Alternative Energy Futures: Part I-The

Future of Liquefied Natural Gas Imports

March 1980

NTIS order #PB80-173552
Library of Congress Catalog Card Number 80-600046

For sale by the Superintendent of Documents, U.S. Government Printing Office

Washington, D.C. 20402 Stock No. 052-003 -00743-6
Foreword

This assessment

for an evaluation of

responds to a request by the Senate Committee on Finance

the economic and energy implications of any future liquefied natural gas (LNG) imports. This part of- OTA’s continuing examination of

Alternative Energy Futures complements and expands upon an earlier OTA

report, Transportation of Liquefied Natural Gas.

Highlights of the study include a discussion of worldwide availability

natural gas for U. S. import as LNG, in the context of projected U.S. gas demand,

alternative North American oil and gas resources, and the security of foreign

supplies. The report also contains sections on LNG project structure, cost, and

financing with observations about balance-of-payment impacts and public exposure to financial risk. Finally, an analysis of the behavior of gas markets in

determining who receives additional supplies by virtue of LNG projects, and

who pays for them, illustrates some of the practical effects of the Natural Gas

Policy Act of 1978.

We are indebted to the members of the advisory panel and to numerous

other individuals and institutions for suggestions, information, and critique.

Also, the contribution of several contractors, who performed background research, is gratefully acknowledged.

.

iii
Liquefied Natural Gas Advisory Panel

Jerome E. Hass, Chairman

Graduate School of Business and Public Administration

Cornell University

Seth Borgos

Director of Research

ACORN

lrvin C. Bupp, Jr.

Graduate School of Business Administration

Harvard University

George Carameros

Chairman

E] Paso LNG Company

Melvin A. Conant

Conant and Associates, Ltd.

James C. Cruse

Vice president

Policy and Analysis

U.S. Export-Import Bank

Todd M. Doscher

Department of Petroleum Engineering

University of Southern California

Michael R. Eaton

Sierra Club

Bruce M. Hannon

Director, Energy Research Group

University of Illinois

Michael Hogan

E. J. Rager & Associates

Max M. Levy

Vice President

Columbia LNG Corporation

William R. Robertson

Executive Secretary-Treasurer

Los Angeles County

Federation of Labor

Robert L. Solomon

Assistant Director

California Energy Resources Conservation &

Development Commission

Macauley Whiting

The Dow Chemical Company
LNG Project Staff

Lionel S. Johns, Assistant Director

Energy, Materials, and International Security Division

Richard E. Rowberg, Energy Program Manager

J. Bradford Hollomon, Project Director

Fern Racine Gold Joanne Seder

Administrative Staff

Lisa Jacobson Lillian Quigg Yvonne White

Contractors

Jensen Associates, Inc. Steven C. Carhart S. Abraham Ravid

OTA Publishing Staff

John C. Holmes, Publishing Officer

Kathie S. Boss Debra M. Datcher Joanne Heming
Contents

Chapte r

1.

2.

3.

Overview . . . . . . . . . . . . . . . . . . . . .

Summary . . . . . . . . . . . . . . . . . . . . .

Introduction . . . . . . . . . , . . . . . . . . . .

Background. . . . . . . . . . . . . . . . . . . . .

Findings . . . . . . . . . . . . . . . . . . . . . . .

1: How much gas is available for

import as LNG? . . . . . . . . . . . . . . .

2: How does security of supply affect

the desirability of LNG imports? . .

3: How much will LNG cost in

the future? . . . . . . . . . . . . . . . . . .

4: How would added gas supplies

from LNG be used? . . . . . . . . . . . .

5: How is the cost of LNG distributed 

among consumers? . . . . . . . . . . . .

6: How strongly do LNG imports

affect the balance of payments?. . .

7: How are present Federal policies

likely to affect future LNG.N(; imports’?

Policy Background. . . . . . . . . . . . .

Administration import policy . . . . . . .

Maritime Administration. . . . . . . . . . .

Export-Import Bank. . . . . . . . . . . . . . .

Department of Transportation . . . . . .

Department of Defense . . . . . . . . . . .

Congressional interest. . . . . . . . . . . . .

States . . . . . . . . . . . . . . . . . . . . . . . . .

other States . . . . . . . . . . . . . . . . . . .

Future Gas Availability and Use. .

U.S. gas demand . . . . . . . . . . . . . . . . .

Comparisons of projection results . .

Effect of prices. . . . . . . . . . . . . . . . .

Effect of public policy. . . . . . . . . . . .

Domestic supplies . . . . . . . . . . . . . . . .

Conventional natural gas . . . . . . . . .

Conventional oil . . . . . . . . . . . . . . . .

Unconventional domestic oil and gas

sources . . . . . . . . . . . . . . . . . . . . .

Canada and Mexico . . . . . . . . . . . . . . .

Canada . . . . . . . . . . . . . . . . . . . . . .

Mexico . . . . . . . . . . . . . . . . . . . . . . .

Gas from overseas. . . . . . . . . . . . . . . .

Worldwide natural gas reserves and

exportable surpluses. . . . . . . . . . .

Competitive importers of LNGEurope and Japan . . . . . . . . . . . . .

Foreign LNG potentially available to

the United States. . . . . . . . . . . . . .

Chapte r

4. Project Structure, Cost, and

Financing . . . . . . . . . . . . . . . . . . .

LNG projects . . . . . . . . . . . . . . . . . . . .

Algeria II . . . . . . . . . , . . . . . . . . . . .

Pac Indonesia . . . . . . . . . . . . . . . . .

Pricing policies of exporting

countries. . . . . . . . . . . . . . . . . . . .

Producing country facilities and

related costs . . . . . . . . . . . . . . . . .

Transportation facilities-cryogenic

tankers . . . . . . . . . . . . . . . . . . . . .

Receiving country terminal and

regasification facilities. . . . . . . . . .

LNG financing. . . . . . . . . . . . . . . . . . .

Overview . . . . . . . . . . . . . . . . . . . . .

Exporting country facilities . . . . . . .

Shipping. . . . . . . . . . . . . . . . . . . . . .

U.S. facilities . . . . . . . . . . . . . . . . . .

Conclusion . . . . . . . . . . . . . . . . . . . .

Cost of service. . . . . . . . . . . . . . . . . . .

Base case . . . . . . . . . . . . . . . . . . , . .

Sensitivity . . . . . . . . . . . . . . . . . . . .

Financial risk . . . . . . . . . . . . . . . . . . .

Technical feasibility . . . . . . . . . . . . .

Project failure . . . . . . . . . . . . . . . . .

Project interruption or delay . . . . . .

Cost overrun. . . . . . . . . . . . . . . . . .

Market uncertainties . . . . . . . . . . . .

Who bears the financial risk’? . . . . . .

The Pac Indonesia project-/\n

example of risk distribution. . . . . .

Risk of LNG embargo the

producing country . . . . . . . . . . . .

5. Social Costs and Benefits . . . . . . .

U. S. consumers of LNG . . . . . . . . . . . .

Modeling of pipeline systems . . . . . .

allocation issue: who gets

the LNG? . . . . . . . . . . . . . . . . . , . .

The price issue: who pays for

the LNG? . . . . . . . . . . . . . . . . . . . .

Supply impact of LNG interruption. .

Air quality benefits of gas utilization . .

Balance payments . . . , . . . . . . . . . .

LIST OF TABLES

Table No.
Contents—continued

Table No.

2. - .

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

Potential Gas Supply in 1990. . . . . . . . . . . .

1990 Gas Demand for Low Oil Price Cases .

1990 Gas Demand for High oil Price Cases .

[J. S. Gas Supply Conventional,

Unconventional, Coal Gas . . . . . . . . . . . . .

Possibl e; Future U.S. Liquid petrole m

Production . . . . . . . . . . . . . . . . . . . . . . .

Forecasts of U. S. Conventional Natural Gas

Production . . . . . . . . . . . . . . . . . . . . . . . . .

Potential Supply . . . . . . . . . . . . . , . . . . . .

Forecasts of U.S. Conventional Liquid

Petroleum Production . . . . . . . . . . . . . . . .

Estimated Potential Production From

Enhanced Recovery . . . . . . . . . . . . . . . , . .

Annual Production From Unconventional

Sources to the Year 2000 at $1.75 and

$3.00/Mcf. . . . . . . . . . . . . . . . . . . . . . . . . .

Projections of Coal Gas Production . . . . . . .

Potential Syncrude Production From Coal .

Shale Oil Production. . . . . . . , . . . . . . . . . .

Canadian Gas Potential . . . . . . . . . . . . . . . .

Mexican Oil and Gas Export Potential . . . . .

Availability of’ Foreign LNG to the United

States Beginning in the 1980’s. . . . . . . . . . .

Natural Gas Supply/Demand projections for

1985 and 1990, European Economic

Community . . . . . . . . . . . . . . . . . . . . . . . .

LNG and Pipeline Gas Import Projects to

OECD Europe . . . . . . . . . . . . . . . . . . . . . . .

20. Japanese LNG Import Projects . . . . . . . . . .

21.

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

32.

Comparison of LNG Import Project

Volumes and Planned Import Levels-Japan

Distances Between LNG Liquefaction Ports

and Typical Import Locat ions. . . . . . . . . . .

Potential Availability of Foreign LNG to the

United States Before 1990. . . . . . . . . . . . . .

Operational LNG Projects, as of July 1, 1979

Estimated Capital Costs of Indonesian-Based

LNG; Facilities for Pacific Indonesia Project .

Capital Costs per Million Btu of Daily

(Contractual Quantity . . . . . . . . . . . . . . . . .

Estimated Capita] Requirements for El Paso

Atlantic-Six Vessels. . . . . . . . . . . . . . . . ,

Estimated Annual Operating Expenses for

El Paso Atlantic-Six Vessels. . . . . . . . . . . .

Point Conception Terminal Estimate of

Capital Costs. . . . . . . . . . . . . . . . . . . . . . . .

Point Conception Terminal Estimate of

Annual operating Costs . . . . . . . . . . . . . . .

Point Conception to Gosford Pipeline

Estimate of Investment Requirements . . . .

Capital Costs for Import Facilities per

Million Btu of Daily Delivered Quantity

of LNG . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

29

31

31

32

33

33

33

34

36

38

39

39

39

41

43

44

55

55

57

58

58

.59

70

80

82

84

85

87

87

87

88

Table No.

33.

34.

35.

36.

37.

38.

39.

40.

41.

4.2.

Cost of Service of an LNG Project Beginning

in 1985 in the Fifth Year of operation. . . .

Sample Calculation of Wellhead Netback

Price in 1989 for a Project Beginning in

1985. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Impact of Fifth Year Cost of Service of

Reducing Return on Equity to 15 Percent

and Interest on U. S. Debt to 10 Percent . .

Impact of Fifth Year Cost of Service of

Increasing Return on Equity to 19 Percent

and Interest on U. S. Debt to 14 Percent . .

Impact on Fifth Year Cost of Service of

Reducing the Round Trip Voyage Distance

to 3,274 Nautical Miles . . . . . . . . . . . . . . ,

Impact on Fifth Year Cost of Service of

Reducing the Round Trip Voyage Distance

to 16,694 Nautical Miles . . . . . . . . . . . . .

Distribution of Financial Risk for

Liquefaction and Loading Facilities of the

Pac Indonesia Project . . . . . . . . . . . . . . . . .

Distribution of Financial Risk for Ships of

the Pac Indonesia Project . . . . . . . . . . . . . .

Distribution of Financial Risk at the

Receiving/Regasification Terminal of the

Pac Indonesia Project . . . . . . . . . . . . . . . . .

Illustrative 1985 Residential and Industrial

Gas Prices With and Without Incremental

Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . .

43. Illustrative 1985 Residential and Industrial

Gas Prices With LNG Rolled-In and Without

LNG; . . . . . , . . , . . . . . . . . . . . . . . . . . . . . .

44. Illustrative 1985 Residential and Industrial

Gas Prices With LNG Rolled-In and With

LNG Incrementally Priced . . . . . , . . . . . . .

45. Distribution of Imported LNG by

Consuming State for Each Pipeline

Importer . . . . . . . . . . . . . . . . . . . , . . . . . .

46. Estimated LNG Sales by State . . . . . . . . . . .

47. Air Pollution From Burning Gas Versus

Other Fuels, in Thousands of Metric Tons

per Tcf/Equivalent . . . . . . . . . . . . . . . . . .

48. National and (California Ambient Air Quality

49.

Standards. . . . . . . . . . . . . . . . . . . . . . . . .

Potential Expenditures in the United States

Included in the Cost of an LNG Import

Project in the Fifth Year of Operationin

1990.. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

96

96

97

97

98

98

102

104

105

118

119

119

122

123

1.24

125

126

LIST OF FIGURES

Figure No. Page

1. Volume Reduction From Natural Gas

to LNG . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Vlll
Contents—continued

Figure No.

2. Major Segments of an LNG Import Project .

3. Projected Oil Production by Conventional

Methods From Known U.S. Reservoirs,

1976-95. . . . . . . . . . . . . 

4. Comparative Estimates of Undiscovered

Recoverable Resources of Crude Oil and

Natural Gas Liquids in the United States

as of Date of Estimate . . . . . . . . . . . .

,.

5. Annual Production From Unconventional

&)Lrr’(:[~s to th[~ Year’ 2000 at $1.75 and

$:3.00 /Nl(;f . . . . . . . . . . . . . . . . . . . . ., . . . .

6. J$’or’]d Natur’al (;as Rf?ser’\r[?s . . . . . . . . . . .

7. Nlar>h[?t Status OF;CI) (;tis Rcs[?r’\’es . . . . . .

8. hlar’kct Status NOPF;(; (;as R[?scrs\7es . . . . . .

:). Nl:~ r.k[?t St :~t LIs ( ) [lP;(: ( hs R(?sc r’kr[?s . . . . . . .

1(). Nlar’ket Status: [ 1.S. S. R., Ir’;in, and Algc?r-ia . .

11. Major> [ Incomnlittc?d (;as R(?scr-\’[?s

I+;xpor.tal)le to t$ror.ki hlar’kcts . . . . . . . . . . .

] ~ (;ost of” s~?r.l,i(;~? as ~~ ~;lrr](:tior~ of” 1)ist[lr~(:[~

Pa$f’

9

36

37

37

47

48

~:]

.50

51

52

I;igurfn Nf],

for’ a Tvpica

F’if’th Year= of op[?r’;it ion. . . . . . . .

I,N(; Irnpor’t Prwjcc in th(?

. . . . . . . .

13. Major’ Segments of” an 1,N(; Imfwrt Prwjcct .

14. Pricing Pr’misions of Pac lndon[?sia and

Algcr’ia 1 I 1 report Pr{)jects . . . . . . . . . . . .

15. (hrnpar’ison of’ the ~’or’wsast [1. S. ‘1’:irif’f’ on

Rcgasif’i[?d 1,lN(; in th(? ,\lgcr.ia II Prwjcct

\l’ittl the Il?liiwrwd Pr’i(w of” Fuel oil . . . . .

16. b’orwcast f“.o.1). Pr’im?s Piiid f“or 1,N(; in Pa(>

Indonesia and Alger’ia II Projw’ts. . . . . .

17. 1,N(; (;ost of’ S[?r’\ficc by Proj[?(’t S[~ction . . .

I/l. 1.N(; (k]st of Ser.\’ ice 1)~1 ‘1’}flw of” (l)st . . . .

l:], ]]lsl}ositiorl” Of 1,N(; (pip[?linc “/}”). . . . . ~ ~

20. (;(]nsl]rnl)tiorl of” [,N(; (pip[?linr “,,1”) . . . . .

21. I)isposit ion of I,N(; (pipeline “H”) . . . . . . . . .

ZZ. I~[?r’L:[?rlt [)istr’il)lrtiorl of’ 1.N(; \’olunl[?s and

(hsts (flipcline “A”) . . . . . . . . . . . . . . . .

23. P[?rw?nt []istrTihLrt ion of” [,N(; t’olumcs and

(;osts (pip(?linc “B”) . . . . . . . . . . . . . . . .

ix
Overview

Further projects to import liquefied natural gas (LNG) from overseas

could be desirable as elements of a strategy to meet future U.S. energy demand, despite current disfavor of such projects by the Department of Energy.

Specific proposals should be evaluated on their individual merits in the light

of the following findings.

. LNG imports could expand from the currently approved level of 0.8 trillion cubic feet per year (Tcf/yr) to between 1.3 and 1.8 Tcf/yr by the middle of the next decade. This amount, less than one-tenth of present domestic gas production, is limited by political instability in Iran, absence of any economic advantage in exporting gas for some other Middle Eastern oil producers, shorter transportation distances to competing European and Japanese markets, and restrictions on trade with the

Soviet Union. The most likely sources of U.S. imports, other than by

pipeline, include Nigeria, Indonesia, Australia, Malaysia, Trinidad, Colombia, and Chile.

. Not all potential LNG exporters are major oil producers or members of

OPEC, so curtailments of foreign gas supplies are less likely to coincide with those of oil than they would be otherwise. Also, LNG export=

ing nations generally have greater financial incentives than oil pro=

ducers do to maintain uninterrupted shipments, because of the difficulty in finding alternative purchasers with appropriate terminal facilities, and the large amount of debt incurred for liquefaction facilities

that must be paid by the exporter from project revenues. To the extent

that Maritime Administration and Export-Import Bank programs promote involvement of U.S. owners and creditors in LNG ships and facilities, the exporter’s stake in uninterrupted revenues diminishes. In the

event of an interruption, the resulting shortfall could be managed to

minimize adverse impacts through the present priority curtailment

system and by sales and exchanges among gas wholesalers.

. Over the next decade, domestic gas production will probably satisfy

essential requirements, but neither domestic sources nor pipeline imports from Canada and Mexico are likely to meet additional marginal

demand except at costs equal to or greater than that of LNG. Delivered

gas from LNG is likely to cost approximately the same as competing

fuels; less than synthetic fuels and distillates from foreign crude oil,

and more than currently regulated domestic natural gas. Consumers

also assume part of the financial risks associated with an LNG project

by paying gas prices regulated to allow investors to recover portions

of their initial costs, regardless of the project’s subsequent commercial success or failure.

. Although the disposition of added supplies in gas markets is complex

and will vary greatly from one case to another, gas made available as a

result of LNG imports will generally be used at least partly, and possibly entirely, in manufacturing and electric-generating applications.

Also, under the Natural Gas Policy Act of 1978, the cost of added sup=

plies will not necessarily be borne by the customers receiving them.

Of the types of consumers likely to obtain more gas from LNG projXI
ects, industrial customers will probably pay a price close to that of

alternative fuels and of the LNG itself, and electric utilities and purchasers of electricity will receive a subsidy in the form of “exempt”

prices under the Act. Although households and commercial establish=

ments would probably receive little additional gas, at least initially, the

price levels in these sectors will rise or fall in response to the higher

cost of LNG and to any savings that may result from improved utilization of transmission and distribution capacity.

● Importing LNG entails a significant outflow of dollars from the United

States compared to domestic alternatives, but its direct impact on the

balance of payments is less severe than that of purchasing equivalent

amounts of foreign oil. Furthermore, the effect of being able to choose

the lowest cost alternative from among LNG, foreign oil, and domestic

production and conservation may outweigh the influence of direct

payments associated with any specific trade by improving the competitive position of U.S. industry generally.

xii
1 ●

Summary
—

-./ ’

r

●

.

1

L . .
1 ●

Summary

Introduction

This assessment addresses whether or not

additional liquefied natural gas (LNG) imports

should be encouraged or restricted in the context of future national energy requirements and

supply alternatives. In the past, public debate

on this question has focused on both the safety

and economics of LNG from overseas as a fuel

resource.

On one side of the issues, proponents of increased imports point to:

●

●

●

●

●

●

●

declining domestic oil and gas production,

proven LNG technology,

lower costs compared to gas from Alaska

or synthetic fuels,

opportunities to diversify sources of foreign hydrocarbons,

less severe impacts than oil imports on the

balance of payments,

environmental advantages of gas, and

savings from any improvement in utilization of present gas transmission and distribution infrastructure.

opponents draw attention to:

●

●

●

●

●

●

●

the high cost of LNG compared to regulated

domestic gas,

the potential of conservation to diminish

the demand for additional fuels,

the fact that LNG involves flows of dollars

out of the United States,

the concern over security of foreign supplies,

the possibility that demand for gas from

higher cost sources like LNG is an artifact

of Government regulation and indirect subsidy,

the desirability of protecting markets for

synthetic fuels or Alaskan gas in order to

encourage development of these resources,

and

the hazardous nature of LNG itself.

Some advocates of conservation and solar power argue further that the United States should

not import more LNG until less costly efficiency

improvements and renewable energy alternatives have been exhausted. At the same time,

others feel that this position holds LNG hostage

to fuel-efficiency measures which are equally

likely to be adopted, regardless of any foreseeable volume of imports.

An OTA report, Transportation of Liquefied

Natural Gas, published in September 1977,

describes the technology, reviews the physical

and institutional components of the LNG import

system, and explores public awareness and concerns. Partly in response to questions raised by

that study, the Senate Committee on Finance

asked OTA to examine LNG import policy in the

context of other energy alternatives, with emphasis on economic costs and benefits. The request arrived after President Carter, through

the National Energy Plan, had relaxed a policy

of the previous administration to limit LNG imports, and after the General Accounting Office

(GAO) had suggested in a report to Congress

that this new policy required reevaluation and

further improvement, essentially because insufficient rationale appeared in the plan.

This assessment is part of an ongoing examination of alternative energy futures, and in

response to the Senate Finance Committee’s inquiry, it focuses on the economic and energy

supply implications of the technology. Safety of

LNG facilities has been excluded, in order not to

duplicate the material in an earlier congressional report, Liquefied Energy Gases Safety,

issued in July 1978 by GAO.

The purpose of this analysis is to assist Congress and Federal and State regulatory bodies in

establishing or reevaluating the circumstances

under which LNG imports are in the public in3
4 ● The Future of Liquefied Natural Gas Imports

terest, and to aid in any further debate over policies that would encourage or restrict LNG imports in the future. Possible policy measures

that could result from resolution of the present

debate on this subject include the following:

●

●

●

●

●

●

●

●

imposition of formal limits on the amount

of LNG that may be imported from a particular supplier or from all foreign sources;

reversal of the Department of Energy’s

present assignment of a low-priority status

to LNG among potential future gas supplies;

change in the treatment of LNG as an incrementally priced supplemental gas source

under the Natural Gas Policy Act of 1978

(NGPA);

refinement of criteria for case-by-case import project approval by Federal and State

regulatory agencies;

alteration of the balance of Federal, State,

and local authority and autonomy in LNG

project approval and regulation;

change in present Maritime Administration

and Export-Import Bank policies, under

which components of LNG projects are eligible for credits and direct aid for specific

purposes;

encouragement or discouragement of LNG

trades as an element of foreign policy; and

decisions by private individuals and institutions to invest or not in LNG import projects.

This assessment does not decide which if any of

these options would be appropriate, but it does

provide the many participants in policymaking

with information and analysis they will need in

order to choose more wisely.

The project consisted of seven separate but

related analytical tasks:

1.

2.

3.

4.

a compilation of the history of Government

LNG import policy;

a review of’ U.S. gas demand projections

under alternative price and policy assumptions;

a survey of North American gas and oil resource estimates;

an investigation into the availability and

cost of LNG in world markets;

5. a description of the cost and structure of

LNG import projects, including financing

and the distribution of risk among the public and other participants;

6. an analysis of the distribution of costs and

benefits of imported LNG in domestic gas

markets; and

7. a brief discussion of the broader social and

environmental impacts of LNG imports.

The remainder of this chapter contains a list

of issues and findings extracted from the rest of

the study. They represent the principal conclusions from the the subsequent analysis.

The policy history, which comprises chapter

2, traces the development of administration attitudes toward LNG imports from President

Ford’s February 1976 energy message through

the National Energy Plan and the formation of

the Department of Energy to the present. The

chapter also describes relevant programs of

such agencies as the U.S. Export-Import Bank

and Maritime Administration, and it includes

expressions of congressional interest as evidenced by studies or recently introduced legislation. Finally, California provides an example of

State involvement in LNG import decisions.

Chapter 3, on future gas availability and use,

begins with a discussion of projected U.S. gas

demand by specific categories of end use under

different price and policy assumptions, reflecting the results of studies by several institutions.

Following the demand discussion is an analysis,

based on available studies, of North American

gas and oil resources (since oil can often be substituted for gas) including conventional and unconventional extraction technologies, synthetic

fuels, and reserves in Alaska, Canada, and Mexico. The latter part of the chapter addresses the

volume of foreign gas available to be imported

as LNG, taking into account such factors as reserves, proximity to competing markets like

Europe or Japan, prior contractual commitments, and political considerations.

The next chapter (chapter 4) includes a description of the structure of LNG import projects, beginning with pricing policies of exporting nations and followed by the capital and operating costs of cryogenic tankers and of facil-
Ch. l—Summafy ● 5

ities in the producing and receiving countries.

After an extensive discussion of the possible

sources of debt and equity financing and their

practical implications, the chapter ends with a

section on the distribution of financial risk

associated with investment in LNG projects,

with particular attention to any public liability

for unforeseen economic losses.

Social costs and benefits are the subject of

chapter 5. It begins with an analysis of who

would receive additional gas if more LNG were

imported and who would pay, given the complexities of the natural gas transmission and distribution system and of the regulatory framework within which it operates. The results are

useful in ascertaining the value of the gas in

terms of what would happen without it, and

Background

they are instructive as an example of the influence of NGPA as it affects gas markets generally. The effect of reduced gas supplies in the

event of a curtailment of foreign deliveries is

also treated in this part of the report. The rest

of the chapter is devoted to the possible influences of gas availability on air quality and employment and the impact of LNG import projects on the balance of international payments.

Three working papers prepared for this project contain more detailed material supporting

chapters 3 through 5. These reports, referred to

occasionally in the pages that follow, are published in a separate Background Reports volume

and will be made available through the National

Technical Information Service.

Since the first voyage in January 1959, of the

Methane Pioneer from Lake Charles, La., to Canvey Island on the Thames River near London,

England, ocean transport of LNG at –2600 F has

been a technological reality. The first regular

commercial trade in the commodity began 5

years later, in 1964, with shipments from

Arzew, Algeria, to Canvey Island and the

French port of Le Havre. Today, 12 operating

projects, 3 of which involve the United States,

account for 1.75 trillion cubic feet (Tcf) of gas

traded annually. The United States presently exports ().0.5 Tcf/yr from Alaska to Japan and imports 0.45 Tcf/yr from Algeria. Two more approved projects involving Algeria and Indonesia

would add 0.38 Tcf/yr to import levels over the

next few years.

The virtue of LNG lies in its high density. In

liquid form, methane, the principal constituent

of natural gas, fits into one six-hundredth of the

space it requires as a gas at room temperature

and atmospheric pressure (see figure 1). The gas

industry has taken advantage of this property

for storage purposes for half a century. With

rising energy costs, more efficient liquefaction

processes, and reliable performance of specially

designed cryogenic tankers, the economics of

Figure 1 .—Volume Reduction From

Natural Gas to LNG

x

= .11 9 = 1/600

Y Y’

SOURCE Office of Technology Assessment
6 ● The Future of Liquefied Natural Gas Imports

shipping gas in this form over ocean distances

have proven to be attractive.

The advantages and disadvantages of further

LNG imports depend in large part on expected

future levels of gas availability and use. As

described in chapter 3, one part of U.S. gas demand involves applications in which conservation or fuel substitution is costly, and the other

consists of applications in which alternative

fuels or improved productivity could be substiFindings

tuted readily, depending on public policies or

relative differences in fuel prices. The first category, or the “basic” demand, is projected at a

level of 14 quadrillion Btu per year in 1990. In

the same year, however, an additional 12 quadrillion Btu could be used in “marginal” applications if it were available at prices comparable to

those paid for gas today, and if electric utilities

were permitted to burn oil and gas. Under those

circumstances gas would be used in place of

coal, oil, nuclear power, and conservation.

At least over the next decade, domestic gas

production will probably satisfy essential requirements, but neither domestic sources nor

pipeline imports from Canada or Mexico are

likely to meet additional marginal demand except at costs equal to or greater than that of

LNG. Furthermore, North American oil production will probably not be sufficient to alter the

demand for gas by substitution. Viewed in this

way, LNG imports are no more or less imperative than other potential energy supplies of

equal size. The Nation has alternatives to LNG

from overseas, but gas in this form may be desirable as part of a portfolio of energy sources

and strategies to meet the projected future demand.

The advantages and disadvantages of LNG in

relation to improved efficiency and fuels from

other sources will depend on such factors as

availability, security of supply, cost, specific use,

distribution of costs among consumers, effect

on the balance of payments, and environmental

impact. Characterized in these terms, broad gas

resource categories are not susceptible to simple ranking, and projects must be compared on

their individual merits.

In many instances, choices are complicated

because action by the Federal Government is

limited to decisions on individual project proposals from the private sector. Denying one application for a license does not necessarily bring

forth a better application, and a series of sound

decisions taken one at a time does not always

lead to a cohesive program. For example, advocates of energy conservation argue that LNG imports should be restricted, because they feel

that improvements in energy productivity to

save fuel are less costly than paying LNG prices,

and hence that a rational policy would not include the imports. However, keeping LNG out of

the country will not necessarily bring about any

investment in demand reduction, and indeed according to one argument, LNG and other new

supplies would promote conservation and improved energy technologies, because they

would increase the average gas price paid by

consumers. What follows are conclusions concerning the major issues to be faced in deciding

the future of LNG imports.

1: How much gas is available for

import as LNG?

The United States could import between 0.5

and 1 Tcf/yr of additional gas during the 1980’s

above the current approved level of 0.8 Tcf/yr.

The maximum total of 1.8 Tcf/yr would represent between 7 and 13 percent of projected

1990 domestic gas use and would require three

or four large terminal facilities in addition to

those already planned.

The availability of gas was determined by surveying world proven gas reserves and assigning

them to categories as follows:

●

●

Inaccessible or flared: gas reserves that are

too small or remote either to justify recovery of flared gas or full field development

of nonassociated gas.

Deferred reserves: reserves in large gas

caps or undergoing gas injection for oil re-
Ch. l—Summary ● 7

covery, such that they are unlikely to be

committed to market projects until some

future time.

● Committed to domestic markets: gas reserves that either are contracted to domestic markets or set aside to assure that domestic requirements will be covered.

● Remote from existing market systems: gas

reserves that are clearly destined for a major industrial market but whose remoteness from this market raises questions

about the feasibility of commercialization

now. Examples would include North Slope

and Arctic Island gas in North America and

some North Sea gas reserves in Europe.

● Committed to export markets: gas reserves

covering required deliveries usually under

firm export contracts.

● Exportable surplus: blocks of remaining gas

reserves that are large enough and adequately located to support export projects.

In a limited number of cases, local national

policy suggests that this gas will not be exported, and in other cases, discussions to

sell the gas to other countries have proceeded to the point where it is no longer

available to the U. S. market.

Most of the gas available for export in the

near future is located in the U.S.S.R. and the nations surrounding the Persian Gulf, principally

Iran and Saudi Arabia. The reliability of Iran

and the Soviet Union can be questioned on political grounds, and some other major oil producers in the Middle East feel at present no economic need to export gas. Also, shorter transportation distances to European and Japanese

markets make sales to the United States less attractive for these and other producing countries. For example, remaining Algerian supplies

are now mostly committed to European purchasers, due in large part to regulatory delavs.

affecting U. S. import projects. The most likely.

sources of LT. S. imports, other than by pipeline,

include Nigeria, Indonesia, Australia, Malaysia,

Trinidad, Colombia, and Chile.

Substantially more gas could become available to import as LNG during the 1990’s if U. S.

policy were to shift in such a way as to as to encourage this type of trade. Nations with undiscovered resources could actively search for new reserves if they perceived the United States as a

more interested and reliable customer. Also, the

impediments to the purchase of Soviet gas lie

primarily in U.S. foreign policy.

Z: now does security of supply affect

the desirability of LNG imports?

Four of the six largest actual or potential exporters of natural gas from the Eastern Hemisphere—Algeria, Iran, Indonesia, and Nigeria—

are members of OPEC. The fifth is the Soviet

Union. Only the sixth, Australia, is a member of

the Organization for Economic Cooperation and

Development (OECD). Although not alone in this

regard, OPEC members have demonstrated

their readiness to impose increases in oil prices

at short notice on existing contract terms. Some

of them also have embargoed crude exports for

political reasons. Curtailments and other abrogations of contract terms are thus possible and

must be assessed for their likelihood and potential impact.

Typical LNG projects are technically and financially integrated, with ships and facilities

dedicated to specific trade agreements covered

by 15- to 25-year contracts. The producing

country must invest as much as $2 billion for

pipeline, liquefaction, and terminal facilities,

and the funds are obtained through long-term

loans often guaranteed by the central government. Therefore, exporters depend on a project’s revenues and are unlikely to find alternative purchasers if trade ceases. For this reason, LNG suppliers and their governments face

stronger incentives to continue shipments than

do oil producers. The producer’s stake in uninterrupted shipments to the United States increases when U. S. institutions are not involved

in the ownership and financing of liquefaction

and shipping facilities. A country willing to curtail supplies on political grounds could also be

prepared to postpone or temporarily}’ halt

payments to U.S. creditors and shipowners,

thereby softening the impact of forgone revenues. For this reason, Maritime Administration

and Export-Import Bank financial participation

does not enhance reliability.

Another important consideration is that since

some potential LNG suppliers are not members
8 ● The Future of Liquefied Natural Gas Imports

of OPEC and others produce relatively small

amounts of oil, interruptions in oil and gas imports are less likely to coincide than they would

be otherwise. During the oil embargo of 1973,

for example, Algeria stopped oil shipments but

did not interrupt LNG traffic to the United

States. Therefore, LNG can help to diversify energy supplies with respect to fuel type and geography.

In the event of a curtailment, management of

the shortfall could minimize the adverse impacts, partly because the distribution of added

gas supply from LNG probably will be geographically diffuse. The present national priority curtailment system established in the winter of

1973-74, should preserve remaining gas for critical uses within the market served by any given

transmission company, and voluntary sales and

exchanges among transmission companies will

alleviate inequities further. Also, the President

is empowered by NGPA to redistribute gas

among pipeline systems in an emergency. Finally, increased storage capacity, although costly,

could ensure further against the impact of an

interruption.

