary and
manpower considerations, as well as an assessment of the benefits to be
gained. In FPC rulemaking matters, formal intervention is not required.
EPA has already commented in one important rulemaking matter (regarding
the optional certificate procedure), and it may desire to do so in others.
F. Acceleration of Offshore Leasing
Clearly, one of the most obvious means for encouraging expansion
of natural gas supply is to accelerate, and regularize, the leasing of off-
shore lands. As noted at an earlier point in this chapter, the Potential
Gas Committee estimates 20% of total U.S. potential gas reserves to under-
lie OCS lands (excluding Alaska), while the Geological Survey estimates
V-56
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the OCS share at 401 (including Alaska). Yet only about II of the federal
offshore area (including Alaska) has been leased. Moreover, the U.S.
Continental Shelf out to 200 meters is reachable by technology now at
hand. These considerations all point unmistakably in the direction of
greater offshore leasing.—
Delays in federal offshore leasing in the past have been unfor-
tunate. Oil and gas lease sales in the 1960's were sporadic, with the
result that promising drilling prospects for the industry did not become
available as fast as they might have with a more regular schedule. The
response of the industry to those sales which were held gives every indica-
tion that additional leasing would have been as favorably received. For
example, in every general lease sale held by the Interior Department begin-
ning in 1967, total bonus bids to the U.S. Government exceeded $500 million.
One sale in late 1970 brought a record high total bonus of nearly $850
million.
Interior has recognized the need for an accelerated leasing program
and currently plans two general lease sales annually, encompassing 300,000
- 600,000 acres each, over a five-year period in the Gulf of Mexico. Some
delay in these plans has already been caused by court litigation over the
adequacy of an Interior Department environmental statement. At a minimum,
the five-year schedule should go forward with every effort to avoid or
minimize further delay. Moreover, Interior might consider additional sales
if the industry appears willing and able to explore and develop further
I/ An acceleration of offshore leasing is not exclusive of the need for
higher gas prices to induce exploration and development.
V-57
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acreage at a faster rate. Alternatively, it has been suggested that the
offering of larger amounts of acreage in each sale -- perhaps one million
acres -- would enable development of more prospects and hopefully greater
reserves.
The Gulf of Mexico is a logical point of principal focus in
Interior's current leasing plan since potential gas reserves in DCS lands
off Louisiana and Texas are estimated (by the Potential Gas Committee) at
99 trillion cubic feet and 53 trillion cubic feet, respectively --or,
together, well over 601 of the total offshore potential (excluding Alaska).
Offshore Louisiana, in particular, is already a prolific producing area,
and most of its undiscovered potential is classified either as "probable"
(extensions of existing fields) or "possible" (new field discoveries in
previously productive formations). Estimated potential reserves for off-
shore Texas are primarily in the "possible" category. In addition, the
DCS area off Florida, Alabama and Mississippi -- where one sale is
contemplated by Interior in the five-year period --is estimated to con-
tain potential reserves of 39 trillion cubic feet, although all classified
as "speculative" (new field discoveries in formations or provinces not
previously productive).
Development of the potential in the Gulf of Mexico areas would
obviously make a significant contribution toward increasing the nation's
domestic resource base in both gas and oil. At the same time, efforts
should also go forward to enable leasing in the Atlantic and Pacific DCS
areas, and in the Gulf of Alaska, at the earliest possible time.
V-58
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From the standpoint of location, the Atlantic OCS -- estimated
by the Potential Gas Committee to contain 36 trillion cubic feet of poten-
tial gas reserves -- is an obvious source of providing substantial supply
increases for the East Coast, already heavily dependent on imports of
foreign oil and likely to become also dependent on imports of foreign gas
(LNG) in the future. While East Coast states will benefit from the develop-
ment of potential reserves in the Gulf of Mexico, they must share that
potential with other areas of the country which rely on Gulf Coast sources
for much of their gas supply. By contrast, all of the Atlantic OCS poten-
tial would presumably be available for local East Coast markets. Also,
assuming the 40 trillion cubic feet upper limit of Interior's estimate of
the gas reserves to be developed by its current five-year leasing schedule
in the Gulf of Mexico, the total reserve potential of these OCS lands will
be substantially drawn down rather quickly. All of these factors make the
leasing of the Atlantic Cuter Continental Shelf, assuming appropriate
environmental safeguards, imperative.—
In offshore California, leasing was halted by the major oil
spill occurring in January 1969, and further drilling on some 35 leases
granted prior to that time has been suspended. Interior's authority to
order suspension of operations is now in the courts. Thus, the situation
is uncertain in California at the moment. However, the same basic con-
siderations dictating the leasing of Atlantic OCS lands also favor a
I/ In a report dated November 1971, the U.S. Geological Survey concluded
~~ that the Atlantic Continental Shelf offers good possibilities for oil
and gas production, especially gas. Geologic Framework and Petroleum
Potential of the Atlantic Coastal Plain and Continental Shelf,
Geological Survey Professional Paper No. 659.
V-59
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resumption of leasing of the California OCS and extension of this leasing,
assuming sufficient industry interest and favorable geological data, to
other Pacific Coast offshore areas. Potential gas reserves, estimated at
some 11 trillion cubic feet for the Pacific OCS, represent an obvious source
of additional clean-burning fuel for these states, especially California.
It should also be noted that the Pacific states are not connected by pipe-
line to Gulf Coast sources of supply and hence, lacking a means of trans-
portation, cannot benefit from gas resources discovered in the Gulf of
Mexico.
It is, of course, understood that OCS leasing should go forward
only under stringent environmental safeguards. The danger of oil spills
can never be entirely eliminated. However, regulations and enforcement of
standards to prevent oil spills are stronger today than ever before and
also are under constant review to identify possible improvements. Among
other things, all offshore operators on federal lands are required to sub-
mit operating plans for approval by the Geological Survey, to install a
wide variety of safety devices and to provide for standby pollution con-
trol equipment.
The efforts being taken by the Interior Department to require
and enforce strict precautionary measures, and the fact that reasonably
safe drilling operations can be conducted on offshore lands, need repeated
emphasis to the public. EPA could make a contribution here.
A corollary issue connected with offshore leasing concerns the
leasing method which will best promote early and rapid exploration and
development of the OCS lands. Interior's present method of awarding
V-60
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leases is through cash bonus bidding, with a fixed royalty (16-2/3%)
required on any ensuing production. This method has been criticized on
the ground that it siphons off large amounts of capital in bonuses which
might otherwise be expended on exploration and development. Another
criticism is that the bidding process is restricted to larger operators
able to afford the cash bonus plus finance subsequent drilling activities,
thereby precluding competition by smaller operators with less financial
resources.— This is said to deter the widest possible participation in
offshore development. Alternative methods have been suggested, the two
principal ones being: (1) a deferred bonus-fixed royalty system under which
portions of the bonus would be due at various times in the future; and (2)
a royalty bidding system, with no bonuses.
Both of the suggested alternatives could make available large
sums of capital for exploration and development that otherwise would be
committed to bonus payments. However, Interior takes the position that
these methods would result in less incentive for full lease development
and recovery of resources. This danger is considered particularly great
in the case of royalty bidding which, Interior fears, would be conducive to
speculative leasing by parties with no intention of exploration and develop-
ment and also to premature abandonment of leases. However, even in the
case of the deferred bonus alternative, the fact of less "sunk" cost could
reduce the incentive of the operator to obtain maximum production.
I/ To date, a number of smaller operators have participated in offshore
leasing and exploration in joint ventures with other companies.
V-61
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In testimony before the Senate Interior Committee on June 19,
1972, Assistant Secretary of the Interior Harrison Loesch defended the
present cash bonus bid-fixed royalty system as the best of the possible
alternatives and said Interior does not currently plan to change this
system unless directed to do so by Congress.-'
G. Encouragement of Supplemental Gas Supply Projects
A final regulatory category for increasing the supply of gas
available to U.S. markets is the encouragement of supplemental projects
involving unconventional and/or foreign sources of supply. The major
2/
such sources now on the horizon— are:
(1) Gas from Alaska;
(2) Gas from Canada imported by pipeline;
(3) LNG imports by ship from overseas nations;
(4) Synthetic gas reformed from liquid hydrocarbons; and
(5) Synthetic gas from domestic coal.
Two points concerning these projects bear emphasis at the outset,
The first is that, despite the publicity focused on supplemental supply,
the fact is that they will make only a relatively modest contribution to
U.S. supply --at least through 1980. Based on projections of the FPC
I/ Statement of Harrison Loesch, Assistant Secretary for Public Land
"" Management, U.S. Department of Interior, before Senate Committee on
Interior and Insular Affairs, on leasing and disposal policies for
energy resources on public lands.
2/ Other possible sources are nuclear fracturing of tight gas-bearing
~ formations, oil shale gasification and tar sand gasification. How-
ever, the current state of technological development in these areas
is very limited. Consequently, all of these potential sources must
be regarded as speculative for some years to come.
V-62
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Staff, as shown above, supplemental sources -- excluding synthetic gas
from liquid hydrocarbons -- are estimated to provide only 1.5 trillion
cubic feet in 1975 and 4.6 trillion in 1980, representing 5% and 13%,
respectively, of forecast annual demand. Assuming reformer gas avail-
ability of 0.5 trillion cubic feet in 1975 and 1.0 trillion in 1980, the
percentages would rise to about 1\ and 16%. Projections by the National
Petroleum Council, shown above, indicate similar proportions. These
calculations serve to illustrate the fact that supplemental gas sources
are only that -- supplements. They in no way diminish the crucial need
to stimulate increases in domestic production, the principal source for
meeting gas demand for many years. At the same time, this does not mean
that supplemental gas projects should be postponed. The projected gas
supply deficits are such that all sources of gas supply should be pursued
with urgency within the framework of national objectives.
The second factor to be kept in mind is that, unlike conventional
wellhead production of domestic gas, the nonconventional supplemental
sources involve a number of considerations bearing on different facets of
national policy. These considerations include national security questions
concerning sources of supply, balance of payments problems, and oil import
restrictions. In addition, supplemental supply projects promise to be very
costly to consumers -- certainly far more so than the cost of domestic gas
at the moment and, at least in the case of some projects, in excess of gas
prices even assuming an increase in domestic gas rates to the price level
of competitive fuels in the marketplace. In short, the regulatory encourage-
ment to be given to supplemental supply sources -- which ones, to what
V-63
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degree, and when -- requires a careful evaluation of a mix of interrelated
factors.
As discussed in Chapter IV, concern with the problem of economic
cost led the FPC to require incremental pricing for sales for resale of
LNG proposed to be imported by three major U.S. pipelines from Algeria.
This means that the LNG must be sold by each pipeline to its customers
at the full import price plus the cost of regasification and transmission
to consumer markets, rather than at rolled-in prices reflecting the
average cost of all systemwide supplies (including domestic supplies
from the Southwest and gas imported from Canada). The degree to which
the FPC will apply incremental pricing concepts to other high cost sup-
ply supplements in the future will have an important bearing on their
marketability in the U.S.