3: How much will LNG cost in

the future?

Delivered gas from LNG is likely to be approximately equivalent in cost to competing fuels—

less expensive than synthetic fuels and distillates from foreign oil, and more costly than regulated domestic natural gas. * This equivalence

is a deliberate outcome of the objectives of the

parties in negotiating supply contracts. To the

extent that LNG permits more economical use of

present transmission and distribution capacity,

the average price to the final consumer will be

less, while any requirement for increased storage or additions to pipeline networks by utilities

will add to the expense.

The cost of shipping LNG in tankers varies

with the distance and other technical and financial features of a specific project, but it is expected to range between $2.60 and $3.50 in

1978 dollars per million Btu delivered in 1990 by

“ Alaskanl gas would cost more initially than LNG, but its price

would probably rise less rapidly in the future.

a project beginning operation in 1985. This estimate encompasses all steps required to deliver

the gas from the foreign wellhead to a domestic

pipeline, including gathering, liquefaction, loading, shipping, unloading, vaporization, storage,

and delivery (see figure 2).

An additional amount to cover production

costs and the value of the resource to the supplier nation is the subject of extensive negotiation between the importer and exporter, and is

included in the f.o.b. price provided in a supply

contract. Generally these negotiations begin

with the presumption that the delivered price

must be competitive with those of petroleum

products in the U.S. market, and that the exporter must recover his investment. Unless the

distance is very great, the U.S. market price of

gas from LNG, after subtracting the total transportation cost, will exceed the minimum required by the exporter, especially after several

years of project operation with fixed capital

charges and rising world energy costs. At least

some of this surplus value will probably accrue

to the foreign producer as a result of price formulas containing escalation provisions and periodic renegotiation of supply contracts.

An important but subtle element of cost involves the consumer’s exposure to financial

risk. In a regulated utility environment, the final

purchaser of gas is inevitably a partner in large

energy projects, since financing depends on

guarantees in the form of prices designed to

allow investors to recover portions of their cost

notwithstanding some kinds of failure or loss. *

In two recently approved LNG projects, the consumer assumes: 1) the liquefaction facility investor’s risk that the gas may not be economically attractive in the U.S. market for the life of the

supply contract, 2) the shipowner’s risk that

shipments may be interrupted or reduced,**

and 3) all of the creditors’ risk related to receiving terminal and revaporization facilities after

gas has begun to flow. In addition, the Federal

“‘1’tl[’ The Federal Energy Regularory Commission and State public

utility commissions are not bound by earlier decisions, so investors do assume some risk that regulation will change over the

life of any energy project.

* “ ,!(’(’ol’dillg to (:()] lllllt)iil 1,~(; (:ol’poI’if[” ion ot t i(’iii]s, ii[ [(’il$it (Jllf>

possil)k” t’uturf’ I,N(; pl+ojf~(!t Un(lf’r dis(}ussion (~[ltiill~ no (soIIsLIIIl(JII

f’kposuw to Ai])ownt>rs’ risk.
Ch. l—Summary ● 9

Figure 2.—Major Segments of an LNG Import Project

Producing

Natural gasfieid

Production

}

gas feed

Gathering —

Processing

SOURCE. Jensen Associates, Inc

country

I

Loading

Energy Regulatory Commission may permit tariffs to cover some types of project failure, delay,

or overrun depending on the outcome of evidentiary hearings to determine the circumstances and the prudence of management actions.

Another part of the cost involves public services. The range of transportation and processing costs mentioned above includes taxes as a

surrogate for public expenses, but does not include the value of Export-Import Bank credit for

foreign liquefaction facilities and ships purchased from the United States, or for Maritime

Administration subsidies and loans for building

American-owned ships. The latter programs are

designed to make U.S. goods competitive in the

world market by equalizing the cost of U.S. and

foreign goods, and thus they have little impact

on LNG project viability or the amount consumers pay. This assessment does not address

the wisdom of these programs and assumes

they are worth what they cost in terms of employment, balance of trade, and health of the

shipping and LNG equipment industries. Finally,

LNG projects, like all waterborne trade, benefit

from activities of the Coast Guard and navigation improvements by the U.S. Army Corps of

Engineers.

4: How would added gas supplies

f rom LNG be used?

The disposition of added supplies in gas markets is complex and will vary greatly from one

case to another. The critical determinants include the mix of interruptible and firm customers in the service area, extent of present curtailments, availability of storage capacity, local regulatory policy concerning connection of new

customers, and climate. In general, however,

gas made available as a result of LNG imports

will be used at least partly and possibly entirely

in interruptible industrial and electric-generating applications. In this context, although the

Power Plant and Industrial Fuel Use Act of 1978

(FUA) prohibits burning of oil and gas for most

electric power generation after 1990, LNG is

specifically exempted under certain circumstances to meet air quality standards. The important implication is that the appropriate comparison in economic and environmental terms is

not exclusively between LNG and No. 2 (home)

heating oil derived from foreign crude, but

must also include coal, residual oil, nuclear

power, and improved energy productivity

among the alternatives.

Over a long period of time, gas utility load

patterns may change in such a way that higher
10 ● The Future of Liquefied Natural Gas Imports

priority consumers receive a larger portion of

the gas made available from LNG. If this shift occurs, present long-term import contracts could

effectively reserve supplies for residential and

commercial users toward the end of the century. Also, to the extent that the rate of delivery

from a receiving terminal can be increased for

brief periods, LNG can contribute to meeting

short-term peaks in space-heating demand.

5: How is the cost of LNG

distributed among consumers?

In regulated markets the cost of added supplies will not necessarily be borne by the

customers receiving the additional gas. Under

NGPA, part of the higher cost of gas from supplemental sources defined in the Act, including

LNG projects not in operation or planned before

May 1, 1978, are paid exclusively by certain

“non-exempt” large industrial purchasers, provided that these buyers do not pay a price

higher than that of competing petroleum fuels.

Once the “non-exempt” industrial price reaches

this maximum, it will not increase further, and

residential, commercial, electric utility, and the

remaining “exempt” industrial customers will

begin to pay higher prices resulting from subsequent purchases of more expensive gas by suppliers. *

Under the latter conditions, the price paid by

“non-exempt” industrial customers, although

high initially, would not increase as a result of

LNG imports. The rest of the buyers, including

electric utilities, commercial establishments,

and households, would experience price increases, although all or part of the higher cost

of gas could be offset by savings from the allocation of fixed charges for present transmission

and distribution capacity over a broader volume

of sales.

Variations on this pattern will occur if nonexempt industrial prices have not reached the

maximum corresponding to alternative fuels. In

this instance, prices would rise more rapidly for

large industrial customers, while exempt purchasers would enjoy equally any savings from

improved pipeline utilization, provided the LNG

project was initiated after May 1,1978. The cost

* St;ilf’ pul)li(’ Lit i lit irs (x)mnlissl(ms Illii)’ illt(’1’ [his outcome t)y

df~(’lifliflg to IN) I1OI’ t 11(’ intcnl of I IN Niitlll’iil (;ii S Policy /1(’1.

of prior projects is averaged with that of domestic gas and affects the price paid by all customers approximately equally, as long as non-exempt prices are below the alternate fuel ceiling.

Thus, of the types of consumers likely to receive additional gas from LNG projects, industrial customers will probably pay a price close

to that of alternate fuels and of the LNG itself;

while electric utilities and purchasers of electricity are likely to receive a subsidy from other

sectors in the form of ‘(exempt” prices, which

will rise more slowly than “non-exempt” industrial prices, under NGPA. Although households

and commercial establishments would probably

receive little additional gas at least initially, the

prices in these sectors would rise or fall depending on the costs and volumes of LNG purchased

by transmission and distribution companies as

well as the extent to which added sales alter the

efficiency of the pipeline system’s use.

6: How strongly do LNG imports

affect the balance of payments?

Importing LNG entails a significant outflow of

dollars from the United States compared to domestic alternatives. On the other hand, the

direct impact on the balance of payments of

purchasing equivalent amounts of foreign oil is

more severe. With the exception of about 1 cent

per million Btu for a small amount of U.S. shipping, almost all of the price of oil leaves the

country, while as much as one-third of the

transportation and processing cost of LNG may

be returned to the United States in the form of

purchases of equipment, construction services,

shipping, and receiving port facilities. The returned portion of the cost consists primarily of

amortized initial capital expenditures in the

United States, so the favorable component of

the impact of importing LNG is immediate and

short term. After the facilities and ships are constructed the balance-of-trade impacts are more

nearly comparable to those of oil.

The effect of being able to choose the lowest

cost alternative from among LNG, foreign oil,

domestic production, and conservation may

outweigh the influence of direct payments associated with any specific trade by improving the

competitive position of U.S. industry generally.

As mentioned earlier, LNG prices will probably
Ch. l—Summary ● 1 1

be slightly less than those of fuels from foreign

crude oil.

In conclusion, importing LNG appears more

advantageous than buying foreign oil to a significant but uncertain extent due to differences

among projects in terms of facility sales by U.S.

firms, and to the fact that lower LNG costs relative to world oil may be the dominant factor.

Nevertheless, LNG can represent a substantial

outflow of dollars.

7: How are present Federal

policies likely to affect future LNG

imports?

While LNG represents only a single element

of energy supply and foreign trade, a variety of

Federal policies affects its future. Regulatory

delays increase costs, and present Department

of Energy policy discourages LNG imports in

favor of sources located in North America. The

attitude reflected in recent actions of the

Department has been that even initially higher

cost Alaskan gas and products of coal conversion technology are preferable to foreign LNG

by virtue of the perceived public interest in

developing domestic resources for the future.

Recent initiatives by the President to establish

an energy mobilization board and to impose oil

import quotas could facilitate LNG trade by

eliminating foreign oil as a choice for some consumers and by removing obstacles to project approval. The effect of these programs would be

reversed, however, if all foreign hydrocarbons

are included in the quotas, or if the board

adopts a policy to encourage domestic production in preference to energy imports of all

forms.

Maritime Administration and Export-Import

Bank programs, while ameliorating the balanceof-payments impacts of some LNG projects and

providing benefits to the U.S. shipbuilding industry, tend to reduce the financial stake of

foreign suppliers in uninterrupted deliveries. As

mentioned earlier, the aid of these two agencies

equalizes costs of domestic- and foreign-produced facilities and therefore does not encourage LNG projects except to the extent that sponsors appear more likely to gain Government approval if ships and machinery are built in the

United States.

Both FUA and NGPA provide incentives to encourage domestic production of gas and conversion of oil- and gas-burning facilities to the use

of coal. To the extent that this legislation is successful, demand for LNG may be slowed or reduced. The effect of FUA is partly to prohibit

use of oil and gas for electric power generation

after 1990. However, the law contains numerous exemptions and exceptions, including one

permitting utilities to burn gas from LNG if necessary for regional air quality. NGPA establishes

an elaborate pricing mechanism for gas, which

affects the distribution of LNG costs among purchasers, as mentioned before.
Policy Background
Policy Background

In recent years, the U.S. natural gas industry

has shown considerable interest in importing

liquefied natural gas (LNG) to supplement the

decline in domestic production. However, the

lengthy and often confusing project approval

process has made the importation of LNG difficult, if not impossible. Consequently, only four

LNG import projects have been approved.

The Department of Energy (DOE) has only begun to clarify the regulatory review process and

formulate the Carter administration’s import

policy. Critics of DOE argue that because of the

lack of a clear policy, projects have been delayed, resulting in an increase in the cost of LNG

and loss of potential supplies to other buyers.

To assist in the overall understanding of LNG

use in the United States, this chapter describes

both past and present LNG policy and the roles

of participating Federal agencies in its formulation.

Administration import policy

President Ford proposed the first explicit administration LNG import policy during his energy message of February 1976. Out of a concern for our growing dependence on foreign

energy supplies, Ford initially proposed to hold

LNG imports to a maximum aggregate of 1 trillion cubic feet (Tcf) per year and directed the

Energy Resources Council (ERC), which had

been created to coordinate energy policy among

Federal agencies, to develop a more refined national LNG import policy. At that time, Government agencies involved in the importation of

LNG included the Federal Power Commission

(FPC), the Maritime Administration (MarAd), the

Export-Import Bank, and the Department of

Transportation (DOT). Prior to the President’s

message, several Federal agencies had expressed reservations regarding Government financial assistance to LNG projects and advocated developing our domestic energy sources

instead. A Federal Energy Administration issue

paper, dated February 20, 1975, clearly discouraged Government financial assistance for LNC

ventures, ) an attitude also shared by the State

and Treasury Departments. However, MarAd

viewed LNG as a useful addition to U.S. energy

supplies and supported LNG shipbuilding programs. According to MarAd, any Government

action to discourage LNG imports could result in

unemployment and the loss of invested tax

dollars.

In response to President Ford’s request, ERC

created an LNG task force to recommend a new

LNG import policy. The task force analyzed

such issues as the level of LNG imports, pricing

provisions, Government financial assistance,

contingency plans, and siting and safety. Public

hearings were also conducted in Washington,

D. C., and Los Angeles to obtain the views of interested parties. While some witnesses expressed considerable concern regarding the siting and safety problems associated with LNG facilities, others supported the importation of

LNG to supplement our own declining natural

gas production.

The results of the task force analysis were announced on April 5, 1976:1

● LNG is needed to supplement our natural

gas supplies, but it must be limited for supply security reasons. ERC recommended a

limit for LNG imports from a single country

of 0.8 to 1 Tcf/yr and a total acceptable import level from all countries of 2 TCf/yr.

The limitation was not intended to be a

strict quota but rather a means by which to

limit U.S. dependency on foreign energy

supplies, and ERC avoided explicitly mentioning Algeria as the one nation likely to

“’t’’(’(l(’l’iil h;llt’l-~j’ S(>\\ S,” t;t’(l(’l’iil 1<.ll(>i’~j’ ot t’i(x’ N’(’}% S K[’l(’ii M’ ,

ALlg 5, I $176.

15
16 ● The Future of Liquefied Natural Gas Imports

●

●

●

●

exceed 1 Tcf. ERC categorized LNG-exporting countries as either relatively secure or

insecure, based on the country’s political

and economic interests. The relatively secure supply sources were Indonesia and,

ironically in retrospect, Iran. The relatively

insecure sources were Algeria, Nigeria,

and the U.S.S.R. At the time of ERC’S recommendation, pending and approved Algeria projects could supply 1.1 Tcf/yr,

which was above the recommended import

level. Consequently, pending LNG applications would have to be evaluated carefully,

and only those projects that provided the

most desirable pricing provisions and assured uninterrupted supplies would be

considered.

The higher price of LNG should be passed

directly through to low-priority and new

users, and averaged with the lower cost of

domestic sources for high-priority users.

This principle would assure reasonably

priced gas for residential customers and

reinforce full energy resource costing for

industry. Implementation of pricing provisions would be left up to FPC and State

and local authorities, but pricing provisions

would be reviewed by ERC continually.

ERC recommended that contingency plans

be submitted with each application to deal

with supply interruptions. The plans

should include underground storage, interpipeline transfers and exchange agreements, and curtailments of lower priority

users.

No changes were recommended regarding

Government financing. ERC believed that if

U.S. subsidies were not available, tankers

would be available elsewhere. Therefore,

MarAd financial assistance for LNG tankers

was not considered essential to LNG projects.

No recommendations were made regarding siting and safety issues. The task force

expressed a willingness to cooperate with

FPC and State and local authorities to resolve these issues.

On completion of its initial recommendations,

ERC identified several issues that required additional analysis and directed the LNG task force

to conduct the analysis. These issues included

LNG safety and siting, development and implementation of contingency plans, the identification of State and local concerns, and mechanisms for implementing policy recommendations. While this analysis was being conducted

President Carter introduced the National Energy Plan (NEP) and the Energy Organization

Act to Congress.

Introduced in April 1977, NEP included LNG

import policy guidelines that replaced those

established by ERC in 1976. NEP places no upper limits on LNG imports, which is the major

difference from ERC policies. It provides for a

case-by-case review of each LNG import application, with emphasis on security of supply, vulnerability to interruptions, safety and siting,

and pricing. In addition, NEP calls for the “equitable” distribution of supplies and the development of contingency plans for use in the event

of a supply disruption. It also proposes siting

criteria that would foreclose the construction of

LNG facilities in densely populated areas.

The LNG task force was reestablished* under

the leadership of DOE to develop a more comprehensive, detailed LNG import policy, based

on guidelines set forth in NEP. DOE staff

prepared reports on LNG import policy issues

with recommendations to then Energy Secretary Schlesinger. Dr. Schlesinger did not formally endorse the staff findings and recommendations, preferring to establish LNG import

policy by building case-by-case precedents. To

date, Energy Secretary Duncan has not formulated a new LNG policy. The major findings and

recommendations made by DOE staff included:2

● LNG is a low-priority gas source and as

such should generally be discouraged. The

mechanisms by which to discourage LNG

imports except where economically justi-

“The LNG (ask torce was abolished with the creation of DOE but

continued to advise on 1,N(; matters as an ad hoc group.

‘Inside DOE, Ma.v 8,1978, pp. 8-9; Aug. 7, 1978, p.3; and Aug. 28,

1978; persona] communication with DOE official, June 20, 1979.
Ch. 2—Policy Background ● 1 7

fied include stringent regulatory requirements, such as requiring importers to contract directly with local distribution companies before the project would be approved,

and encouraging States to require incremental pricing. However, if need is sufficiently demonstrated from a national

standpoint, LNG projects should be approved.

Price escalation provisions in supply contracts should be based on broader economic indicators than world oil prices.

LNG imports do not add to foreign dependency but displace imported oil by serving

as an alternative fuel.

Although LNG viewed in isolation would

appear to have a slight negative balance-ofpayments impact, the net payments effect

would likely be positive, a result of cost

structure differences between LNG and

foreign oil.

OPEC influence on LNG prices would be

limited because of the relatively small

amount of LNG in world energy markets

and the limited number of purchasers.

LNG would have a less adverse impact

on the environment than other energy

sources, such as coal, oil, and nuclear

power. LNG accidents are unlikely, but additional safety analysis and reporting are

needed.

DOE staff did not address pricing issues, because natural gas pricing legislation was being

considered by Congress at the time.

On August 4, 1977, President Carter signed

into Iaw the Energy Organization Act (Public

Law 95-91) which created DOE. This law abolished the Energy Research and Development

Administration, the Federal Energy Administration, and FPC and transferred their functions to

the new Department. The Economic Regulatory

Administration (ERA) and the Federal Energy

Regulatory Commission (FERC) were created

within DOE to perform regulatory functions, including the approval of LNG imports. ERA, pursuant to section 3 of the Natural Gas Act (NGA),

is responsible for ruling on whether natural gas

import projects are in the public interest. FERC

has certain statutory functions regarding LNG

terminal facility certification as well as the price

and other terms under which regasified LNG is

sold in interstate commerce, pursuant to NGA,

sections 4 through 7.

As mentioned earlier, DOE has not formally

adopted an explicit LNG import policy. Each

case is resolved individually on its own merits,

and approval is based on whether or not the

project is consistent with ‘(national energy policy. ” The national energy policy, as defined by

the present administration, is to provide secure,

adequate energy at reasonable prices while reducing U.S. dependency on foreign supplies.

The extent to which an LNG project is perceived

to conform with this policy determines its acceptability, and the precedents established in

import policy decisions illustrate the prevailing

DOE attitude toward imported LNG.

While DOE recognizes the need for imported

and unconventional energy like LNG to supplement our own supplies, the Department prefers

that our natural gas comes first from conventional sources within the United States. Therefore, each LNG application is viewed cautiously

in light of DOE’s order of preference for new

natural gas supplies as outlined in ERA’s Tapco

decision: 3 ‘(proximate, ” “intramarginal,” and

‘(marginal. ” Ranking criteria include generalized

cost and proximity of the supply to U.S. markets, but not size or timing of development relative to demand. DOE also considers whether the

import project has the potential to discourage

the development of future domestic gas

sources, such as Alaskan gas or synthetic gas

from coal. As a result, DOE considers preferred

proximate sources to be those within the contiguous United States, including the Continental

Shelf, which are within reach of conventional

drilling technology and located near established

pipelines. Intramarginal sources include gas

from Alaska; various supplies from advanced

technology applied to domestic resources, such

as coal gas, gas from unconventional sources,

and enhanced recovery; and over land supplies

from neighboring sovereign countries, i.e., Mex-

‘I) OF;IEXA opinion 1%0, 2, Piic II IdoIIes Ia I ,lN(; (k) and 11’estern

1,N(; ‘1’f~rmlm] Associates, Rvhearing, SepI. 29, 1978
18 ● The Future of Liquefied Natural Gas Imports

ico and Canada. The least preferred marginal

supplies include synthetic natural gas from petroleum and LNG from overseas.

The capital intensiveness, long-term contract

commitments, vulnerability to interruption, and

relatively high price make LNG a marginal supply in DOE’s view. In addition, long leadtimes

needed to construct terminal facilities and tankers as well as potential cost overruns on shipping and liquefaction make it difficult to determine whether LNG will be competitive with

other energy sources. In early 1979, the administration began encouraging imports from Latin

America, because transportation costs are

lower and energy supplies from this region are

considered politically more reliable. These

short-haul imports are categorized somewhere

between “intramarginal” and “marginal” energy

supplies. In addition, DOE expects the Natural

Gas Policy Act of 1978 (NGPA) and the Power

Plant and Industrial Fuel Use Act of 1978 (FUA)

to make more gas available to high-priority markets by establishing incentives for exploration

and production and by promoting long-term

conversion of oil- and gas-burning facilities to

coal. (Although FUA generally prohibits the use

of gas for electric generation after 1990, LNG is

excepted and may be burned in new powerplants after that time for air quality reasons.)

Furthermore, the import reduction program introduced by president Carter in July 1979 provides new incentives for the development of

synthetic fuels, unconventional gas, heavy oil

resources, and oil shale and establishes an oil

import quota of 8.5 million barrels per day

(MMbbl/d) for 1980 and a goal of 4 to 5 MMbbl/d

in 1990. LNG was not included explicitly under

the import quota, so if the import quota cannot

be met, the administration may look more favorably on the importation of LNG. If, on the

other hand, the administration chooses to include LNG in the quota, expanded imports may

be impossible.

Each LNG project application is jointly submitted to ERA and FERC. While ERA conducts

an analysis to reach DOE’s initial decision, FERC

begins preparation of the environmental impact

statement (EIS) but does not otherwise act on

the application during this initial phase. ERA reviews each application in light of such issues as

the security of supply, national and regional

needs, cost, the effect on the U.S. balance of

payments, and the project’s consistency with

DOE’s natural gas import policy.

Supply security implications are carefully

weighed by ERA. ERA will consider the adequacy of the exporting country’s reserves to fulfill the sales contract and the degree of susceptibility to natural, political, or technical disruption within the country, along shipping routes,

or at the receiving terminals, Because uninterrupted delivery of LNG supplies cannot be guaranteed, ERA requires that contingency plans be

submitted with the application. Before approval, ERA must be satisfied that the contingency

plan is adequate to compensate for long-term

supply interruptions. For example, one of the

reasons the El Paso Algeria project application

was denied was that ERA felt the contingency

plan relied too heavily on voluntary conservation measures.

In determining need, ERA looks to the enduser market, rather than to the interstate pipeline company’s contractual obligation to deliver.

According to ERA, contractual obligations do

not always reflect the real need of a particular

area, and a good test for regional need is the degree to which gas distribution utilities will contract directly for preferred gas.4 It is the applicant’s responsibility to provide ERA with an

analysis of the region’s particular requirements

and to assess whether these requirements can

be satisfied by an alternate energy source

within a reasonable time. Only those projects

are approved in which the need for gas cannot

be met by more conventional sources.

Pricing has often overshadowed other issues

in the application approval process. To be advantageous to the Nation, the cost of LNG

should be competitive with alternative fuels or

conservation measures over the lifetime of a

project. The fact that a gas wholesaler could

market LNG under past pricing policies has not

necessarily meant that LNG was the least costly

alternative. The reason was that the cost of LNG

or other relatively expensive sources was aver4

1 X) E:,’ F; R/\ opinion INO, 3. opinion and order on I mporlat km o!

1.N(; trom ,Algf’1’la t)y ‘1’enlw(’() Atlan[i(’ l]ipt~lilltl (h. aId ‘1’ CIIINXSO

(LIS Pipelinfl (h., a [)liiswn of” ‘I”vnntw), lm~ , I)fx’. 18, 1978,
Ch. 2—Policy Background . 19

aged or rolled-in” with the less expensive flowing gas from old domestic sources. Therefore,

the price to the consumer was less than the actual cost of the LNG. The arguments against

“rolled-in” pricing were that it masked the true

cost of some forms of new energy and provided

fewer incentives to conserve or to convert to

other less costly fuels. Rolled-in pricing also

served to expand the use of gas, thereby improving the utilization of the gas transmission

and distribution system, and spreading the associated fixed costs over a larger number of customers. Because rolled-in pricing encouraged

the sale of LNG, investors have felt that it was

both appropriate and necessary to secure financing. On the other hand, the Council on

Wage and Price Stability and others have argued that the projects should fail if the gas cannot be sold when potential buyers must pay the

full cost .

Historically, elements of FPC and DOE staff

have favored “incremental” pricing, at least in

theory, and industry has opposed it. Under this

pricing mechanism, gas from each category is

sold at a price that reflects its specific cost. The

main argument against incremental pricing is

that there is no perfect mechanism for deciding

which customers may buy the less expensive

gas and which must pay the incremental cost of

supplemental supplies. Another argument is

that incremental pricing would be difficult to

administer during a shortage. Under NPGA, interstate pipelines and distribution companies

may contract for gas from any producer, intrastate pipeline, or distribution company to meet

high-priority user requirements during a shortage. However, if the shortage is not alleviated

through purchase authority, Government allocation of gas supplies will result, and some seriously doubt that a purchaser of LNG at its incremental price would continue to receive the gas

under these conditions. Consequently, LNG purchasers may find themselves questioning the

value received for the price paid.

The pricing issue has been resolved at least

for the present by NGPA which stipulates that

LNG from projects planned after May 1, 1978,

and gas from other unconventional sources be

priced incrementally and paid for by certain

large industrial customers, whether or not they

benefit from or receive the incremental gas supplies. However, if the price paid by these purchasers reaches the price of the equivalent

amount of oil, the higher cost of unconventional

gas is shared by other users. Thus, NPGA shields

residential consumers from the higher cost of

new resources as long as industrial gas prices

do not reach a level that would induce industry

to switch to foreign oil.

Of utmost importance to ERA is the protection

of consumers from unwarranted costs and

risks. The project must show an equitable distri

bution of risk between project sponsors and

consumers regarding unexpected shipping

costs, project failure, f.o.b. cost escalation, and

long-term future prices of alternatives.5 Because

the characteristics of LNG import projects make

them more risky than conventional energy

sources, ERA expects the applicants to bear

some of the risk of supply interruptions. Therefore, extraordinary circumstances must prevail

for ERA to entertain recovery of equity on nondelivered supplies under minimum bill provisions in supply contracts. In genera], ERA finds

it inconsistent with public interest for consumers automatically to bear the risk of supply

interruptions, although the consumer does in

effect guarantee through tariff provisions some

of the debt portion of the financing and possible

return of equity if the applicants can show good

and just cause.

Energy imports involve at least some outflow

of dollars from the United States. Therefore,

ERA also requires a detailed analysis of the project direct impacts on the balance of trade.

If ERA determines that the application or components of the application are not consistent

with the public interest, a rehearing and judicial

review may be scheduled under section 19 of

NGA. If ERA decides favorably, FERC then begins proceedings to decide on the remaining issues: safety, siting, construction, and operation

of port facilities, and prices charged for the resale of the gas in interstate markets. FERC can

reject the entire application if it determines that

ERA’s decision is inconsistent with FERC;

S pol-

‘It)l[l
20 ● The Future of Liquefied Natural Gas Imports

icy, but it cannot reject components of the decision.

Although DOT is responsible for formulating

minimum safety standards, FERC has the authority to impose more stringent ones if necessary and to require that LNG facilities be located

away from densely populated areas. The siting

issues in the El Paso H and Tenneco projects

were decided by ERA, because the division of

responsibility between ERA and FERC had not

been formalized until the project approval process was well underway. Siting decisions in the

Pac Indonesia project are shared by ERA and

FERC. ERA has expressed a willingness to cooperate with States in deciding siting issues and

recommended the use of independent technical

experts to judge the quality of design and construction of terminal facilities to assure project

safety further. G

6D0E/ERA opinion No. 6. opinion on Rehearing—Issues Related

to Treatment of Costs, Safety, and Siting, Pac Indonesia LNG Cornpany and Western LNG Terminal Associates, Apr. 24, 1979.

Maritime Administration

MarAd is part of the Department of Commerce. -Its primary purpose is to promote the

development of the U.S. shipbuilding industry

and U.S. shipping capabilities through various

financial assistance programs: construction and

operating subsidies, mortgage guarantees, and

tax deferral via the capital construction fund.

Of these four programs, mortgage guarantees

(title XI) for U.S. owned and operated LNG

tankers are the most significant. By mid-1979,

MarAd had guaranteed mortgages amounting to

$1.24 billion for 16 LNG tankers under title XI;

the interest rate for such mortgages was then

9.35 percent. MarAd had also provided $270.5

million for 11 LNG tankers in construction differential subsidies under title V.8 However,

MarAd does not provide operating subsidies for

LNG tankers because the operating expense differential between U.S. owned and operated and

foreign-flag vessels is insignificant.

FERC also approves prices for the resale of interstate gas. Prior to NGPA, if FERC had ruled in

favor of incremental pricing for interstate resales, it was up to the State regulatory commissions to decide whether or not costs should be

rolled-in or incrementally priced to the ultimate

consumer. If FERC ruled in favor of rolled-in

pricing, direct users were not confronted with

incremental prices. Recently, FERC has proposed procedures for interstate pipelines and

distributors to pass through increased costs of

unconventional natural gas, including LNG, to

large industrial users as required by NGPA. This

will reserve for high-priority users the benefits

of access to less expensive gas sources, at least

for the time being. FERC also established three

incremental price ceilings, based on No. 2, and

high- and low-sulfur No. 6 fuel oils, for each region of the country in an attempt to prevent

customers from switching from gas to imported

oil.7

7“Prt)cedures SW to Pass on Incremental Gas (: Os[)” Oil and Gas

.Journa/, June 11, 1979, p.47.

Like DOE, MarAd reviews financial assistance

applications on a case-by-case basis. Before subsidies/guarantees are granted for LNG tankers,

MarAd must be convinced that the LNG project

is economically sound and be assured that, at

the very least, the cost of the vessel will be repaid. MarAd will no longer finance LNG vessels

on a “no guarantee required” basis as it did for

the Algeria I project. This policy developed out

of a concern that MarAd was concentrating too

large a portion of its total funds in one area—

LNG tankers. Title XI guarantees for LNG tankers represent 22 percent of total MarAd commitments. Concern over long delays in the LNG

application approval process and lower estimates of the market for LNG tankers also contributed to the development of the debt assurance policy. 9 Because of the long delays, some

tankers have been idle. Although section 905(a)

of the Merchant Marine Act, amended, allows

“Personal commun icat ion with Mar Ad official, Mav 9, 1979.

‘1’hest~ figures do not include tht~ required national d~ft+nse teatures or engineering changvs. ‘Inside DIIE, hla.v 15, 1978,
Ch. 2—Policy Background ● 21

the use of LNG tankers for other purposes, al- liquid petroleum gas trade, because the tankers

ternative employment is not practical, except in are specially built for their unique cargo.

Export-Import Bank

The Export-Import Bank aids in financing and

facilitating export sales to foreign countries.

This is accomplished through direct lending at

favorable interest rates or issuance of loan guarantees and insurance to foreign purchasers of

U.S. goods.

Export-Import Bank policy regarding LNG

projects has been to consider loan applications

for U.S.-made liquefaction equipment and port

facilities only after the project has been approved by DOE/ERA and FERC. Each project is

assessed in terms of the financial conditions of

the foreign borrower, the viability of the project, and the economic and political situation of

the country in which the project is located. Before approving a loan, the Bank must be satisfied that the project is economically, financially,

and technically sound and be reasonably assured of repayment. The Bank requires security

either in the form of a guarantee from the government, a bank, or a parent company or based

on the financial strength of the borrower. Because Algerian LNG facilities are State-owned,

the Export-Import Bank requires that the guarantees be from the government. 10

Section 2(b)(3) of the Act (amended) requires

that Congress be notified of any proposed loans

or guarantees for $100 million or more. Notification must generally be at least 25 days of continuous session prior to the date of final approval, with certain exceptions covering long

adjournments. If either House is adjourned for a

period of 10 days after notification, the Bank

may approve the loan after 35 calendar days unless Congress dictates otherwise.

Under the Trade Act of 1974 and the ExportImport Bank Act Amendments, the Bank is pro-

““’l; kpol’t 1“’lnanclng iin[l the HOI(” of 111(’ F:x])ol’t-llll] )ol’t” lkirlh o f

th[’ ( I s ,“ Journal of Intfv-nafion;]l I,;lw and Ikonomif-st 101.2, No. 1,

I 976 , p 123.

hibited from extending credit to the U. S. S. R., a

potential supplier of LNG, and other Communist

countries unless the President determines the

transaction to be in the national interest. Additional Presidential approval and congressional

notification are required for loans of $5o million

or more. Furthermore, Congress must be notified of loans of $25 million or more to the

U.S.S.R. for goods or services involving the research, exploration, or production of fossil fuel

energy resources. These limitations on trade

and economic assistance to Communist countries are clearly linked to human rights and emigration policies. Given the present political climate, potential LNG ventures with the U.S.S.R.

may not receive Export-Import Bank financing.

By mid-1979, the Export-Import Bank had provided $715.7 million to Algeria and Brunei in

overseas LNG-related loans and guarantees to

promote American exports. (It should be noted

that Export-Import Bank loans/guarantees are

not necessarily tied to U.S. trade. For example,

Algeria and Brunei export LNG to Europe and

Japan.) Out of this total, $674.3 million was still

outstanding (all to Algeria). In addition, the

Export-Import Bank has tentatively approved a

$313.5 million loan at an annual interest rate of

8.5 percent to Sonatrach for the construction of

its third LNG terminal at Arzew. Because of the

size of the loan, Congress must be notified before final approval. No loans have been made to

Indonesia, because the project has only recently

cleared all of the major regulatory hurdles. 11

The Export-Import Bank’s commitments for

LNG projects have increased due to contractor

problems in Algeria. The Bank, thus far, has financed $67 million out of $167.5 million in cost

overruns for Algeria’s Arzew I project.

1 I pel.sona] (.omnl Lllll[.atlo[l i~,ith ~jx~~or-t-lrlll]o].t Bank official ,

June 21, 1979

59-406 0 - 80 - 3
22 ● The Future of Liquefied Natural Gas Imports

Department of Transportation

DOT formulates the general minimum Federal safety standards for LNG facilities. In April

1979, DOT and FERC drafted an agreement that

allows FERC to override and tighten DOT’s

safety regulations for LNG facilities if the situation warrants. The agreement will settle a dispute between FERC and DOT over LNG safety

standards. 12

The U.S. Coast Guard (USCG) is responsible

for vessel traffic management. To ensure the

safety of vessel movements the Coast Guard has

authority to escort tankers to and from the terminal facilities and establish security zones

around or near a vessel or facility. In addition to

traffic control, USCG establishes regulations

governing the design, construction, inspection,

and operation of U.S. and foreign-flag LNG carriers. USCG also works with the Inter-Governmental Maritime Consultative Organization

(IMCO) in developing uniform worldwide standards for the safe transport of liquefied gases. If

U.S. or foreign-flag vessels do not appear to be

in compliance with the IMCO standards and

U.S. requirements, USCG has authority to review the vessel’s technical plan to ensure such

compliance. Furthermore, USCG has authority

to examine vessels prior to authorizing the

transport of liquid gases and at specified intervals and to conduct safety boardings prior to

entry into a U.S. port. 13

USCG and the Materials Transportation Bureau (MTB) cooperate to ensure the safety of

LNG facilities and participate in technical conferences with LNG import applicants. Within

DOT, primary responsibility for establishing

standards for siting LNG facilities rests with

MTB unless otherwise stated. Under the terms

of a memorandum of understanding dated February 7, 1978, MTB and USCG agreed to a division of regulatory responsibility with regard to

waterfront LNG facilities. USCG is responsible

for establishing regulations for facility site selection as it relates to vessel traffic management in

and around a waterfront facility, fire prevention and protection methods used at waterfront

facilities, and security of waterfront facilities.

On February 8, 1979, MTB proposed more

stringent safety standards for the design and

construction of LNG facilities, which include establishing a thermal exclusion zone around an

LNG terminal to protect individuals and property from heat radiation caused by vapor ignition. 14 MTB also expected to propose new operation and maintenance standards for LNG facilities by the end of 1979.

#Z/n~jde DOE, Apr. 23, 1979, p, ~

Department of Defense —

The Army Corps of Engineers reviews and issues permits for work performed in U.S. navigable waters. Any major obstruction that would

interfere with navigation requires the approval

of Congress as well. The Corps also issues (with

the concurrence of the Environmental Protection Agency) permits for the disposal of dredge

or fill material in U.S. waters. Other Corps activities may indirectly affect LNG projects. For example, the Corps has dredged a ship channel

from the Gulf of Mexico to Lake Charles, La.,

where the Trunkline LNG terminal and many

other industries, such as oil refineries, and pe-

“1350 LJ. S.C. 191.

14Federa/ flq+.~ter, vol. 44, No, 28, Feb. 8, 1979, p. ~ 142.

trochemical, chemical, and fertilizer plants, are

located. Trunkline along with the other industries will benefit from this project, which was

authorized by Congress. 15 Based on a 1960

cost/benefit analysis, the Corps estimated that

savings of $0.28 per ton and $590 per round trip

(1960 dollars) would accrue to larger tankers using the channel. 16 This savings represents a very

small fraction of the Trunkline project’s shipIsper.Wnaj ~ommulllcatlon ~i,it h Army (:orps of” Engineer official,

Net4 orleans District, June 19, 1979; Aug. 21, 1979.

IGl{ouse I)ocllmt?nt g6.A36) (;a lcasi[w R it’er and Pass, La., 1960, p.

24.
Ch. 2—Po/icy Background ● 23

ping costs. In 1978, Congress requested the

Corps to conduct a cost/benefit analysis of further improving the channel. These proposed improvements include the construction of a passing lane and holding area which are desired by

Congressional interest

Thus far, congressional interest in LNG has

focused on the hazards of transporting LNG,

siting and safety of LNG facilities, and the regulatory process. The 96th Congress is no exception. Five LNG-related bills have been introduced in the 96th Congress and fourteen in the

95th Congress.

Recently, substantial interest has emerged in

establishing a liability and compensation fund

for the repayment of claims arising out of an

LNG accident and setting forth a liability limit

for such an accident, unless caused through

gross negligence or violation of safety, construction, or operation standards.

Brief summaries of bills before the 96th Congress are presented below:

H.R. 51 —Fuels Transportation Safety

Amendments Act of 1979

Introduced by Congressman Markey, January 15, 1979

Referred to Subcommittees on Energy and Power, Surface

Transportation

Hearings held March 1 and June 8, 1979

Passed House September 18, 1979

S. 411, as amended, passed in lieu, September 18, 1979

1. Provides for the safe operation of pipelines

that transport natural gas and liquefied petroleum gas.

2. Requires DOT to establish minimum siting,

construction, and operation standards for

new LNG facilities and to promulgate

standards for existing LNG facilities.

3. Establishes civil and criminal penalties for

the violation of safety and financial responsibility standards and the willful destruction of pipeline or gas facilities.

local interests because of increasing oil tanker

traffic and impending LNG tanker traffic.17

17[J,s,,l,.nl},(:(Jrps of Engjllf,[>I.$, Prdirninary Report, Lake Charles

(Ihannel. ‘

H.R. 1414—Liquefied Gas Marine

Transportation Safety Act of 19?9

Introduced by Congressman Biaggi, January 24, 1979

Referred to Subcommittees on Energy and Prover, Coast

Guard and Navigation, Merchant Marine, and

oceanography

Joint hearings held on July 18-19, 1979.

1. Prohibits ownership, design, construction,

and operation of an LNG facility without

certificate of safety or license.

2. Directs DOT to prescribe siting, safety, environmental, and operation standards for

both onshore and offshore LNG facilities.

3. Establishes a liquefied bulk gas incident liability and compensation fund in the Treasury and limits liability for an accident to

$50 million, except for accidents determined to be caused by gross negligence or

violation of safety, construction, or operating standards.

H.R. 3749—Coastal Area Liquefied Gas

Facility Safety Act

Introduced by Congressman Murphy, April 25, 1979

Referred to Subcommittees on Energy and Power, Coast

Guard and Navigation, Oceanography, and Merchant

Marine

Joint hearings held on July 18-19, 1979.

1.

2.

3.

Establishes a coordinated Federal-State regulatory approach related to siting, construction, and operation of LNG facilities in

or near the coastal zone.

Sets forth minimum siting, construction,

and operation standards for LNG facilities.

Prohibits siting, construction, or operation

of an LNG facility within or near coastal
24 ● The Future of Liquefied Natural Gas Imports

4.

s. 4

zones unless the State has applied for or

been granted exempt status.

Imposes civil and criminal penalties for violations of the Act.

11 —Fuels Transportation Safety

Amendments Act of 1979

Introduced by Senator Cannon, February 9, 1979

Referred to Senate Committee on Commerce

Hearings held April 25-26, 1979

Passed Senate June 4, 1979

Passed House September 18, 1979 (in lieu of H.R. 51)

Became Public Law 96-129 November 30, 1979.

1. Provides for the safe operation of pipelines

that transport natural gas and liquefied petroleum gas.

2. Requires DOT to conduct a cost/benefit

analysis of increased fuels transportation

safety regulations and study the risks associated with the production, transmission,

and storage of LNG or liquefied petroleum

gas.

3. Requires DOT to establish minimum siting,

construction, and operation standards for

new LNG facilities and to promulgate minimum standards for existing facilities.

4. Requires an LNG facility operator to submit

a contingency plan in the event of an LNG

accident prior to operation of the facility.

5. Established civil and criminal penalties for

violation of safety or financial responsibility standards and willful destruction of interstate pipelines or LNG facilities.

S. 666—Comprehensive Liquefied

Energy Gas Siting, Safety, and Liability

Act of 1979

Introduced by Senator Durkin, March 14, 1979

Referred to Senate Commerce Committee

1. Prohibits construction of new LNG facilities without DOT’s approval.

2.

3.

Provides standards for siting, construction,

and operation of LNG facilities.

Establishes a comprehensive liability and

compensation fund in the Treasury derived from tax on LNG sales and limits liability for an accident to $100 million except

for accidents caused by gross negligence or

violation of safety, construction, or operating standards.

* * *

To assist Congress in debating LNG-related

legislation, several reports have been prepared

by OTA, the General Accounting Office (GAO),

and the Congressional Research Service (CRS).

The OTA report, Transportation of Liquefied

Natural Gas, reviews the major areas of concern

in transporting LNG, such as tanker construction, operation, and safety, and the siting of LNG

facilities. OTA staff also testified at oversight

hearings on liquefied energy gases held by the

Senate Committee on Commerce, Science, and

Transportation during December 1978. These

hearings focused on siting and safety issues,

regulatory delays, jurisdictional conflicts, liability, and compensation. GAOIS reviewed safety

issues, LNG import policy, and the regulatory

process under the Carter administration. In

February 1978, CRS conducted a seminar entitled “Liquefied Natural Gas: Safety, Siting and

Policy Concerns” which provided Congress with

background information on public policy issues

associated with the importation of LNG.

ln(;}~(), ~jque~jed ~rler%v (ja.ye,$ ,sa/~:1 V, 3 i’olunws, JuI-v 31, 1978;

. . .

Need 10 improve lie~ulatfwv Reb’icwf Process fi)r Liqo@ied Natural

Gas Imixwts, JuI}I IJ, 1978;”The New l\Ia[ior]al”Liqu~ fi”t:[i Natural Gas

Import Policy Requires [’ur-ther Irl]/>r{Jb,f~rf]er)t.s, [Mc, 12, 1977,
Ch. 2—Po/icy Background . 2 5

States

Because of the controversy surrounding the

Pac Indonesia project proposed by Pacific Gas &

Electric Company and Southern California Gas

Company, attention has been focused on California’s response to the LNG issue. To improve

the site selection process, the California LNG

Terminal Siting Act was signed into law in 1977.

The keystone of this law is remote siting, Under

the law, the California Public Utilities Commission (PUC) has exclusive authorization to issue

permits to construct and operate an onshore

LNG terminal and thus is the final arbiter of the

site location. The law also requires the California Coastal Commission to evaluate and rank

proposed terminal sites and report their findings to PUC, and it authorizes the California Energy Commission to study the natural gas supply and demand picture to determine whether

or not LNG is needed.

The siting law was first applied in the Pac Indonesia LNG project. The major impact of the

law was to eliminate Oxnard, which had already

been approved by an FPC Federal administrative Iaw judge, in favor of Point Conception as a

terminal site. But before the judge’s decision

could be reviewed by the five-member FPC, it

was stripped of its authority to rule on import

matters and the case was transferred to the

new ERA. ERA found Oxnard to be an acceptable site but expressed reluctance to approve

Point Conception without new hearings. The

Agency, however, was not opposed to the other

site and expressed willingness to cooperate with

State authorities in selecting the best location.

The applicant requested that Point Conception be considered as a terminal site, and the approval process began once again. FERC staff

prepared an EIS on Point Conception and asserted that the site was unsuitable because of

earthquake hazards. In addition, Native Americans opposed the Point Conception site because

of its spiritual significance. FERC staff again recommended Oxnard and Rattlesnake Canyon as

an alternate. Hearings were held on the EIS and

on August 13, 1979, a FERC administrative law

judge approved Point Conception as a suitable

terminal site. However, the judge’s ruling was

subject to final approval by both FERC and ERA.

On September 26, 1979, ERA reaffirmed its approval of the importation of LNG and the price

at the point of importation into either Oxnard or

Point Conception. However, ERA made no determination as to the appropriateness of Point

Conception as a site for LNG-receiving facilities.

In October 1979, FERC was given authority to

approve/disapprove applications for the construction of LNG facilities at Point Conception

and ERA retained authority to approve the construction of facilities at Oxnard. The final decision by FERC in October 1979, was to approve

the Point Conception site.

Other States

Other States have established guidelines

and/or councils to deal with the energy facility

siting issue. For example, Massachusetts has established an energy facilities siting council. Its

purpose is to establish guidelines for the siting

and safety of LNG facilities. The Council proposed guidelines that would require a demonstration of facility need, a cost analysis, a comparison of alternative sites, and an EIS. In addition, the guidelines specify thermal radiation

and vapor performance standards, *

8

The State of New York established an LNG

program which is assigned to the Bureau of

Mineral Resources in the State Department of

Environmental Conservation. Also, the State of

New Jersey has formally expressed positions on

the siting and safety of LNG facilities. The State

opposed the Tenneco project out of concern for

the safety of its citizens and claimed that the

project was contrary to sound energy policy.

According to the State, LNG should be limited to

peak-shaving and very low-priority baseload

use.

lg(:(lmmolltt,ea]t h of’ kfassac.husf~tts Energ~~ Faciiit if?s Siting (~OUn-’

cil, “liquefied Natural (;as Siting (;uiclelines, An F;xplanati{)n ,“ attachmrnt to trstimonlf gif en hJ James (kmnellj’, I)q]ut: IIirwtor,

tfiiss;ichusetts I-lwrg}, of’ficr, I)t]f’ol’f” thf’ S(>lliitf’ (:ommittf~e 011

(:ommerw, Science, ilIl(l ‘l’ I’iiIISpoI’tiiti oil,” tk-. 12-13, 1978, p. 332.
3.

Future Gas Availability and Use
Future Gas Availability and Use

Policy alternatives related to future liquefied

natural gas (LNG) imports can only be evaluated

in the context of the possible ranges of gas availability and use over the duration of a supply

contract. Although such projections are highly

speculative, this chapter presents the results of

a review of the relevant literature.

On examining the forecasts from several

econometric demand models, one observes that

projected U.S. gas use falls between 14 and 25

quadrillion Btu (Quads) in 1990 depending on

such factors as future fuel prices, energy productivity, and public policy. Table 1 indicates by

sector what portions of expected demand are

“basic” in the sense that alternatives are costly

or unlikely, and what are “marginal,” i.e., possible if supplies are available at attractive prices

and policies are favorable.

Since LNG is just one of many possible sources

from which to meet demand, this chapter also

includes a survey of North American gas and oil

production potential. As shown in table 2, domestic production, now at a level of about 19.6

trillion cubic feet per year (Tcf/yr) in 1979, may

decline to as low a level as 14.6 Tcf/yr by 1990,

barely enough to meet ‘(basic” demand. It could

also possibly satisfy “marginal” demand, but

only at high prices. Furthermore, Mexico and

Canada will probably not significantly alter the

balance, and oil production in the continent is

not likely to increase either,

In the rest of the world, large gas reserves occur particularly around the Persian Gulf and in

the Soviet Union. However, for political or economic reasons, most of these resources either

would not be exported or would flow to closer

markets, in Japan and Europe, for example.

Thus, only perhaps 0.5 to 1 Tcf/yr could presently be committed to future LNG sales to the

United States beyond those imports already approved. These remaining available volumes are

located in Nigeria, Southeast Asia, and South

America.

Table 1 .—Projected Levels of Potential

Gas Demand in 1990 by Consuming Sector

Under Alternative Policies and Prices

(quadrillion Btu)

Sector Basica Marginal b Total

Buildings . . . . . . . . . . 5 3 8

Industry . . . . . . . . . . . 8 2 10

Utilities. . . . . . . . . . . . .5 4 4.5

Other. . . . . . . . . . . . . . .5 3 3.5

Total . . . . . . . . . . . . 14 12 26

aaa~l~ d~mand Inc[udes applications for which alternatives are relatively costlY

or unl!kely.

bMarglnal demand Includes other economical uses that are Possible If 5uPPlle5

are available at attractive prices, and policles are favorable

SOURCE: Of ftce of Technology Assessment, based on data from several separate studies (see text for assumptions).

Table 2.–Potential Gas Supply in 1990

(trillion cubic feet; approximate quadrillion Btu)

NPGA Over Over

prices a$3/Mcf b$51Mcfb

Domestic

Conventional . . . . . . . 12.5-16.6 12.5-16.6 12.5-16.6

Alaska North Slope. . — — 1.6

Unconventional. . . . . 2.3 3.6-8.4 3.6-8.4

Synthetics . . . . . . . . . — — 0.3-1.4

Subtotal . . . . . . . . . 14.8.18.9 16.1 -25.0 18.0-28.0

North American imports

Canada. . . . . . . . . . . . — 0.6 0.6

Mexico . . . . . . . . . . . . — 0.7-1.2 0.7-1.2

Subtotal . . . . . . . . . — 1.3-1.8 1.3-1.8

LNG imports

Present & approved. . — 0.8 0.8

Possible additions . . — 0.5-1.0 0.5-1.0

Subtotal . . . . . . . . . — 1.3-1.8 1.3-1.8

Total . . . . . . . . . . 14.8-18.9 18.7 -28.6 20.6 -31.6

aprjce5 sPecified in the Natural Gas Policy Act of 1978 (Public Law 95-6’21)

blg78 dollars per thousand cubic feet.

SOURCE: Office of Technology Assessment.

29
30 ● The Future of Liquefied Natural Gas Imports

U.S. gas demand

This section presents a survey of recent studies of energy and natural gas demand, particularly those that emphasize the tradeoffs between gas use and efficiency improvement technologies in the residential, commercial, industrial, and powerplant sectors. The resulting

range of estimates of likely demand for natural

gas in the next 10 to 20 years is then contrasted

with projections of available gas supplies.

The projections analyzed here were performed by the Energy Information Administration, American Gas Association (AGA), Brookhaven National Laboratory, Dale Jorgenson Associates, Energy and Environmental Analysis,

Inc., Jensen Associates, and the National Academy of Sciences Committee on Nuclear and Alternative Energy Systems (CONAES). The underlying models and analytical methods, described

in the Background Reports volume of this report,

generally account formally for potential

changes in end-use efficiency and technology,

consistent with assumed energy prices, economic growth rates, and Government policies,

As the differences among the projections

listed below illustrate, analytical modeling is an

imprecise art, requiring judgment as well as

logic and facts. The inclusion of many studies

here is intended to indicate how varying assumptions affect the results, and to dramatize

the uncertainty associated with any given projection. As a result, the premises underlying the

individual studies are not necessarily mutually

consistent, although in most cases the long-term

real economic growth is assumed to be 3.5 percent per year. Direct comparisons, such as

those that follow, must be tempered with these

considerations in mind.

Comparisons of projection results

The level of gas demand predicted in any particular study is a function of both the structure

and data input to the demand-side model, and

the exogenous inputs to the model such as price

and economic growth. Generally, models with

more detail on the demand side may be expected to capture a higher degree of consumer

response to price increases, provided the costs

and efficiencies of end-use technologies are

represented accurately. In addition, the higher

the assumed price of fuels and the economic

growth rate, the lower the predicted demand

for gas and other fuels, all else being equal.

Because of the importance of world oil prices

as a pacing variable for energy prices generally,

the summary gas demand for the studies considered are presented in two separate tables. Table

3 presents the gas demand for the projections

that assume little or no increase in the real price

of world oil. Table 4 presents the results of several projects that begin with assumptions of between 50- and 150-percent real increases in

world oil prices between 1978 and 1990.

Effect of prices

Since imported oil is the principal alternative

fuel for many uses, the price of substitutes will

tend to rise to world oil price levels, absent regulation. In a theoretical free market, the price of

natural gas might be expected to rise to the

price of distillate oil refined from foreign crude.

Most world oil price projections fall in the range

between no real price increase ($15 to $20/bbl

in constant 1978 dollars)* and increases to approximately $4o to $50/bbl by 1990.

Gas demand projections assuming nearly constant world oil prices, fall fairly consistently in

the range of 7 to 9 Quads in buildings and 8 to

11 Quads in industry, if gas prices are limited to

no more than the Btu equivalent of imported oil.

In the high world oil price cases, however, the

difference between gas prices at Btu equivalency with oil and at lower regulated levels is

striking. The projections by Jensen Associates

and Brookhaven assume gas to be priced well

below Btu parity. Gas demand for buildings and

industry in these cases is not very different

from the projections shown in table 3, indeed,

gas demand may be slightly higher due to substitution for oil. A more dramatic contrast is between the CONAES scenarios, in which gas is

priced at a slight premium over oil due to its

“I’his lower limit has become outdated in recent months.
Ch. 3—Future Gas Availability and Use ● 31

Table 3.—1990 Gas Demand for Low Oil Price Cases

(quadrillion Btu)’

AGA (2) AGA (2)

Report ElA(l) A EIA (1) B ElA(l) C ElA(l) D ElA(l) E low supply high supply

Oil

Imported

1978 $/bbl . . . . 16.00 23.50 18.50 15.60 21.00 19.06 19.06

Gas

Well head

1978 $/Mcf . . . . 1.99 3.27 2.40 2.01 2.79 2.05 2.05b

Residential ., . 5.57 5.33 5.41 5.48 5.35 5.80 5.80

1

Commercial. , . 2.75 2.38 2.37 2.45 2.29 3.20 3.20

Industry. . . . . . 8.24 8.60 9.98 9.60 7.97 13.50 10.90 ~

Utilities . . . . . . 0.52 0.54 0.51 0.52 0.60 2.20 2.20

Other . . . . . . . . 0.47 0.48 0.53 0.47 0.45 3.00 3.10

Total. . . . . . . 17.55 17.33 18.80 18.52 16.66 27.70 25.20

BNL (3) BNL (4)

DJA L BECOM L —

15.83 16.59

2.50 2.74

(6.80

space heat)

1

6.91

16.80

(3.95 process N/S

heat)

3.10 NIS

N/s N/S

19.90 N/S

N/S Not specified

a

1015 Btu = 0.98 Tcf of gas = 1 Quad

bSupplemental priced comparable to world oil.

SOURCES: 1. Energy Information Administration, Energy Supply and Demand in the Midterm 1985, 1990, and 1995, 1979.

2 American Gas Association, A Forecast of the Economic Demand for Gas Energy in the U.S. Through 1990, 1979.

3 R J Goettle, E. A Hudson, and J. Lucachinski, A Comparative Assessment of Energy-Econorrry Interactions: Price Versus Growth, BNL 50923, Upton

N Y , 1978

4 S C. Carhart, S S. Mulherker, and J. Schwam, Energy, Employrrrent, and Environmental Irnpact of Accelerated Investment in Conservation and Solar

Technologies m Buildings, BNL 50918, Upton, N.Y.,1978

Table 4.—1990 Gas Demand for High Oil Price Cases

(quadrillion Btu)a

JAI (1) BNL/DJA-H (2) BNL BECOM-H(3) CONAES A(4) CONAES B(4) CONAES B’ (4)

World oil price. . . . . . . . . 42.00 29.12 49.20 45.09 25.15 25.15

Gas wellhead price. . . . . 2.50 3.49 3.46 9.76 4.78 4.78

Residential . . . . . . . . . . . 5.32

)

16.55 6.14 4.6 b

5 . 1

b

5 . 7

b

Commercial. . . . . . . . . . . 2.77

Industry. . . . . . . . . . . . . . 9.37 N/S 8 . 0

b

7.1 b 8 . 4

b

Utilities , . . . . . . . . . . . . . 4.80 1.75 N/S N/S N/S N/S

Other . . . . . . . . . . . . . . . . 2.48 N/S N/S N/S N/S N/S

Total. . . . . . . . . . . . . . . 24.74 18.30 N/S N/S N/S N/S

N/S Not specified

a

1 0

1s Btu = 098 Tcf of gas = 1 Quad

bAdjusted for 3.5 percent per year GNP growth for comparability with other forecasts.

SOURCES 1 Jensen Associates, Inc., Imported Liquefied Natural Gas, 1979 (vol. II of this report).

2. R. J Goettle, E. A. Hudson, and J. Lucachinski, A Comparative Assessment of Energy-Economy Interactions Price Versus Growth, BNL 50923, Upton

N Y , 1978

3. S. C. Carhart, S. S. Mulherker, and J. Schwam, Energy, Employment, and Environmental Impact 01 Accelerated Investrmen! in Conservation and Solar

Technologies in Buildings, BNL 50918, Upton, N. Y,,1978.

4 National Academy of Sciences, Committee on Nuclear and Alternative Energy Systems, Alternative Energy Demand Futures, Report of the Demand/Conservation Panel, 1980.

ease of use and cleanliness, and the other high

oil price cases. The results are substantial reductions in gas demand—to 5 Quads in the

buildings sector and to 8 Quads in industry.

The implication of the latter figures, while

preliminary and not strictly comparable, is that

substantial conservation in buildings and industry is economically justified between the $2,05

per thousand cubic feet (Mcf) price contemplated in the AGA high-demand case and the $5

to $10 Mcf assumed by CONAES. On the basis of

these studies taken together, one concludes that

1990 buildings and industry demand will probably lie in the 12- to 14-Quad range if gas is

priced on a Btu equivalency basis with higher

priced oil, in contrast with 16 to 20 Quads for

the lower gas price cases.
32 . The Future of Liquefied Natural Gas Imports

Effect of public policy

The range of demand for utilities and miscellaneous uses falls between 1 and 7 Quads. The

main difference in these projections arises from

varying interpretations of the Power Plant and

Industrial Fuel Use Act, which calls for negligible levels of natural gas use in powerplants by

1990, but provides for numerous exemptions

and exceptions. Regulatory interpretation of the

law over the next decade will be a key factor in

resolving this uncertainty.

Another major element of Government policy

concerns incremental pricing and use of natural

gas for the generation of steam. The AGA study,

which explores what type of energy service in

industry would absorb marginal supplies of gas,

illustrates the effect of these policies. A “high

Domestic supplies

This section reviews U.S. gas and oil resources

and potential supplies in terms of quantity, time

of availability, and cost. In the context of projected demand, this discussion is designed to aid

in assessing the need for imports. The method

of analysis draws heavily on numerous available

supply forecasts. The results, presented in

greater detail in the Background Reports volume, rely on secondary resources and do not

represent yet another supply projection,

Table 5 summarizes U.S. gas production from

all sources. The ranges in estimates are indicative of the uncertainty associated with each

source. Production is principally dependent on

the rate at which new reserves can be added,

supply” case assumes that supplemental supplies, such as LNG, will be used by, and priced

incrementally to, industrial users. In the “low

supply” case, no supplemental gas is included,

and prices stay at the average level for conventional supplies. The effect of incremental pricing in industry is to reduce demand by 2.6

Quads, the bulk of which would have raised

steam, largely through displacement of other

fuels, as shown in table 3. The incrementally

priced high-supply case projection of 10.9

Quads in industry is quite comparable with

other projections. However, if all gas to industry

is incrementally priced, and world oil prices are

in the $40 to $50/bbl range, CONAES case A suggests that total demand in industry might be expected to fall to around 8.0 Quads.

and Alaska’s contribution also hinges on the

construction of the Alaska gas pipeline. Realization of the potential of unconventional gas

sources will require time and technological

progress, and coal gasification also will require

large capital outlays.

Maintaining current levels of U.S. liquid petroleum production over the next decade or two

will be extremely difficult. Natural gas liquids

production may decline with declining production of natural gas, and conventional oil production from proved reserves will continue to decline. At the same time, enhanced oil recovery

(EOR) processes and new discoveries may not

add enough to reserves in time to offset declinTable 5.—U.S. Gas Supply Conventional, Unconventional, Coal Gas

(trillion cubic feet)

Alaska Unconventional Coal gas

Lower-48 NGPA-pricesa

$5.00-$6.00 $1.75 $3.00 $3.00 $5.00-$6.00

Low Med High 1978$ 1972 High 1978$

1980. . . . . . . . . . . . . . . . . . . . . . . 18.8 18.8 18.8 — .3 .5 .5

1985. . . . . . . . . . . . . . . . . . . . . . .

—

14.7 16.3 17.8 .8 1.3 1.9 4.1 .2-.7

1990. . . . . . . . . . . . . . . . . . . . . . . 12.5 14.5 16.6 1.6 2.3 3.6 8.4 .3-1.4

1995. . . . . . . . . . . . . . . . . . . . . . . 11.4 12.4 13.6 2.5 2.8 4.4 8.4 2.4

2000. . . . . . . . . . . . . . . . . . . . . . . 10.8 11.6 12.2 3.6 2.8 4.4 9.0 4.0

aAccordlng 10 the Natural Gas Policy Act of 1978 (Public Law 95-621).

SOURCE: Office of Technology Assessment.
Ch. 3—Future Gas Availability and Use ● 33

ing production from older fields. Progress in developing oil shale and coal will be slow, and synthetics production on a large scale is not anticipated before the mid-1990’s) even if potential

environmental problems are resolved.

Future U.S. liquid petroleum production

could consist of the components in table 6. In

spite of the inherent uncertainty, the forecast

does suggest that domestically produced liquid

petroleum will not be available to substitute for

shortfalls in gas or other energy sources. Indeed, large quantities of imported oil will continue to be required to meet liquid petroleum

demand in the foreseeable future.

Conventional natural gas

Five forecasts of conventional gas production,

summarized in table 7, have been examined in

this study, representing a range of institutional

perspectives. They were chosen in part to represent the widely different levels of optimism

expressed by analysts in this field, but all forecasts (except one by AGA) project a decrease in

U.S. conventional natural gas production from

about 19.6 Tcf in 1979 through the end of the

century.

As of year-end 1978, U.S. proved reserves of

natural gas totaled 200.3 Tcf, including approximately 30 Tcf of North Slope, Alaskan gas for

which no transportation and delivery system is

available, at least for the next 5 years. Estimates

of indicated and inferred reserves range from

52 to 202 Tcf, reflecting differences in the definitions of categories, less certain geology, and

lack of interest in exploration (particularly for

nonassociated gas) due to Government price

Table 6.–Possible Future U.S.

Liquid Petroleum Production

(million barrels per day; 25.381978 dollars/bbl)

1985 1990

Conventional liquid petroleum known

fields. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6 4.2

Enhanced recovery . . . . . . . . . . . . . . . . . . 1.0 1.8

New discoveries . . . . . . . . . . . . . . . . . . . . 2 2

Shale oil . . . . . . . . . . . . . . . . . . . . . . . . . . . — .1-.4

Coal liquids . . . . . . . . . . . . . . . . . . . . . . . . — .1-.5

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-9 8-9

Table 7.—Forecasts of U.S. Conventional

Natural Gas Production

(trillion cubic feet)

American Gas

Associational EXXON Shell Lewin

C Tenneco

1980 . . . . . 18-19 17.0 17.0 17.0 18.0

1985 . . . . . 16-18 15.3 14.0 14.0 16.0

1990 . . . . . 15-17 14.3 13.0 13.0 15.0

1995 . . . . . 14-15 NA NA NA 14.0

2000 . . . . . 12-14 NA NA 11.0 12.0

a

The higher estimate assumes gas price deregulation.

bExcludes Alaska.

C

lncludlng developments of unconventional gas already underway.

SOURCE: Office of Technology Assessment.

regulations. Estimates of undiscovered, recoverable natural gas resources varying from 361 to

920 Tcf, are even more speculative. Estimates of

remaining recoverable U.S. conventional gas resources are summarized in table 8.

Proved reserves are the most significant determinant of production in the immediate future, since the ratio of reserves to production,

8.5 to 1 in the United States, excluding Alaska, is

close to its technical limit. In the lower 48

States, proved reserves have declined every

year since 1968 as production has exceeded additions. With no net additions to reserves, a

lower reserve-to-production ratio, even if technically feasible, would delay but not reverse the

decline in natural gas production which began

in 1973.

Over a period of several years, however, additions to production potential would arise from

revisions and extensions of existing fields, new

discoveries, and Alaskan reserves. Since 1970,

Table 8.–Potential Supply

(trillion cubic feet)

Year of Old New

estimate Source fields fields Proved Total

1974 . . . Hubbert 135 361 200 696

1974/5. . Mobil 52 485 200 737

1975 . . . National Academy

of Sciences 118 530 200 848

1975 . . . Institute of Gas

Technology (633-1 ,138) 200 833-1,338

1975 . . . U.S. Geological

Survey 202 322-655 200 724-1,057

1978 . . . EXXON (202-860) 200 400-1,060

1978 . . . Potential Gas

Committee 199 820 200 1,219

SOURCE Office of Technology Assessment SOURCE: Office of Technology Assessment
34 ● The Future of Liquefied Natural Gas /reports

additions to reserves outside Alaska have averaged 9.3 Tcf/yr, consisting mostly of new reservoir discoveries in old fields and revisions and

extensions of presently producing fields. The

contribution of new field discoveries to this

total has averaged only 1.8 Tcf/yr since 1971. To

maintain current production at the 8.5:1 reserves to production ratio, additions to proved

reserves would have to equal current production, about 20 Tcf/yr, so an additional 10 Tcf

above historical reserve additions would have to

be found to maintain current production levels.

Optimism or pessimism in the forecasts cited

above turns on the likelihood of large additions

to reserves in the future, in the light of uncertain geology and the unknown effect of higher

prices of drilling rates.

Alaska contains an estimated 225 Tcf of potential gas, including indicated and inferred reserves and speculative resources, representing

perhaps 23 percent of the U.S. total. Of the 31.8

Tcf of proved reserves within the State, the major portion is located in the Prudhoe Bay field of

northern Alaska, and gas resulting from oil production there is being reinfected into the gas

cap. None of this gas will be available until an

Alaska pipeline project is completed, in 1984 at

the earliest, and the financing for the venture is

still problematic. When completed, the pipeline

would have a nominal design capacity of 0.9

Tcf/yr. When a west coast LNG terminal is built,

50 billion cubic feet (Bcf) of Alaskan gas from

southern Alaska, which is currently shipped to

Japan, could come to the United States.