The incremental pricing issue is complex. However, it is
vital that the issue be understood, and it is recommended that EPA take
no position until the matter has been fully explored. The incremental
price conditions imposed by the FPC in the El Paso Algeria case are of a
precedent-setting nature in that they could lead to a substantial altera-
tion of pricing practices (i.e., rolled-in pricing) followed by the pipe-
line industry to date. If the incremental pricing principle can be con-
cluded to be in the public interest for the El Paso Algeria LNG project,
then it is equally applicable to other "supplemental" gas supplies (reformer
gas, coal gas, gas from Alaska and Canada, additional LNG imports), as well
as to new domestic supplies priced higher than the existing rolled-in
(average) price of gas delivered from the Southwest.
V-64
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A shift to incremental pricing consistently applied in the
future to all new gas supplies priced higher than the rolled-in average
of existing gas supplies would create administrative problems, but more
seriously, could limit and reduce the amount of new gas supplies for
U.S. markets. This is because there are only limited markets which will
be prepared to incur the risk of contracting and then selling supplemental
gas supplies at a multiple of the historically prevailing gas prices.
Such an abrupt change would be in direct contrast to an orderly restructur-
ing of the gas industry which is in a serious state of disequilibrium at
this time because of the supply shortage.
These end results could be detrimental to EPA's pursuit of an
enhanced supply of gas. It should be kept in mind that gas pipelines
and distributors seek higher cost supplemental supplies because of the
failure of domestic supplies to meet existing requirements. The forepart
of this chapter speaks to ways in which these adverse domestic supply
trends could be reversed, but inevitably with a substantial time lag.
Furthermore, there is no way to predict how responsive new domestic gas
supplies will be to the incentive of higher field prices. On this basis,
gas pipelines have sought supplemental supplies, and have been encouraged
to do so by government.
In most instances, these supplemental supplies will be needed
to maintain current demand levels and provide gas pipelines and their
distributor-customers an opportunity to up-grade their markets away from
interruptible service to higher priority service, by adding additional
storage. Yet, to incrementally price supplemental supplies creates the
V-65
-------
risk that only the larger distributors would be prepared to incur the
risk of passing on the cost to the consumer in such an abrupt fashion.
On this basis it would seem advisable at this time for pipeline systems
to acquire the supplemental gas supplies because of (1) their larger
market systems, (2) their ability to command the capital needed to mount
the type of project needed to recognize economies of scale and (3) their
ability to roll in these higher gas costs for the purpose of pricing
supplies for resale to their distributor-customers. In this way, an
orderly method may be provided for a transition from the current supply-
demand imbalance to an orderly increase in supply of gas which would be
available to meet at least moderately increasing demand.
1. Gas from Alaska
Alaskan gas emerged as a significant source of possible supply
for markets in the Lower 48 States with the major oil find by Atlantic
Richfield Co. and Humble Oil § Refining Co. in the Prudhoe Bay area of the
North Slope in 1968. This find also resulted in the discovery of large
volumes of gas associated with or dissolved in the oil.
Gas reserves in the Prudhoe Bay area are currently estimated at
26 trillion cubic feet, comprising about 841 of Alaska's total proven
reserves at the end of 1971. None of this gas, however, can be made avail-
able until the oil with which it is associated can be produced and marketed.
Delays encountered in obtaining the necessary regulatory approvals for the
proposed oil pipeline from the North Slope to Valdez in southern Alaska
are well known and require no elaboration here.
V-66
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Extensive studies are presently being conducted with respect to
transportation of North Slope gas via pipeline through the Mackenzie Delta
corridor in the Northwest Territories into Alberta, and from there to U.S.
markets. At one time, a North Slope gas pipeline was under study by three
separate groups: (a) the Mountain Pacific Project -- which contemplated
the construction of a pipeline system extending from the North Slope
through the Fort Liard region of the Northwest Territories into British
Columbia, with transportation ultimately to Pacific Coast markets as far
south as Los Angeles; (b) Gas Arctic Systems Group -- which proposed a
1,550-mile line to connect the Prudhoe Bay area with an extension of
Alberta Gas Trunkline's system in Alberta, with gas then to be made
available to U.S. West Coast and/or Midwest markets through interconnection
with existing pipeline systems; and (c) the Northwest Project Study Group
-- which contemplated a 2,500-mile line from Prudhoe Bay to the inter-
national boundary near Emerson, Manitoba (presently a major export-import
point for Canadian gas). The Canadian Government, however, has made clear
that it will permit only one pipeline through Canada from the North Slope.
The latter two groups subsequently merged to form one group (the Gas Arctic-
Northwest Project Study Group). This group now has 19 participants, in-
cluding the two major distribution systems serving the State of California.—
_!/ The 19 participants include seven major U.S. pipelines or gas distribu-
tion systems (Michigan Wisconsin, Natural Gas Pipeline, Northern
Natural, Texas Eastern, Columbia System, Pacific Gas § Electric, and
Pacific Lighting), two Canadian pipelines (Trans-Canada and Alberta
Gas Trunk Line), three U.S. producing companies (Atlantic Richfield,
Humble Oil and Standard of Ohio), three Canadian producers (Imperial
Oil, Shell Canada and Gulf Canada), one Canadian distributor (Union
Gas Co.), The Canadian National Railway, the Canadian Pacific Railway
and Canadian Development Corp.
V-67
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Target dates for the Gas Arctic-Northwest Project are presently
mid-1973 for filing initial requests for authorizations in Canada and the
U.S. , January 1976 for commencement of construction, mid-1978 for commence-
ment deliveries, and 1980 for full throughput deliveries (about 3.5
billion cubic feet per day, or 1,278 billion cubic feet per year).^/ jn
addition to Alaskan gas, the proposed line would also transport Canadian
gas developed in the Mackenzie Delta area now under active exploration.
More recently, on December 4, 1972, El Paso Natural Gas Co.
announced the commencement of studies to determine the feasibility of a
gas pipeline from the North Slope to a port in Southern Alaska where the
gas would be liquefied and transported by tanker to the West Coast. This
is the first publicly announced proposal for a gas pipeline through Alaska
rather than Canada. El Paso estimates that the cost of such a project,
including facilities to liquefy and transport LNG to the West Coast, would
be comparable to the cost of an all overland pipeline.
From the standpoint of national security and balance of payments,
Alaskan gas has considerable advantages over some other possible sources of
supplemental supply. While export and import authorizations would be
required in the case of a line through Canada, these would not seem to pose
an insuperable barrier, although accommodations with the Canadian and Alberta
Governments would undoubtedly be necessary. In the case of a line through
Alaska, the need for such accommodations would be avoided.
I/ Speech of Wilber H. Mack, Co-Chairman of the Gas Arctic-Northwest
~~ Project Study Group, before the Gas Men's Round Table, Washington,
D.C. , August 1, 1972. Mr. Mack remarked that the described schedule
may be "somewhat optimistic."
V-68
-------
From a cost standpoint, however, the proposed Alaskan-Canada gas
pipeline --or the El Paso project, assuming a roughly comparable cost --
would be one of the costliest pipeline projects ever undertaken. Total pro-
ject capital investment is presently estimated in the range of $5 billion,
excluding any facilities south of the international border. Transportation
costs to U.S. markets -- excluding the cost of gas in the field -- are esti-
mated in the range of 80<£ to $1.00/Mcf or more. Adding an assumed wellhead
price of -- say -- 35<£, the delivered cost of Alaskan North Slope gas to
U.S. markets would be no less than $1.10/Mcf and probably nearer to $1.35/Mcf,
or higher. This is more than three times the average city gate cost of
gas delivered to major Midwest and California market areas in mid-1972.
Moreover, while the North Slope of Alaska is considered the
predominant source for augmenting gas supplies to the Lower 48, substantial
gas potential is also believed to exist in the southern part of the state,
especially the Gulf of Alaska. As of December 1971, proved gas reserves
in South Alaska -- located primarily in the Kenai Peninsula -- amounted to
slightly more than 5 trillion cubic feet. Of the 153 billion cubic feet of
gas produced in Alaska in 1971, approximately two-thirds was utilized
locally and 51 billion cubic feet was shipped as LNG to Japan.
Interest has been expressed by Pacific Lighting Corp. in
importing LNG from the Kenai Peninsula to markets in Southern California.
A tentative plan contemplates import of 250,000 MMBtu per day initially,
ultimately increasing to 750,000 MMBtu per day. The cost of initial
volumes delivered to the Los Angeles city gate has been estimated at about
V-69
-------
$1.00/MMBtu.— This cost would undoubtedly be cheaper if it were not for
the Jones Act, which requires ships operating solely within U.S. waters
to be built in U.S. shipyards and manned with American crews. It has
been estimated that the cost of using domestically built and manned
vessels will add 6
-------
any substantial increase in imports from Canada until sufficient reserves
are developed in frontier regions to support new gas export projects.—
Exploratory activity -- financed in part by advance payments from
U.S. pipelines --is currently proceeding in three frontier areas: the
Mackenzie Delta in the Northwest Territories, the Arctic Islands, and the
Sable Island area off Nova Scotia. Discoveries described as "significant"
have been announced, but without disclosure as to the magnitude of the
reserves. At present, there is no way to transport gas from these frontier
areas to consuming markets. However, as noted above, Mackenzie Delta gas
would likely be transported along with North Slope gas via the proposed Gas
2/
Arctic-Northwest Project,— assuming this project is eventually effectuated.
Gas from the Arctic Islands of Canada is more uncertain, although
about one-third of the 25 to 30 trillion cubic feet of reserves necessary
to justify a pipeline is estimated to be already proven. Also, it was
announced last June that a preliminary survey will be conducted to evaluate
a route for transporting Arctic Island gas to markets in eastern Canada and
the U.S. Nevertheless, supplies from this area seem unlikely to be avail-
able to consuming markets for at least another ten years.
I/Whereas proved reserves in Canada at December 31, 1971 were estimated at
55.5 trillion cubic feet (less than estimated proved reserves of 75
trillion cubic feet in South Louisiana), potential gas reserves in Canada
have been estimated at 725 trillion cubic feet, largely in frontier areas.
2J Under advance payment contracts with Michigan Wisconsin Pipe Line Co. and
Natural Gas Pipeline Co. of America, Imperial Oil Ltd. is obligated to give
the two pipelines first call on 10 trillion cubic feet out of the first 12
trillion of reserves developed by it in the Mackenzie Delta. The initial
price for this gas in the field has been reported at 32<£/Mcf, plus
definite and indefinite escalations. (Oil g Gas Journal, July 24, 1972.)