Conventional oil

The United States has already reached the

1:10 production-to-reserves technical limit. To

maintain current production levels, additions to

reserves, whether through enhanced recovery

or new discoveries, would have to equal current

production—about 3 billion barrels per year

(bbl/yr). In fact, the United States has been adding to reserves at a rate of about 1.8 billion

bbl/yr (excluding Prudhoe Bay). For this reason

the United States will probably be unable to

maintain current production levels over the

next decade, since enhanced recovery and new

discoveries are not likely to offset the decline in

older producing fields.

Five domestic oil production forecasts appear

in table 9. Although difficult to compare because of inconsistent and inexplicit assumptions, most forecasts project no increase before

1990 in U.S. liquid petroleum production from

the 10.3 million barrels per day (MMbbl/d) level

achieved in 1978. Indeed, EXXON and Shell project a decline from current levels, and in general, the more recent the forecast the lower the

projected production figures. *

The extent to which any of these forecasts are

borne out depends on petroleum reserves, recovery factors, and the rate at which resources

are discovered. The following analysis examines

each of these factors.

At the end of 1978, U.S. proved crude oil reserves stood at 27.8 billion bbl. Typically, as exploration and development work yields greater

information on a field, inventories of proved reserves will change, and estimates of additional

oil include 4 billion bbl of indicated reserves and

23 billion bbl of inferred reserves. The importance of these potential additions to proved reserves is their near-term availability (1 to 3

years).

Table 9.— Forecasts of U.S. Conventional Liquid

Petroleum Production

(millions of barrels per day)

Petroleum

Energy Industry

Information Research

Agency/ Foundation EXXON CIA Shell

DOE 1978 1978 1978 1978 1978

1980. . NA 9.8 9.6 10.4 9.8

1985. . 10.8 10.3 8.5 10.2 9.7

1990. . 10.4 10.4 7.2 10.3 9.9

NA = Not available.

a

lncluding natural gas Iiqulds.

SOURCE: Office of Technology Assessment

*These estimates may not fully reflect more recent large world

oil price increases and the President’s decision to deregulate domestic oil production,
Ch. 3—Future Gas Availability and Use ● 35

Photo credit Courtesy of American Gas Association

Alaska’s North Slope contains new reserves of natural gas. At Prudhoe Bay, this rig is typical of

initial exploratory and production efforts

In the lower 48 States, annual production has

exceeded additions to reserves since 1970. Also,

as indicated in figure 3, the addition of Prudhoe

Bay reserves will permit only a temporary increase in production, after which North Slope’s

contribution will be insufficient to offset the decline in older producing fields. The extent to

which production can be maintained or increased depends on the existence and availability of additional reserves represented by EOR

and new discoveries.

Primary oil recovery takes advantage of the

natural flow of oil in a reservoir to a producing

well, and the application of secondary recovery

techniques, water flooding and gas injection, increases the proportion of oil-in-place that can be

recovered and accounts for approximately 50

percent of the current U.S. oil production discussed above. These established techniques

leave significant quantities of oil in the ground,

and the future availability of this remaining oil

depends on the development and application of

EOR technology, including thermal, chemical,

and miscible processes.

Predictions of the quantity of oil to be recovered by enhanced recovery technology and potential production rates are beset with uncertainty. While interest in EOR is longstanding,

most of the processes, with the exception of

steam injection, remain unproved. Nevertheless, the results of three production estimates

appear in table 10, reflecting varying assumptions about future price and process performance.

Further additions to production will have to

come from new discoveries, and estimates of
. .

36 . The Future of Liquefied Natural Gas imports

Figure 3.—Projected Oil Production by Conventional

Methods From Known U.S. Reservoirs, 1976-95

1976 1980 1985 1990 1995

NOTE: The decline curves for proved reserves do not include enhanced oil recoveries recorded within these categories.

SOURCES: a

Federal Energy Admintstration, National Energy Outlook, 1976.

b

us, Geological Survey, Circular 725, 1975.

cAmerican petroleum Institute, Reserves of Crude 0il, Natural Gas

Liquids, and Natural Gas m the u.S. and Canada as of December

30, 1975, Lewin & Associates, Inc., for Federal Energy Administration, Decline Curve Analysls, 1976.

Table 10.—Estimated Potential

Production From Enhanced Recovery

(millions of barrels per day, $10-$25/barrela)

OTAbLewinc NPCd

Poor process performance

1985. . . . . . . . . . . . . . . . . . . . . . . .4- .9 .5- .7 .4-1.0

1990. . . . . . . . . . . . . . . . . . . . . . . .5-1.8 .5- .9 .8-1.9

1995. . . . . . . . . . . . . . . . . . . . . . . .5-2.3 .5-1.0 .8-1.9

High process performance

1985. . . . . . . . . . . . . . . . . . . . . . . .5-1.3 1.7-2.5 1.6-2.3

1990. . . . . . . . . . . . . . . . . . . . . . . 1.1-2.3 2.6-4.3 2.9-3.9

1995. . . . . . . . . . . . . . . . . . . . . . . 1.7-6.0 2.8-4.5 3.3-4.6

a

1976 dollars.

bEnhanced 01/ Recovery Potential m the United States, Office of Technology

Assessment, 1978.

cResearch and Development in Enhanced Oil Recovery, Lewin and Associates,

1976.

dEnhanced 01/ Recovery, National Petroleum Council, 1976.

undiscovered resources vary widely, converging in recent years around a figure of 60 to 100

billion bbl (figure 4). Recent exploration results

in south Alaska and the Baltimore Canyon generally confirm the downward trend. Since undiscovered resources, to the extent that they exist, must be found and developed before they

can contribute to U.S. oil supply, their potential

contribution lies in the longer term, and most

forecasts assume that by 1990, 25 percent of

U.S. oil production will have to come from reserves not yet discovered. Since 1970, 10.8 billion bbl of oil have been discovered in new

fields, but if Prudhoe Bay is excluded only 1.0

billion bbl of this category of discovery have

been added to reserves in the entire 1970-7?

period. If undiscovered resources are to contribute significantly to U.S. oil supply, the finding rate will have to increase.

Unconventional domestic oil

and gas sources

In addition to conventional supplies, oil and

gas may be available from other sources including unconventional gas, synthetic fuels from

coal, and oil shale. This section evaluates these

potential sources.

UNCONVENTIONAL GAS

In addition to conventional natural gas, significant quantities of methane are found in Devonian shales of the Appalachian Basin, low-permeability formations in the Western and Northwestern United States, coal seams in the Eastern

and Western United States, and geopressured

aquifers located primarily near the coast of Louisiana and Texas. Although gas is known to be

present in each of these locations, its extent and

commercial recoverability are uncertain. Nevertheless, for the purposes of this analysis, the

projections by Lewin and Associates presented

in figure 5 are representative of a reasonable

range of expectations. The contributions of individual resource categories appear in table 11,

based on varying technology and price assumptions. The President’s 1979 energy message suggests that 1990 unconventional gas production

could be between 1 and 2 Tcf/yr.

Devonian shales are low-permeability, sedimentary rocks present throughout an area of

210,000 square miles stretching from New York

to Alabama. The low permeability of the shale

restricts gas production to very slow rates, albeit for long periods of time, and requires artificial stimulation to enhance recovery. Thus,

while the total resource base is large, the recov-
Ch. 3—Future Gas Availability and Use ● 37

Figure 4.—Comparative Estimates of Undiscovered Recoverable Resources of Crude Oil and Natural Gas

Liquids (NGLs) in the United States as of Date of Estimate

Undiscovered

recoverable

bbls

500

300

100

Reserves

and

cum. prod.

SOURCE: Charles Masters, “Recent

100

200 I

Estimates of U.S. Oil and Gas Resource Potential,” U.S. Geological Survey, Open File Report 79-236, 1976.

Figure 5. —Annual Production From Unconventional

Sources to the Year 2000 at $1.75 and $3.00/Mcf

(except geopressured aquifers)

:6~ Base case

.-

Z5 —

54 —

——$1.75

Base case

k 3 — <~.,=! 3

:2—

=1 “

o

1977 1980 1985 1990 1995 2000

SOURCE. Lewin and Associates, Enhanced Recovery of Unconventional Gas,

February 1978

erable resource may be no more than 1 to 10

percent of the gas-in-place. Estimates of recoverable resources range from 3 to 285 Tcf, and

studies by OTAl and Lewin and Associates 2

1Gas Potential From Devonian Shales of the Appalachian Basin

(Washington, D.C.: Office of Technology Assessment, November

1977).

2

Lewin and Associates, Enhanced Recovery of Unconventional

Gas, October 1978.

agree that production is unlikely to reach 1 Tcf

in the next 20 years.

Natural gas is also present in tight basins of

low-permeability sandstone, siltstone, and chalk

formations located primarily in the Western

United States, the northern Great Plains, and

parts of Texas and Louisiana. Although the gas

in these formations cannot be recovered economically using conventional technology, it may

contribute about 1 Tcf to U.S. annual gas production already and appears to hold the greatest

near-term potential for contributing significantly to U.S. gas supply, depending on progress

in resource characterization, stimulation technology, and higher gas prices. Estimates of total

gas-in-place for tight basins range from 400 to

1,200 Tcf. In some places, recoverability may

approach 70 to 80 percent, but in most, recoverability will be in the 40- to 50-percent range. At

$3.00 (1977) per Mcf, production could reach 7

to 8 Tcf/yr in the 1990’s given technological advances from Federal and industry R&D efforts.

Methane in coal mines constitutes a major

safety hazard, and research in the United States

59-406 0 - 80 - 4
38 ● The Future of Liquefied Natural Gas Imports

Table 1 1.—Annual Production From Unconventional Sources to the Year 2000

at $1.75 and $3.00/Mcfa (trillion cubic feet)

1985 1990 2000

$3.00 $3.00 $3.00

$1.75 $3.00 Advanced $1.75 $3.00 Advanced $1.75 $3.00 Advanced

Devonian shale . . . . . . . . . . . . . .05 .1 .3 .1 .3 .6 .04 .3 .5

Tight gas. . . . . . . . . . . . . . . . . . . 1.2 1.8 3.8 2.2 3.2 7.7 2.7 4.0 7.0

Coalbeds . . . . . . . . . . . . . . . . . . .02 .02 .02 .04 .05 .05 .05 .07 .08

Geopressured aquifers. . . . . . . (Uncertain) (l-2?)

Total . . . . . . . . . . . . . . . . . . . . 1.3 1.9 4.1 2.3 3.6 8.4 2.8 4.4 9.0?

a

1977 constant dollars.

SOURCE: Data from Lewin and Associates, Enhanced Recovery of Unconventional Gas, October 1978.

has concentrated on disposing of the gas. However, several European countries—notably the

United Kingdom, Belgium, the Netherlands, and

West Germany—have recovered and utilized

methane from coal seams as a fuel. In the period

1971-75, 200 bituminous coal mines emitted

about 80 Bcf/yr, mostly in the Appalachian region. Further development of methane recovery

from minable coal is hampered by difficulties of

resource definition, economic uncertainties and

high costs, institutional questions involving

ownership of the gas, and conflicting economic

interests of mine operators and gas producers.

In spite of these problems, a small amount of

gas, about .05 Tcf/yr, could be produced from

mines in the Appalachian Basin by 1990. Recovery of an additional but uncertain small amount

of gas may be possible from coalbeds that are

too deep or thin to sustain mining.

Geopressured aquifers contain methane dissolved in water trapped at higher than normal

pressures in sedimentary deposits underlying a

large portion of the northern shorelines of the

Gulf of Mexico. Estimates of gas-in-place vary

widely reflecting geological uncertainty and inconsistent analytical techniques. Also, the recoverability of natural gas depends on the

amount of water that can be produced by wells

tapping these reservoirs, and the requirement

of high flow rates limits the number of geopressured aquifers that might be suitable for recovery of methane. The economics of natural

gas recovery from geopressured aquifers might

be improved by the simultaneous exploitation of

hydraulic and geothermal energy. However,

water production may be limited by declining

pressure to about 2 to 5 percent of a reservoir’s

capacity over a 30-year period. Institutional and

environmental constraints on the recoverability

of natural gas from geopressured aquifers include: questions of ownership of the gas, possible land subsidence problems, and problems of

water disposal. Less than 5 percent of the gasin-place may be recoverable even assuming favorable reservoir properties and high methane

extraction efficiency, and estimates of recoverable resources range from 42 to 1,146 Tcf. Although Lewin and Associates considered the uncertainties too great to forecast production potential, other sources indicate that geopressured aquifers may yield 1 to 2 Tcf/yr of natural

gas by 1995-2000, assuming gas prices of $3.00

to $4.50/Mcf (1977 dollars).

SYNTHETIC FUELS FROM COAL

Coal is the Nation’s most abundant fossil energy resource, and coal conversion technology

is not new. Gas from coal was distributed as

town gas in the United States before the advent

of an extensive natural gas pipeline network.

Coal liquefaction processes are also well-known.

Germany produced synthetic oil from coal in

the 1930’s and South Africa currently produces

coal liquids on a limited scale. Nevertheless, coal

conversion does not overcome all of the safety

and environmental problems associated with

conventional coal use and has yet to result in oil

or gas that is competitive with alternative

sources in terms of price. Further development

may improve the efficiency of individual processes and the economics of coal conversion generally, but only in time.

Estimates of potential coal gas production

have been repeatedly scaled down. In 1973, the

Federal Power Commission (FPC) National Gas

Survey estimated 1985 production at 0.7 to 1.9
Ch. 3—Future Gas Availability and Use ● 39

Tcf. By 1975, FPC announced that the lower end

of the range appeared more realistic. Other projections of coal gas production (table 12) agree

that coal gasification’s most significant contribution to U.S. energy supply will probably be after

1990. Even the realization of these forecasts

would require Government incentives, advanced technology, and possibly some relaxation in environmental regulations.

Coal liquefaction is presently thermally inefficient and costly. It also poses the same environmental problems as coal mining and introduces

some new ones, The promise of significantly

greater efficiencies of future liquefaction technologies may make investors reluctant to apply

present technology on a large scale. Given long

leadtimes associated with the development of

improved technology, high plant costs, and

heavy capital investments, the need to scale-up

pilot plants to commercial size, greater interest

in oil exploration and enhanced recovery on the

part of the oil companies, and water availability

problems, rapid development of a substantial

synthetic fuel industry is not anticipated. AIthough the President’s July 1979 energy message suggested that gas and liquids from coal

could contribute between 1.0 and 1.5 MMbbl/d

to domestic fuel supplies in 1990 at a cost of

$38 bbl, recent forecasts, shown in table 13, indicate that production will be significantly less

than this amount, at least without massive Government participation.

OIL SHALE

Oil shales are fine-grained sedimentary rocks

containing significant quantities of an organic

Table 12.—Projections of Coal Gas Production

(trillion cubic feet)

1985 1990 1995 2000

American Gas Association (1977) . .1 .6 1.8 3.3

Department of the lnterior (1975) . .4 N/A N/A 4.7

Shell Oil Company (1978). . . . . . . . .6-.7 1.4 N/A N/A

Frost and Sullivan (1976) . . . . . . . . .2 .6 N/A N/A

Congressional Research Service

(1978) . . . . . . . . . . . . . . . . . . . . . . N/A .3-.5 N/A N/A

EXXON (1978) . . . . . . . . . . . . . . . . . .5 .7 N/A N/A

Table 13.—Potential Syncrude

Production From Coal

(million of barrels per day)

1985 1990 1995 2000

DOE . . . . . . .09 .5 1.5 4.0

Shell. . . . . . .04 .3 N/A N/A

NPC . . . . . . .08-.9 N/A N/A N/A

EXXON . . . . — .1 N/A N/A

N/A = Not available.

SOURCE: Off Ice of Technology Assessment

material, which, when heated, yields gas, residual carbon, and a highly viscous liquid oil product. With the addition of hydrogen, shale oil is

upgraded to become a synthetic crude feedstock, which can be refined to produce conventional fuels. While oil shale resources are widespread throughout the United States, attention

has focused on the extensive and rich deposits

in the Green River formation of Colorado, Utah,

and Wyoming. Although estimates of shale oil

resources recoverable with currently available

mining technology and aboveground processing

are in terms of billions of barrels, potential

large-scale shale oil production will be constrained by environmental considerations, water availability, construction logistics, Federal

leasing policies, land title conflicts, leadtimes

needed to scale-up and construct commercial

plants, and the marginal economics of shale oil

vis-a-vis natural crude oil. Estimates of potential

shale oil production have been consistently

scaled down since 1974 (see table 14).

Table 14.—Shale Oil Production

(thousands of barrels per day)

1980 1985 1990

Project Independence (1974). . 50-100 250-1,000450-1,600

Synfuels interagency

task force . . . . . . . . . . . . . . . NA 100-830 NA

Shell (1978) . . . . . . . . . . . . . . . . 0 40 300

EXXON (1978) . . . . . . . . . . . . . . 0 0 100

President Carter (July 1979). . . NA NA 400

N/A = Not available

SOURCE Off Ice of Technology Assessment

NA = Not available.

SOURCE Office of Technology Assessment
40 . The Future of Liquefied Natural Gas Imports

Canada and Mexico

Pipeline imports from neighboring countries

in North America represent another potential

source to meet projected demand for gas and

oil. Under present Canadian policy, which may

change in the future, gas exports to the United

States would increase from a present level of 1

Tcf to a peak of 1.8 Tcf before declining to

about 0.6 Tcf/yr by 1990, reflecting depletion of

reserves and a policy of self-reliance. Mexico

could have 0.7 to 1.2 Tcf/yr of gas available for

export by that time to make up for reduced supplies from Canada, depending on how attractive

sales to the United States are compared to domestic consumption. Prospective oil imports

from these two nations will not alter the situation. Mexico could increase petroleum exports

as much as 0.5 MMbbl/d by 1990 if markets are

found for associated gas, but under official Mexican policy, the United States would receive no

more than 60 percent of this amount. Also, Canadian production is not as likely to increase,

and given domestic requirements, exports will

probably be small in volume, interruptible if Canadian demand requires, and tied to exchange

agreements. Selling to the United States at substantially less than competing fuel prices in the

world market is not in the interest of either

country.

Canada

Throughout the decade of the 1960’s and into

the early 1970’s, Canada was a major energy

supplier to the United States. By 1970, the

United States was importing 760,000 bbl/d of

liquid petroleum from Canada, and in 1978 the

United States purchased approximately 1.0 Tcf

of Canadian gas,

In the early 1970’s however, a deteriorating

domestic resource position, higher international

oil prices, and concern with the security of foreign oil supplies led Canada to adopt a policy of

self-reliance which was reaffirmed by the recent conservative government.

Balanced against the self-reliance policy and

arguing in favor of Canadian energy exports are

domestic economic and political considerations.

Energy resources are concentrated in western

Canada, and the provincial governments exercise a great deal of power over their resources.

Western provinces, eager to encourage further

exploration and development and concerned

with controlled domestic prices, favor exports

as a means of earning greater revenue. The

quid pro quo for lower domestic energy prices

is often some level of allowable exports. Finally,

given the distances involved in moving western

resources to eastern markets, economics often

favor exports to closer U.S. markets, since payments for crude imports for eastern Canada are

more than offset by earnings on western exports.

Generally, only oil and gas supplies surplus to

Canadian needs will be available for export. In

assessing Canada’s energy potential, one must

rely heavily on the projections prepared by Canada’s National Energy Board (NEB), which is responsible for forecasting Canadian energy supply and requirements and for recommending

export policy for Government approval. Thus,

projections from this source have a major impact on the volumes available for sales to the

United States quite apart from their technical

validity.

Higher Canadian gas prices have led to expanded drilling activity in recent years, and a

decline in proved reserves in 1972 and 1973 was

followed by increases beginning in 1974. The

NEB gas production capability forecast for conventional areas (table 15) is based on established

reserves, historic finding rates and reserves-toproduction ratios, and estimated leadtimes for

the construction of gas delivery systems. While

the frontier areas appear promising in terms of

gas resources, NEB does not include potential

production from them in its forecast of producing capability, since no delivery system has been

built or approved to bring frontier gas to market.

NEB has devised three tests all of which must

be satisfied if new export licenses are to be

granted, in order to protect Canadian requirements. NEB anticipates that gas exports already

contracted will be fulfilled, and it recently approved an additional total of 3.75 Tcf of gas for
Ch. 3—Future Gas Availability and Use ● 41

Table 15.-Canadian Gas Potential

(trillion cubic feet per year)

Producing capability, Total

Year conventional areas Canadian demand

1980 . . . . . . . . . 4.1 1.9

1985 . . . . . . . . . 4.6 2.4

1990 . . . . . . . . . 3.8 2.6

1995 . . . . . . . . . 3.0 2.9

2000 . . . . . . . . . 2.3 3.3

SOURCE. Canadian National Energy Board, November 1979.

export to the United States in the period

1980-87. Under the new decision, total exports

are expected to reach a peak of about 1.8 Tcf/yr

in 1982, declining to about 1.0 Tcf by 1987.

After that time, only gas under existing contracts would continue to be delivered, at volumes declining rapidly to 0.6 Tcf/yr in 1990 and

zero shortly thereafter, unless new exportable

surpluses are identified.

The NEB projections of exportable surplus are

conservative in that estimated demand is high

and supply is low. Demand is inflated by the inclusion of eastern Canadian markets, while

hearings still are underway to determine the economic advisability of expanding the transmission system beyond Montreal. Supply excludes

the frontier areas, even though the Alaskan

highway gasline and the proposed Dempster lateral could bring Mackenzie Delta-Beaufort Sea

gas to market by the mid-1980’s. Some Arctic Islands gas might also be available for export to

the U.S. east coast if a proposed LNG project is

approved.

The price of Canadian gas exports is not tied

to the price of any particular oil product, but instead to the cost of alternative fuels in selected

U.S. markets and the cost of imported oil in Toronto. A new official price of $4.47/Mcf took effect on February 17, 1980.

Potential Canadian liquid hydrocarbon supply

derives from conventional producing areas, oil

sands, and frontier areas. The conventional

areas include those already producing oil.

Proved reserves total about 6 billion bbl, and Alberta and Saskatchewan account for approximately 95 percent of the total. Since 1970, annual production has exceeded yearly additions

to reserves. As in the United States, Canadian

production potential depends on the existence

of additional resources and the rate at which

they are found and developed. NEB estimates

that 4.9 billion bbl of reserves might be added

from enhanced recovery, revisions and extensions of known fields, and new discoveries. Nevertheless, production in conventional producing

areas is forecast to decline through 1995.

While the resource potential of heavy oil and

oil sands deposits is large, technological and

economic considerations will slow development.

NEB projects 155,000 bbl/d of oil sands production in 1980, increasing to 255,000 bbl/d in 1985

and 755,0OO bbl/d in 1995. Although representing over 50 percent of prospective Canadian oil

supply in 1995, oil sands production will merely

offset the decline in production anticipated for

conventional producing areas.

The frontier areas—the Mackenzie DeltaBeaufort Sea region, the Arctic Islands, the Labrador Shelf, and the Atlantic Shelf South—are

characterized by their distance from markets

and harsh environments. The existence of oil resources in these regions and the economic attractiveness of production are both uncertain.

Important recent discoveries have involved natural gas more often than oil. Even if large discoveries occur in the next few years, Ieadtimes

associated with production in hostile environments are long. Indeed, NEB does not anticipate

any production from the frontier regions at

least until 1995.

NEB oil demand and base case supply forecasts project imports of 300,000 bbl/d in 1980,

700,000 bbl/d in 1985, and 900,000 bbl/d in 1990

and 1995, assuming no exports. Given the Canadian oil supply/demand situation and the official

policy of self-reliance, large volumes of Canadian crude are unlikely to be sold to the United

States. Small quantities may be available as further development of indigenous resources requires temporary access to the larger U.S. markets, and considerations of logistics, crude quality, and refining capacity also may argue for

some exports to the United States. However,

under Government policy, light crude exports

are to be phased out completely by 1981, and

heavy crude exports are determined quarterly.
42 ● Thee Future of Liquefied Natural Gas Imports

Mexico

Estimates of Mexico’s resource and production potential are uncertain. Since the 1938 ejection of foreign oil companies and the nationalization of the petroleum industry, Mexican hydrocarbon development has been the sole responsibility of the national oil company, PEMEX,

which considers the information necessary for

independent resource and production estimates

to be proprietary. Moreover, the PEMEX monopoly may constrain petroleum development.

While the company has a long operating history

and a core of highly skilled personnel, the scale

of present developments may strain its manpower and equipment resources. The strength

of nationalist sentiment and the petroleum

workers’ union militate against heavy reliance

on foreigners, although some have been hired

for work in highly technical areas. Finally, uncertainty as to Mexico’s potential relates also to

the fact that only 10 percent of Mexico’s potential hydrocarbon-bearing areas have been explored.

Domestic and international politics are also

important in determining Mexico’s production

potential and export policy. A domestic concern

is that oil revenues should be consistent with

Mexico’s ability to absorb the added income for

balanced economic growth without major social

and political dislocations. Mexicans are also convinced that their oil and gas resources are to be

exploited for their own benefit and not prematurely exhausted for the benefit of foreigners.

Finally, Mexico can avoid increasing dependence on the United States by diversifying its export markets.

On the other hand, transportation costs are

lower to the United States than to other markets, especially for gas, and U.S. reliance on

Mexican fuels could counter Mexican dependence on the United States as a major purchaser.

Also, increased production provides the opportunity to gain international prestige as a major

oil exporter and to alleviate pressing internal

economic problems and a heavy foreign debt

burden. While resources and domestic demand

place outer limits on availability of imports from

Mexico, political and economic factors will determine the actuality. However, the available

evidence suggests that while Mexico may become a major hydrocarbon exporter, that nation alone does not represent an answer to U.S.

energy problems.

Mexico’s official estimates of proved oil and

gas reserves have increased steadily from 5.8

billion bbl oil equivalent at the end of 1974 to

40.2 billion bbl as of January 1979. Depending

on assumed associated gas/oil ratios and the

fields included in the estimates, this figure could

include 26 to 32 billion bbl of oil and 45 to 80 Tcf

of gas. In addition, PEMEX estimates 44.6 billion

bbl oil equivalent of probable reserves (34.4 billion bbl of liquids and 72,4 Tcf gas) and 200 billion bbl of potential hydrocarbon resources.

The resource base appears sufficient to sustain

increased levels of production.

Mexican oil production has increased rapidly

from 0.5 MMbbl/d in 1973 to over 1.4 MMbbl/d

in 1978, and gas production reached 0.9 Tcf in

1978. PEMEX development plans call for oil production of 2.25 MMbbl/d and gas production of

1.5 Tcf/yr by the early 1980’s. While official

plans do not extend beyond the early 1980’s,

available forecasts suggest that, on the basis of

resources alone, Mexico could continue to increase oil production after that time, but unofficial reports suggest that oil production will be

limited to less than 3.8 MMbbl/d.

In a 1978 study,3 the Congressional Research

Service (CRS) developed two cases for potential

Mexican oil and gas production. Case I assumed

that gas would not be exported and oil production would be constrained by the inability to

utilize associated gas. Case II assumed that oil

production would not be constrained, and gas

would be available for export. In a later study,4

Lewin and Associates developed three scenarios

of Mexico’s oil and gas potential. Their base case

assumed development of already discovered

fields, and alternative cases included assumptions regarding future exploratory success. CRS

Case I projects somewhat lower levels of oil production than does the Lewin base case assess3Congressional Research Service, Mexico's Oil and Gas Policy: An

Analysis (Senate Foreign Relations Committee and Joint Economic

Committee, December 1978).

4

Lewin and Associates, The Potential of Mexican Oil and Gas, May

1979.
Ch. 3—Future Gas Availability and Use ● 43

ment, reflecting in part a lower resource estimate. However, both studies note that even

their lowest cases are likely to strain Mexico’s

technical and managerial capabilities, and in the

light of expected 1979 production estimates of

1.5 MMbbl/d official targets may be missed. Interviews with industry sources also suggest that

Mexican oil production is more likely to resemble CRS Case I, with the Lewin base case an upside possibility.

With regard to gas production potential,

Lewin’s figures are lower, particularly after

1985, reflecting lower associated gas-oil ratios

than those used in the CRS study. The high gasoil ratios of 1,200 to 2,000 cf/bbl prevailing in

the Reforma field are not obtained in the fields

of Campeche or Chicontepec as CRS assumes, so

the Lewin assessment represents a more reasonable range of potential Mexican gas production than the CRS study. However, given the

greater likelihood of lower oil production figures than those assumed by Lewin even the

base case may prove to be high.

Adding to the uncertainty of export projections are trends in Mexico’s domestic energy

consumption, in terms of both aggregate level

and fuel types, and domestic energy policy still

is undefined. For example, the greater use of

gas domestically would leave less available for

export but might free additional oil for foreign

purchasers. Also, oil production may be limited

by the ability to export or to utilize associated

gas internally.

Based on the preceding analysis of production

potential, CRS oil estimates and Lewin gas estimates are assumed to be the most reasonable to

derive the potential export 1evels shown in table

16.

The Lewin gas production figures are somewhat overstated, and gas exports to the United

States would probably be less than those indicated in the table. Mexico could readily convert

enough industries to use gas to absorb 1.5 Tcf

annually, thereby precluding gas exports at

least in the near term. Presumably, gas could

also be exported as LNG, but the return would

be quite low, on the order of $0.27/Mcf. Mexico

also has some discretion in gas production. The

estimates presented above include 0.4 Tcf of

production from the Northern, nonassociated

gasfields, which could be shut in without constraining oil production. In addition, Mexico

might elect to develop oilfields with less or more

associated gas depending on domestic needs

and export opportunities.

On the other hand, Mexico does have somewhat less than 1 Tcf of gas for export to the

United States within a short period of time if the

conditions are advantageous. In 1977, six U.S.

interstate natural gas companies signed a letter

of intent for the purchase of Mexican gas, and a

pipeline was to be constructed linking Mexican

gasfields with the U.S. gas transmission system

in Texas. The entire line from the southern

fields to the north was to cost $1 billion and

Table 16.—Mexican Oil and Gas Export Potential

Oil Gas

Domestic Domestic

Year Production demand Exports Production demand Exports —

(M Mbbl/d) (Tcf)

1 2 1 2

1980 . . . . . . 2.2 2.2 1.1 1.1 1.5 1.5 .7 .8

1981 . . . . . . 2.3 1.1 1.2 1.2 1.1 1.5 .7 .8

1982 . . . . . . 2.4 1.1 1.3 1.3 1.1 1.5 .8 .7

1983 . . . . . . 2.5 1.2 1.4 1.3 1.2 1.6 .8 .8

1984 . . . . . . 2.6 1.2 1.5 1.4 1.1 1.6 .8 .8

1985 . . . . . . 2.7 1.2 1.5 1.5 1.2 1.6-1.8 .9 .7-.9

1986 . . . . . . 2.8 1.2 1.5 1,6 1.3 1.6-1.9 .9 .7-.9

1987 . . . . . . 2.9 1.3 1.6 1.6 1.3 1.7-2.0 1.0 .7-1.0

1988 . . . . . . 3.0 1.4 1.8 1.6 1.2 1.7-2.2 1.0 .7-1.2

1 = no gas exports.

2 = with gas exports

SOURCES Congressional Research Service; Lewln and Associates
44 . The Future of Liquefied Natural Gas Imports

would have eventually carried 0.7 Tcf/yr to the

United States.

The gas deal met domestic opposition in Mexico from the political left and campesinos, who

resented the land confiscations required to

build the pipeline. Moreover, a public debate

surrounded the proper rate of exploitation of

Mexican hydrocarbon reserves, particularly if

the United States was to be the main beneficiary

of rapid development.

To secure domestic agreement on gas exports

the Mexicans drove a hard bargain, demanding

a take-or-pay contract, gas prices tied to distillate fuels delivered in New York harbor ($2.60/

Gas from overseas

Natural gas constitutes 42 percent of the

known proven world supply of gaseous and liquid hydrocarbons. While natural gas resources

are widely scattered around the globe, the largest proven reserves are in North America and

the Persian/Arabian Gulf. The amount of gas

that can be dedicated to LNG projects is far less

than the total reserves. Most gas, such as that

found in Europe, is dedicated to local markets,

and other resources are too remote or too small

to support a world-scale LNG project. Additional

exportable supplies, such as those in Canada

and Mexico, are likely to move to consuming

Mcf at the time and $3.00/Mcf in May 1979), and

the option to lower or halt exports as required

by domestic needs. The U.S. Economic Regulatory Administration failed to approve the

terms, and the Mexican Government allowed

the agreement to lapse.

Intergovernmental negotiations were renewed in 1979 resulting in a limited agreement

involving about 0.1 Tcf/yr at $3,625 /Mcf. It now

seems that Mexico will make every effort to utilize the gas domestically, and barring a change

in political relations, Mexico may be satisfied to

free up additional oil for export.

markets by pipeline rather than as LNG. Table

17 summarizes, by geographic area, the important LNG export countries and the amount of

LNG that might come to the United States from

operating, approved, and possible projects.

Algeria is currently the only supplier of LNG

to the United States, but as her remaining gas

reserves have now been committed to European

buyers, additional Algeria-U.S. projects are not

likely in the near future. Moreover, the prospect of a higher netback price to the Algerian

natural gas wellhead because of the expected

Table 17.—Availability of Foreign LNG to the United States Beginning in the 1980’s

(trillion cubic feet per year)

Operating and Exportable surplus Possible

approved projects as of 12/31/78 projects

Algeria. . . . . . . . . . . . . . . 0.63 8 —

Nigeria. . . . . . . . . . . . . . . — 33 0-0.59

Southeast Asia. . . . . . . . 0.2 41 0.15

Western Hemisphere. . . — 19 0.39

Persian/Arabian Gulf . . . — 231 plus —

U.S.S.R. . . . . . . . . . . . . . . – 439 —

Existing reserves are committed to

Europe.

Europe a strong competitor. Possible

political problems.

Japan a strong competitor.

Scattered small potential projects. Four

are anticipated including the Arctic

Island project from Canada.

Locational disadvantage relative to

Europe and Japan. No projects to

United States likely before 1990.

No shipments to United States like/y

before 1990.

Total. . . . . . . . . . . . . . . 0.83 0.54-1.13

SOURCE: Jensen Associates, Inc
Ch. 3—Future Gas Availability and Use ● 45

success of the trans-Mediterranean pipeline,

combined with the heavy capital costs of LNG

and the apparent concern in Algeria with the allocation of large amounts of capital to hydrocarbon development, raise strong doubts about

additional LNG trade with the United States before 1990, However, as is the case of Russian

gas, if the U.S. Government were to seek Algerian LNG aggressively and provide substantial

financing, additional Algerian LNG is a possibility, most likely from new gas discoveries. Russian LNG trade is possible before 1990 but will

also require financing and the encouragement

of the U.S. Government. Otherwise, imports of

Russian LNG before 1990 seem unlikely.

Gas from additional LNG projects in Southeast

Asia is expected to flow mostly to Japan, but

Australia may sell perhaps 0,15 Tcf/yr to the

United States. Nigeria will probably develop one

or two large LNG projects, and the resulting

supplies are likely to flow either to Europe or to

the United States, or both. Anticipated projects

in the Western Hemisphere, principally in Trinidad, Colombia, and Chile could bring LNG to the

United States, and a Canadian Arctic Island LNG

project may be developed. Projects likely to be

approved in the next 5 to 7 years could bring an

additional 0.54 to 1.13 Tcf/yr to the United

States. The higher figure is less probable because Europe will be a strong competitor for Nigerian LNG. It is also possible that Japan will

take all of the LNG that Australia has thus far

approved for export.

Worldwide natural gas reserves

and exportable surpluses

Estimated proved reserves of natural gas as of

the end of 1978 amounted to 2)5575 Tcf, constituting 42 percent of the energy content of the

world’s combined proved reserves of oil and

gas. Since the oil embargo of 1973, worldwide

additions to proved gas reserves reported by

the Oil and Gas Journal have amounted to 55

percent of combined oil and gas additions.

Growth in gas reserves should continue, since

the lack of a market outlet in many cases has

relegated gas discoveries to the noncommercial

5

‘oil and Gas Journal, American Gas Association, Canadian Gas

Association, PEMEX.

category, and the amount of gas that has been

found or indicated probably substantially exceeds the proved reserve figure.

Despite the magnitude of worldwide reserves,

the role of gas in international trade is quite

small, and worldwide consumption is less than

30 percent of the total of oil and gas combined.

In 1978, international oil trade, primarily in

tankers, was at a level of 33.8 MMbbl/d while

gas trade was only 2.9 MMbbl/d of oil equivalent, of which only about 470,000 bbl/d moved

in LNG tankers instead of pipelines. Thus, despite the major worldwide gas reserve base and

optimism about gas discoveries, LNG tanker

trade represents only 1.4 percent of oil trade.

The reasons for this disparity involve the high

cost of gathering and transporting natural gas

compared with oil. Oil valuation almost anywhere in the world can be related through quality differentials and transportation costs to the

price of the marker crude, Arab Light f.o.b. Ra’s

at Tannurah. Gas generally competes with other

fuels, predominantly oil, so in determining

whether natural gas will be sold in any given

location, one estimates the equivalent oil value

and determines whether it covers distribution,

transportation, gathering, and production of natural gas. If the answer is no, as is often the

case, the gas will not be marketed. For example,

the U.S. Bureau of Mines estimates that in 1976

over 12 percent of world natural gas production

was disposed of by flaring.

Determining the outlook for world LNG trade

requires looking beyond the gross numbers

representing reserves or production to identify those special combinations of large uncommitted gas reservoirs, geographic location, and

political stability that will form a basis for a

viable project. Viewed in this light, less than

one-third of total world gas reserves (less than

one-quarter of free-world reserves) appear favorably situated for international trade.

Gas reserves may be either associated/dissolved or not associated with oil. Production of

nonassociated gas is discretionary in the sense

that the discovery can be shut-in and not developed until the economic climate is appropriate.

Associated/dissolved gas is produced along with
46 . The Future of Liquefied Natural Gas Imports

oil. Unless it can be sold or reinfected for EOR or

for later withdrawal, it has to be flared. Some

associated gas is contained in large gas caps in

oilfields where its premature extraction will deplete reservoir pressures and reduce ultimate

recovery of the oil. While one usually cannot

delay production of dissolved gas, one often

cannot practically accelerate the production

from associated gas caps. An estimated 28 percent of world gas reserves are associated/dissolved while the remainder are nonassociated.

While the flaring of dissolved gas often focuses attention on the potential availability of

“free” gas as a basis for international trade, the

costs of gathering and compressing it, together

with difficulties of controlling its rate of production, often make it less desirable as a basis for

export projects than large, high-pressure, nonassociated gasfields. With the exception of projects in Libya and Abu Dhabi, all LNG projects to

date have been based on nonassociated rather

than associated gas.

A gasfield’s location relative to markets is important, as mentioned earlier, because of the

high cost of transportation. Figure 6 shows estimates of world proved gas reserves as of December 1978, subdivided both geographically

and by political grouping, including proportions

of associated and nonassociated gas. Political

categories include the developed world as the

Organization for Economic Cooperation and Development (OECD), the Sine-Soviet countries,

and the less developed nations subdivided into

OPEC and NOPEC (or non-OPEC) groups. In this

table, the U.S.S.R. appears in Europe, despite

the fact that large portions of its substantial gas

reserves are physically located in Asia. Note that

the role of OPEC is much less dominant in gas

than in oil. Whereas OPEC constitutes 77 percent of total world proved oil reserves and 90

percent of free-world oil reserves, it represents

only 38 percent of world gas reserves and 60

percent of free-world gas reserves.

Estimates of gas reserves are much less reliable than those for oil. Where gas has no commercial value, either because it will be flared or

because the size of the deposit does not justify

marketing it, discoveries have often not been included in the figures. The amount of gas that remains to be discovered from future exploration

is also very large. Some recent estimates place

the undiscovered gas resource base in the vicinity of 6,500 Tcf of natural gas or roughly 2.5

times present proved reserves.6

The development of a new outlet for gas reserves, such as a pipeline or LNG project may

generate specific field development or even exploration. Proved reserves can therefore increase rapidly to provide a basis for an export

project where present estimates do not suggest

such a potential. The figures reported for Trinidad, for example, are significantly lower than

those which would be required to justify a

world-scale export project of 500 MMcf/d or

more. However, there is considerable optimism

in Trinidad that additional exploration and development will generate more than enough reserves to support such a project.

Without local markets, recovery of dissolved

gas is difficult to justify, and flaring is likely to

continue. Similarly, many small nonassociated

fields are too remote to warrant the gathering

and transmission expense of moving the gas to

market. Thus, a significant portion of reserves

might be considered as noncommercial because

they are either inaccessible or likely to be

flared.

In order to determine the extent to which gas

reserves are potentially available to support

LNG trade in the future, they have been analyzed country-by-country to determine those

potential blocks of reserves that are not presently committed and are large enough to support LNG and pipeline export projects. * The basis of this analysis is the proved reserves figures

just mentioned, subdivided into six different

categories of commercial status as follows:

1.

2.

/accessible or flared: gas reserves that are

too small or remote either to justify recovery of flared gas or full field development

of nonassociated gas.

Deferred reserves: reserves in large gas

caps or undergoing gas injection for oil recovery that are unlikely to be committed to

markets until future time.

6

‘For example, see Energy Topics, Dec. 5, 1977.

*For further discussion, see the Background Reports volume of

this report.
Ch. 3—Future Gas Availability and Use ● 47

1,000

900

800

700

z

a 600

.—u

a

3

u 500

c

.-0

= 400

.-

;

300

200

100

0

Figure 6.—World Natural Gas Reserves (trillion cubic feet)