V-71
-------
As to offshore Nova Scotia gas, Texas Eastern Transmission Corp. --
which has contracted to advance a total of $24 million to a Canadian sub-
sidiary of Mobil Oil Corp. -- outlined plans in an FPC proceeding (concern-
ing the rate treatment of the advance) to move up to 660,000 Mcf/d (or 241
billion cubic feet per year) through a large-diameter pipeline from the
Sable Island area to Boston, Massachusetts. The cost of the 775-mile pipe-
line was estimated at about $320 million and the unit cost of transportation
at about 26t/Mcf, both in 1971 dollars. These estimates appear conserva-
tive, and again this gas does not seem likely to be available for several
years, assuming that a viable project can in fact be developed and all neces-
sary regulatory authorizations on both sides of the border obtained. It
can be reasonably anticipated that the Canadian Government would require
at least a portion of the gas to be retained for markets in eastern Canada.
Thus, it does not appear that Canadian gas will be available in
substantial quantities -- beyond presently authorized import volumes --
during the balance of the current decade to alleviate U.S. supply shortages.
To the extent that frontier area gas reserves are developed, transportation
facilities are constructed and Canadian export licenses granted, such gas
could be considered as a relatively secure source of supply. However,
balance of payments problems would arise. Also, as in the case of Alaskan
gas, the same high delivered costs pertain -- with the possible exception
of offshore eastern Canada gas which possibly could be delivered to New
England markets for less than $1.00/Mcf.
V-72
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3. LNG Imports
The importation of LNG began in 1968 for peak shaving purposes on
a short-term basis. Since that time, various New England distributors, and
Texas Eastern Transmission Corp., have been authorized to import one or more
shiploads from Algeria or Libya for limited periods (usually not exceeding
six months) at rates up to $1.70/Mcf.-
The first applications to the FPC for long-term imports of LNG
were filed in 1970. One application involved a project by Distrigas, a
subsidiary of Cabot Corp., to import approximately 15.4 billion cubic feet
annually from Algerian sources for a period of 20 years beginning in 1971
to help meet peak shaving needs of distributors in the New England and New
York City areas. A second proposal concerned the importation of one billion
cubic feet of LNG per day --or 365 billion cubic feet per year --by sub-
sidiaries of the Columbia Gas System, Consolidated Natural Gas Co. and
Southern Natural Gas Co. from El Paso Algeria Corp. over a 25-year period
beginning in 1975 for base load needs. Both projects were certificated by
the FPC in 1972; pertinent details of these authorizations, and some of
their implications for future LNG projects were described in Chapter IV.
In addition, two other long-term LNG import proposals have been
filed in the FPC -- one by Eascogas LNG Inc. to import varying quantities
up to approximately 237 billion cubic feet annually from Algeria for 22
years for base load use primarily by Algonquin Gas Transmission Co. in New
England and by Public Service Electric § Gas Co. in New Jersey, and the
_!/ LNG has also been imported from Canada into New England by truck on
~ a spot basis at rates up to $1.94/Mcf.
V-73
-------
other by Distrigas to import an additional 45 Bcf annually from Algeria
for 20 years (thus expanding its original project by nearly three times)
-- while several other prospective projects have been announced in the
press. The prospective projects reveal a considerable diversity of supply
source, as indicated in Table V-ll summarizing the various long-term LNG
proposals announced to date (or reported to be under consideration).
Even assuming effectuation of all of the announced projects, it
is unlikely that they will proceed according to current schedules in view
of the length of time required to obtain necessary governmental authoriza-
tions and to build the extensive facilities involved in any large-scale
LNG import project. The FPC Staff projects LNG import volumes of 0.3
trillion cubic feet in 1975, rising to 2.0 trillion in 1980, 3.0 trillion
in 1985 and 4.0 trillion in 1990. The National Petroleum Council projects
0.2 trillion cubic feet in 1975, 2.1 trillion in 1980 and 4.0 trillion in
1985.
From a regulatory standpoint, the importation of LNG on a large
scale for base load purposes poses national security problems, balance of
payment problems and cost problems. With regard to national security, the
bulk of the world's estimated gas reserves -- exclusive of North America --
are located in the Soviet Union, the Middle East and North Africa. Each of
these area sources could be interrupted in the event of international
political or military problems. In time, the consequences of any such
interruptions can be alleviated in part by achieving a maximum diversity
of LNG sources. Also, the large amount of capital investment required
by the exporting countries in production, pipeline, liquefaction and
V-74
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FILED AND PROSPECTIVE LNG IMPORT PROJECTS
Table V-ll
Origin
of LNG
Algeria
Algeria
Algeria
Algeria
Algeria
Principal Importing
Company (or Companies)
Distrigas Corp.
Columbia LNG Corp. )
Consolidated System LNG)
Southern Energy Co. )
Eascogas LNG Inc.
Distrigas Corp.
Consolidated System LNG
Phillips Petroleum Co.
Shell Oil Co.
Amoco International Oil Co.
Pacific Lighting Corp.
Pacific Lighting Corp.
Pacific Lighting Corp.
Tenneco Oil Co. )-'
Texas Eastern Transmission) USSR
Brown (, Root )
El Paso Natural Gas Co. )-/
Occidental Petroleum Co.) USSR
Bechtel Corp. )
Destination of LNG
Boston, Mass. )
Staten Island, N.Y.)
Cove Point, Md.
Cove Point, Md.
Savannah, Georgia
Providence, R.I. )
Staten Island, N.Y.)
Boston, Mass. )
Staten Island, N.Y.)
Cove Point, Md.
Nigeria
and/ or
North Sea
Nigeria
Trinidad
Venezuela-
Alaska
Australia
Indonesia
East Coast
East Coast
Gulf Coast
California
California
California
East Coast
West Coast
Announced
Annual Startup Status
Volume Date in FPC
15.4 1971-
1,095
365
-/
7-' 1975
365
237
164
475
146
183
365
438
1978
1975
1975
1978
1976
1976
1980
1980
Approved
109 1975 Approved
128 1975 Approved
128 1975 Approved
Filed
45 1975 Filed
55
a/ A first shipload was delivered in 1971, but further deliveries have been delayed due to
liquefaction plant startup difficulties in Algeria.
b_/ Projected delivery volume in fourth through twentieth year of 22-year term, less in other
years.
£/ The Venezuelan Government is reportedly pursuing plans for two LNG plants producing about
1.3 billion cubic feet per day. A bid for tanker construction by a U.S. company has been
submitted to the Venezuelan Government. The target date for first LNG production is mid-
1975.
d/ The Iranian Government has announced a joint project with International Systems and
Controls Corp. The LNG would be supplied to the U.S., South America and Japan.
£/ Projects under negotiation. No agreements have been reached.
Source: FPC Bureau of Natural Gas National Gas Supply and Demand, 1971-1990, Staff Report No. 2,
pages 67-72; press articles.
V-75
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other equipment necessary to bring about an LNG project is another
factor tending to lessen the danger of supply cutoff.—
On the other hand, a supply interruption over any significant
period of time could cause severe problems for particular pipelines or
distributors which become heavily dependent on imported LNG. In the El
Paso Algeria case, for example, the LNG imports are estimated to account
for a substantial portion of the total future gas supply of the three U.S.
purchasing pipeline companies -- 9.11 for the Columbia Gas System, 14.3%
for Consolidated Natural Gas Co. and 20.1% for Southern Natural Gas Co.
To mitigate the impact of a possible cutoff of LNG, the Defense Department
has suggested that the FPC adopt rules limiting the volume of overseas LNG
taken by any one distributor for firm (as opposed to interruptible) use to
the percentage of total system gas not considered critical, requiring
large firm gas users to have standby facilities for alternate fuels or
else be converted to an interruptible basis, or possibly requiring
larger storage facilities or emergency sources of domestic gas for
2 /
distributors using substantial amounts of overseas LNG.—
These views raise the question of whether LNG imports should
be subjected to overall import restrictions. No restrictions apply at
present. However, it is a valid inquiry whether it is sensible to allow
I/ In connection with the El Paso Algeria project to import one billion
~~ cubic feet daily, the U.S. State Department argued that the Algerian
Government's ownership of all facilities in Algeria necessary for the
project will give it a major financial interest in continued sales,
thus enhancing security of supply.
2/ Letter dated July 23, 1971 from Defense Department to FPC in re Columbia
~ LNG Corp. (CP71-68 et al.).
V-76
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the importation of LNG without limitation while at the same time con-
trolling the importation of crude oil at lower energy equivalent prices.
As to balance of payments problems, there is no doubt that pur-
chase of increasing gas volumes from foreign nations would aggravate the
nation's foreign trade balance deficit. The same problem exists for oil
imports, which could substitute for some of the proposed LNG imports,
except that imported oil --to the extent it remains cheaper on an energy
equivalent basis than imported gas -- would have a lesser impact on the
deficit.
With respect to costs, the long-term LNG projects filed to date
in the FPC already reflect a rising cost trend which may be expected to
continue as a result of both inflationary factors and pressures for higher
prices by the exporting countries. Specifically, the first Distrigas pro-
ject involved a delivered LNG price of 68
-------
Natural at Savannah, Georgia are 77$ and 83
-------
Administration for six of these ships.!/ In addition, the Maritime
Administration predicts that up to 60 LNG carriers could be constructed
in American yards by 1980, thus providing a major boost to U.S. employment
and shipbuilding capabilities. On the other hand, some question the
wisdom of constructing a large fleet of LNG tankers with U.S. subsidies
for the purpose of importing a fuel which costs more than other imported
fuels and substantially more than domestic gas.!/
The capital requirements of LNG projects are another factor to
be considered. The El Paso Algeria project is now estimated to require a
capital investment of $1.7 billion for deliveries of one billion cubic feet
per day, including about $628 million for facilities in Algeria. Under
present plans, a large part of the Algerian facilities would be financed
in the United States --by the Export-Import Bank and by a consortium of
U.S. banks. Conservatively assuming an average capital investment of $1
billion per one billion cubic feet of daily capacity (or $1 per cubic foot
per day), this equates to $6,000 per barrel of oil per day.
4. Synthetic Gas Reformed from Liquid Hydrocarbons
Another potentially important source of supplemental gas is syn-
thetic pipeline quality gas (SNG) reformed from liquid hydrocarbons. This
source, however, is heavily dependent on imports of oil or oil products.
As such, changes in the present oil import program are critical to the
V The subsidies cover the estimated difference in cost between building
the ships in an American as opposed to a foreign shipyard.
2/ E.g., address of James Akins, Energy Director of the State Department,
~~ to the Institute of Gas Technology in Chicago on November 16, 1972.
V-79
-------
magnitude of SNG which will become available in the future.
Over 40 different projects to synthesize gas from liquid hydro-
carbons have been announced during the past year and a half. Most are in
the investigation or planning stage; a few which are based on domestic or
quota-free LPG feedstocks (such as Canadian ethane and propane) and do not
require FPC authorization are under construction; five have been filed
with the FPC; and several have been submitted to the OEP with requests for
waiver of the MOIP to permit importation of foreign feedstocks. The various
projects are summarized in Table V-12, together with estimated capital
costs, unit output costs, targeted completion dates and present status.—
OEP has estimated that base load SNG proposals submitted to it to
date would, if implemented, result in the production of 1.2 trillion cubic
21
feet per year of synthetic gas by 1975 and 2.2 trillion per year by 1980.—
In general, reformer gas projects are of two types: those based
on conversion of naphtha or light hydrocarbon liquids to synthetic gas,
and those based on use of crude oil as the original feedstock. The
majority of the projects announced thus far fall in the former category.
Several commercial techniques, based on technology developed in the
United Kingdom, West Germany or Japan, are currently available for the
reforming of naphtha or lighter liquids. Projects based on crude oil
contemplate, for the most part, the refining of imported crude into
_!/ The information in the table is based on company estimates which are
~~ highly tentative in many instances. Also, the time framework reflected
in the table does not represent a realistic picture at this time.
2/ Address by Robert E. Shepherd, Chief of Oil and Energy Division, Office
of Emergency Preparedness, to Institute of Gas Technology in Chicago on
November 16, 1972.
V-80
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ANNOUNCED REFORMER CAS PROJECTS
Company and Location Process
Algonquin SNG, Inc. CRC
Freetown, Mass.
Amerada Hess
Reading, N.J.
Apco Oil Corp.
Eastern Pennslyvanla
Ashland Oil MRG
Appalachia
Baltimore Gas &
Electric CRG
Baltimore, Md.
Boston Gas Co. KRG
Everett, Mass.
Brooklyn Union Gas Co. CRG
Brooklyn, New York
Central Illinois Light CRG
Cities Service Gas Co.
Missouri
Cities Service Gas Co.
Missouri (each of
five plants)
Coastal States Gas CRG
Producing Co.
Corpus Chrlstl, Tex.
Columbia LNC Corp. CRC
Green Springs, Ohio
Commonwealth Natural CRG
Gas
Chesapeake, Va .
Consumers Power Co. CRG
Marysvllle, Mich.
Continental Oil Co.
East Coast (each of
two plants)
Crown Central Petroleum
Corp.
Baltimore, Md.
El Paso
Texas Gulf Coast
Felmont Oil
Oleon, New York
Expected
Completion
Date
Oct. 1973
1974
1973
1973
1973
Late 1973
Last Q
1975
1976-1980
1974-1975
July 1973
Oct. 1973
Early 1973
1974
1974
1974-1975
Feedstock
Investment MBbls.
$ Million Day Type c/Gal.
39.5 24.2 Naphtha 10.5
14 Naphtha
28 28 Naphtha
10 Light
Hydrocarbons
Naphtha
4.5 10 Propane
12-23 10 Naphtha
Naphtha
20 25 Naphtha
20 25 Naphtha
25 30 Naphtha
37.8 86.9 NGL 7.00
NGL
50-60 50 NGL
30 33 LPC
200 100 Crude oil
60 65 bbls. Naphtha
Conden.
22.5-24 Naphtha
Source
Domestic (Humble)
and Foreign
Bahama Is Is.
Canada
Domestic
Domestic (Humble)
Domestic
Domestic and
Foreign
Prlmarl ly
Domestic
Canada (Dome
Petroleum)
Venezuela
Canada (Dome
Petroleum)
Foreign
Middle East
Algerian
Condensate
Foreign
Output
MMcf Cost
Day c/Mcf Cost Basis Purchaser
120 142 335 days/yr. Algonquin Gas
lgo 151 days/yr. Trans. Co.
125
125 105- Columbia LNC
113 Corp.
49 Iroquols Gas
125
40 130 Seasonal
Operation
50 150- ISO days/yr.
160
60
125 125
125 125
125 110 Trunkllne Gas
Corp .
250 112
30
100-1973 115-
200-1974 125
125
100 105 Columbia Gae
System
250 350 days/yr.
95-100
Status
Filed with FPC (Docket CP72-35) Examiners
decision Issued 3/28/72
Included In plans to expand other facili-
ties, Indicated to OEP
Notified OEP of plana
Indicated In press
Indicated in press
Under construction. May switch to naphtha
Construction to have begun 6/1/72
Indicated In press
Has acquired Land options; Indicated In
Motion to File Brief Anlcus Curlae
(Docket CP71-68) that exhibit materials
are being prepared for application to FPC
Indicated to OEP
Letter of Intent algned by both firms.
(Docket CI72-848)
Under construction; filed with FPC
(CP72-8)
Announced
Under construction
Under construction
Indicated to OEP
Indicated to OEP; gas would be used for
Southern Division system
Requested permission to Import naphtha;
startup 24 months after Import alloca-
tlon is received
-------
Expected
ANNOUNCED REFORMER GAS PROJECTS
Feedstock
Company and Location Process
Foster Wheeler Corp. CRG/
Nansemond County, Va. FBH
Casco, Inc.
Honolulu, Hawaii
Howard Oil Co.
Philadelphia, Pa.
Indiana Gas Co.
Indiana
Iroquois Gas Co.
New York State
Niagara Mohawk-
Consolidated Gas
Supply
Oswego, New York
Northern Illinois Gas CRG
Co.
Morris, Illinois
Northwest Natural Gas CRG
Portland, Oregon
Orange and Rockland
Utilities
New York
Pacific Gas and
Electric Co.
PG&E Service Area
Panhandle Eastern
Pipe Line Co.
(with Amerada Hess)
I lllnols
Peoples Gas Light & Coke CRG
Will County, Illinois
Philadelphia Electric
Co.
Pennsylvania
Public Service E & G CRG
Livingston, New Jersey
Public Service E & G CRG
Livingston, New Jersey
New Jersey
Tecon Gasification Co. MRG
South Plalnfleld, N.J.
Completion Investment MBbls.
Date $ Million Day Type
180-310 180 Crude
1975 15 2.7-1975 Naphtha
3.5-1980 Naphtha
1973-1974 156 150 Crude
Naphtha
NCL,
Naphtha
Late 1974 Naphtha
Early 1974 50 35 NGL
1974-1975 Naphtha
Naphtha
Crude
1974 60 Naphtha
1974-1975 50 33 NCL
1974 Naphtha
Late 1973 30 25 Naphtha
1972-1973 Propane &
Butane
Naphtha
Late 1973 140 1 10 Naphtha
MMcf Cost
c/Cal. Source Day c/Mcf Cost Basis Purchaser
Kuwait 258-719 95
Foreign and/or 1975 - 163-
Domestlc 187/MMBtu
1980 - 152-
176/MMBtu
Middle East 250
(Gulf Oil)
Middle East
New Eng. Pet. 125
Energy Refinery
Domestic (Mapco, 100 105
Inc.)
50
Foreign
Foreign 125-250 120- TrunUine Gas
130 Co.
Domestic 150 110
(American Oil,
Union Oil of
Calif.)
125
7 Foreign 125 77
20
125
10.25 Domestic (1/3) 500 125
8.71 Foreign (2/3)
Status
Fuels complex under consideration
Indicated to OEP
Site acquired; design In progress;
indicated to OEP
Under investigation
Indicated in press
First in a series of proposed energy
refineries
Indicated in press
Indicated in press
Under consideration
Startup 15-18 months after initiation;
request has been made to OEP to Import
21 MHbbl./yr.
Announced plans to build and operate
plants needed by 1986
Under construction
Indicated In press; subject to regulatory
approval, financing and site selection
Filed with FPC (Docket CP72-100)
32
oo cr
ro
O i
ro
Ul
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ANNOUNCED REFORMER GAS PROJECTS
Company and Location
Tenneco, Inc .
Tenneco, Inc .
Transco Energy Co.
Pennsylvania
Transco Energy Co.
Eastern Seaboard
Trunkline Gas Co.
Midwest
Washington Gas Light
Co.
Near Wash. , D.C.
Zapata Nor ness , Inc .
Louisiana (each of
two plants)
United Gas Pipe Line
Gulf Coast
Expected
Completion Investment MBbls .
Process Date $ Million Day
1974
Lurgl 1974-1975 85 53.5
4.2
Late 1975 300 100
60 60
1974 15-20
1975 200-250 85
1975 150
Feedstock Output
MMcf Cost
Type c/Gal . Source Day c/Mcf Cost Basis
Crude and Foreign
unfinished
oils
Naphtha
Naphtha 10.7 Foreign & Domestic 250 1.20-
Propane 10.9 Domestic I .40
Crude Middle East 460
Naphtha Foreign 300 100+
Naphtha 50-60 100+ Peaking
facility
Crude 5.9- Persian Gulf 400 L85-
7.1 105
Crude Foreign 340 95
Purchaser
Indicated
indicated
Transcontinental Filed with
Gas Pipe Line
Status
to OEP
to OEP
the FPC (Docket CP73-20)
Siting under investigation; preliminary
planning accomplished; engineering in
progress
Indicated
Under cons
in press
ideration
Request made to OEP for modification of
Oil Import Program to permit feedstock
Imports
Had indicated plans for series of plants
to FPC; has acquired land options at
Pascagoula , Mississippi
Source: Comments filed with Office of Emergency Preparedness.
Oil and Gas Journal, July 31, 1972.
Pipeline and Gas Journal, May 1972.
Other current articles from The Oil Daily, The^Ja^ll Street Journal, Oil and Gas Journal, and The Journal of Commerce.
FPC Dockets CP71-68, CP72-8, CP72-35, CP72-100, C172-20, CI72-848.
o ^
-------
naphtha and low sulfur residual fuel oil, with the naphtha then reformed
by a subsequent process into SNG. At this time, there is no known com-
mercial process available for the direct gasification of crude oil.
Considering reformer projects based on naphtha (°r LPG) , there are
two major advantages from the standpoint of increasing gas supply. One is
that plants of this type can be built in about two years, which represents
a considerably shorter lead time than required for other supplemental
sources of supply. Thus, reformer gas could be made available to alleviate
supply shortfalls more rapidly than other alternatives. A second advantage
is that the necessary capital investment is far below that entailed for
base load LNG import, coal gasification or Arctic pipeline proposals. For
example, compared with an assumed capital outlay of approximately $1 per
cubic foot per day of capacity required for a base load LNG import project,
the five reformer plant proposals filed with the FPC to date involve a
capital investment ranging between about 15
-------
that the cost of feedstock accounts for about 75% of the tailgate cost of
reformer gas. It is further estimated that each 1<£ increase in the price
of naphtha will increase the cost of synthetic gas output by approxi-
mately 8f to 9
-------
425,000 barrels per day in 1975, 850,000 barrels per day in 1980 and
1,350,000 barrels per day in 1985.