❑ u

n Nonassociated

- Associated dissolved

n.<

~~~~

OECD SINO NOPEC OPEC

SOVIET

SOURCE Jensen Associates, Inc , based on Oil and Gas Journal, American Gas Association, Canadian Petroleum Associatlon, and PEMEX Reserve Estimates

3. Committed to domestic markets: gas reserves that either are contracted to domestic markets or set aside to assure that domestic requirements will be met. Without

detailed information about many such setasides, a modified Canadian formula,

which provides for 30-year coverage of

present domestic consumption has been

applied.

4. Remote from existing market systems: gas

reserves that are clearly destined for a major industrial market, but whose remoteness from this market raises questions

about the feasibility of commercialization.

Examples would include North Slope and

Arctic Island gas in North America and

some North Sea gas reserves in Europe.

Some of this gas will prove feasible for

commercialization and thus may later belong to the “committed to market” or “exportable surplus” classifications.

5. Committed to export markets: gas reserves

usually in firm export contracts covering

the deliveries over the life of the contract.

6. Exportable surplus: blocks of gas reserves

that are large enough and well-located

enough to support export projects, In a limited number of cases, current national policy suggests that this gas will not be exported and, in other cases, discussions to

commit the gas have proceeded to t he

point where it is no longer available.

Figures 7 through 10 show these market status estimates in somewhat greater detail for the
48 ● The Future of Liquefied Natural Gas Imports

Figure 7.— Market Status OECD Gas Reserves

220 

I

-

C

200

180

160

140

120

100

80

60

40

20

0

Committed to

market

Committed to

export

Deferred

reserves

United Canada Norway

States U.K.

SOURCE: Jensen Associates, Inc.

OECD, NOPEC, OPEC (excluding Iran and Algeria), and for the large gas export areas of the

U. S. S. R., Algeria, and Iran. (It is important to

note that the scale on each bar chart varies with

the relative magnitudes of reserves typical of

the group, ) An estimated 812 Tcf of world reserves are in the exportable surplus category,

representing about 32 percent of the world

total. Three-quarters of the exportable surplus

is concentrated in the Soviet Union and Iran.

The failure of Iran to be able to deliver associated gas to the Soviet Union through the IGAT

system during the Iranian revolution and the resulting inability of the Soviet Union to honor

some of its export commitments to Europe have

focused attention on supply security from these

two countries. With Iranian and Russian reserves out of the exportable surplus category,

only 7.2 percent of the world proved gas reserves remain. Figure 11 shows where the major exportable volumes are concentrated. About

32 Tcf of reserves worldwide are likely to be exRemote from

market systems

n

Exportable

surplus

1

El Inaccessible

or flared

Netherlands Other Japan

Europe Australia

New Zealand

ported by pipeline, including the 2 Tcf which

NEB in Canada has deemed surplus to Canadian

requirements, as well as the 25 Tcf of Mexican

gas reserves (consistent with the January 2,

1979, PEMEX gas reserve estimate of 65.1 Tcf

proved) which is in excess of Mexican domestic

commitments. The U. S. S. R., Iran, and Algeria

have all operated or considered both pipeline

and LNG export schemes.

U.S.S.R.

Out of the total exportable surplus of 812 Tcf,

635 is located in the U. S. S. R., Iran, and Algeria.

The Soviet Union has 35 percent of the world’s

gas reserves. Although the Soviet reserve estimates are somewhat less conservatively stated

than those in much of the rest of the world, including not only proved and probable but some

possible resources, they are, nonetheless, impressive in magnitude. Earlier, Russian oil and

gas exploration was concentrated in the south

near the Black Sea and Caspian Sea. The major
Ch, 3—Future Gas Availability and Use ● 49

Figure 8.— Market Status NOPEC Gas Reserves

I

60

50

40

30

20

10

0

I

Committed to ❑Remote from

market market systems

Committed to

1

Exportable

export surplus

Deferred

• 1

Inaccessible

reserves or flared

1

I

H

.

L1kliilIl

Eli

Mexico Other Africa Middle Brunei Other

Latin

America

SOURCE Jensen Associates, Inc

gas discoveries of more recent vintage are located in west Siberia, particularly in the giant

fields of the Ob Peninsula, such as Urengoy,

Yamburg, and Zapolyarnoe. Approximately 75

percent of Russian reserves are concentrated in

West Siberia. Areas to the south and west, such

as Turkemenistan, Uzbekistan, and the VolgaUrals region, constitute another 20 percent, The

rest of the gas is scattered throughout the country in several producing basins.

The Soviet Union currently imports small

quantities of gas by pipeline from Afghanistan.

It also has been supplementing its more limited

southern reserves by importing about 1 billion

C/d from Iran through the IGAT- 1 pipeline system, while at the same time delivering 1.45 billion cf/d to West Germany, Italy, and Austria

from its northern reserves. While not a formal

East Malaysia Asia

Pacific

exchange agreement as IGAT-2 was intended to

be, the arrangement has similar effects. Iranian

shipments under the IGAT-1 contract ceased

during the winter of 1978-79 and have still not

returned to contractual levels as of July 1979.

Also, the Iranian Government has publicly announced the cancellation of all planning on

IGAT-2, which would have delivered an additional 1.65 billion cf/d ultimately to Europe via

the Russian exchange route. Since Russian deliveries to Europe were reduced to compensate for

the loss of Iranian gas, the question of the future level of European reliance on the very

large Soviet gas reserves as well as the reliability

of Iran is being reevaluated. While most immediate plans for utilization of Russian gas contemplate pipeline expansions, LNG projects have

been discussed both for the U.S. east coast from

west Siberia reserves and to the U.S. west coast
50 . The Future of Liquefied Natural Gas /reports

130

120

110

100

90

80

70

60

50

Figure 9. —Market Status OPEC Gas Reserves

I

Committed to

market

Committed to

export

Deferred Exportable

reserves ., surplus

Remote from

n

Inaccessible

market systems or flared 1

40

r

30

20

10

0

Venezuela Libya

Ecuador Nigeria

Gabon

Kuwait

Iraq

SOURCE: Jensen Associates, Inc.

and Japan from the Yakutsk area of eastern Siberia. ‘None of these projects appear particularly active at present.

IRAN

Iranian gas reserves are second only to those

of the Soviet Union. Approximately 210 Tcf of

the 500 Tcf of Iranian gas reserves are associated/dissolved, and a large portion of these are

concentrated in the very large gas caps of some

of the Khuzestan oilfields. About half of the Iranian gas reserve is contained in very large nonassociated gasfields, both onshore near Kangan

and extending out into the central Persian Gulf.

Smaller quantities are located near the Straits of

Hormuz, around Bandar Abbas, and scattered

throughout the country.

t

n

Saudi Qatar Indonesia

Arabia UAE

Oil recovery in the Khuzestan fields is particularly sensitive to bottom-hole pressure decline.

Before the overthrow of the Shah’s government,

the National Iranian Oil Company was experimenting with a major gas injection program

which, if successful, was to be extended to virtually all of the Khuzestan fields. The program,

designed to increase oil production, would not

only have postponed production from the gas

caps but would have reinfected significant quantities of dissolved and nearby nonassociated gas

into the oil formations for later recovery. Injecting gas in this way would have deferred production of almost half of the Iranian reserves, so

Iran represents the largest single volume in the

deferred reserve category worldwide. Iran had

also planned to export gas to Europe via the
—

Ch. 3—Future Gas Availability and Use ● 51

1,000

900

800

700

Iii

J? 60 0

0

E

: 500

c

.-o——

E 400

300

200

100

0

Figure 10.—Market Status: U. S. S. R., Iran, and Algeria

‘1 I

Committed to Remote from

market market systems

U.S.S.R. Iran Algeria

planned IGAT-2 pipeline and had discussed a

large LNG project from the Kangan area to Japan and the United States. The reserves that

would have been dedicated to IGAT-2 and the

Kangan LNG project would probably have

amounted to almost 21 Tcf.

However, the uncertainties surrounding future Iranian gas policy call into question

whether any of these projects will come to fruition in the foreseeable future. Both IGAT-2 and

the Kangan project are now canceled, and contract commitments under IGAT-1 may not be

honored. The future of the major gas injection

scheme also is in doubt. Thus, in spite of an estimated 188 Tcf of exportable surplus for Iran,

new projects are not likely to be initiated soon.

Had Iran gone ahead with its earlier plans,

manv of the large gasfields, which are most eco-

.

nomically situated to support export, would

SOURCE Jensen Associates, Inc.

have been committed to the gas injection program instead. The remaining exportable” reserves, including the very large “E,” ‘I F,” and “G”

structures, which are quite far out in the Gulf,

together with some of the “C” structure (or Pars

gas reserves) both onshore and offshore near

Kangan, would have been more expensive to

commercialize than some of the onshore gas.

However, they might lend themselves well to

barge-mounted LNG facilities in the future if

Iran is prepared to discuss exports again.

ALGERIA

Algeria was the first country to export I.NG on

a commercial scale and has the most extensively

developed programs for LNG export. Figures 6

and 10 are based on Algerian proved reserves of

105 Tcf. Approximate}’ another 25 Tcf are

classed by the Algerians in the “possible” category, and the 25-year master Algerian gas devel-
52 ● The future of Liquefied Natural Gas Imports

Figure 11 .—Major Uncommitted Gas Reserves Exportable to World Markets

(trillion cubic feet)

w

OTHER SOURCES

SOURCE: Jensen Associates, Inc.

opment program is designed to handle all of the

proved plus a portion of the possible resources. A remaining 116 Tcf of reserves are located

The program is designed to be scaled down if

possible reserves fail to materialize. Firm commitments for 11 LNG projects and the pipeline

across the Mediterranean to Italy account for

nearly 60 Tcf. Local markets are expected to

take about another 30 Tcf, and a certain amount

of oil well gas flaring would leave an estimated 8

Tcf in the exportable category. Most of this surplus has already been virtually committed. This

volume includes the provisions for the Algeria 11

and Tenneco St. John’s projects, and when these

projects were disapproved by the U.S. Government, a scramble in Europe developed to take

over these contract commitments. The Italian

pipeline and negotiations with several potential

European LNG purchasers now appear to have

accounted for all of the available volumes, and

Algeria is essentially sold out, barring further

discoveries in the future. The 8 Tcf of exportable surplus shown in figure 10, though not yet

firmly contracted for and approved, is spoken

for.

in countries that could be considering worldscale LNG export schemes, projects of a thousand-cubic-feet-per-day export capacity or

greater. The map in figure 11 indicates where

some of these projects might be located. Qatar

has discovered Permian Khuff gas in the Northwest Dome offshore, reported at 34 Tcf. Although it is too early to estimate reserves with

a ny

- accuracy, the field could range up to 100

Tcf when fully developed. Clearly, this large

block of reserves could serve a major LNG

trade, although its location well out in the Gulf

may make it expensive. The Permian Khuff formation is deeper than the typically oil-productive zones on the Arabian Peninsula. The number of Permian Khuff tests to date has been limited, but geologists have expressed optimism

that the formation could provide Saudi Arabia,

Kuwait, and the Emirates with large future reserves of nonassociated gas.

Nigeria has been anxious to develop gas markets for its associated gas to reduce the level of
Ch. 3—Future Gas Availability and Use ● 53

—

flaring. A number of earlier proposed LNG projects have been consolidated into one large export scheme with Phillips as the operator, and

discussions are being held with a number of

U. S. and European companies about possible

markets for the gas. The project, if it materializes, could require approximately 14 Tcf to support the large volume of planned exports. Nigeria also has large reserves of nonassociated

gas, which could support further LNG exports,

if an initial project with associated gas were successful.

Australia has discovered large volumes of

nonassociated gas in the Northwest Shelf region, remote from limited Australian markets,

and promoters have attempted to organize projects for both Japan and the U.S. west coast from

an exportable surplus on the order of 17 Tcf.

Smaller projects have been considered from Malaysia (Sarawak), which would move the gas to

adjacent Brunei for export, and from Bangladesh, which could have about 7 Tcf of exportable gas available.

Indonesia has an estimated 7 Tcf remaining of

exportable surplus. Indonesian market commitments include both Badak I and the Japanese

portion of the Arun project. Badak 11 still requires additional reserve development. The Pac

Indonesia portion of the Arun project is included with Badak II in the 7 Tcf of exportable

surplus.

Abu Dhabi has discussed a second project for

Japan based on the estimated 5 Tcf of onshore

gas reserves of Bu Hasa and the Bab Dome (the

old Abu Dhabi Petroleum Co. producing area).

Also, Bahrain could support a small project with

4.4 Tcf of excess exportable reserves in a deep

gas reservoir.

In a number of other areas, the size of the individual discoveries together with commitments

to protect local markets, prevent the assembly

of enough reserves to support a 500 MMcf/d export project worldwide, approximately 28 Tcf

may be concentrated in these small blocks.

Trinidad, which currently falls into this category, has been anxious to utilize gas for local industrial development in fertilizer plants and a

steel mill, and to protect its local market with a

40-year reserve coverage. Developing enough

gas reserves to support LNG exports has therefore been difficult. Nonetheless, the Government has expressed great optimism that further

exploration and development will provide reserves sufficient to support a project of between

600 and 750 MMcf/d.

Although possible U.S. imports from Colombia, Chile, Ecuador, and Venezuela have been

mentioned in the past, none of these countries

have exportable surplus great enough to support a major project now. Venezuela has retreated from extensive earlier plans for LNG export and now plans to keep all of its gas at

home, although the country could export at a

level of about 350 MMcf/d. Chilean reserves are

small and remotely located in Tierra Del Fuego,

at the southern end of South America. Argentinian exploration in the San Sabastian area, also in

Tierra Del Fuego, is discovering nonassociated

gas in excess of Argentinean requirements, and

the possibility of some type of joint venture appears at least technically possible.

Tunisia has discovered offshore Mediterranean gas, which it may provide for LNG export

in the future, and exploration offshore in Thailand has resulted in some gas which could conceivably form the basis for a future project to

Japan. Libya has gas in excess of current market

requirements, which might not justify an expansion of present LNG facilities but might enable

Libya to negotiate the extension of contracts

with Italy and Spain in the future.

Thus, despite the extent of world gas reserves, the number of countries that could export LNG to the United States is quite limited.

Algeria appears to be sold out and is not prepared to make further commitments to the

United States in the immediate future. The next

most likely alternative sources would appear to

be Nigeria and Trinidad. Gas from the Middle

East will probably be expensive. Much of the

gas in South America is in such small blocks that

world-scale projects are not likelv without some

form of integration.

.

Competitive importers of LNG—

Europe and Japan

International trade in LNG began abroad,

from North Africa to Western Europe, in the

59-406 0 - 80 - 5
54 ● The Future of liquefied Natural Gas Imports

mid-1960’s. Japan, too, was importing its first

cargos (of American LNG from Alaska) by 1969,

about 2 years before deliveries under the first

U.S. import contract (by Distrigas in Boston

from Algeria) commenced. In 1980, the United

States will be importing nearly as much LNG as

Europe (approximately 0.5 Tcf/yr) but much less

than Japan (0.79 Tcf annually), in spite of the

fact that the total American gas market is nearly

3 times as large as Europe’s and 30 times as

large as Japan’s.

Historically, demand for gas imports into

Western Europe has developed as a complement to the successive discoveries of large-scale

gas reserves there (notably in the Netherlands

and the North Sea), and the decline of traditional coal-gas making. In 1977, local output was

over 6 Tcf, covering about 90 percent of consumption. But since production from most of

the known reserves is now peaking or leveling

off, European utilities are actively seeking further imports, both as LNG from Algeria and by

pipeline from the U.S.S.R.

Japan has been unable to discover significant

reserves of natural gas (or of any other fuel), so

it is planning much greater imports of LNG during the 1980’s and 1990’s, particularly as its

nuclear prospects have been revised downwards. Its main imports so far are from Southeast Asia (Brunei, Indonesia, and in the future,

from Malaysia), and it will compete strongly for

LNG from Australia and possibly New Zealand.

Japan has also begun the only LNG import

scheme yet developed from the Middle East (of

associated gas in Abu Dhabi). All of the several

projects put forward in recent years for LNG exports to Japan from Iran’s huge nonassociated

gas reserves now appear to have been canceled

(along with the European contracts for substantial “indirect imports” of Iranian gas through

trades with the U.S.S.R.). Notwithstanding this

setback for Middle East gas exports, soaring oil

prices may now be approaching the levels at

which exports as LNG of associated gas produced with Gulf crude will begin to become

commercially viable.

If so, Japan and Europe would again have a

transport advantage over the United States, as

they each have from Southeast Asia and Africa

respectively. In addition, they experience fewer

administrative delays in governmental approval

of gas import projects. Initially, both regions

paid delivered prices for LNG related to local

market values for fuel oil. But in Europe, where

low-sulfur content had little value, prices were

significantly lower than in Japan, where LNG

commanded high premiums along with low-sulfur crudes and fuel oils, U.S. premiums for lowsulfur, and hence landed values for LNG, came

in-between those in Europe and Japan. So even

allowing for higher transport costs, the netback

value to Algeria from landed prices under U.S.

contracts could be higher than Europe was paying. Since the mid-1970’s, however, European

buyers appear to have paid Algeria prices representing comparable netback values to those

from American contracts.

European and Japanese markets for gas will

never compare with the sheer volume of the

U..S. market. But for LNG from Africa, Southeast

Asia, and the Pacific, and potentially from the

Gulf, both regions may offer strong competition

to U.S. importers.

WESTERN EUROPE

Natural gas imports into Western Europe

have been forecast to rise from their recent

annual level of 0.83 Tcf (1977) to around 4 to 5

Tcf by 1990 (see table 18). How much of that gas

will be brought in as LNG will depend on the

amounts available by pipeline, which are at the

moment liable to particular uncertainties (table

19).

In 1977, Western Europe imported about 0.5

Tcf of natural gas annually from the U.S.S.R.

That amount represented about one-half of total

Soviet gas exports, which account for about 9

percent of total Soviet production. The rest of

Russian gas exports go to Eastern Europe, As

mentioned earlier, the U.S.S.R. has been importing about 0.3 Tcf annually (1977) of Iranian gas

through the IGAT-1 pipeline to the Caspian Sea

region.

Implementation of plans to formalize and expand this indirect export of Iranian gas to Europe now seems unlikely. In 1975, a trilateral

deal for a second, parallel IGAT-2 pipeline
Ch. 3—Future Gas Availability and Use ● 55

Table 18.—Natural Gas Supply/Demand Projections for 1985 and 1990, European Economic Community

(trillion cubic feet)

1985 1990

Imports from Imports from

Production outside Europe Consumption Production outside Europe Consumption

EEC . . . . . . . . . . . . 6.12 2.84

.

9.75 5.25 3.45 10.41

Belgium. . . . . . . . . — .23 .50 — .24 .55

France. . . . . . . . . . .22 .77 1.40 .14 1.20 1.66

Germany. . . . . . . . .61 .89 2.61 .53 .87 2.66

Italy . . . . . . . . . . . . .55 .72 1.47 .42 .97 1.67

Netherlands . . . . . 2.89 .15 1.47 2.16 .16 1.45

United Kingdom. . 1.70 — a 2.12 1.80 — a 2.23

NOTE These import figures exclude imports from Norway, which IS within OECD Europe but outside EEC Community governments in fact expect to import some

1 15 tcf from Norway in 1985, and perhaps about 1.40 tcf by 1990 (though that would imply higher gas exports than Norway IS yet counting on to make by then)

Also, for particular EEC countries, the import figures also exclude intra- EEC trade in natural gas, essentially Dutch exports to Belgium, France, Germany, and

Italy aUnited Kingdom projections do not include Imports from Algerla under its orlglnal LNG contract, which may be renewed

SOURCE. Jensen Associates, Inc , from EEC member governments estimates, 1978 (made before Iran announced to cancel IGAT-2 plpellne exports)

Table 19.—LNG and Pipeline Gas Import Projects to OECD Europe

(trillion cubic feet per year)

Operational

Algeria-United Kingdom . . . . . .

Algeria-France. . . . . . . . . . . . . .

U.S.S.R.-Austria. . . . . . . . . . . . .

Libya-Italy. . . . . . . . . . . . . . . . . .

Libya-Spain . . . . . . . . . . . . . . . .

Algeria-France. . . . . . . . . . . . . .

Algeria-Spain . . . . . . . . . . . . . . .

U.S.S.R.-Germany . . . . . . . . . . .

U.S.S.R.-Italy . . . . . . . . . . . . . . .

U.S.S.R.-Finland . . . . . . . . . . . .

U.S.S.R.-France . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . .

Possible before 7985

Algeria-France. . . . . . . . . . . . . .

Algeria-Italy . . . . . . . . . . . . . . . .

Algeria-Belgium. . . . . . . . . . . . .

Algeria-Germany . . . . . . . . . . . .

Algeria-Netherlands . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . .

Possible before 1990

Algeria-Germany . . . . . . . . . . . .

Algeria-France. . . . . . . . . . . . . .

Algeria-Spain/France . . . . . . . .

Iran/U.S.S.R.-Germany . . . . . . .

Iran/U.S.S.R.-Germany . . . . . . .

Iran/U.S.S.R.-Austria. . . . . . . . .

U.S.S.R.-France . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . .

Nigeria-Europe. ., ... , . . . . . . .

Startup

1964

1965

1968/80

1969

1971

1972

1974

1974/78

1974/78

1974

1976/80

Contracted delivery

Form of import volumes - Notes

LNG

LNG

Pipeline

LNG

LNG

LNG

LNG

Pipeline

Pipeline

Pipeline

Pipeline

.04

.02

.09

.11

.04

.14

.18

.36

.27

.11

.15

1980 LNG

1981 Pipeline

1982 LNG

1984 LNG

1984 LNG

1985 LNG

1985 LNG

? Pipeline

‘? Pipeline

? Pipeline

7 Pipeline

? LNG

1.51

.20

.45

.20

.41

.15

1.41

.15

.18

.54

.20

.13

.07

.18

1.45

up to .59

Due to end 1979: renewable?

Starting up to 1980

(.53 LNG) (.98 pipeline)

(.96 LNG)

May be alternatives

Exchanges via U.S.S.R.

Iran plans to cancel, 1979

Linked with U. S. S. R.-U.S.A.

? LNG Or to U S. A.?

—

NOTE Projects are also being discussed for Algerian LNG to Sweden, Switzerland, and Yugoslavia

SOURCE Jensen Associates Inc.
56 . The Future of Liquefied Natural Gas Imports

would have raised the system capacity to 1.0

Tcf/yr, and would have enabled Russia to export

another 0.4 Tcf/yr to Germany, Austria, and

France, beginning in the early 1980’s. However,

the new authorities in Tehran have announced

that the contract for deliveries through IGAT-1,

halted for a time during the Iranian revolution

and since reported to be running below the volumes planned for this period, might not be renewed when it expires in 1985. They also said

they would cancel the IGAT-2 line, jeopardizing

the exchange supplies onward to Western Europe. The German and French gas utilities involved hope that the original contracts with

Iran will finally be honored, perhaps with inevitable delays to the earlier timetable. As an alternative, they might hope to secure extra deliveries from Russia, eventually to restore the whole

planned volume, without the Iranian backup.

(The Economic Commission for Europe currently reckons that natural gas availability for net

export from the U.S.S.R. might reach 1.8 Tcf/yr

by 1990.) Russian reserves are ample, but the

development of additional reserves, pipeline capacity, and infrastructure would probably

strain Soviet engineering resources, even

though the investment might be financed from

Western Europe.

The uncertainty about further pipeline supplies from the East may increase Europe’s demand for LNG supplies from Africa, notably

from Nigeria. European utilities have also recently contracted for much of the gas remaining

available for export from Algerian reserves so

far developed, about 1.4 Tcf/yr by 1985 in

added projects over and above the 0.45 Tcf/yr

due for Europe by then under earlier contracts.

However, 0.44 Tcf/yr of these extra imports are

now planned to move from Algeria by pipeline

across the Mediterranean to Italy and north into

the European gas grid. Another pipeline across

the Mediterranean might move up to 0.5 Tcf/yr

of Algerian gas to Spain and perhaps from there

to France. Recently, however, new gas discoveries onshore in northern Spain and offshore in

the south could be sizable in relation to the

country’s consumption. The resulting addition

to Spanish energy may increase the uncertainty

of this second European pipeline import project.

If the pipeline links to Italy are completed successfully, it may eventually prove more economical to double those up. In any case, tying Algerian supply by one pipeline or two into the European gas network may secure for European customers some continuing advantage in access to

additional reserves of uncommitted gas that Algeria may find and develop in the future.

Much of the gas Europe expects to begin importing in the 1980’s was originally to be

shipped as LNG to the United States. European

buyers took advantage of administrative and

regulatory delays over American LNG projects

to negotiate alternative standby contracts with

Algeria’s Sonatrach for the same supplies, to

take effect if the U.S. purchasers could not meet

agreed timetables. Because only three of the

U.S. contracts were eventually approved by the

regulatory authorities, Algeria has allotted the

gas covered by the others to Europe. Algeria

reasons, therefore, that all of its planned gas

production for export in the 1980’s, some 2.6

Tcf/yr, is committed.

Europe appears now to have contracts for

some 1.9 Tcf/yr of LNG and pipeline gas from

North Africa by 1985, possibly reaching 2.5

Tcf/yr by 1990. It might be able to secure up to

1.4 Tcf/yr from Russia with or without exchanges of Iranian gas, but to meet total import

requirements of perhaps 4 to 5 Tcf by 1990, it

will still remain interested in further LNG imports during the later 1980’s, possibly the 0.59

Tcf that may become available as LNG from Nigeria.

During the 1990’s) local production may decline more rapidly, even allowing for North Sea

fields not yet discovered. Projections assuming

that natural gas will provide 15 percent of total

energy requirements, and that growth in OECD

Europe’s gross domestic product will continue

at 3 percent annually (which may be optimistic),

call for total LNG imports of perhaps 7 Tcf/yr at

the end of the century. In contrast, gas consumption may not grow at all if European production falls sharply, and even to hold consumption level would require increasing imports or

rapid development of synthetic natural gas.

‘(Near-in” sources of LNG for Europe seem

hardly able to offer larger volumes by then on a

continuing basis, though even heavier import
Ch. 3—Future Gas Availability and Use ● 57

dependence on gas pipelined from Russia may

be possible. By that time the only other major

potential source of extra gas supplies, as LNG or

by pipeline, may be the Middle East for all importers.

JAPAN

Relative to its total energy use, gas consumption in Japan is small. In 1977, only 4 percent of

Japan’s total energy requirements were served

by gas, compared with 26 percent in the United

States. Japanese consumption is concentrated in

residential, commercial, and electric power generation sectors, while in the United States, industry is the largest consumer.

The oil embargo of 1973 and subsequent rapid

increase in crude oil prices in world markets increased Japan’s attraction to LNG. In 1973, imported petroleum comprised 75 percent of the

energy used in Japan, compared with 58 percent of the energy used in OECD Europe and,

even though oil imports have increased dramatically since then, only 16 percent of the total energy requirement of the United States. During

the 17-year period, from 1960 to 1977, the

growth rate of industrial energy consumption

in Japan was 8 percent per year, far higher than

in the United States and in Europe. The remarkable growth in Japanese industry during this

period was fueled largely by imported oil. Because most petroleum flows to Japan from relatively few countries in the Middle East, the Japanese economy and society are heavily dependent, more so than the United States and Europe,

on stable oil supplies from that part of the

world. But the oil embargo of 1973, the 1979

revolution in Iran, and rapid price increases

have caused the Japanese to look for ways to diversify their fuel supplies. Importing LNG is one .

route they are taking.

A report entitled “Japan’s Energy Strategy Toward the Twenty-First Century” states,

Liquefied gas has many advantages: among

others, the volume of natural gas deposits is

more comparable to that of petroleum, natural

gas is relatively more widely distributed than

petroleum, and liquefied gas is a clean energy.

Therefore, natural gas is considered as an energy source Japan should actively try to introduce

as a petroleum substitute.7

To implement these objectives, the report

continues,

In promoting the introduction of LNG, Japan

needs to construct liquefied gas plants and LNG

carriers, locate receiving terminals and other receiving facilities, prepare a pipeline network,

and organize users. These preparatory activities

need to be supported through measures such as

financial assistance by the national government.8

Substantial quantities of nonassociated gas are

located outside of the Middle East in Indonesia, Brunei, Malaysia, the U. S. S. R., Australia,

and New Zealand. Japan imports LNG from the

United States, Indonesia, Abu Dhabi, and Brunei; and projects from other nations including

Iran and Qatar are being considered, as shown

in table 20.

Table 20.—Japanese LNG Import Projects

(trillion cubic feet per year)

Contracted

Startup delivered

date volumes Total

Operations

United States (Alaska) . . . . . . Nov. 1969

Brunei . . . . . . . . . . . . . . . . . . . Dec. 1972

Abu Dhabi (Das Island). . . . . . May 1977

Indonesia (Badak). . . . . . . . . . Oct. 1977

Indonesia (Arun) . . . . . . . . . . . Aug. 1978

Total operations . . . . . . . . .

Possible additions by 1985

Indonesia (Badak) expansion 1983

Malaysia (Sarawak). . . . . . . . . 1983

Indonesia (Arun) expansion. . 1984-85

Australia (NW Shelf). . . . . . . . 1984-85

Abu Dhabi (inland) . . . . . . . . . mid-1980’s

Qatar . . . . . . . . . . . . . . . . . . . . mid-1980’s

0.05

0.26

0.10

0.16

0.22

0.79 O.Gb

0.16

0.31

0.12

0.17-0.32

0.25

0.31

Total additions . . . . . . . . . . 1.32-1.47

Total. . . . . . . . . . . . . . . . . 2.11-2.26

Possible addition before 1990

Iran. . . . . . . . . . . . . . . . . . . . . . ? 0.13

U.S.S.R. . . . . . . . . . . . . . . . . . . ? 0.38

Thailand. . . . . . . . . . . . . . . . . . ? ?

Bangladesh. . . . . . . . . . . . . . . ? ?

China . . . . . . . . . . . . . . . . . . . . ? ?

aAt 52 MM Btu/tonne and 1,020 Btu/cf.

bActual receipts year ending Mar 31, 1979

SOURCE Office of Technology Assessment

7“Re pOrt of the Advisory Committee for Energy Conference o n

Fundamental Issues-March 1979” [Background Information, Ministry of International Trade and Industry BI-33), p.7.

‘I bid., p. 24.
58 . The Future of Liquefied Natural Gas Imports

If all possible projects were to come to fruition

by 1985, Japan would have nearly quadrupled

its LNG imports and would have exceeded the

planned import levels for 1985 as shown in table

21. The Advisory Committee for Energy sets tarTable 21.—Comparison of LNG Import Project

Volumes and Planned Import Levels—Japan

(trillion cubic feet)

1985 1990

Operating and possible LNG import

projects (table 20) . ................2.1 1-2.26

Advisory Committee for Energy?. . . . . . . 1.53 2.24

Institute of Energy Economics. . . . . . . . 1.33 1.79

a

"Japan'ss Energy Strategy Toward the 21st Century,” a report of the Advisory

Committee for Energy, Conference on Fundamental Issues. Published by the

Ministry of International Trade and Industry, BI-33, March 1979.

b

“Energy in Japan,” report No. 44, March 1979, by The Institute of Energy

Economics, Tokyo.

gets for energy development, and the Institute

of Energy Economics has forecast imports based

on its perception of Japan’s ability to absorb

LNG. Both the targets and the forecast are exceeded by the volumes represented by existing

and possible projects.

The 1979 OPEC price increases for crude oil,

as well as agreements among the leaders of the

industrial nations at the 1979 Tokyo summit

meeting, heightened Japan’s need to reduce oil

imports from the Middle East. In 1977, Japanese

industry consumed oil which would be the

equivalent of 8 Tcf of gas. If industry would

switch to LNG, considerably more could be imported. But historically, gas has been too expensive for industry, and distribution systems for

the regasified LNG would have to be developed,

and processes and appliances adapted for natural gas.

A factor which favors industrial use of LNG is

that a large segment of Japanese industry is located within a few miles of existing LNG import

terminals, and new pipelines to serve large industrial customers could be built quickly. With

the financial support of the government for

pipelines, expanded terminals, and conversion

equipment, Japan could easily accept all the

LNG available by 1985, shown in table 20, i.e.,

2.1 to 2.4 Tcf. Industry would need only to increase its LNG consumption from .05 Tcf to between 0.8 and 1.0 Tcf. To meet its goals of geographical and political diversity of energy

sources, one would expect Japan to give priority

to LNG from Southeast Asia.

Foreign LNG potentially available

to the United States

LNG must be carried further to the United

States from major export points than to either

the European or Japanese markets. Table 22

Table 22.—Distances Between LNG Liquefaction

Ports and Typical Import Locations

(nautical miles)

Europe and United States —

Bushehr

Iran

Arzew Bonny via Cape of

Algeria Nigeria Good Hope via Suez

Rotterdam. . . . . . . 1,637 4,390 11,222 6,469

Philadelphia. . . . . 3,594 5,185 11,906 8,426

Lake Charles, La. . 4,961 6,102 12,479 9,793

Yokohama. . . . . . . 6,624 (east from

Arabian Gulf)

Japan and United States

Lhakseumawe a

Sumatra Indonesia

Yokohama. . . . . . . 3,369

Los Angeles . . . . . 8,347

aLhakseumawe is the Iiquefication port for the Arun field gas.

SOURCE: Jensen Associates, Inc.

shows the distances between major sources of

LNG and ports of northwest Europe, the U.S.

east coast, and Japan. Algerian LNG will travel

less than half the distance to Europe than to

either the U.S. east or gulf coast. The relative

advantage of Europe is less for Nigerian LNG,

but Europe still has a 800- to 1)800-nautical-mile

advantage. Both Japan and Europe are closer to

Iran and other Arabian Gulf ports than is the

United States, and Japan is far closer than the

United States to the gas deposits in Southeast

Asia.

This locational disadvantage influences the

availability of LNG to the United States from

outside the Western Hemisphere. In order to

compete with Europe and Japan by offering the

same price at a liquefaction plant, the United

States must accept a higher landed price for the

LNG because of the increased distance and shipping costs. Table 23 summarizes the possible
Ch. 3—Future Gas Availability and Use ● 59

Table 23.—Potential Availability of Foreign LNG

to the United States Before 1990

(trillion cubic feet per year)

Country

Algeria

Nigeria

Western

Hemisphere

Southeast Asia

Persian/Arabian

Gulf

U.S.S.R.

Canada (Melville

Island)

Remarks Tcf/year

Operating and approved

projects 0.63

Additional amounts only from

new reserves, if any ?

0.0-0.59

0.3

0.35

Not likely before late 1980’s ?

Not likely before 1990 0.04

?

0.1

SOURCE Jensen Associates, Inc.

supplies of LNG to the United States in light of

this limitation, and individual sources are discussed below.

ALGERIA

Algeria has become the world’s largest exporter of LNG and seems likely to remain so for

the rest of the century. It has perhaps the most

elaborately coordinated master plan for optimized joint development of all its petroleum resources—natural gas, crude oil, condensates,

and liquid petroleum gas (LPG)—of any producer. Its pricing policies are also the most fully

spelled out. It is becoming a significant supplier

of LNG to the United States (0.63 Tcf by 1985),

but for the present, it has no more gas to offer.

The State company, Sonatrach, says it has already committed in long-term contracts the 2.6

Tcf/yr* of exports that it plans to build up by

1985 and maintain until after 2000. Under these

contracts, a total of about 60 Tcf would be exported over the period 1976-2004.

In the past, some Algerian authorities have

suggested that the country might have an additional 30 Tcf “available for export, ” but the Government has given no sign that it wishes to contract for this amount. It is making any further

* %me 2.2 ‘I’cf will mote as 1,N(; and ().J ‘rcl hj pipeline. ‘1’he

pipeline contract across the hfediterranean to lt?lj (m’hirh was at

01)() t inw rcplared h} an I, NC; plan, [hen changed hark) does not

appear 10 I)(} included in this 2,6 Trf )’r. “rhe second pipeline projert, to motfe gas to Spain and E’ranw, is not included, nor are the

,Anwrirarl Algeria [[ and ‘1’rnnwo projerts. All three are classified

as depending on the results of further exploration

negotiations conditional on the results of exploration, which can only be uncertain and delayed.

The effort and investment required to implement present contracts are enormous.

Algeria’s Valorization Hydrocarbon Development Plan (VALHYD) aims at

. . . maintaining a level of gas sales volume as

high and as stable as possible during the longest

period of time while taking into account gas

needs for cycling operation, re-injection in oilfields, and gas lift.

Covering the period 1976-2005, at a capital cost

of $33.4 billion (1976 dollars), the plan provides

for national production rising to about 4 Tcf/yr

by 1985, and thence to nearly 5 Tcf by 2000,

from 130 Tcf of reserves. Of these volumes, a

plateau level of about 2.6 Tcf/yr will be exported from about 1985 to about 1998. Exports

theoretically return to nil before 2005, because

VALHYD does not count any “potential and possible” reserves in known and other basins, nor

does it allow for the uprating of reserves in

fields recently discovered.

One of the VALHYD objectives is “re-injection

of gas, particularly associated gas, whenever

this will lead to a better oil reserves recovery. ”

Moreover, losses in the recovery, gathering,

transmission, and processing of gases for export

from fields far from coastal terminals, will represent a sizable debit against total gas production, approaching 1 Tcf/yr at the plateau level.

Thus, the total gas for disposal under this plan,

for home use and export, will be around 4

Tcf/yr. Algeria’s own domestic consumption of

gas, which was only about 0.35 Tcf in 1977, is

expected to treble by 1985, and to reach about

1.5 Tcf/yr around 2005. By that time about 60

percent of the reserves for development under

VALHYD may have been used up, unless more

of this gas is released for export in the meantime.

After the cancellation of the Tenneco and Algeria 11 projects, the United States will have difficulty obtaining more Algerian LNG. Europe is

even more interested in Algerian LNG with the

cancellation of the Iranian IGAT-2 contract and

a reduction in Russian gas last winter. Further,

the Netherlands is refusing to extend long-term

contracts, and the amount of gas that Europe
60 The Future of Liquefied Natural Gas Imports

believes it needs in 1990 exceeds what appears

to be available. Although Algeria seeks to diversify its markets and feels over committed to Europe, the United States should expect vigorous

competition for the remaining Algerian gas.

Even if Algeria proves up additional reserves,

Europe will remain competitive, especially if the

trans-Mediterranean pipeline is completed.

Since 1975, Sonatrach has sought to obtain a

base f.o.b. price of $1.30/MMBtu, calculated to

yield a return on investment in gathering and

trunk pipelines, liquefaction facilities, and export terminals, plus a commodity value of $0.30

to $0.40 /MMBtu for gas at the wellhead. That

f.o.b. price escalates automatically with the

prices of competing oil products in the import

market concerned, and contracts provide for

additional review of the base price every 4

years. The specific price escalation formula in

each contract has depended on individual negotiations, and for U.S. contracts, as Sonatrach

soon discovered, on their approval by Federal

regulatory bodies.

Algeria has recommended a similar pricing

formula based on a minimum wellhead commodity value, to other OPEC gas exporters, but

it has never recommended uniform OPEC

prices for LNG. Its objective for the price of LNG

regasified in final markets would be comparability with the cost of incremental alternative

fuels, which it recognizes, will depend on the

prices that OPEC has the power to set for crude,

not on any leverage through LNG supply per se.

The Algerian Government has consistently been

a “hawk,” supporting the highest possible level

of basic OPEC prices. Its own low-sulfur crudes

enjoy quality and often freight differentials over

the OPEC base level, and its sales contracts provide for quarterly adjustment of these differentials.

Algeria participated in the 1973-74 oil embargo against the United States. If the occasion

were to arise, it would probably do so again. At

the time, its only LNG shipments were to France

and the United Kingdom, and those destinations

were not embargoed. Interruptions of LNG

shipments to the United States (Distrigas in

Boston) were ascribed to problems in the liquefaction lines and the contract with Distrigas,

which provided only for LNG which was surplus to the United Kingdom and French commitments. Sonatrach argues that producers are as

dependent on uninterrupted revenues as purchasers are on secure supplies:

When a country has earmarked over half’ of

its largest natural resource for export, entailing

the investment of half of its current GNP while

raising its debt burden to the limit, there can be

little reason for consumer concern over security of supplies. g

Although its Government remains committed to

revolutionary Arab nationalism, Algeria is also

perhaps the most businesslike and sophisticated

technically and commercially of the OPEC governments from whom importers can presently

hope to buy LNG.

NIGERIA

Although LNG from Nigeria has been discussed for many years without result, negotiations with potential buyers have begun for a

new project with Phillips Petroleum as operator. Reserves are ample, and a large project of

0.59 Tcf/yr (1,500 MMcf/d) able to serve more

than one receiving terminal is being considered.

This LNG is available to U.S. buyers but they

will face aggressive competition from Europe,

which enjoys a small distance advantage. Politics may intervene, as well. Nigeria is allocating

oil to those nations that adhere to its African

policies and has recently reduced British Petroleum’s (BP) offtake by 100,000 bbl/d. The U.S.

Government may not allow energy availability

to influence U.S. foreign policy, and U.S. gas

buyers and investors will be exposed to clear

political perils to an LNG supply. In fact, U.S. antiboycott legislation may make contracting with

Nigeria difficult.

Proposals to export Nigerian gas go back as

far as the mid-1960’s, before the country’s civil

war, and before the British, then the most likely

prospective customer, discovered its own natural gas in the southern North Sea. Nigeria has

large, never fully measured, known reserves of

gas far exceeding likely domestic consumption

during the rest of this century, Perhaps two-

‘K1, Bt?lguedj, Directcw, (;as k;xprts, Sonat r-ach, Petrdeurnfk;onon?k, December 1978
Ch. 3—Future Gas Availability and Use ● 61

thirds of the reserves maybe nonassociated, but

Nigeria would probably first gather associated

gas for export, to avoid the visible waste of flaring. Two parallel proposals were being considered until last winter, when they were amalgamated. The combined scheme would now be

owned 70 percent by the Nigerian National Oil

Company (since BP, with 10 percent, has been

nationalized), and the other 30 percent would

be shared among American, Anglo-Dutch,

French, and Italian companies.

Nigeria’s crude oil is of a high gravity and lowsulfur content now in very strong demand in

the United States. The Nigerian Government has

always sought to maximize the price differentials that it can secure for this quality, and it is

reported recently to have sought higher than

the OPEC “official selling prices” from its contractual customers for all except “equity”

crude. *

Politically, Nigeria, like most other OPEC

members, is committed to an embargo of oil to

South Africa. This year, stricter application of

that embargo, regarding tankers, first threatened to embroil two of the non-American companies operating there with U.S. laws against

compliance with such restrictions, and then,

after reports that the United Kingdom might indirectly sell North Sea crude to South Africa, led

to the nationalization of BP’s Nigerian interests.

A further serious political conflict could arise

for all companies operating in Nigeria and prospective customers for gas and oil as well, if the

United States, the United Kingdom, and other

European countries lift economic sanctions

against Rhodesia and recognize its newly reconstructed government. Such an action could affect deliveries of Nigerian crude and the tenure

of the American and Anglo-Dutch companies

producing oil there, including most of those involved in promoting LNC exports. The most important government in Black Africa, a conservative military regime planning to hold elections

and hand power over to a civil government, is

unlikely to ignore the political attitudes towards

African sovereignty that its most important customers for petroleum choose to adopt.

* E.quIt~ (rude IS what Nigeria rweites in proportion to [h(> -J.5

per(fmt that II wtitlns ()! equit.v ownf’rshlp in t’ornwr cOncessiOnal’y opt lolls.