Consequently, assuming the validity of the above conclusions, the
naphtha reforming route would require substantial imports of a refined
crude oil product to produce gas which would doubtless exceed the energy
equivalent cost of crude oil for some time. In addition, this route would
result in increased reliance on foreign refining capacity.
An alternative and possibly more desirable route is the importation
of crude oil to produce naphtha in domestic refineries, for subsequent con-
version to SNG, and low sulfur residual fuel oil. Advantages of this course
of action, compared with the importation of naphtha, include (a) encourage-
ment, rather than discouragement, of domestic refining capacity; CD) pro-
vision of two needed fuels rather than only one, with concomitant benefits
of interfuel competition; and (c) the ability to use high sulfur crude oil
as the basic refinery input.
In short, the encouragement of synthetic gas production, while
a potentially important supply supplement, is enmeshed with many other
policy questions and can not be considered from the sole standpoint of gas
supply maximization.
5. Synthetic Gas from Coal
Coal gasification offers a promising and advantageous source of
supplemental gas; however, significant volumes are unlikely to be forth-
coming before 1980. The FPC Staff projects the availability of 300 billion
cubic feet in that year.
V-86
-------
The only commercial coal gasification process available at this
time is the Lurgi process, developed in Germany some 30 years ago. Several
commercial Lurgi plants have been built, mostly in Europe, and are in opera-
tion today. Lurgi gasification is particularly suitable for noncaking
coals of the subbituminous or lignite type, found in large quantities in
the western United States. However, a major problem with the Lurgi process,
from the standpoint of attaining pipeline quality gas, is that the heating
value of the produced gas is only between 400 and 450 Btu per cubic foot,
far below the 1,000 Btu per cubic foot norm required for substitution and.
interchangeability in American gas pipeline and distribution systems.
Therefore, a further methanation step is necessary to raise the heating
content of Lurgi gas. This further methanation process, not yet commer-
cially proven, is currently undergoing pilot plant evaluation.
To date, only one coal gasification project has reached a suffi-
ciently advanced planning stage to be filed with the Federal Power Commis-
sion. This project comprises a 250,000 Mcf per day complex proposed to be
constructed by El Paso Natural Gas on a 40,000 acre coal lease situated
within a Navajo Indian Reservation in San Juan County, New Mexico. El
Paso has established over 700 million tons of coal in this area, sufficient
to support three projects of the contemplated size. The gasification
plant would use the Lurgi process, plus a further methanation step. Feed-
stock requirements are expected to approach 8.8 million tons of coal annually.
The targeted startup date for the plant is late 1976, and the cost of syn-
thetic gasified coal to El Paso in the first full year of operation (1977)
V-87
-------
is $1.21/Mcf.- The projected capital cost of the mining, gasification,
dehydration, compression and other facilities is estimated at $420 million
(or approximately $1.70 per cubic foot per day of capacity).
Another proposal for coal gasification in northwestern New Mexico
has been announced by a consortium of three companies -- Texas Eastern
Transmission Corp., Pacific Lighting Corp. and Utah International Inc. --
which is investigating the feasibility of several Lurgi plants capable of
producing 250,000 Mcf per day, the first tentatively scheduled for startup
in 1975 or 1976. No application has been submitted to the FPC for this
proposal.
In addition, FMC Corp. recently formed a consortium with Tenneco
Inc. and Panhandle Eastern Pipe Line Co. to construct a pilot plant near
Princeton, New Jersey in order to test the commercial feasibility of the
so-called COGAS process for conversion of char into synthetic pipeline
gas, with synthetic crude oil as a by-product. If pilot plant operations
are successful, FMC envisions construction of a commercial plant later in
the decade to produce 250,000 Mcf per day of high Btu synthetic gas and
24,000 barrels per day of synthetic crude. Cost figures of 75£ to 90
-------
into an agreement calling for the joint funding of a research program to
test various processes through pilot plant operations, and the most likely
of the processes through demonstration plants, over the next eight years.
The first four years of the effort -- the pilot plant phase -- will be
funded at the rate of $30 million per year, of which two-thirds will be
provided by Interior— and the remaining one-third by the gas industry.
Two pilot plants are already in operation under this operation, and two
more are scheduled for construction in the near future. The second four
years, or demonstration plant phase, is estimated to cost about $176 mil- •
lion, but no arrangements for funding have yet been made. Assuming con-
tinuation of funding at the necessary levels, it is hoped that one or
more commercial processes will be available by 1980.
Several factors will affect the future rate of development of
coal gasification. These include the availability of substantial tonnages
of coal for conversion, the tremendous capital expenditures required for
mining and gasification facilities, environmental consequences of large-
scale mining projects (especially those involving strip mining), and prob-
lems associated with locating the mine-plant complexes in areas able to
provide the necessary reserves of uncommitted coal plus the very large
volumes of required process water. Moreover, the economics of coal gasi-
fication are highly uncertain at present and must necessarily await the
results of further research.
I/ The $20 million annual contribution by Interior (Office of Coal
Research) compares with a total expenditure of approximately $28 mil-
lion by OCR on coal gasification research over the entire period from
1960 through fiscal 1971.
V-89
-------
If these obstacles can be overcome, development of an economi-
cally viable coal gasification industry offers several benefits relative
to certain other supplemental supply alternatives. First of all, no
adverse national security impact and no balance of trade problems are
presented. Second, coal is, by far, the most abundant of the nation's
fossil fuel resources. Third, gasification of coal would permit the use
of resources which might otherwise never be directly consumed for environ-
mental reasons.
In short, it is suggested that EPA support the continued federal
funding of present coal gasification research efforts. It might also con-
sider participating in proceedings before the FPC on El Paso's currently
proposed project and on any others which may be filed in the future. In
this regard, one contribution of EPA could be a thorough evaluation of
environmental factors in an effort to assure maximum protection w'dle
countering unreasonable attacks.
V-90
-------
Bibliography
Akins, James E. (Energy Director of State Department), Speech to Institute
of Gas Technology in Chicago, Illinois on November 16, 1972
American Gas Association, Committee on Natural Gas Reserves, Annual Reports
on Proved Reserves of Natural Gas in the United States, 1958-1971
Bagge, Carl E.
"Gas Producer Price Legislation: An Alternative to Whistling in the
Dark," Natural Resources Lawyer, January 1971
Speech before Gas Industry Seminar at Oklahoma State University on
May 13, 1969
Speech to Institute of Gas Technology in Chicago, Illinois on
October 30, 1969
Speech to Midwest Gas Association in Colorado Springs, Colorado on
February 24, 1970
Speecli to Permian Basin Petroleum Association in Midland, Texas on
April 28, 1970
Speech to American Association of Oilwell Drilling Contractors in
Dallas, Texas on September 27, 1970
Speech to Society of Petroleum Engineers in Pittsburgh, Pennsylvania
on November 5, 1970
Brooke, Albert B., Jr.
Speech to Tennessee Gas Association in Gatlinburg, Tennessee on May 22,
1969
Speech to Independent Natural Gas Association of America in Colorado
Springs, Colorado on September 10, 1969
Speech to American Public Gas Association in Boston, Massachusetts
on September 11, 1970
Speech to Gas Men's Roundtable in Washington, D.C. on October 5, 1971
Canadian Petroleum Association, Potential Reserves of Oil, Natural Gas,
and Associated Sulphur in Canada, April 1969
Carver, John A., Jr.
Speech to Tenth Annual Institute on Exploration and Economics of the
Petroleum Industry in Dallas, Texas on March 5, 1970
Speech to Tennessee Gas Association in Nashville, Tennessee on May 15,
1970
Speech to Rocky Mountain Mineral Law Institute in Albuquerque, New
Mexico on July 10, 1970
Speech to Council of Economics of AIME in New York City, New York on
March 3, 1971
Speech to Petroleum Economics and Management Conference at Northwestern
University on March 30, 1971
Speech to Institute of Public Utilities on November 5, 1971
V-91
-------
Dole, Hollis M.
Speech to North Dakota Oil and Gas Association on September 14, 1970
Speech to American Gas Association in New Orleans, Louisiana on
October 13, 1970
Speech at Stanford University in Palo Alto, California on January 12,
1971
Speech to American Association of Oilwell Servicing Contractors in
New Orleans, Louisiana on February 11, 1971
Speech to Midwest Gas Association in Milwaukee, Wisconsin on March 9,
1971
Economic Reports of the President, February 1971 (pp. 130-133), and January
1972 (pp. 118-122)
Feucral Power Coi.miission
Gas Supplies of Interstate Pipeline Companies, 1970
National Gas Supply and Demand, 1971-1990, Staff Report No. 2, February
1972
Opinion No. 595, issued May 6, 1971 in re Texas Gulf Coast Area Rate
Proceeding (AR64-2); 45 FPC 674
Opinion No. 598,issued July 16, 1971 in re Southern Louisiana Area
Rate Proceeding (AR61-2); 46 FPC 86
Opinion No. 613, issued Marcli 9, 1972 in re Distrigas Corp. (CP70-196)
Opinion Nos. 622 and 622-A, issued June 28, 1972 and October 5, 1972 in
re Columbia LNG Corp. (CP71-68 et al.)
Opinion No. 637, issued December 7, 1972 in re Algonquin SNG Corp.
(CP72-35)
Opinion No. 639, issued December 12, 1972 in re Area Rates for the
Appalachian and Illinois Basin Areas (R-411)
Order No. 455 (R-441), issued August 3, 1972
Comments submitted in Docket R-441, "Optional Procedure for Certifi-
cating New Producer Sales of Natural Gas"
Foster Associates, Inc., Weekly Reports (covering federal regulation of
natural gas industry), 1970-1972
Freeman, S. David
Speech to American Public Gas Association in Gatlinburg, Tennessee on
September 17, 1969
Speech to Southwestern Social Science Convention in Dallas, Texas on
March 26, 1971
Future Requirements Agency, Future Gas Requirements of the United States,
Volume 4, October 1971
International Petroleum Encyclopedia, 1972
V-92
-------
Joint Association Survey of U.S. Oil and Gas Producing Industry, Drilling
Costs, November 1971
Mack, Wilber H. (Co-Chairman of the Gas Arctic-Northwest Project Study
Group), Sppech to the Gas Men's Round Table, Washington, D.C.,
August 1, 1972
McElvenny, Ralph T., Speech before AGA Annual Convention on October 16,
1972
Moody, Rush, Jr.
Speech to TIPRO in Fort Worth, Texas on June 6, 1972
Speecn to Mineral Law Section of Texas State Bar Association in Houston,
Texas on July 6, 1972
Nassikas, John N.
Speech to New England Gas Association in Boston, Massachusetts on
March 19, 1970
Speech at FPC 50th Anniversary Program in Washington, D.C. on June 3,
1970
Speech to International Gas Union in Moscow, USSR on June 10, 1970
Speech to Independent Natural Gas Association of America in Boca Raton,
Florida on October 6, 1970
Speech to American Gas Association in New Orleans, Louisiana on
October 12, 1970
Statement before Flood Control and International Development Subcommittee,
House Committee on Public Works, August 1, 1972
Speech to Independent Petroleum Association of America in Dallas,
Texas on October 18, 1972
Speech to Independent Natural Gas Association of America in Puerto
Rico on October 24, 1972
Speech before Institute of Gas Technology in Chicago, Illinois on
November 16, 1972
National Journal, "Energy Report: Administration Readies 1973 Program to
Encourage More Oil, Gas Production," October 21, 1972, pp. 1621-1632
National Petroleum Council, U.S. Energy Outlook: An Initial Appraisal
1971-1985, Volume I (July 1971) and Volume II (November 1971)
New York Public Service Commission, Staff Report on Gas Supply Situation,
August 1971
0'Connor, Lawrence J., Jr.
Speech to Petroleum Accounting Conference at Louisiana State University
on May 16, 1969
Speech to Pacific Gas Association in San Diego, California on
September 10, 1969
V-93
-------
Speech to American Public Gas Association in Gatlinburg, Tennessee
on September 16, 1969
Speech to Association of Petroleum Landmen in Oklahoma City, Oklahoma
on June 18, 1971
Office of Emergency Preparedness, Submissions to OEP in connection with
study of synthetic gas production from imported crude oil and oil
products, January and February 1972
Oil and Gas Journal, 1972 issues
Pipeline and Gas Journal, May 1972
Potential Gas Committee, Potential Supply of Natural Gas in the United
States, October 1971
Resources for the Future, Regulation of the Natural Gas Producing Industry
(Papers presented at a seminar conducted by RFF in October 1970, edited
by Keith C. Brown)
Shepnerd, Robert E. (formerly Chief of Oil and Energy Division, Office of
Emergency Preparedness), Speech to Institute of Gas Technology in
Chicago on November 16, 1972
U.S. Congress
Hearings on gas supply situation before Subcommittee on Minerals,
Materials and Fuels, Senate Interior Committee, November 12 and 13,
1969
Hearings on gas supply and FPC policy questions before Subcommittee
on Energy, Natural Resources and Environment, Senate Commerce
Committee, January 30, 1970
Hearings on H.R. 2513 (Sanctity of Contract bill) before Subcommittee
on Communications and Power, House Interstate and Foreign Commerce
Committee, September 14-16 and 21, 1971
Hearings on natural gas reserve estimates before Subcommittee on
Small Business, House Select Committee on Small Business, July 22,
1971
Hearings on natural gas policy issues before Senate Interior and
Insular Affairs Committee, February 25 and 29, 1972 and March 2, 1972
Hearings on S. 2467 arid S. 2505 (Sanctity of Contract bills) before
Senate Commerce Committee, March 22-23, 1972
Hearings before Subcommittee on Special Small Business Problems, House
Select Committee on Small Business, March 16 and 21, 1972
Hearings on fuel and energy resources before House Committee on
Interior and Insular Affairs, April 10-13, 1972
Hearings on natural gas shortage (and other energy matters) before
Joint Economic Committee, June 7-9, 1972
V-94
-------
U.S. Department of Interior, Geological Survey, Energy Resources of the
United States, 1972 (Geological Survey Circular 650)
Wakefield, Stephen A., Speech before Boston Energy Symposium in Boston,
Massachusetts on December 7, 1972
Walker, Pinkney (and Lay, Kenneth), New Dimensions in Utility Regulation,
Public Utilities Fortnightly, June 8, 1972
Speech to National Association of Business Economists in Houston,
Texas on November 5, 1971
Speech to Interstate Oil Compact Commission on December 11, 1971
Speech to AGA Conference on Natural Gas Research and Technology in
Atlanta, Georgia on June 7, 1972
Speech at dedication of LNG plant in Beech Grove, Indiana on July 28,
1972
Speech to Pacific Coast Gas Association in Phoenix, Arizona on
September 21, 1972
V-95
-------
CHAPTER VI - THE COST EFFECTIVENESS AND TIME REQUIREMENTS FOR
ALTERNATIVE REGULATORY STRATEGIES REGARDING GAS
SUPPLIES
A number of alternative regulatory strategies are set out in
Chapter V with respect to regulatory policies which will affect the sup-
plies of gas in the future. These alternative strategies focused primarily
on regulatory policies which could affect domestic production of natural
gas.- It is for this reason that the directional cost effectiveness
analysis set out in this chapter focuses on domestic supplies of natural
gas.
I/ A definitive cost-effectiveness analysis of alternative strategies
for increasing supplies of gas for U.S. markets, is beyond the scope
of this contract. If such an analysis were undertaken, it should
include supplemental supplies (LNG, reformer gas, Arctic gas and
coal gas) as well as domestic production, including, among other
matters, the following interrelated considerations: the anticipated
"city gate" cost of alternative levels of supplies, supplemental as
well as domestic, over a sufficient span of time to move beyond the
"first generation," especially with regard to coal gas; the compari-
son of these city gate costs with alternative types of energy (oil,
coal, nuclear, etc.) for specific market sectors (residential, com-
mercial, industrial, electric power) in specified regions of the
country, taking also into account the resulting benefit to society
by reducing air pollutants; the time span for realizing substantial
base load volumes, contracting, for example, the two to three year
lead time for a reformer gas plant versus the need for further five
to ten years) pilot plant research for coal gasification; the impact
on national macro-economic considerations, such as balance of pay-
ments, security of supply, the intent to reduce further exportation
of refining capacity, i.e., the MOIP.
VI-1
-------
All of the more important alternative strategies pertain to
regulation by the Federal Power Commission:—
(1) Amend the Natural Gas Act to deregulate field prices of gas
produced in the United States;
(2) Amend the Natural Gas Act to deregulate field prices of gas
produced in the United States and sold under new contracts;
(3) Amend the Natural Gas Act to instruct the FPC in its continuing
regulation of field prices of gas to grant "contract sanctity"
and to determine reasonable new gas prices by reference to
economic factors in the marketplace, not by reference to cost
of service; and
(4) Amend the Natural Gas Act by giving the FPC authority to allocate
gas supplies among intrastate as well as interstate consumers.
These four alternatives require amending the Natural Gas Act
by Congress. The first three affect the field price of domestically
produced gas whereas the fourth is adressed to allocating shrinking sup-
plies of gas. Therefore, an optimal strategy for EPA to increase gas
supplies in the United States could be to support any of the first three
indicated amendments to the Natural Gas Act so as to allow prices of gas
under new contracts to rise to their commodity value level in accordance
with the mandate of the marketplace. The marketplace will, in time,
_!/ Chapter V also stresses the need for accelerated and regularized leasing
of federal DCS lands by the Interior Department. The rate of develop-
ment of gas reserves underlying DCS lands will be influenced by several
factors -- including bonus payments, royalty payments and FPC-allowed
prices, among others.
VI-2
-------
adjust the price to rise to its competitive level vis-a-vis substitutable
fuel. To the extent this price elicits, in due course, greater gas sup-
plies produced in the Lower 48 States, the nation's economy will benefit
compared with the cost, as demonstrated below.
From the point of view of increasing supplies of gas, the focus
is clearly on the field price of domestic gas, and this focus is quite
logical. In 1971 production of gas in the Lower 48 States accounted for
over 96% of the nation's consumption of this fuel, the balance being
imported from Canada. Even under a more pessimistic outlook for future
domestic production (as forecast by the National Petroleum Council) , gas
produced in the Lower 48 States is still projected to account for 75% of
U.S. consumption in 1980, Alaska for 5% and the remainder being Canadian
overland imports, LNG imports and synthetic gas.
A. The Cost Effectiveness of Increased Field Prices of Gas in the Lower
48 States
Two basic questions must be answered in appraising the cost
effectiveness of increased field prices of natural gas in the Lower 48
States:
(1) What is the field price of gas which is equivalent to its
commodity value as determined in the marketplace?
(2) If the field price of gas increases to this level, what
effect will this have on the supply of gas?
VI-3
-------
B. The Current Commodity Value of Gas in U.S. Markets
The current commodity value of gas in U.S. markets was the sub-
ject of a major study recently completed by Foster Associates for EPA
(Contract No. 68-01-05-31) and 23 other industrial and government clients.
The title of this study is "The Current and Prospective Commodity Value of
Natural Gas in North American Markets, 1972-1982," dated October 1972. The
following analysis is based on the findings of this study.
Table VI-1 brings together pricing differentials and market
characteristics to provide a basis for estimating the commodity value
differential of natural gas on a regional basis for the first quarter of
1972.
The estimates are shown on two separate bases. The first esti-
mate is made by reference to the total gas market and is constructed as
follows:
(a) The residential househeating price of gas comparative with the
price of distillate and electricity is shown at Column (1) on a
weighted average basis.
(b) The firm industrial and commercial price of gas comparative
with substitutable fuels is shown at Column (2) on a weighted
average basis.
(c) The power plant and interruptible price of gas comparative with
substitutable fuels is shown on a weighted average basis.
(d) These three sectors of each regional market are weighted at
Column (4) in accordance with the 1971 regional consumption
of gas by sector.
VI-4
-------
TABLE VI-1
THE DIFFERENTIAL BY WHICH NATURAL GAS IS PRICED BELOW ITS
COMMODITY VALUE LEVEL IN CONSUMER MARKETS
FIRST QUARTER 1972
(*/MMBtu)
Estimated by Reference
to the Total Market
Firm
Indus - Power
trial Plant
and and
Residen- Commer- Inter- Weighted
tial a/ cial ruptible Average
err
A. Interstate Market Regions
73)
74)
Estimated by Reference
to the Priority Market
Firm
Indus-
trial
and
Residen- Commer- Weighted
tial b/ cial Average
75)
Pacific
Southwest
Pacific
Northwest
Northern
Plains
Great Lakes
MidContinent
Southeast
East
Appalachian
New England
West
Appalachian
202*
69
94
93
62
93
42
(4)
121
23*
(8)
16
0
9
7
(43)
(79)
4
10*
0
0
5
7
(9)
0
(10)
0
69*
13
32
35
20
14
2
(28)
11
67*
44
39
35
38
29
5
(36)
44
23*
(8)
16
0
9
7
(43)
(79)
4
52*
13
28
16
24
15
(18)
(52)
22_
Subtotal
32*
14*
B. Local Market Regions
Rocky
Mountains
Gulf Coast
183
124
10
16
(3)
5
58
20
77
15
10
16
46
16
Total
29*
15*
a/ Includes price differential based on electric heating.
§7 Excludes price differential based on electric heating.
VI-5
-------
Based on this total market approach, the price of gas is found
to be below the price of substitutable fuels in 10 of the 11 markets,
ranging from a 2<£ differential in the Eastern Appalachian Region to a 69£
differential in the Pacific Southwest Region. In New England the price of
gas is shown to exceed substitutable fuels by a weighted average of 28
-------
Second, the total market approach gives full weight to the
power plant and interruptible boiler fuel market, although this is not
a priority market under current FPC regulation and is expected to decline
in importance in the future, based on evolving patterns for allocating
limited gas supplies.