WESTERN HEMISPHERE

LNG from Trinidad, Colombia, and Chile,

which could total about 0.3 Tcf/yr, would nor-

.

really flow to the United States, which is much

closer than Europe and Japan. The lower shipping costs would give the LNG exporters better

prices than they would obtain from the more

distant markets.

In addition, a project to ship LNG from the

Arctic Islands of Canada to Savannah, Ga., has

been suggested. This gas might flow alternatively to the Maritime Provinces in Canada or

through pipelines to other Canadian and U.S.

markets. Canadian policy about shipping the

Arctic Island gas south and supplying gas to

eastern Canada has not yet been resolved.

In 1972, Peoples Gas of Chicago contracted

with the Standard Oil Company of Indiana

(AMOCO) to import LNG from AMOCO’s gas

finds offshore to the east of Trinidad. However,

the Government of Trinidad canceled the project in 1974, because it wanted the gas for internal industrial development, especially for fertilizer and ammonia plants and a steel mill at

Point Lisas on the western coast. By 1973, oil

production in Trinidad had risen to 159,000

bbl/d from reserves that were thought to

amount to 2.2 billion bbl. 10 By the first of 1979,

oil reserve estimates had been revised downward to 500 MMbbl. At the 1978 production

level of 240,000 bbl/d, the reserves to production ratio had fallen to about 6, and exports are

expected to decline. At the same time, gas reserves had increased to an estimated 8 Tcf by

January 1979, and two strikes to the north of

Trinidad led many observers to think that this

figure could be understated. Proved gas reserves now represent more than 21/2 times the

energy content of the oil reserves, and LNG exports appear to be the only way in which Trinidad can maintain the income stream from hydrocarbon exports as oil production declines.

Existing reservoirs are more than ample to meet

the 40 years of internal requirements that Trinidad requires before permitting exports.

Trinidad is not a member of OPEC, and the

number of rigs drilling in Trinidad has in-
62 The Future of liquefied Natural Gas Imports

creased steadily over the past few years. While

the Government is participating in some new

ventures, its take from some production is still

in the form of royalty and income tax.

The Government is likely to buy the natural

gas from a producer and to maximize the price

it receives for the LNG. However, Trinidad will

not easily be able to shut down an operating

LNG project to force the price up, The revenues

would represent a significant part of GNP,

which the people, having become accustomed

o a rising income, might be unwilling to forgo.

Both Chile and Argentina have discovered oil

and gas on the very southern tip of South America, bordering the Straits of Magellan and on the

Tierra Del Fuego Islands. Argentina pipelines

gas up the length of the country, serving Buenos

Aires and towns along the way. Chile is actively

developing its oil reserves and producing liquefied petroleum gas to relieve heavy imports at

rising prices. For example, in 1977 Chile imported 77 percent of its total petroleum needs. ”

During the mid-1970’s, the nation faced a serious decline in oil production and increased dependence on expensive imported oil, so in 1974,

it ended a 50-year Government monopoly in the

oil industry by a constitutional reform and invited foreign companies to assist in the exploration and development of oil through service

contracts. Resulting new discoveries in the

Straits of Magellan have increased production.

Although Chile has substantial gas reserves in

this region, the Andes Mountains make pipelining to population centers uneconomic.

In the early 1970’s, a project to liquefy approximately 0.08 Tcf/yr for delivery to two LNG terminals elsewhere in Chile was proposed but

dropped. Another LNG project to California of

about the same size is currently being formulated, since receiving terminals on the Chilean

coast appear uneconomic. Chile’s need for foreign exchange and the absence of markets for

the gas would reduce the likelihood of supply

interruption once exports began. On the other

hand, Chile, which was once considered one of

the most stable democracies in Latin America,

I I U, S. Department of Energy, Energv fnformat ion A~encey, /nternationai Petroleum Annual 1977, June l“, 1979.

has undergone political turmoil during the

1970’s and is experiencing rising inflation and

other economic problems.

At the end of 1978, Colombia had an estimated

750 MMbbl of oil and an equivalent amount (4.8

Tcf) of gas in its hydrocarbon reserves. Until

1976, the Colombian Government kept petroleum prices low. Consumption was high, oil production declined over a 10-year period, and Colombia ceased exporting oil and became a net

importer. With financial incentives, exploration

improved in 1977.

Natural gas reserves are sufficient for internal

use plus 0.05 Tcf/yr of exports. If Colombia

wants to sell gas abroad, LNG shipments to the

United States are the only possibility. Since not

enough gas is available to support an independent project, Colombian LNG would need to

share a receiving terminal with gas from some

other source.

SOUTHEAST ASIA

Although Pacific nations appear to have more

gas than Japanese markets can absorb, Japan

has a strong incentive to buy LNG in Southeast

Asia to diversify its energy supply geographically and politically. The Japanese have also

demonstrated the ability to take action quickly

and could utilize all gas from this region as industrial fuel. In addition, the greater distances

from Southeast Asia LNG sources to the U.S.

west coast allow Japan to offer better prices and

other terms. However, the countries of Southeast Asia may prefer to diversify their markets

and sell to the United States as well as Japan as

long as they suffer no significant economic penalty.

Indonesia, Australia, and Malaysia together

have considered LNG exports totaling 1.,1

Tcf/yr, most of which would flow to Japan. The

United States could probably obtain 0.35 Tcf/yr,

including 0.2 Tcf from the recently approved

Pac-Indonesia project.

Indonesia is now supplying Japan with LNG

under two projects, and the Pac Indonesia proposal for shipments to the United States has

been approved but awaits a west coast terminal.

Together, these exports should eventually reach

a level of about 0.6 Tcf/yr from the large Arun
Ch. 3—Future Gas Availability and Use ● 63

and Badak gasfields in Sumatra and Kalimantan,

remote from Indonesia’s main centers of population and energy consumption in Java. Exports

have been described as a second-best option:

If we have the gas in such huge quantities and

in such remote locations that there will be no

significant domestic uses in the near future,

then export may be the more beneficial alternative. 12

In general, however, Indonesia would rather

use gas for local development and maximize exports of oil, which fetches much higher f.o.b.

prices with less local investment. Moreover, gas

reserves, if located close to markets, can be

developed for domestic consumption more

quickly.

Indonesia is a huge country with by far the

largest population in OPEC, and rapidly rising

local energy consumption, Its oil production is

modest by OPEC standards and can perhaps be

maintained around 1.6 to 1.8 MMbbl/d throughout the 1980’s. Gas, along with coal, will have to

provide a much larger share of domestic energy

supply as consumption increases. Exploration

may still discover large gasfields far from practicable markets that might offer further LNG

possibilities. However, Indonesia is hardly eager

to develop gas exports beyond present schemes,

Indonesia maintains closer and more amicable

relations with its production-sharing operators,

which are mainly American companies, than do

most OPEC governments. Its relationships with

customers, primarily in Japan, are also close,

and Indonesia has never participated in an oil

embargo. Political considerations, indeed, appear to influence petroleum operations less

there than in most OPEC countries.

Approximately 12.2 Tcf of gas are located

about 80 miles off the northwest coast of Australia at 400 to 450 ft. A consortium of Australian and foreign companies is considering

whether to proceed with a project, estimated to

cost $2.8 billion to $3.3 billion (1977 dollars) to

export up to 0.33 Tcf/yr as LNG and to supply

the city of Perth by pipeline. Although the

Northwest Shelf project is almost certain to be

1 Zl\, ija ,,s., [)ll.(;ctol.. (;t,llf>l,a I (11 Pet ram ina, I PA convention, Jakarta, hf:i~ 1977.

approved by the consortium, its prospects have

not always seemed assured. At various times,

Australia’s opposing political parties have expressed sharply contrasting views generally

about the development of natural resources, including Northwest Shelf gas, and particularly

about export policy and the participation of foreign companies.

Concerned about the high level of foreign investment in Australia’s resources, the Labor

governments of 1972 to 1975 introduced several

measures to “buy back the farm. ” They imposed

restrictions on the level of foreign equity in new

projects and established a “variable deposit

rate” whereby a high proportion of foreign loan

capital had to be deposited at zero interest in

the Federal Reserve Bank. Even if the participants in the Northwest Shelf venture at that

time had met these restrictions, the Labor government opposed the export of gas with a view

to tying the reserves into a proposed national

pipeline system to supply Sydney and the eastern states.

Following the December 1975 election, a Liberal and National Country Party coalition government removed restrictions on overseas borrowing for projects costing more than $615 million. A target of 50-percent Australian equity in

new projects (and 75 percent in uranium developments) was announced, but not strictly applied. In any event, the Northwest Shelf project

could virtually meet this target, because the

Broken Hill Proprietary Co. purchase of Burmah

Oil’s interest, in 1976, raised the Australian

equity share to about 48 percent.

In the August 1977 budget, the Federal Government announced its approval in principle of

the export of LNG and condensate from the

Northwest Shelf. In so doing, it acknowledged

the consortium’s view that gas could not be delivered economically to the eastern states, nor

could reserves be developed for the market in

Western Australia without LNG exports. The

Government’s approval covered 6.5 Tcf of gas

(53 percent of proven reserves), equivalent to

exports of up to 0.33 Tcf/yr for 20 years.

The guiding principle of the Liberal government’s gas export policy is that exports will be

permitted “subject to satisfactory evidence that
64 ● The Future of Liquefied Natural Gas Imports

every reasonable effort has been made to market the product in Australia. ” This principle was

confirmed by the Minister for National Development.

Should a Labor government be elected to office in the future, it would be unlikely to reverse the approval of gas exports from the

Northwest Shelf. In its last months in office, the

1975 Labor government relaxed or abandoned

many of its restrictive policies relating to the development of natural resources. It also conceded that some gas exports may be necessary

to make the Northwest Shelf project viable. Nevertheless, some of the tax allowances granted to

the project by the Liberal government could be

reduced, and the disposition of gas reserves discovered in the future may be restricted.

Export prices for Northwest Shelf LNG will be

commercially negotiated within long-term (20-

Year), take-or-pay contracts. All but one of the

participants have appointed Mitsui/Mitsubishi

“seller’s helpers” in negotiating contracts with

Japanese buyers. However, the participants

have also met recently with the U.S. west coast

utilities, Pacific Gas & Electric and Southern

California Gas Company.

The Northwest Shelf participants are expected to sell their LNG at the price which,

when netted back from a particular market,

provides the highest value for gas at the wellhead. In the Japanese market, they will probably seek a price for delivered LNG that is equivalent on a heating-value basis to the price of competing fuels, such as low-sulfur fuel oil, LPG, or

even LNG from alternative sources. Thus, in

order to be competitive, potential U.S. buyers

would need to offer a price for LNG equivalent

on a netback basis to the Japanese market price.

PERSIAN/ARABIAN GULF

Although the nations in this area possess large

reserves of gas, the gulf is farther from all three

of the main regional markets for imported gas

than Africa or Southeast Asia. Netback values

for gas exports from there might in many cases

be negative, or at best, miniscule in comparison

with the high economic rents that exporters can

exact for their oil. Both Europe and Japan are

closer than the United States to the Arabian

Gulf and thus have a competitive commercial

advantage. Abu Dhabi currently is exporting

LNG, and Iran has canceled proposed projects

with the United States and Japan. The only uncommitted gas, other than in Iran, is in Abu

Dhabi and Qatar, where the Japanese are discussing LNG purchases. Some gas from additional reserves may be available to the United

States eventually, but projects are not likely in

the near future.

In June of 1979, the Iranian Government announced that it expected to cancel the second

IGAT scheme for pipeline exports of gas to the

U. S. S. R., even though a considerable mileage of

the large-diameter pipeline involved is reported

to have been laid. The immediate direct effect of

this indication of the revolutionary government’s attitude towards gas exports would be

on the Soviet gas system, but indirectly, it would

also affect Western markets for gas imports

substantially.

As mentioned earlier IGAT-2, feeding up to 1

Tcf/yr into the Russian network by the early

1980’s, would have enabled the U.S.S.R. to export 0.4 Tcf/yr to Western Europe and 0.4

Tcf/yr to Czechoslovakia in the mid- to late1980’s. If European countries are deprived of

these pipeline imports, they may become even

stronger competitors for available supplies of

Eastern Hemisphere LNG.

A restrictive policy of the Iranian Government

could represent official adoption of an attitude

expressed by some of the country’s petroleum

authorities in the past. They argued that Iran

can afford to wait to develop what may ultimately be its more important petroleum resource, gas, until its oil reserves are closer to

depletion. Earlier LNG export schemes, for example, were postponed for that reason.

The new Islamic revolutionary government,

in any case, appears to look forward to slower

depletion rates for oil than in the past. It has cut

its oil exports sharply and canceled some of the

arms and industrial development projects that

drew heavily on foreign exchange earnings. It is

even reported to be cutting back on exploration
Ch. 3—Future Gas Availability and Use ● 65

and development drilling in the oilfields. * Initially, denouncing Western-style materialistic

ambitions, the Islamic regime appears ready to

accept substantial reductions in oil income. The

surge of international prices that its cuts in production set off, however, may indeed now provide Iran with higher total oil revenues in current dollars, and perhaps even in real terms,

than its larger export volumes in 1978. If so, financial incentives to invest large sums in gas exports will diminish.

The Iranian Government has also announced

that it will place extra emphasis on conversion

of the country’s industrial, commercial, and domestic usage to gas, and it is cutting back nuclear energy plans. These actions will accelerate

domestic demand beyond the considerable

growth planned already, but local consumption

increases can hardly take up more than part of

the gas that had been committed earlier to injection in the oilfields. More associated gas may

therefore be flared and lost, but nonassociated

gas can be left in the ground.

So long as Government policy is against gas exports even by pipeline, LNG projects appear unlikely. Questions about Iranian pricing policy

become academic. As to political security, recent months have demonstrated how insecure

what once looked like the strongest and most

stable governrnent of any gulf exporter really

turned out to be. It is too early yet to guess

whether and when any settled pattern of commercial and contractual practice in foreign

trade under the Islamic regime will emerge.

Elsewhere in the gulf region, the present

small-scale Abu Dhabi LNG trade with Japan,

when first planned in the early 1970's, appeared

likely to yield an exceptionally low netback

value for the contracted ().1 Tcf/yr of associated

gas. By the time deliveries began in 197’7, prices

“It Ilh 101$(11” oil IIIX)CIU([ Ion) 1[’ss asMNI;Il[I(l gas k~ ill I)(1 [)ro(lu(wi.

1’1)(> N, II IOI)dl Ilallidll ( )11 (:011]]),11):[]lii\ . ii Is() (’LI1 t)ii(’k t }1(’ Iii 1’~(>-

S(’ii 1(’ l)liill~ f ( )1’ I’[’-i iljt’(1 1o11 01 ii SS()(’lill P(l ~ii S Into S()[11(’ of” t 11(’ oil

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(111( ’(’ c1 t I 11(> (’ill’ li[>l’ 1(’\’(>l 01 ()\’(’l’ [i \l Ihl 1)1)1 (1 1)(’1’ (iii\’ (’0111{1 1)(’ Illii i il -

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loll~iIl~ t tl(’ [)(’ii h 1)[’()(111(’t ion ()\ (’[’ S(>\ (’l’ill ~’(’ii I’S

in Japan had roughly doubled, and though construction costs had inflated too, much of the liquefaction and terminal facilities had been constructed on fixed-price contracts. Thus, Abu

Dhabi, in spite of technical problems in its early

operations, may achieve an acceptable return

on investment, and LNG exports from there

may increase. However, the experience hardly

offers much commercial precedent for other

LNG exports from the gulf.

Qatar has very large reserves of nonassociated gas in the deep Permian Khuff strata

which extends, and may also contain gas, underneath the Kuwait oil reservoirs). It has also

less opportunity than neighboring gulf exporters to expand oil production, which has remained at around .500, ()()()” bbl/d for some years.

If the Government wants to increase petroleum

exports, development of this gas offers an alternative opportunity, but whether and when this

tiny and rich State will decide to proceed with

LNG remains uncertain.

Kuwait has been drilling deep wells to ascertain whether the Khuff strata under its territory, too, contains gas but has reported 1 1 0

finds. Any gas found would first severe local consumption, and then exports of’ LPGs and natural

gas liquids (NGLs). At present, Kuwait limits oil

production to 2.2 MMbbl/d and associated gas

appears at times insufficient to meet local demand. Also, the LPG/NGLs facilities that Kuwait

brought into operation this year were designed

to accommodate 3 MMbbl/d of crude production. The Kuwait Government is perhaps the

firmest exponent in the gulf of the policy of

keeping petroleum in the ground for the benefit

of future generations, SO even if it now finds

new reserves of nonassociated gas, early development of LNG exports is unlikely.

Saudi Arabia is estimated to possess the second largest gas reserves in the gulf, primarily in

the associated category. Some nonassociated

gasfields have also been discovered there, but

none have been developed. However, the country has never shown an interest in exporting

any of this gas as LNG. Government spokesmen,

on the basis of technical studies, have consistently dismissed both I. NC, and methanol as too

costly ways of exporting their abundant energy.
66 ● The Future of Liquefied Natural Gas Imports

Instead, Saudi Arabia is committed to huge investments in gathering most of its associated

gas, using the methane and ethane inside the

country for petrochemical and other industrial

purposes and for domestic fuel supplies, and

stripping out the LPGs and NGLs for export.

This effort is likely to transform the world

market for LPGs by the mid-1980’s, and may offer supplementary supplies for the gas utilities

of Europe and Japan. Even assuming changes in

governmental attitudes, early development of

LNG exports is not probable in the light of this

major component of the Saudi industrialization

program.

No proposals for LNG exports from Iraq have

been publicized, either. The limited indications

are that this country too, may be adopting a policy, comparable with those of Saudi Arabia and

Kuwait, to use the dry gas from its northern oilfields for internal consumption, and to strip out

LPGs for export from its southern operations.

Notwithstanding those negative signs, changing oil prices must be shifting the balance of

economics for gulf LNG projects. In 1977, Sonatrach of Algeria reckoned that the market price

for OPEC crudes, then $12.70/bbl, would need

to rise 50 percent in real terms to about $19/bbl,

to make the gathering, processing, and export

of associated gas in the gulf as commercially

worthwhile. The market price applied for most

OPEC crudes had reached $20/bbl by mid-1979.

Construction costs in the gulf have continued to

rise since 1977, and the dollar has fallen, but

OPEC crude prices have risen sharply in the

past year in real terms and could reach the

threshold of economic viability for LNG exports

from the gulf well before 1985. *

U.S.S.R.

The U.S.S.R. is a substantial exporter of gas

(about 1 Tcf in 1977) from the largest reserve

base in the world. Only about half its exports go

to Eastern Europe. Exports to the non-Commu-

“ Nil’, Ail [ ,aoussin(~ ()! Solliitl’il(’tl tlitS SU~~PSt(’d ii St(3ddJ’ 1 5-~(’1’-

(wnt riw yeit I.IJI in OPPX: pri(x~s, wh i(+ m’ it h 1 O-pt’r(’rnl illtlilt io n

\% 0111(1 lllt’il Il ii .50-1 )(’1’{’(’111 ill(’rt>iist! 111 I’t’iil lt’I’lllS t)J’ 1985.

nist world are rising and could possibly be trebled by 1990. So far, all exports have moved by

pipeline, but couId be available to the United

States as LNG in the future. Two projects have

been proposed, but international politics may be

more important than commercial feasibility in

determining their success. Any export of Russian LNG to the United States is unlikely to start

before 1990.

Details of the border prices charged for Russian gas exports to Western European customers are not known. But the delivered prices

have had to compete with Dutch gas, and hence

with fuel oil values. The U.S.S.R. needs foreign

exchange, so in the past its gas exports, moving

very long distances, must have returned relatively low-commodity values at the wellhead.

From now on, as Dutch supplies decline, and

the prices of competing oil products rise, the

U.S.S.R. can raise its tariffs. It is also seeking

financial and possibly technological support

from prospective customers for field development and pipeline construction, including pipe

to supplement its own production.

Proposals for LNG exports of Siberian gas to

the United States and France, or the United

States and Japan, have not progressed in recent

years. Western Europe may prefer to seek additional supplies by pipeline, with or without the

backup of Iranian gas.

Politically, Western exports of gas run the

same strategic risks, no more and no less, as imports of other goods from the U.S.S.R. The European community has always monitored the

level of energy imports from Eastern Europe

and is likely to be vigilant about possible excessive dependence on Russian gas. On the other

hand, in the mid-1990’s) unless very large-scale

LNG exports from the Middle East develop, gas

moving from or through Russia may be the only

major source of incremental supply to Western

Europe and perhaps Japan. However, that the

United States would ever develop sufficient imports of LNG from Russia to become significantly dependent on that one source seems

hardly conceivable.
4

Project Structure, Cost,

and Financing
4c

Project Structure, Cost, and Financing

The only present way to transport natural gas

across ocean distances is to ship it as a liquid at

— 260o F in specially insulated tankers. Meth -

.

ane, the principal constituent, is 600” times

denser in liquid form than as a gas at room temperature, and this reduction in volume permits

economical use of ships notwithstanding the

cost of specialized liquefaction, revaporization,

storage, and other terminal facilities.

Liquefied natural gas (LNG) projects are expensive. The total capital required for a worldscale venture involving 1 billion cubic feet per

day (Bcf/d) beginning in the early to mid- 1980s is

nearly $.5 billion ( 1978 dollars). Approximately

40 percent of this cost is applied to the gas production and liquefaction facilities in the exporting nation, about 40 percent is needed for ships,

and the balance of about 20 percent is for the

import terminal and revaporization facilities in

the United States. The cost of service, including

operating~ expenses and amortization of the initial investment, for a typically structured project appears as a function of distance in figure

12.

An LNG importer must pay in addition to

transportation costs a return to the producing

country for the wellhead value of the gas, and

supply contracts generally contain f.o.b. price

provisions calculated to make imported gas

competitive with distillate fuels in the U.S. market. However, escalation formulas in present

contracts are such that delivered LNG prices

should rise more sIowly than those of products

from foreign crude oil.

LNG projects

Figure 12.— Cost of Service as a Function of

Distance for a Typical LNG Import Project in the

Fifth Year of Operation (1990)

I I I I

o 5,000 10,000 15,000

Distance (nautical miles)

SOURCE OTA, based on Jensen Associates data

Financial risk represents another element of

cost, and the public guarantees in part the commercial success of’ an LNG project through regulated retail prices designed to allow investors to

recover portions of their cost notwithstanding

some kinds of failure or loss. on the other hand

the risk of’ unilateral interruption of shipments

by the supplier country is reduced by high capital costs and a project structure that ties buyer

and seller into a tight economic partnership.

Commercial I.NG trading began in 1964 with

the Algeria- United Kingdom project, involving

().()4 trillion cubic feet (Tcf) of gas per year.

Over the past 15 years, the international trade

has grown to 12 currently operating projects totaling 1.75 Tcf/yr from six producer countries

(table 24). Japan has the largest portion of present imports (45 percent), f’ollowed by Western

Europe (29 percent) and the United States (26

percent). However, the rate of future expansion

in international LNG trade is uncertain. Should

all the projects listed in table 24 materialize,

worldwide trade in LNG would increase to 6.44

Tcf/yr by the mid-1980’s, of which U.S. imports

69

59-406 2 - 80 - 6
70 ● The Future of Liquefied Natural Gas Imports

Table 24.–Operational LNG Projects, as of July 1,1979

Destination

Contract

Purchasing Startup Volumesa

Origin Country Terminal companies date Tcf/year Remarks

OPERATING

Algeria

Arzew United Kingdom Canvey Is. British Gas Corp. 1964 0.04 Contract has been

Arzew

extended

France Le Havre Gaz de France 1965 0.02

Skikda France Fos Gaz de France 1972-73

1971-77 0.14

Skikda United States Everett, Mass. Distrigas 1978 0.05

Skikda Spain Barcelona Enagas 1976 0.55

Arzew United States Cove Pt., Md. Columbia Gas, 1978 0.40

Savannah, Ga. Consolidated Gas,

Southern Energy

Alaska

Kenai Japan Negishi Tokyo Electric 1969 0.05b

Tokyo Gas

Brunei

Lumut Japan Negishi Tokyo Electric 1972 0.26b

Sodegaura Tokyo Gas

Semboku Osaka Gas

Libya

Marsa el Brega Spain Barcelona Catalana de Gas 1971 0.04

Marsa el Brega Italy La Spezia Snare 1970 0.09

Abu Dhabi

Das Island Japan Sodegaura Tokyo Electric 1977 0.10b

Indonesia

Badak (Bontag) Japan Himeji Kansai Electric 1977 0.16b

Chita Chubu Electric

Arun (Lhakseumawe) Japan Tobata Kyushu Electric 1978 0.22b

Semboku Osaka Gas

Nippon Steel

APPROVED

Algeria

Hassi R’mel Italy Sicily EN I 1981 0.44 Pipeline replaced

(gas pipeline) an LNG project

Arzew Belgium Zeebrugge Distrigaz 1982 0.20 Terminal site

uncertain

Arzew France Montoir Gaz de France 1980 0.20

Arzew/Skikda United States Lake Charles, La. Trunk line 1980 0.18

Arzew/Skikda West Germany Wilhelmshaven Ruhrgas, Salzgitter, 1984 0.41

Netherlands Emshaven Gasunie

Arzew/Skikda West Germany Wilhelmshaven Brigitta-Thyssen 1985 0.16

Indonesia

Arun United States Pt. Conception Pacific Gas & Electric 1983 0.20 Approved Sept. 26,

So. California Gas 1979.

Alaska

Cook Inlet United States Pt. Conception Pacific Gas & Electric ? 0.15 Approved Oct. 12,

So. California Gas 1979. Added reserves needed

PROBABLE

Australia

Dampier Japan Tokyo Tokyo Electric 1984-85 0.33

Tokyo Gas, etc.
Ch. 4—Project Structure, Cost, and Financing ● 71

Table 24.—Operational LNG Projects, as of July 1, 1979—continued

Destination

Contract

Purchasing Startup volumesa

Origin Country Terminal companies date Tcf/year Remarks

Malaysia

Bintulu Japan Sodegaura Tokyo Electric 1983 0.31b

Tokyo Gas, etc.

Indonesia

Badak (exp.) Japan Various Chubu Electric 1983 0.16b

Osaka Gas

Kansai

Toho Gas

POSSIBLE (active)

Nigeria

Bonny United States/ Columbia, Mid 0.6

Europe Consolidated, 1980s

Southern, Mich-Wis,

Trunkline and others

Trinidad

Pt. Lisas United States Gulf coast Tenneco 1984-85 0.18

Peoples

Canada

Melville Is. Canada/ St. Lawrence Southern Natural Gas 1982-83 0.09

(Arctic Is.) United States

Australia

Dampier United States Pt. Conception So. California Gas late 0-0.15

Pacific Gas & Electric 1980’s

Cabo Negro United States Pt. Conception So. California Gas 1983-85 0.08

Pacific Gas & Electric

Indonesia

A run (exp.) Japan Various 1985 0.12

POSSIBLE

Algeria

not announced Sweden Wilhelmshaven Swedegas AB 1984-85 0.07 Trends in Swedish

energy policy

cast doubt on

this project

not announced France Gaz de France 0.18

not announced Switzerland 0.000018

not announced Austria Ferngas; OMV 0.07

not announced Yugoslavia 0.07-0.11

Arzew United States La Salle United, El Paso mid 0.40

El Paso 1980’s

Qatar

not announced Japan Tokyo Tokyo Electric mid 0.31 b

Tokyo Gas 1980’s

Mitsubishi

Shell

Abu Dhabi

Rubais Japan C. Itoh & Co. mid 0.25b

1980’s

Colombia United States 0.05

U.S.S.R.

Yakutsk United States Tokyo Gas 0.75

Japan Tokyo Electric

El Paso

Occidental
—

72 ● The Future of Liquefied Natural Gas Imports

Table 24.—Operational LNG Projects, as of July 1, 1979—continued

Destination

Contract

Purchasing Startup volumesa

Origin Country Terminal companies date Tcf/year Remarks

Murmansk United States 0.75

Europe

United Kingdom

North Sea United Kingdom 0.75 Floating barge

liquefaction

plant.

Iran Japan 0.13

Thailand Japan

China Japan

New Zealand Japan Maui gas, Mobil

has proposed an

automotive fuel

project

aAt I,1020 Btu/cf Normally contract volumes are given f o b the Iilquefaction plant

b

lndlcates c. i. f. volumes, I e , delivered.

SOURCE Jensen Associates, Inc.

would account for about 36 percent. Not all of

these projects will come to fruition, however,

and most past projections regarding the future

of LNG trade have overestimated the rate of

growth. The possible level of LNG imports is

particularly uncertain in the U.S. market,

where Government policy regarding LNG imports has been difficult to predict. The Department of Energy (DOE), the Federal Energy Regulatory Commission (FERC), and State Public Utilities Commissions decide on all aspects of individual projects case-by-case in regulatory proceedings that take years, Given the present uncertainties, a more reasonable expectation

would be that worldwide trade in LNG will

reach 4.19 Tcf/yr by 1985, of which 46 percent

will move to Western Europe, 34 percent to Japan, and 20 percent to the United States.

A baseload LNG project is a complex and

highly capital-intensive venture, consisting of’

three primary segments (figure 13):

1. liquefaction, storage, and loading facilities

in the producing country;

2. transportation facilities (cryogenic tankers); and

3. terminal and revaporization facilities in the

receiving country.

Total capital investment of a 1 Bcf/d project

can exceed $5 billion (1978 dollars). The cost

varies with such factors as the gas-gathering

system, shipping distance, and new delivery

pipelines required. The cost of liquefaction and

related facilities in the producing country can

account for as much as 50 percent of overall

project costs. 1

What follows is a more detailed description of

the physical and cost structure in LNG import

projects, including the price policies of the exporting countries. Two LNG projects are used

for the purpose of illustration: Pac Indonesia

and Algeria 11. Although only one of them has

received final U.S. Government approval as of

this writing, * the projects are good examples,

because their costs and pricing provisions are

recent and represent current LNG trade.

Algeria II

The proposed project was based on an October 28, 1975, contract, as amended, between

Sonatrach (Societe Nationale pour la recherche,

1 FOI” (l(’l’(’lol)llll’ 111 01 l~l)i(>al 1,N(; (os1 (ISI In):i[(}s, S(I(I K N’.

l)] N’iiPOli, “l;still]altn, q (;os1s lo]” 11;1s1’-10;1({ I ,S(; l]liilll S,” oi/ iil?d (;;1S

.h)llrnd, N()\ 17, 1 97.;.

“1’llt’ ,,llg(>l’iii II 1)1’oj(’(’l \\ il~ (’oll(lillolliill~’” ill)l)l’()\ (’(l 1)}’ 111(1 };l’(:

I

; F;K(’ il(illlillihl l’iilil (’ IiI\\’ j(l(lg(’ 011 ()(’t. 25, 1977 lio\i (’\’(’l’, 1111( 1(’1’

[11(’ l)(>j)ill’l Illt’111 ot liIl(’1’~J’ ol’~iilli~iltloll” ,\(’l (’l’t(’(’l l\ (’ ()(’1 1, I !)77,

I 11]1)01’1 jurih(l 1(’1 ion \f ilS t I’illlst (’1’1’(’(1 10 I X )I;’s l;ll(’1’gJ’ 1{(’glllii 101’}”

.\(!ll)l])lstl’<illotl IFIR l] 1)01:, t;,R,1 IIIA (IIWK1 III(’ Illiliiil (I(l(isio[l III IIS

of)l[lioll” N() 4 ot I J(I(. 21, 1 !)78 P(lrn)lssioll 101” l’(’11(’iil’ill~ 11:1s 1)(’[}11

[’(’(’(’111 IJ’ ~1’iill[(’(1
Ch. 4—Project Structure, Costj and Financing ● 73

Figure 13.— Major Segments of an LNG Import Project

SOURCE: Jensen Associates, Inc.

1a production, le transport, la transformation et

la commercialization des hydrocarbons) and El

Paso Atlantic Company (a subsidiary of El

Paso). 2 It provided for the sale of LNG containing 410,625 billion Btu annually, for a term of 20

years. This amount is equivalent to approximately 1 Bcf/d of natural gas at 1,125 Btu/cf.

The gas was to be produced by Sonatrach, the

Algerian State oil and gas company, in the Sahara, pipelined 315 miles to the Mediterranean

coast, and there liquefied, stored, and loaded

aboard LNG tankers. El Paso Atlantic, which

would acquire the title to the LNG at the tanker’s receiving flange, would arrange for the

transportation by a fleet of 12 cryogenic tankers

to an import terminal and regasification plant

(the La Salle terminal) located near Port O’Connor, Tex. Six of the ships would be provided by

Sonatrach and six by Atlantic. As each vessel entered the international waters off the coast of

A]geria, the title to the LNG would pass to El

Paso Eastern, the legal importer. The La Salle

‘The El Paso Companies involved in the project, and their genealogy, are as follows:

The El Paso Company

El Paso LNG Company El Paso Natural Gas Company

El Paso Eastern Company ("Eastern") [El Paso Natural)

El Paso LNG Terminal Company

(“Terminal”)

El Paso Atlantic Company [“Atlantic”)

SOIIR(’L /nllla/ Dem$mn, 1 jwn ,4p@.almms 10 In]lxmf f,,\’(; f’rom Al,qfwa, F’i.R( 01. I 2.5,

1979, Docket N(M (.11 77.330, N <i] p 4

terminal facilities would be built and operated

by the El Paso LNG Terminal Company which

receives, stores, and revaporizes the LNG. At

the outlet of the terminal, the gas would be sold

by El Paso Eastern: 65 percent to the El Paso

Natural Gas and 35 percent to the United LNG

Company. The entire quantity would be pipeIined to the United Gas Pipeline Company’s existing mainline facilities near Victoria, Tex.

There, United LNG’s 35 percent of the gas

would be sold to its parent, United Gas Pipeline,

which serves other major pipelines that deliver

gas throughout the area east of the Mississippi.

The remaining 65 percent of the gas would be

transported via a new 432-mile-long pipeline to

be built by El Paso Natural to its Waha treating

plant located in Reeves County, Tex., where it

would enter the present El Paso system serving

the Southwest and California.

In 1977, at the time of the participants’ initial

application to the Federal Power Commission

(FPC) for import authorization, the total capital

costs of the project were estimated as follows:*

● $2,300 million for gas welIs, pipeline, and

liquefaction facilities in Algeria (including

$391 million for interest on funds used during construction);

● In 1975-76 dollars.
74 ● The Future of Liquefied Natural Gas Imports

● $1,752 million for 12 vessels and shoreside

facilities required for ocean freight; and

● $719 million for receiving terminal, regasification plant, and new pipelines in Texas.

Pac Indonesia

Two gas utilities in California—Pacific Lighting Corporation (PLC) and Pacific Gas and Electric Company (PG&E)—have formed a partnership to import LNG from Indonesia through two

subsidiaries. The first subsidiary, Pac Indonesia,

has entered into a contract with Pertamina, the

Indonesian Government-owned oil and gas company, for the purchase of 226,194 billion Btu annually (approximately 550 MMcf/d) for a period

of 20 years. *

The gas for the project would be produced in

the Arun field of Northwest Sumatra by Mobil

Oil Indonesia, Inc., under a production-sharing

contract with Pertamina. From the field, the gas

will be transported via a 20-mile pipeline to the

liquefaction plant, which will be owned and financed by Pertamina.

Pac Indonesa has entered into contracts for

the hire of nine cryogenic tankers to transport

the purchased LNG from North Sumatra to California. Three of the vessels have already been

completed in foreign shipyards and plans call

for the remaining six to be constructed in the

United States.

The LNG would be delivered to a proposed receiving terminal to be constructed by Western

LNG Terminal Associates, the second subsidiary, near Point Conception, Calif. After storage

and revaporization, the gas will be transported

via a new 112-mile pipeline to the transmission

systems of PLC and PG&E, which will jointly

own the pipeline. Pac Indonesia will sell half of

the gas to Southern California Gas (So Cal), a

wholly owned subsidiary of PLC, and the other

half to PG&E. The two utilities combined comprise the transportation and marketing mecha-

“rhe original contract between Perusahaan Pertamban&in Minyak Dan Gas Bumi Negara (Pertarnina) and Pac Indonesia’s predecessor—Pacific Lighting International, S, A.—was signed in Septwnber 1973, Since then, it has been amended three times in regard to

its priring provisions. ‘1’he last amendment was introduced in July

1978.

nism that handles virtually all natural gas consumption in California.

Based on 1976-77 cost estimates, the capital

expenditures for the project are as follows:

●

●

●

$869 million for the pipeline, liquefaction

plant, and related facilities in Indonesia,

(including an estimated $164 million for interest during construction but not the cost

of developing the Arum gasfield);

$1,230 million required for nine chartered

tankers, including $930 million for six vessels to be built in the United States (at $155

million per ship);

$436 million allocated for the receiving terminal and pipelines in California. These facilities, estimated to cost a total of $749 million, are to be shared by Pac Indonesia and

Pac Alaska. On the basis of the contracted

throughputs, the cost allocated to Pac Indonesia would be just over 58 percent of the

total.

Pricing policies of exporting countries

As a consequence of large crude oil price increases in 1973-74, the LNG projects negotiated

or renegotiated after 1974 contain fuel-related

escalation clauses applicable to their base f.o.b.

ship’s rail prices, the purpose of which are to establish parity between LNG and alternative

fuels. Minimum (floor) price levels designed to

remove the producing country’s investment, or

to assure the timely repayment of project-related debt, have also become standard contractual provisions. In addition, the pricing formulas usually contain safeguards against currency

fluctuations. Sonatrach has adopted a fairly uniform f.o.b. pricing policy for all of its recent

contracts—U. S. and European alike. A review of

the major price provisions in the Algeria II and

Pac Indonesia contracts provides a good indication of a LNG pricing mechanism that typifies all

recent LNG trades.3

.lFor a more detailed discussion of I.N(; pricing mechanisms, see

“Economic Considerations and Operating History of Base-Load

LN(; Projects, ” Philip J. Anderson and F;dward J. Daniels, lnstitutt~

of Gas “technology, December 1977.
Ch. 4—Project Structure, Cost, and Financing ● 75

The procedural history of pricing clauses negotiated and approved in the Pertamina-Pac Indonesia contract illustrates the evolution of policy involved in f.o.b. pricing. Under the original

September 6, 1973, Pertamina contract, the

price to be paid by Pac Indonesia’s predecessor

would be $0.63/million Btu (MMBtu) plus 2-percent annual escalations, adjusted by a currency

reevaluation factor and subject to certain floor

and ceiling levels. The Indonesian Government

did not, however, approve the contract on the

ground that the price formula which contained

a fixed escalator would not reflect the development of world energy prices in general and, in

particular, was not linked to the price of Indonesian crude oil. Consequently, the first

amendment issued January 9, 1975, established

a new f.o.b. base price of $l.25/MMBtu—approximately double the prior price—and deleted

the fixed 2-percent-per-year price escalator. A

new escalation formula reflected equally

changes in Indonesian crude oil export prices

and U.S. energy prices as measured by the

Bureau of Labor Statistics wholesale index for

fuels. The renegotiated formula no longer contained a floor or a ceiling, so it offered no protection to either party against potentially wide

fluctuations in LNG price through the operation

of the escalation clause. The possibility of a fall

in crude oil prices presumably led to the minimum bill provision, which assured Pertamina’s

lenders that the price of LNG would be at least

sufficient to service Pertamina’s debt and to

meet operating and maintenance expenses (second amendment, issued October 28, 1975).

Although the FPC administrative law judge

conditionally approved the proposed project

and its pricing provisions, one of FPC’S successor agencies, DOE’s Economic Regulatory Administration (ERA), did not allow the automatic

flow through of cost increases under the price

escalator clause, charging that the provision

was tied too directly to future movements in

OPEC-administered prices, and that the U.S.

fuels index would be influenced by future domestic energy pricing policy and by the price of

the import itself; thus creating a significant selfcompounding effect.4 This rejection of the escalater led to yet another price amendment, issued July 28, 1978, and approved by DOE/ERA

shortly thereafter.

Under the renegotiated escalation clause, the

Indonesian half of the escalator will still be tied

to Indonesian crude oil export price, but with

the added constraint of a 15-percent absolute

limit on annual fluctuations in that price. Any

adjustment above the 15-percent absolute limit

or below the floor can be carried forward until

it can be applied. The U.S. half of the escalator

was changed to substitute the broader based

Bureau of Labor Statistics “all commodities” index for the former fuels-related index.

The pricing formula, as finally approved, is

shown in figure 14. The calculated contract

sales price is $1.25/MMBtu multiplied by the

equally weighted changes in the Indonesian

crude price (subject to a limit on annual fluctuations) and in the U.S. wholesale index for all

commodities. A contract sales price is then multiplied by a currency reevaluation factor to arrive at the billing prices. *

If at any time during the debt amortization

period, the calculated contract sales price

should be lower than the minimum price calculated by Pertamina, the latter will be the billing

prices

The Pertamina-Pac Indonesia contract includes a “most favored nation clause” under

which Pac Indonesia would be entitled to a contract sales price for LNG no higher, on an f.o.b.

equivalent basis, than that paid by any other importer under any other contract with Pertamina

in existence as of January 9, 1975. Otherwise,

the contract does not provide for future price

reviews.

The Algerian pricing system has a twofold

purpose: 1) to ensure that imported gas is com-

‘ iI()\%(?\(Ir, operation of the (wrrwq factor cannot reduce the

billing pri(>e t)dot~ M’tuit it was on the difte ot’ first cteli\wries, no r

increase it morf? than M perrf>nt ahm’e ~hf~ r)t hf!rjt’isf~ applicat)lv

price in any gilfm calendar qLmrler.

5’[’hf> FIY adrninist rat i~re la~$; juc!gf> t$’ho con(iit iona]lv ir}]prolred

the Piic In[lonwia projecf interpretcc~ (hc minimum hi; l sut)jc(.t [0

all the l~rol isions o] [hc sales contract. ‘1’}lLIS, Pa{’ lndonesia ki Ould

not I)f’ rfquird to pa)’ for qutintilies rrol ddilwd ‘(whether l))’

rf’irson of PfJrtaminii’s fii Lilt or force m~i jeuix’ or :issim iliit(’[i (ii’-

(mmslti ilws uccuriilg in an-v ])ii rt of t 11[’ fii(’il it if’s, in(>lud ing t Ilf’

ships or tf?rminal. ” (Init iii] Ilfx. ision, p 62)
76 . The Future of Liquefied Natural Gas Imports

Pac Indonesia

Figure 14.—Pricing Provisions of Pac Indonesia and Algeria II Import Projects

(U.S. dollars per million Btu, gross heating value, loaded f.o.b.)

Algeria II

Contract ("invoice") price

Calculated quarterly. Calculated semiannually.

F

1

= price for No. 6 fuel oil, low pour, max. sulfur of

0.30%, delivered New York harbor.

F lo = $13.505.

B =

cl =

C2 =

on the date of initial deliveries for each

of the currencies.

the arithmetic average of the commercial

rates of exchange on the applicable dates

in each quarter for each of the currencies.

B = 1 until its absolute value changes at least

by 0.1 O/O. Thereafter new value for B used

only if it differs from old by 0.1 0

/0 or more.

Maximum B = 1.25.

MI:,,*, ;

.“’

. , - ,

During its debt amortization period Pertamina will

calculate a price sufficient to meet:

1)

2)

3)

E = arithmetic average of the results obtained by

applying the formula:

R

~– 1 to each of 6 currencies.

A = average commercial exchange rate for each

currency during July 1975.

B = average commercial exchange rate for each

currency as measured by average purchase and

sales rates for telegraphic transfer for each

business day of preceding month.

E = O until its value increases by at least 0.1%

as compared to O. Thereafter new value for E used

only if it differs from old value by 0.1 0

/0 or more.

M P 1 = recalculated minimum price.

x = actual capital costs incurred by Sonatrach

(in millions of dollars),

Y = actual operating costs of Sonatrach during the

first year of operations (in millions of dollars).
Ch. 4—Project Structure, Cost, and Financing ● 77

adjust the minimum price only upwards, and

with no upper limit.

Since oil prices are likely to continue rising,

the contract (“invoice”) price rather than the

minimum price will probably determine Sonatrach’s billing price. Recently, Sonatrach and El

Paso’s subsidiary have renegotiated the invoice

price formula in a 1969 contract which underlies the Algeria I project. * Under the 1969 contract, the current price for LNG f.,o.b. Algeria

would amount to some $0.363 /MMBtu. In rationalizing the price renegotiation, Sonatrach

has observed that “in the decade since signing of

the contract, the capital cost and operating costs

of the project have increased substantially, and

that, as a result, Sonatrach is suffering a huge financial burden while providing the cheapest incremental source of natural gas to the United

States,”7 The renegotiated base price will be