Finally, no price-equivalent consideration is given to the non-
price premiums attached to gas over oil and coal in the firm industrial
and commercial market as well as the power plant and interruptible market.
To eliminate several of these more extreme considerations, an
alternative estimate of the differential by which gas is priced below
substitutable fuels was prepared on Table VI-1. Made by reference to
the priority market (residential, commercial and firm industrial), the
estimate is constructed as follows:
(a) The residential househeating price of gas is compared only with
the price of distillate, as shown at Column (5) of Table VI-1.
The price comparison with electricity is eliminated.
(b) The price of gas in the firm industrial and commercial markets
comparative with substitutable fuels is shown on a weighted
average basis at Column (6) of Table VI-1.
(c) These two sectors of each regional market are weighted at
Column (7) of Table VI-1 in accordance with the 1971 regional
consumption of gas by sector.
Based on this priority market approach, the current price of
natural gas was found to be below the price of substitutable fuels in 9 of
the 11 markets, ranging from a 13
-------
Northwest market to a 52
-------
Appalachian and New England markets where, on a price only basis, gas is
currently priced above levels of substitutable fuels.
In summary, the price of gas in U.S. priority consumer markets
is found to be below the most conservative estimate of its co;nmodity value
level by 14
-------
Thus, the above table indicates a current commodity value of
34 to 35* for all gas in the field. However, it is necessary to carry
the analysis one step further to consider the role of price under different
vintages of contracts, i.e., new gas contracts versus existing gas con-
tracts . This vintage concept is embedded in FPC area rate regulation and
is based on the rationale that it is the price of new gas which provides
incentive to producers to explore and drill for increased supplies. In a
free market, new contract prices clearly change in response to supply and
demand factors. At the same time, however, it must be borne in mind that
prices under existing, or so-called "old" contracts generate a major por-
tion of the cash flow available for exploration and drilling of new gas
reserves. Because of the importance of this cash flow, it is suggested
some portion of the commodity value differential, determined as of the
first quarter 1972, be assigned to old gas prices as well as to new gas
prices. Such an assignment is shown on two bases on the following table.
ALTERNATIVE STRUCTURES FOR PRICING GAS AT ITS
COMMODITY VALUE LEVEL IN THE FIELD, BASED
ON THE VINTAGE CONCEPT: FIRST QUARTER 1972
(*/Mcf at 14.73 psia and 1032 Btu/cf)
Volumetric
Weight a/
86%
Actual
22.6*
19.5
Commodity
Value
Level b/
60.0*
30.1
New gas
Old gas
Total gas 100% 19.9* 33.9*
a/ Based on 1971 purchases of gas by interstate gas pipe-
lines.
b_/ Most conservative estimate for priority markets.
VI-10
-------
The 6(K price for new gas seems the more plausible alternative
based on current trends. Gas prices under new contracts signed in the
Southwest, free of regulatory area pricing constraints, are predominantly
in the 30-40
-------
NATURAL GAS PRODUCTION BASED ON THE
BUREAU OF NATURAL GAS FORECAST a/
(Trillion Cubic Feet at 14.73 psia and 1032 Btu/cf)
Year
1971
Projection
1972
1973
1974
1975
1976
1977
1982
Reserve
Additions
9.4
13.0
14.0
15.0
16.0
17.0
17.0
17.0
Production
21.9
22.6
22.9
23.2
23.7
23.0
22.4
20.2
Year-End
Total
Reserves
247.4
237.8
228.9
220.7
213.0
207.0
201.6
181.7
Reserves-to-
Production
Ratio
11.3
10.5
10.0
9.5
9.0
9.0
9.0
9.0
a/ Based on reserves additions projected by the FPC Bureau of Natural
Gas in National Gas Supply and Demand, 1971-1990, February 1972.
In projecting these supplies, the BNG report stated:
"We have concluded that an increase from the present
level of reserve additions to the average national finding
level of the past ten years (17 Tcf annually) is consistent
with other factors such as the undiscovered potential and
recent regulatory actions, which have increased the wellhead
price of gas in several important supply areas. ... The
Commission did find . . . that there exists a positive
relationship between gas contract price levels and explora-
tory effort and on this basis concluded that the higher
rates established would result in increased drilling efforts
and the development of new gas supplies." I/
\l The National Petroleum Council, apparently utilizing the same general
assumptions, arrived at a more pessimistic forecast, with production
peaking in 1972 at an estimated 22.4 Tcf and declining thereafter,
amounting to 15.7 Tcf by 1982. U.S. Energy Outlook, An Initial
Appraisal, 1971-1985, November 1971.
VI-12
-------
Based on this statement, a supply curve can be simulated by
reference to commodity value pricing in comparison with prices based on
existing area rates. The fundamental assumption in this projection is
that the price elasticity of new gas reserves will be +.45 -- i.e., a
increase in price will provide a 4.51 increase in new gas reserves.—
Utilizing a new gas price of 60
-------
(1) The reserves additions projected to 1980 and to 1985 by the FPC
Bureau of Natural Gas reflect the incentive structure according
to the current area pricing format set for South Louisiana
(26
-------
would be 24.2 Tcf compared with 22.4 Tcf under FPC current price ceilings.
By 1982 the comparison is 25.3 Tcf versus 20.2 Tcf.
The impact on pipeline and distributor load balancing problems
and marketing patterns will be substantial as between these two projections,
compared with the forecast demand. This is shown in graphic form on the
following table. Exclusive of field use, and stated at 1000 Btu/cf, pro-
duction based on commodity value pricing comparative with current area
ceiling pricing would make available in 1977 an additional 1.7 trillion
cubic feet of gas (4.7 billion cubic feet per day) for deliveries to con-
sumers. By 1982 the difference between the two projections is much greater
-- 4.9 trillion cubic feet per year, or 13.4 billion cubic feet per day --
PROJECTED PRODUCTION
COMPARED WITH
LATENT DEMAND IN THE LOWER 48 STATES
3
Z
o
HU
30
20
10
n
—-
Pro<
•
!•!••»*»
Auction
^~~
Josed o
'
n Currei
(Fvtur*
*~~~
i»ir^«
^«
if Areo
tofen
Require
+~^
'^^^
»
Prices
f Demon
menff C
PC boii
4PC baii
d
9mmif fe«
..it""""
— '
t"
1 ,••"»""
Prod
Comma
^^
ln»»tlil
ucfion B
diry Va
^*""
osed on
ue Prici
ng
NOTE: Projection ii exclusive of field ute and i> stated at 1000 Btu/cf.
VI-15
-------
because the BNG production forecast commences to decline after 1975, while
the commodity value production forecast continues to increase in a moderate
degree.
The above analysis is predicated on an assumed elasticity of
supply of +0.45. This could be a conservative assumption for no econometric
model can anticipate the numerous and complex variables that will affect
the response of industry to a change in field prices. For this reason the
following table was prepared to illustrate the impact of a higher elasticity
of supply, ranging up to +1.0.
EFFECT OF ELASTICITY OF SUPPLY ON PROJECTED
PRODUCTION OF GAS IN THE LOWER 48 STATES
| ASSUMING THE PRICE OF GAS UNDER NEW CONTRACTS
INCREASES FROM 26< to 60< per Mcf on Jan. 1 1973
24
40
50
60 .70 .80
ELASTICITY OF SUPPLY
.90
1.00
VI-16
-------
Assuming the price of new gas supplies increases from 26
-------
forego market growth or, alternatively, inject ever-increasing additional
supplies of supplemental gas.
However, the additional supplies of domestic gas resulting from
commodity value pricing can only be obtained at a substantial cost compara-
tive with the price of declining supplies as projected under current area
pricing policy. This is illustrated by the following figure.
THE UNIT COST OF INCREMENTAL DOMESTIC SUPPLIES
ASSUMING THE PRICE OF GAS UNDER NEW CONTRACTS
INCREASES FROM 26{/Mcf to 60
-------
For example, the unit cost of these incremental supplies under
commodity value pricing is estimated to be 118
-------
"old" gas on this table is defined as the weighted average of "old" and
"new" gas according to the current FPC vintage pricing, including all gas
contracted through December 31, 1972. "New" gas on this table is defined
as gas contracted beginning January 1, 1973.
In 1973 and 1974 the initial price of gas under new contracts
is projected to average 50^/Mcf. From 1975 to 1982 the initial price of
gas under new contracts is assumed to average 60£/Mcf.
Old prices are assumed to increase at an annual average amount
of 2.3<£/Mcf per year to 1977, a substantial regulatory lag but reflecting
the overriding need for an increased cash flow to explore and drill for
new supplies of gas.
It will be noted that the optijual strategy for EPA focuses on
new gas contract prices for it is here the "incentive" price is estab-
lished. However, a basic assumption is made that if the FPC continues to
regulate "old" gas prices, it will establish a level sufficient to gen-
erate a cash flow required to support exploration and development. If,
alternatively, it is assumed the FPC fails to establish "old" gas prices
at a sufficient level, then the optimal strategy for EPA must be complete
deregulation of field prices.
If field prices are totally deregulated by Congress, the old gas
prices are projected to respond more readily to the shift of new gas prices
toward their commodity value level, primarily by redetermination-type
clauses. By 1977 old gas prices on this basis are projected to be 36.9<£
per Mcf. Furthermore, some 18% of the volume of old gas will be under
contracts expiring over this forecast period and therefore renegotiated as
VI-20
-------
new gas contracts. This would result in the average "rolled-in" price of
gas by 1977 being 45<£/Mcf.
As to the benefits, field prices at a commodity value level
would spur the development of additional gas supplies by providing greater
incentive to drill for gas and increased cash flow to finance exploration
and development. The gas pipeline and distribution industry would benefit
from increased throughput or utilization of existing capacity. Without
allowing gas prices to achieve commodity value levels, natural gas produc-
tion in the U.S. will decline. The high proportion of total cost represented
by fixed costs (costs which do not vary with output) in pipeline and distribu-
tion operations results in diseconomies of scale with declining throughput.
Cost per unit of throughput increases as utilization of capacity declines.
Natural gas prices fixed by reference to the market would also
benefit the energy industry because of the interrelationship of gas with
oil, both in terms of exploration effort and corporate structure. The search
for gas has become, increasingly directional in recent years. Notwithstanding
this factor, the price of gas, like the price of oil, makes a contribution to
the search for hydrocarbons. To a non-quantifiable degree, higher gas prices
will also spur additional drilling for associated-dissolved gas found with
oil reserves.
Moreover, the increased cash flow to oil and gas producers
resulting from gas will increase the internal funds available for hydro-
carbon exploration and development. Hence, commodity value pricing will
act to increase supplies of associated-dissolved gas resulting from domestic
crude oil production.
VI-21
-------
It can also be noted that increased exploration and development
of gas reserves in the United States will directly increase employment and
income in industries servicing the gas production industry. Assuming a
1:1 multiplier for indirect:direct expenditures would result in an esti-
mated total annual contribution of $8 billion to the GNP from 1973 to 1977,
and $13 billion annually from 1978 to 1982. Payments to royalty owners
(estimated at 13.5% of total production value) would increase from $0.6
billion in 1972 to $1.2 billion in 1977 to $1.7 billion in 1982. Hence,
it may be seen that commodity value pricing would have a material impact
on GNP in the United States.
Mother direct benefit of commodity value pricing for gas would
be the contribution to the U.S. balance of payments. Each Mcf of gas dis-
covered due to the greater exploration effort under commodity value pricing
would accordingly reduce the need to import oil or gas from other countries.
E. The Benefit of Increased Gas Supplies Resulting from a Reduction of
Sulfur Emissions
In summary this chapter has developed alternative strategies
which might be pursued by the EPA in seeking to achieve increased gas
supplies.
While a number of alternative strategies are available to EPA,
the optimal strategy is found to be an incentive structure which would
allow the price of new gas contracts to be fixed by reference to the market-
place. This would best be achieved by amending the Natural Gas Act to deregu-
late field prices of gas produced in the United States and sold under new
contracts. The objective could also be attained, with lesser effectiveness
VI-22
-------
and a greater time lag, by amending the Natural Gas Act to instruct the
FPC in its continuing regulation of field prices of gas to grant "contract
sanctity" and to determine reasonable new gas prices by reference to economic
factors in the marketplace, not by reference to cost of service.
Under either alternative the objective would be to allow new gas
prices to reach a "market clearing level," the commodity value level.—
In addition to the benefits to the nation's economy, as described
above, the increased supplies of gas which would result from this optimal
solution will have a direct benefit with respect to EPA's regulation of
sulfur emissions into the atmosphere from stationary sources.
It has been estimated that there will be a short-fall in coal and
perhaps oil supplies available to meet sulfur regulations in accordance
with State Implementation Plans (SIP). For example, a recent Mitre report
to EPA, entitled "Impact of State Implementation Plans on Fossil Fuel Avail-
ability and Requirements," estimates that in 1977 approximately 14,760
trillion Btu of low sulfur coal will be required to meet SIP but only
6,960 trillion will be available. Therefore, a deficit of 7,800 trillion
Btu of low sulfur coal will exist in that year. The report also estimates
that in 1977 approximately 9,030 trillion Btu of low sulfur fuel oil will
be required to meet SIP, but only 6,864 trillion will be available. There-
fore, the deficit of 2,166 trillion Btu of low sulfur oil will exist. On
I/ A necessary companion to this optimal solution is the need to price
flowing (old) gas at a level sufficient to generate a cash flow which
will support the expanded exploration and well drilling activity
resulting from increased incentives caused by allowing new gas prices
to reach commodity value levels.
VI-23
-------
this basis there will be a short-fall of low sulfur oil and coal amounting
to 9,966 trillion Btu by 1977 in the United States if the SIPs are to be
met, in accordance with Congressional mandate.
It is within this context that an increasing supply of domestic
gas would be of direct benefit to the Congressional mandate to reduce
sulfur emissions into the atmosphere from stationary sources.
The contrast between the projected production of gas in the
Lower 48 States under existing FPC area price ceilings, and the optimal
solution afforded by commodity value pricing of gas in the field, is
summarized on the following table.
FORECAST OF GAS PRODUCTION IN THE LOWER 48 STATES-''
[Trillion Cubic Feet at 1000 Btu/cf)
Based on Commodity Value Pricing
Based on Current Assuming Elasticity of Supply at
Area Prices b/ +0.45 +0.75 +1.0
1977 21.4 23.1 24.2 25.2
1982 19.3 24.1 27.5 30.1
a/ After exclusion of field use.
BY Based on the Federal Power Commission estimate set out in National
Gas Supply and Demand, 1971-1990, February 1972.
The benefit resulting from commodity value pricing compared with
current area pricing would be an increase in supplies of gas produced in
the Lower 48 States in 1982 ranging from 4.8 to 10.8 trillion cubic feet,
depending on the elasticity of supply that will ultimately prove to be
the fact.
VI-24
-------
This increased production of gas will directly offset the projected
deficiencies in low sulfur coal and oil availability, and doubly so, if addi-
tional supplies of fuel oil will be required in the future to fulfill short-
falls in gas demand caused by declining gas production projected on the
assumption of a continuation of current FPC area price ceilings.
The analysis to this point demonstrates the volumetric benefit
of increased gas production from the point of view of reducing sulfur
emissions in the United States. An equivalent expression in dollars can
be estimated. A literature search found no definitive study of the direct
dollar benefits to the nation of reduced sulfur emissions. Accordingly,
the sulfur tax proposed by bills submitted in 1972 to Congress will be
used to translate increased gas production into dollars of benefit from
the point of view of reducing sulfur emissions.
The Pure Air Bill of 1972, the sulfur tax sponsored by the
Administration could, in the opinion of EPA, provide a strong economic
incentive for the.reduction of sulfur in fuels. If passed, this tax would
become effective in 1976 and be levied on sulfur emitted into the atmos-
phere from combustion, refining, smelting and other processes. It would
apply in those regions where the primary and secondary standards are not
met. For those regions where the primary standards are not met, the amount
of the tax would be 15
-------
Alternative bills submitted to Congress in 1972 would tax sulfur
emissions at a rate of 20$ per pound regardless of whether ambient air
standards are not exceeded.—
If it be assumed the shortfall in low sulfur oil and coal can
only be filled by oil and coal at 2.51 sulfur by weight, then the "cost"
to society can be determined by reference to the sulfur tax, summarized
on the following table.
ESTIMATED UNIT BENEFIT OF AN INCREASED GAS SUPPLY IN THE
UNITED STATES WITH RESPECT TO REDUCTION IN SULFUR EMISSIONS
(f/MMBtu
A. Gas replaces coal containing 2.5% sulfur [by weight)
1. Sulfur "tax" at 15$ per pound 28.8
2. Sulfur "tax" at 20$ per pound 38.4
B. Gas replaces fuel oil containing 2.51 sulfur (by weight)
1. Sulfur "tax" at 15$ per pound 20.7
2. Sulfur "tax" at 20$ per pound 27.5
Because coal contains more sulfur'per unit of heat content (Btu
content), the benefit to society of gas replacing high sulfur coal ranges
from 28.8 to 38.4$/MMBtu while the benefit of gas replacing high sulfur
fuel oil ranges from 20.7$ to 27.5$/MMBtu.
When related to volumes shown on the table on page VI-24,. the
benefit to society from increased gas supplies projected to 1982 in monetary
terms is summarized on the following table.
I/ H.R. 10480 and H.R. 53057.
VI-26
-------
ESTIMATED TOTAL BENEFIT OF AN INCREASED GAS SUPPLY IN THE
UNITED STATES WITH RESPECT TO REDUCTION IN SULFUR EMISSIONS
Maximum
Minimum
Increase in 1982 Gas Supply
Resulting from Commodity
Value Pricing Commencing
January 1, 1975 a/
(Trillion Cubic Feet)
10.8
4.8
Cost Benefit in 1982 if the
Increased Gas Supply Replaces
High Sulfur Coal or Oil
Coal
Oil
(Million Dollars)
$3,100-4,147
1,382-1,843
$2,236-2,970
994-1,320
a/ Supply range reflects alternative elasticity of supply assumption
ranging from +0.45 to +1.0.
Source: Tables on pages VI-24 and VI-26.
Another way of demonstrating the benefits of increased gas
supplies to society is the reduction in emissions of sulfur dioxides that
could be attained by replacing high sulfur coal and residual fuel oil.
This is set set out in the table below.
ESTIMATED BENEFIT OF AN INCREASED GAS
SUPPLY IN THE UNITED STATES WITH RESPECT
TO REDUCTION IN SULFUR DIOXIDE EMISSIONS
Maximum
Minimum
Increase in 1982 Gas
Supply Resulting from
Commodity Value Pricing
Commencing January 1, 1973
(Trillion Cubic Feet)
10.8
4.8
Reduction in S0? Emissions
in 1082 if the Increased
Gas Supply Replaces:
High Sulfur
Coal a/
High Sulfur
Oil a/
[Million Tons SO^J
19.7 14.2
8.8 6.3
a/ Assuming a 2.5% sulfur fuel.
VI-27
-------
Bibliography
Federal Power Commission, Staff Report No. 2, National Gas Supply and
Demand, 1971-1990, February 1972
Foster Associates, Inc., study entitled The Current and Prospective
Commodity Value of Natural Gas in North America Markets, 1972-T982,
October 1972
MacAvoy, Paul W., "The Regulation-Induced Shortage of Natural Gas,"
Regulation of the Natural Gas Producing Industry, Resources for the
Future, 1972
National Petroleum Council, U.S. Energy Outlook: An Initial Appraisal,
1971-1985, November 1971
VI-28
-------
BIBLIOGRAPHIC DATA
SHEET
I. Report No.
APTD-1459
3. Recipient's Accession No.
I. Title and Subtitle
An Analysis of the Regulatory Aspects of Natural Gas Supply
5. Report Date
March 1975
6.
7. Authorfs)
M. W. Rockefeller and R. L. Schantz
8. Performing Organization Kept.
No.
9. Performing Organization Name and Address
Foster Associates, Inc.
1101 Seventeeth Street, N.W.
Washington, B.C. 20036
10. Project/Task/Work Unit No.
11. Contract/Grant No.
ict/Grant No.
68-02-0640
12. Sponsoring Organization Name and Address
EPA, Office of Air Quality Planning and Standards
Strategies and Air Standards Division
Research Triangle Park, North Carolina 27711
13. Type of Report & Period
Covered
Final Report
14.
IS. Supplementary Notes
16. Abstracts
A study was conducted to review the current regulatory picture affecting the supply and
distribution of natural gas and low sulfur fuel oil, to analyze possible changes in this
regulatory picture, and to appraise alternate regulatory strategies which could bring
about increased supplies of these clean±>urning fuels. The results of the study are
contained in two separate reports, one report for natural gas and the other for fuel
oil. Also, abridged copies of the two comprehensive reports are provided.
17. Ktv tt'or.ls and Document Analysis. 17a. Descriptors
Government
Law
17b. Identifiers/Open-Ended Terms
Air pollution
Natural gas
I7e. COSATI Field/Group
18. Availability Statement
Unlimited
19. Security Class (This
R v port)
UNCLASSIFIED
20. Security Class (This
Page
UNCLASSIFIED
TIS-33 (REV. 3-721
21. No. of Pages
279
22. Price
USCOMM-DC I4932-P72
------- |