$1.75/MMBtu, effective as of July 1, 1979. A

series of discounts will be applied to this price

ranging from $0.60/MMBtu for the remainder

of 1979 and then decreasing by $0. 10/MMBtu increments until mid-1983. The price escalator is

tied to No. 2 and No. 6 fuel oils as described for

the Algeria 11 project.

Unlike the Pertamina contract, the Sonatrach

agreement provides for the regular review of

the contract sales price. The parties are expected to meet during the first year after regular delivery begins, and every 4 years thereafter, to ascertain whether the prevailing price

of the gas resulting from this project is still competitive in the U.S. energy markets. Furthermore, either party may request a meeting at any

time if the particular indices selected to reflect

fuel oil prices in the U.S. market fail to do so

adequately.

This important price provision may result in

significantly higher f.o.b. prices to Sonatrach

than would otherwise prevail without renegotiations. The reason is the disparity, which is
78 ● The Future of Liquefied Natural Gas Imports

likely to develop over time, between the U.S.

tariff imposed on the regasified LNG and the

price of oil in U.S. markets (figure 15). In light of

Figure 15.—Comparison of the Forecast U.S. Tariff

on Regasified LNG in the Algeria II Project With

the Delivered Price of Fuel Oil*

●

designed. Operating costs are subject to inflation, but they constitute a small portion

of the tariff. For simplicity, the graph reflects the assumption that the shipping and

terminating components of the tariff will

remain fixed.

Because the f.o.b. price of LNG grows more

7.0

6.0 I

Delivered price of

‘

— oil in U.S. market

— 

U.S. tariff A

on regasified LNG A

f.o.b. price of LNG

‘

- without renegotiations

2.0

1

2.

Light Arabian marker crude

price increases by 420/.

In 1979; by 12°/0 annually

1979-82; by 170/. per year

until 1990.

U.S. inflation rate equals 70/.

1 I I I I I I I I I !

1978 79 80 81 82 83 84 85 86 87 88 89 1990

Year

. Every 4 years a portion of the difference between the delivered price

of oil and the U.S. tariff on regasified LNG is liable to Sonatrach’s

claims through the operation of the price renegotiation clause.

SOURCE: Jensen Associates, Inc.

the price review provision, Sonatrach may

claim this potential price differential for its own

benefit. The price disparity–represented on the

graph by the darker tone–will occur for the following reasons:

● The LNG (f.o.b. ) price component of the

tariff grows in the same proportion as the

oil price, but since this rate of growth applies to a smaller base, the dollar difference

between the oil price and the f.o.b. price

for LNG increases in time.

● The shipping and terminating components

of the tariff consist largely of capital

charges, which are either fixed or declining in time –depending on how the tariff is

slowly in terms of-absolute dollars than the

oil price, while the shipping and terminating costs are fixed, a gap develops and

grows between the price of oil and the tariff for the regasified LNG.

Revisions of f.o.b. price may well serve as a

vehicle for liquidating such disparity by adding

the price differential to Sonatrach’s f.o.b. price

for LNG. It should also be noted that by keeping

the price of the gas competitive with that of oil,

the price revision clause assures the marketability of Algerian gas in the United States. For instance, should the regasified LNG become more

expensive than reference New York harbor fuel

oils, the price renegotiation clause may be invoked to bring the price of Algerian gas down to

the competitive level.

Conditional approval of the Algeria 11 project

by the FPC/FERC administrative law judge on

October 25, 1977, was subsequently reversed by

DOE/ERA. Much of the ERA criticism of Sonatrach’s price provisions echoed its earlier objection to the Pac Indonesia pricing mechanism

prior to the issuance of the last amendment.

ERA objected mostly to the fact that the Sonatrach price escalator is entirely linked to future

changes in OPEC-determined prices of premium

petroleum products. The formula was found

lacking safeguards against extreme oil price increases, since it imposed no limits on the annual

price fluctuations. ERA also criticized the use of

No. 2 and No. 6 posted prices rather than the

weighted average of the actual transaction

prices (the latter practice is proposed for the

Pac Indonesia project). DOE/ERA, however, indicated that its approval of the Pac Indonesia

project did not create a precedent for subsequent decisions. In other words, should Sonatrach adopt exactly the same price provisions as

Pertamina, the project would not necessarily be

approved on those grounds alone.
Ch. 4—Pro/ect Structure, Cost, and Financing 79

Figure 16 depicts the forecast f.o.b. prices derived from Sonatrach’s and Pertamina’s formulas assuming no price renegotiations. Under the

Figure 16.—Forecast f.o.b. Prices Paid for LNG

in Pac Indonesia and Algeria II Projects*

I I 1 I 1 I 1 i. I I I

1978 79 80 81 82 83 84 85 86 87 88 891

Year

‘Assumptions:

1. Light Arabian marker crude price increases by 420/. in 1979; by 12°/0

annually 1979-82; by 17°A per year until 1990.

2 U.S. inflation rate equals 70/. annually.

3. Sonatrach’s formula IS not periodically revised.

● “The two curves for Pac Indonesia show f.o.b. price calculated with and

without the 15 percent ceiling on the annual fluctuations In the value

of the Indonesia half of the price escalator.

SOURCE: Jensen Associates, Inc.

listed assumptions, Algeria 11 prices would increase considerably faster than Pac Indonesia’s.

This difference is due to two factors:

1. the expected rate of growth in the price of

imported fuel oil is well above the presumed U.S. inflation rate; and

2. the annual ceiling on the Indonesian crude

price increases limits the impact of the

project price hikes.

Producing country facilities and

related costs

PAC INDONESIA

The Pac Indonesia project entails the following operations in Indonesia:8

1.

2.

Production and gathering by Mobil Oil Indonesia of natural gas from the Arun field

in North Sumatra and transportation of the

gas via pipeline to Pertamina’s liquefaction

plant and marine terminal on the north

coast of Sumatra.

Liquefaction, storage, and delivery of the

LNG by Pertamina to the LNG vessels chartered by the Pac Indonesia LNG company at

Pertamina’s marine terminal.

The source of the gas is specified in the Pertamina contract as Contract Area “B” in the

Aceh Province, * which contains the inland

Arun gas condensate field discovered by Mobil

Oil Indonesia in late 1971. Arun’s proven reserves consist of an estimated 13 Tcf of nonassociated gas. For an LNG import project, nonassociated gas is preferable because the availability and stability of its supply is not adversely affected by potential interruptions and other

problems in crude oil production.** Pertamina

has contracted to sell LNG produced from Arun

not only to Pac Indonesia by also to a group of

five Japanese purchasers, who are scheduled to

receive a slightly greater average daily volume.

The field is being developed by Mobil Indonesia, a wholly owned subsidiary of Mobil Oil

Corporation, under a production-sharing contract with Pertamina. Eventually, 64 wells (with

an average depth of 11,483 ft) will be needed to

maintain an adequate gas supply for both Pac

‘For description, see Initial Derision on Importation of Liquefied

Natural Gas From Indonesia, FPC, July .22, 1977, Docket NO.. CP

74-10 et al.

● Other producer countries, for instance Algeria, do not dedicate

specific gas reserves to the fulfillment of individual contracts All

Algerian gas reserves stand twhind all of its contracts.

* *For instance, Libyan gas is normally f’ound associated with

crude oil and therefore gas availability depends to a great extent

on crude oil production. Conservation policies in I.ihyan crude oil

production will limit the quantities of gas available for liquefaction.
80 The Future of Liquefied Natural Gas Imports

Indonesia and Japanese contracts. Due to unusually high reservoir pressure and temperature,

each wellhead has to be equipped with specially

designed piping and valves to control the gas

stream.

From the field, the gas is transported to the

Arun liquefaction plant at the north coast of Sumatra via a 42-inch-diameter, 20-mile-long pipeline with a design capacity of 1,777 MMcf/d–

sufficient to transport the quantities of gas to

service both the Japanese and the Pac Indonesia

contracts. * As shown in table 25, the capital cost

of the pipeline attributable to Pac Indonesia

(half of the total) is $13 million.

Table 25.—Estimated Capital Costs of lndonesianBased LNG Facilities for Pacific Indonesia Project’

(millions of dollars)b

Amount Total

Pipeline. . . . . . . . . . . . . . . . . . . . . . . . . . . .

Plant facilities

Gas treating and liquefaction

(3 trains) . . . . . . . . . . . . . . . . . . . . . . .

LNG storage and loading . . . . . . . . . . .

Plant utilities . . . . . . . . . . . . . . . . . . . . .

Site development, buildings,

miscellaneous . . . . . . . . . . . . . . . . . .

Contractor’s home office costs. . . . . .

Supporting facilities

Housing . . . . . . . . . . . . . . . . . . . . . . . . .

Communications facilities. . . . . . . . . .

Other. . . . . . . . . . . . . . . . . . . . . . . . . . . .

Intangibles

Project management. . . . . . . . . . . . . . .

Pre-startup and training costs . . . . . . .

Other (land, insurance, taxes,

royalties, misc.) . . . . . . . . . . . . . . . . .

Contingencies . . . . . . . . . . . . . . . . . . . . . .

Subtotal . . . . . . . . . . . . . . . . . . . . . . . . .

Interest on funds used during

construction:. . . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 13

202

81

59

88

72 502

49

6

7 62

25

18

35 78

50

705

164

$869

aThese cost estimates include.

-The construction of liquefaction trains 4,5, and 6, assuming that procurement

will take place in the world market and that mechanical completion of the 4th,

5th, and 6th trains will fake place in May, August, and November 1981 respectively.

-One-hlalf of the cost associated with the “common” facilities required to service all SIX liquefaction trains. Interest during construction IS not included.

bresumably 1976 dollars.

cEstlmated by Jensen Associates, lnc.

SOURCE: Testimony of President.Director of Pertamlna, Piet Harjono, before

the Federal Power Commlsslon, Feb. 25, 1977. Exhibit No. 175,

FPC Docket No CP-74-160.

The liquefaction plant converts the natural

gas received from the pipeline into a liquid suitable for storage. A liquefaction facility consists

of three main sections.

1.

2.

3.

Gas preparation section-Any constituents,

such as water vapor, which freeze at liquefaction temperatures and thereby plug the

cryogenic equipment, must be removed.

Removal of hydrogen sulfide is also required to meet LNG product specifications.

Liquefaction section—Mechanical equipment refrigerates the gas in order to liquefy it. At atmospheric pressure, the gas becomes a liquid at – 260° F and its volume

diminishes by a factor of 600.

Storage and loading section—Insulated tankers retain the natural gas as a liquid at atmospheric pressure, and the loading system transfers the product from land-based

storage to oceangoing tankers.

Approximately 3 years are required for the

complete design and construction of a large liquefaction plant.

The liquefaction facilities proposed for the

Pac Indonesia project (the Arun plant) represent

equipment, processes, and costs that are typical

for contemporary large-scale LNG plants. The

overall Arun plant will include six liquefaction

trains (three for the Japanese project and three

for Pac Indonesia) together with feed gas pretreatment, refrigerant preparation and storage,

LNG loading, and required offsite and utility

facilities.9 The first three liquefaction trains

have already been completed and, since August

1978, are serving Pertamina’s obligations to the

Japanese clients. The design and construction of

the first three trains anticipated the projected

six-train operation in terms of sizing, location,

and utilities layout. This sharing of facilities
Ch. 4—Project Structure, Cost, and Financing ● 81

Photo credit El Paso Co

Frost forms at the flange and on the articulating arm as

cold LNG flows onto an LNG tanker at the

loading terminal

provides for convenience in operation and savings in capital costs.

Each train is designed to produce LNG equivalent to 200 MMcf’/d* in 341 days Of annual operation. Three trains would therefore produce

102 percent of the annual quantity contracted

for by Pac Indonesia. Indeed, the Indonesian

plants that serve Japanese contracts (Arun as

well as the somewhat older Badak plant) have

consistently produced well in excess of their

design capacity. Reliability of production is

enhanced by the fact that both gas-processing

and liquefaction trains are arranged in parallel

so that the failure of any one component will

not result in a plant shutdown. Table 25 indicates that liquefaction equipment represents

the greatest portion of direct costs-about w

percent. Pertamina estimateci the cost of one liquefaction train to be constructed for Pac Indonesia at $67 million, assuming that procurement

would take place in the world market and that

all three trains would be completed by the end

of 1981. *

LNG will be stored in four double-walled insulated tanks of 125,000 m3 each. The combined

capacity of the four tanks equals 8.5 days ful]

production of’ the six-train plant. The loading

system utilizes four pumps (with a fifth as

a spare), which drain LNG from the tanks

through two insulated pipes. The pipes terminate in loading arms that accommodate the relative movement of the ship and the pier. The system is capable of loading a 125,000 m3 ship in 12

hours at either of two berths. The total cost of

LNG storage and loading facilities is $162 milIion, half of which constitutes Pac Indonesia’s

share.

ALGERIA II

The Algeria 11 project111 provides for daily delivery of approximately 1 Bcf/d, a volume close

to the combined Pac Indonesia and Japanese

contractual amounts. Liquefaction, storage, and

loading facilities proposed for the Algeria 11

project are very similar to the ones described

for the Arun plant. The six-train liquefaction facility at Arzew will use the same air products

and chemicals (APCI) liquefaction process* * as

in the Indonesia project. Plants are similarly arranged m parallel independent equipment

trains. However, the facilities are designed to

produce 105 percent of requireded yearly quantities in 330 days, thus, in theory, providing a

greater allowance for downtime than the Arun

plant (102 percent in 341 days). On the other

hand, the Arzew plant will have relatively less

storage space than the one at A run. Arzew will
82 ● The Future of Liquefied Natural Gas Imports

have three storage tanks, each with capacity of

100,000 m3

, to accommodate its 1,000 MMcf/d

production, compared to Arun’s four 125,000

m

3 tanks for the combined Pac Indonesia-Japanese production of 1,131 MMcf/d. Loading facilities are similar in both countries. Another common feature is sharing of equipment among

projects. The six proposed trains for Algeria 11

will share certain supporting facilities—such as

the cooling water system, steam system, and administration—with those already serving the Algeria I project, and the marine terminal will also

serve other future projects.

As can be seen from table 26, the estimated

capital cost of liquefaction and supporting faciliTable 26.—Capital Costs per Million Btu of

Daily Contractual Quantity

(1976 dollars/million Btu/day)

Pac Indonesia Algeria II

Pipeline from gasfield to

liquefaction plant . . . . . . . . . . . . $ 21 $ 360

Liquefaction, storage, and loading 1,117 1,134

Subtotal. . . . . . . . . . . . . . . . . . . . 1,138 1,494

Estimated interest on funds used

during construction . . . . . . . . . . 265 348

Total. . . . . . . . . . . . . . . . . . . . . $1,403 $1,842

SOURCE: Jensen Associates, Inc.

ties per million Btu of contracted daily production is comparable in both projects, reflecting

similar processes and equipment. Sonatrach estimates the total capital cost of its Arzew plant

at $1,276 million.

The most significant difference in the costs of

the two projects lies in the respective field and

pipeline systems. The Hassi R’Mel field, which

will Supply gas for the Algeria 11 project, * requires only 22 wells with an average depth of

7,054 ft to supply the contract quantity. In comparison the Indonesian Arun field requires 64

wells with an average depth of 11,483 ft, plus

special stream control equipment, to produce a

similar amount of gas. These factors influence

production costs, since, for example, drilling

costs rise almost exponentially with well depth.

Sonatrach has estimated that its field facilities

for Algeria 11 would cost $228 million.

While the Pac Indonesia project requires only

a 20-mile, 42-inch pipeline between the field and

the liquefaction plant, the cost of which would

be shared with the Japanese purchasers, Sonatrach plans to construct a 315-mile-long, 40-

inch-diameter pipeline exclusively for the Algeria II project between Hassi R’Mel and the liquefaction plant at Arzew. Gas turbines at five compressor stations will maintain the pressure and

flow. The estimated cost of the pipeline is $405

million, and as shown in table 26 the capital cost

it represents per million Btu of daily contracted

quantity is 17 times higher in the Algeria II project than in Pac Indonesia, reelecting the difference in the mileage. * Sonatrach estimates the

total construction funds to be $2,300 million,

and the annual operating cost at $60 million

(1976 prices).

Transportation facilities—cryogenic

tankers

Although they resemble conventional tankers

in many ways, LNG carriers are highly specialized, with designs strongly influenced by the

unique characteristics of LNG—especially its

low density, cryogenic temperature, and flammability. 12 The principal feature is extensive insulation of the tanks to minimize vaporization

en route and to protect parts of the ship’s structure that would be damaged by extreme cold.

For the actual arrangements of LNG shipping,

several alternatives are available. An importer,

or exporter, may own the vessels or operate

them through bare-boat charters, contracts of

affreightment, time charters, or leverage lease

arrangements. The proposed shipping arrangements for Algeria 11 and Pac Indonesia illustrate

two of these alternatives.

The Algeria 11 fleet would consist of 12 tankers, each with cargo capacity of 125,000 m3

. Six

of the vessels would be furnished by Sonatrach,
Ch. 4—Project Structure, Cost, and Financing ● 83

 e -

.

Photo credjt Marty Saccone

Modern LNG tankers typically carry 125,000 m3 of liquefied gas

the other six by El Paso Atlantic, presumably the fleet will transport 143 loads of LNG annualthrough indivual shipowners. IS

Each carrier will have an average service

speed of 18.5 knots and will be capable of completing the round trip voyage of about 10, I50

nautical miles between Arzew and the La Salle

terminal in an average of 28.4 days. With each

ship operating from 332 to 333 days per year,

ly, and a ship will arrive at the La Salle terminal

approximately every 2.5 days. The energy delivered by the LNG carrier fleet for use in the

United States will represent about 95 percent of

the quantity loaded at the Arzew terminal. The

small amount of vapor that boils off during the

trip is consumed as fuel in the ship’s boilers.

In addition to the double hull, other safety features of the carriers include a computerized collision avoidance system, bow thruster, lead-detection systems, dry-chemical and water firefighting systems, two complete navigational ra-
84 . The Future of Liquefied Natural Gas imports

dar systems, and five separate communication

svstems. 14 .

The estimated yard cost per vessel, constructed in a foreign shipyard—or in a U.S. shipyard, after construction differential subsidy*—

would be about $106.5 million at 1976 prices.

Other direct and indirect capital costs relating

to the vessels (see table 27) would bring the estimated capital investment per ship to $142.6 million. Shore-based facilities for all] 12 vessels

would be supplied by Atlantic at an estimated

cost of $40 million. Thus, assuming that the

same capital cost is required for Atlantic’s and

Sonatrach's vessels ($142.6 million per tanker),

the aggregate investment by Atlantic would be

$896 million, and $856 million by Sonatrach.

The total estimated capital cost for the Algeria II

tanker fleet would therefore amount to $1,752

million, or $l)639/MMBtu/d.

Operating costs of LNG vessels are a function

of trip distance. For Algeria 11, the total fleet operating expenses per year have been estimated

at $72.5 million (1976 prices). Atlantic's operating cost—for three foreign and three domestic

vessels--would amount to. about $38 million annually (see table 28). The corresponding expenses for Sonatrach’s vessels are expected to

be the same as those estimated for Atlantic’s foreign vessels, 15 and therefore would tot al about

$34.5 million. The total operating costs amount

to $(). 19/MIMBtu delivered in the Algeria 11 project.

The Pac Indonesia project involves a different

shipping arrangement. To transport the purchased LNG from North Sumatra to the United

States (8,300” nautical miles each way), Pac Indonesia has entered into contracts for the hire

Table 27.—Estimated Capital Requirements for

El Paso Atlantic—Six Vessels

(thousands of 1976 dollars)

of nine vessels. Three of the vessels have already been constructed in foreign shipyards,

and plans call for the remaining six to be built in

U.S. yards. All of the ships would be available to

Pac Indonesia under time charter agreements,

which provide for monthly billing beginning on

specified dates. The FPC’S administrative law

judge described these arrangements as follows:
Ch. 4—Project Structure, Cost, and Financing ● 85

Table 28.—Estimated Annual Operating

Expenses for El Paso Atlantic—Six Vessels

Thousands of

Operating expenses for six vessels 1976 dollars

Crew (3 foreign, 3 U.S.). . . . . . . . . . . . . . . . . . . . . .$ 8,172

Maintenance and repair. . . . . . . . . . . . . . . . . . . . . 5,856

Stores and supplies @ $103,000/ship . . . . . . . . . 618

Bunker “C” fuel @ $1,371,000/ship . . . . . . . . . . . 8,226

Nitrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 354

Annual insurance premiums. . . . . . . . . . . . . . . . . 8,484

Post charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,484

Shoreside expenses . . . . . . . . . . . . . . . . . . . . . . . 3,527

Manning agent (3 foreign ships only). . . . . . . . . . 42

Miscellaneous expenses @ $29,000/ship . . . . . . 174

Estimated total annual operating expenses ... .$37,937

SOURCE. El Paso Atlantlc Company, Economics of Shipping A/ger/an LNG to

Texas Gulf Coast, Oct 11, 1976

accident or damage to the vessel, breakdown of

the vessel’s machinery, deficiency of men or

stores). These risks are thus borne by the shipowners, not Pac Indonesia. 16

The capacity of each vessel will be about

125,000 ms

, the industry’s current standard.

Each carrier will be scheduled to operate 345

days out of the year (as opposed to 332 to 333 in

the Algeria II project) leaving the balance of the

year for shipyard repairs and miscellaneous delays. At an average speed of 18.5 knots, each

ship will require 18.7 days for the 8)300 nautical-mile voyage from Indonesia to the United

States and will be able to complete 8.5 round

trips per year. The energy delivered to the

United States will be approximately 92 percent

of the quantity loaded at the A run terminal, reflecting fuel use of boil-off vapors during the

vovage.

.

To illustrate how the shipping distance affects

costs, the capital and operating costs per vessel

on Pac Indonesia’s project are assumed to equal

the corresponding costs for Algeria II. Under

such an assumption, the shipping costs per million Btu of LNG delivered daily in the Pac Indonesia project would exceed by 42 percent the

equivalent costs in the Algeria 11 case, as a result

of the greater distance involved in the Inck)-

nesian project.

The capital costs of the three foreign ships

constructed in French shipyards* and chartered by Pac Indonesia are not publicly disclosed, but can be reasonably estimated at approximately $100 million per vessel. Pac Indonesia’s transportation contracts with U.S. shippers, concluded in late 1975, provide for charter rates based, in part, on the estimated capital

costs of $140 million per American-mack tinsel

plus escalations. The FPC judge used $155 million estimated average capital cost per U.S. vessel in establishing the shipping component of

Pac Indonesia’s initial certificate rate. This

figure represents the judge’s estimate (in

mid-1977) of the average cost for the six U.S.

tankers assuming a specified delivery schedule

between January 1980 and May 1981. The actual inflation in LNG tanker construction costs in

the United States turned out to be higher, judging by the current (mid-1979) total price estimate of about $195 million (after subsidy) per

125,000 m3 vessel to be delivered in 1982-83.

Receiving country terminal and

regasification facilities

A terminal for the receipt of LNG consists of

three major segments -unloading, storage, and

vaporization. The principal components of the

unloading portion of the terminal are berthing

facilities, unloading arms and lines, return

vapor lines and blowers, and prov’isions for handling excess vaporization due to boil off. The

storage facilities at the receiving terminal are

similar in type to those at the liquefaction plant.

“The regasification (vaporizing) equipment consists of liquid pumps and vaporizers. Regasification facilities represent much less sophisticated

technology than do the liquefaction plants in the

producing country. In terms of the total costs involved, the importing country’s facilities usually

account for the smallest portion of a three-part

LNG project. The design and construction of the

receiving terminal facilities require 2 to 3 years.

Pac Indonesia proposes the construction of an

LNG terminal on the southern California coast

approximately 3.5 miles east of Point [conception. * The plant will have an ultimate baseload

capability of 1,300 M Mcf/d, with peak \’aporiza-

.
86 c The Future of Liquefied Natural Gas Imports

Photo credit’ Courtesy of Colomb/a Gas System, Inc.., Consolidated Natural Gas Co, and American Petroleum Institute

LNG receiving terminal at Cove Point, Md. At the terminal LNG will be converted back into ordinary natural gas for

use by customers of the Columbia Gas System, Inc., and the Consolidated Natural Gas Company
Ch. 4—Project Structure, Cost, and Financing . 87

tion capacity of an additional 300 MMcf/d. The

Indonesian volume to be received at the terminal is estimated to be about 500 MMcf/d. The total baseload capacity will be shared by Pac Indonesia and Pacific Alaska LNG Associates (the latter proposes to import LNG from the Cook Inlet

area of Alaska).

The marine facilities will consist of one berth

located about 4,600 ft offshore. LNG from the

ship will be unloaded into the land-based LNG

storage tanks by onboard ship pumps. Three

550,000 barrel double-wall, insulated storage

tanks are planned for the terminal.

Thirteen seawater-heated LNG vaporizers will

be installed to accommodate the total baseIoad,

and peaking capacity of 300 Mcf/d will be provided by additional gas-fired LNG vaporizers.

The vaporization plant is designed to deliver natural gas continuously 365 days per year. The

gas will then go through a trim heater, odorizers, and metering station, before entering the

gas transmission system.

A 112-mile, 34-inch pipeline looped with

another 45-mile, 34-inch pipeline will extend

from the metering station at the terminal site to

a point of interconnection with PG&E’s existing

pipeline near Gosford, Calif., with an intervening interconnection with Southern California

Gas Company’s present facilities at North Coles

Levee. The present pipeline design requires no

compressor stations. 17

The total estimated capital cost of the Point

Conception terminal amounts to $632 million (in

mid-1977 dollars), and the annual operating

costs to $20 million—see tables 29 and 30 respectively. The estimated capital cost of the new

pipeline requires another $117 million (see table

31). On a strictly volumetric basis, the Pac Indonesia share will be over 58 percent, or $368 million for the terminal facilities and $68 million

for the pipeline. Pac Indonesia’s costs would be

higher if the facilities were built for the use of

this project alone. For instance, all storage tanks

would still be needed, due to the industry’s

practice of requiring that storage space be suffi-
88 ● The Future of Liquefied Natural Gas /reports

cient to accommodate at least two LNG shiploads. Pipeline costs also exhibit economies of

scale.

The Algeria 11 project involves the construction of the La Salle terminal in Matagorda Bay,

designed for a maximum sendout rate of 1.64

Bcf/d. Thus, unlike Pac Indonesia’s terminal, La

Salle would be serving only the Algeria 11 project. 18 The marine terminal consists of independent berths to accommodate two LNG carriers simultaneously. More storage will be available

than in Pac Indonesia’s terminal; three 629)000

barrel tanks. The estimated cost of the La Salle

terminal is $456 million (4th quarter, 1976),

which as table 32 indicates, amounts to a higher

cost per million Btu delivered than in Pac Indonesia’s project. This discrepancy is due primarily to the volumetric cost allocation for the Pac

Indonesia project, and only secondarily to the

physical differences between the two terminals.

Algeria II requires more extensive pipeline facilities on the receiving end than does Pac Indonesia. El Paso Natural proposes to build a pipeline capable of accepting 115 percent of the average daily output of La Salle terminal, or 1,065

MMcf. The first 31 miles of the new pipeline (36-

inch diameter) will transport the gas from the

La Salle terminal to United LNG’s present facilities near Victoria, Tex., where 35 percent of the

total quantity will be sold. The remaining 65

percent will be transported via a 432-mile (30-

inch diameter) pipeline to El Paso Natural’s system at Waya, Tex. Together with the required

five compressor stations, the new pipeline facilities are estimated to cost $263 million. As shown

in table 32, the pipeline cost per million Btu per

day is 37 percent of the total capital investment

in Algeria II import facilities, whereas similar

costs for the Pac Indonesia project are only 16

percent.

Table 32.–Capital Costs for Import Facilities per Million Btu of Daily Delivered Quantity of LNG

LNG financing

Because much of the cost of an LNG project is

incurred at the beginning of the project, and because an LNG project has a long economic lifetime, financing terms strongly influence the

unit cost (cost-of-service) of moving the gas from

the field to the market. This section examines

some of the major financing options open to

LNG project sponsors and then, incorporating

this information, derives an idealized cost-ofservice.

Overview

The fundamental determinants of financibility for any capital project are risk and return.

The important characteristics of an LNG project

affecting perceptions regarding risk and return

are:

● The total capital costs of an LNG project are

large, and the return is not certain.
Ch. 4—Project Structure, Cost, and Financing ● 89

●

●

Ownership of LNG projects is often spread

among parties in different countries.

Integrated LNG projects are comprised of

several stages (e.g., liquefaction, shipping),

each one possessing an individual identity.

To see how the scale of capital requirements

for an LNG project impacts financibility, it is

useful to put the capital requirements in perspective. The estimated costs of the proposed

Algeria 11 project total over $5 billion from wellhead to final consumer. By comparison, total

U.S. net private fixed investment in 1978 was

only $128.7 billion, * and this for the largest

economy in the world.

Photo credit. El Paso Co

Natural gas transmission lines may be seen above-

-ground in remote areas, but most of the Nation’s

pipeline system is underground

Because capital requirements are so large,

project sponsors may have to look to several

capital markets for funding, simply because the

total exposure would be too large for one market to absorb. By using several capital markets

and many lenders, project sponsors can diffuse

the large financial risk of the project and

thereby reduce borrowing costs. However, the

use of several capital markets (or, for that matter, large financing in one capital market) may

entail substantial transactions costs, offsetting

the gains achieved through this strategy and, in

fact, ultimately limiting the degree of diversification that is economically feasible.

Transaction costs incurred through diversification may take several forms. The requirement

for documentation alone can be significant. In

the U.S. institutional market, for example, each

of several separate bond issues underwritten

and offered publicly could require a separate

prospectus and indenture, demanding significant outlays for legal, accounting, and possibly

technical services. Transactions costs may also

take the form of decreased flexibility. Restrictive covenants required in one capital market

on, say, an issue of unsecured bonds may limit

the project sponsors’ freedom in obtaining financing in other markets.

In addition to the high transaction costs of reliance on many sources for financing, the size of

the project ultimately limits the capacity of capi-
90 ● The Future 0f Liquefied Natural Gas Imports

tal markets to absorb the risk. Whereas a modestly sized capital investment can be divided

among many investors so as to represent only a

small portion of any single portfolio, an LNG

project is sufficiently large that enough lenders

may not be available to distribute the risk adequately.

A second major factor influencing financibility is the international character of LNG

projects, since financiers look to the contracts

among the parties for security. Since the contract signatories are typically domiciled in different countries and, perhaps more fundamentally, since their physical facilities are located in

different countries, no one legal jurisdiction can

enforce the claims of one party against another.

A third factor is the multistage nature of the

LNG project, and separate stages of the LNG

project may have access to different capital

markets for several reasons. First, for facilities

to be owned, for example, by the producing

country, officially supported credits may be

available from countries desiring to promote exports from their own construction and capital

goods industries. A second reason is that potential lenders may have different attitudes toward

risk depending on the stage. An LNG import terminal, for example, can be used efficiently for

one purpose only: the receipt, storage, and regasification of liquid gases at the location where

the terminal is built. If the project fails because

of, say, market conditions in the importing

country, the terminal just sits there generating

capital charges. The LNG carriers, on the other

hand, if prohibited from offloading at the inoperative terminal can still be used in an L N G

trade somewhere else. Thus, the potential investors might perceive less risk attendant on

LNG carriers than on an import terminal.

The following sections examine, in light of

these general considerations, some of the financing options open to the sponsors of LNG

projects, with a particular view toward their effects on project cost. The discussion is organized by production stage: first, exporting country facilities, then ships, and finally, U.S. import

terminals. For each stage, the discussion of financing focuses on the debt requirements, and

the section on the financing of exporting country facilities includes overall project equity.

Exporting country facilities

Total capital requirements for exporting facilities may vary considerably with differences in

gasfield characteristics, distance of field from

the plantsite, cost of local labor, and other variables, but for a project of 1 Bcf/d the total cost of

all exporting country facilities is likely to be well

over $1 billion, and may exceed $2 billion.

The total cost of the facilities may be financed

with the credit backing of the exporting country

itself, as in the case of the Algeria 11 project, by

outside participants, such as multinational oil

companies, or a combination of both. While

“project” financing, for which the security is the

value of the specific facilities or contractual obligations associated with the project itself, may be

possible in concept, financing is not likely to be

obtained in this way without independent credit

support.

Major sources of capital for producing country facilities include the eurocurrency market,

private and public equity, and in the case of exporting country ownership, officially supported

export credits. Each of these sources are discussed below.

OFFICIALLY SUPPORTED EXPORT CREDITS

Several Organization for Economic Cooperation and Development (OECD) countries have

officially supported export credit programs,

which supply direct loans and credit guarantees

to promote their industries. This tied financing

offers some important advantages to the LNG

exporting country. While some export credit

programs, such as those of the United States

and Germany have tended to be on basically

commercial terms, other countries, such as

France, Japan, and the United Kingdom offer

preferential–if not concessionary–credit supports. The lower cost of the financing available

from some countries improves the economic viability of the project from the point of view of

the producing country and also lowers the costof-service. A second advantage of officially supported export credits is that other potential
Ch. 4—Project Structure, Cost, and Financing ● 91

lenders to the project may feel more secure in

their investments with the participation of official government agencies, and in any event,

will perceive that the lower cost of funds

available through export credit financing provides additional capacity to service private debt.

France, through its foreign trade bank BFCE

(Banque Francaise du Commerce Exterieur),

provides financing for long-term maturities

through either direct credits at subsidized rates

or through discount and refinancing arrangements. The rate on the BFCE direct credit, or

discount on the subsidized portion of the bank

loan, is set by BFCE so that the blended rate, *

exclusive of fees and premiums, is at the minimum allowed under the OECD arrangement. * *

In addition, Coface (Compagnis Francaise d’Assurance pour le Commerce Exterieur) guarantees the total amount of the credit (BFCE plus

private portion) for a rate premium of approximately 0.85 percent.

In some cases, however, the French “mix”

credits by tying aid and loans together in one

package. Such tied-aid credits may include loans

at rates as low as 3.5 percent with repayment

terms up to 20 years. The average cost of such a

package is therefore considerably less than it

would be in a strict export finance deal.

Japan, through the Ministry of International

Trade and Industry and its Export-Import Bank,

also provides long-term finance packages on

preferential terms. As France’s BFCE, Japan’s

Export-Import Bank will extend direct credits,

up to 60 percent of the total export financing, so

that the blended rate is at or near the minimum

allowed by the OECD arrangement. As with

Coface, their Export-Import Bank provides insurance for its own and the private loan portions of the total credit for a premium.

Japan has officially denied that it offers tiedaid credits to an extent that would derogate the

OECD arrangement. However, some claim that

tied-aid credits on essentially concessionary

terms are widely available for export financing

from Japan.

The United Kingdom through ECGD (Export

Credits Guarantee Department) sets rates for

commercial bank loans to buyers and pays a direct interest subsidy to banks to make up for

the actual cost of funds. To relieve the overall

credit burden this creates, ECGD also provides

limited refinancing for sterling denominated

loans used for export financing. ECGD guarantees 100 percent of the bank loans, and the rates

set by ECGD are, as in the case of France and

Japan, at or near the minimum allowed under

the OECD arrangement. British tied-aid credit financing is also available.

The United States and Germany are more conservative in their approach to export financing.

Historically neither country has typically offered tied-aid financing of exports. In addition,

both countries operate their respective export

programs without recourse to subsidy–in the

case of Germany only a modicum of direct credits are even provided at long-term and preferential rates, the bulk of long-term credit support

taking the form of insurance.

The United States through the Export-Import

Bank (Eximbank) and related organizations such

as the Private Export Funding Corporation, provides support for long-term export credits. Historically, Eximbank has provided direct credit at

rates linked to the agency’s cost of funds and

has guaranteed the private bank portions of the

total credit, which are usually extended at floating rates. Eximbank typically charges a guarantee fee on the private bank portion.
92 The Future of Liquefied Natural Gas Imports

Recently, however, U.S. Eximbank policy has

begun to favor improving competitiveness with

foreign export agencies. This policy shift is reflected in the tendency toward increased direct

coverage at reduced rates. In so-called exceptional cases, Eximbank may offer a direct credit

for the total amount of the export credit (85 percent of the contract cost of the goods and services) at rates below the agency’s marginal cost of

funds.

An example of the use of export credit is the

U.S. Eximbank’s $240 million credit to Algeria to

help finance $320 million U.S. goods and services component of the Arzew 11 liquefaction

plant. The credit was extended to Sonatrach at

8.5 percent. Repayment is in 20 semiannual payments beginning 6 months after the last of six

liquefaction trains is completed. The remainder

of the U.S. goods and services component is to

be financed by a Sonatrach payment of $48 million (15 percent) and private-source loans of $32

million. Payments on the total of the Eximbank

credit and the private source loans will be arranged in such a way that the private-source

loans are paid off first.

THE EUROCURRENCY MARKET

Another important source for financing of

LNG exporting country facilities (whether

owned by the country in question or by outside

parties) is the eurocurrency market, in which

loans are negotiated in currencies not native to

the country in which the bank offering the loan

is located (eurocurrency bank credits) and

bonds are issued outside the country of the borrower (international bonds). The size of this

market is substantial. In 1978 alone, over $70

billion in eurocurrency bank credits were negotiated, and new international bond issues totaled $35 billion. In 1978, Algeria, a major LNG

producing nation, borrowed over $3 billion on

the eurocurrency market, while Indonesia,

another important LNG center, borrowed over

$1 billion.

An important feature of the eurocurrency

bank credit market is that its funding tends to

be for periods of no more than 5 to 10 years.

Also, loans on this market typically have floating

interest rates. So, for example, a loan on this

market with a repayment term of 8 years might

carry an interest rate of 1.75 percent over

LIBOR (the London interbank offering rate, a

measure of the bank’s cost of funds), reflecting

maturities of 6 months. At the end of each 6-

month period, the loan is effectively renewed

for the amount of principal still outstanding at

an interest rate corresponding to the then- current LIBOR.

One of the main advantages of the eurocurrency bank credit market is that with sufficient

credit backing, such as the guarantee of the

Central Bank or Development Bank of the potential LNG exporting country, considerable

funds are available on this market. A second advantage is that credit obtained on this market,

and private-source capital in general, tends to

have fewer strings attached than, for example,

the tied loans available through officially supported export-financing agencies.

Two important disadvantages of this market

are the shortness of the repayment periods and

the variability of the interest rates. The economics of large projects with long lifetimes sometimes are not certain until late in the project,

and if the loan must be amortized over too short

a period at the beginning, debt service may exceed the available cash flow after deduction of

other expenses. In such an instance, borrowing

from equity is required, and to the extent that

this is expensive or simply not feasible, other

financing arrangements are necessary,

The variability of interest rates on eurocurrency bank credit also adds a dimension of uncertainty to the management of cash flow and to

the overall economics of the project. owners of

long-term projects may be willing to pay a considerable premium to remove this element of

uncertainty.

An example of eurocurrency bank credit is

the $250 million 7-year loan raised by Sonatrach, guaranteed by the Banque Nationale

de’Algerie, and jointly led by Citicorp, Bank of

America, Apicorp, Bankers Trust, Bank of Montreal, and Continental Illinois. This loan carries

an interest rate of 1-3/8 percent over LIBOR and

will help to finance the Arzew II liquefaction

plant facilities.
Ch. 4—Project Structure, Cost, and Financing ● 93

Fixed interest rate financing is also possible on

the euromarket through the issue of bonds or

notes. These international bonds, which are

comparable in terms of maturity with eurocurrency bank credits (5 to 10 years), can provide

added cash flow predictability at a minimum

cost.

Examples of eurobonds are two recent Sonatrach issues, one 12 million dinars (DA) guaranteed by the Banque Exterieure d’Algerie, maturing in 10 years, bearing a yield of 8.5 percent;

and one DA 8 million 5-year maturity bearing

8.5 percent.

PUBLIC AND PRIVATE EQUITY

A third important element of financing for

LNG exporting country facilities is public and

private equity. Equity capital can be generated

by reinvestment of earnings, such as profits

from a country’s other hydrocarbon ventures or

the net revenues from unrelated operations of a

multinational oil company; or alternatively,

through the issue of ownership shares, as exemplified by the Islamic Development Bank’s

equity participation in Jordan’s petroleum refinery project. Equity can be public, resulting

from taxation or earnings on public enterprises;

or private, supplied by ownership of shares by

private entities.

Generally, lenders require some equity as a

buffer in the event of difficulties, but it can

dilute ownership and is typically more expensive than debt. The U.S. Eximbank, for exampIe

requires a 15-percent cash payment by the

buyer of U.S. export goods. This 15-percent may

be funded by equity or debt or both, however,

and this 15-percent should therefore not be

viewed as necessarily bearing “true” equity

costs.

CONCLUS1ON

Whether the project owners are to be the exporting country itself, an outside entity, or a

combination, many financing options are available as described above. Nevertheless, certain

constraints should be recognized. The availability of officially supported export credit financing at preferential or concessionary rates may

depend on who owns the producing country facilities. In addition, while project financing is

possible in principle, it is rare in practice, and

consequently, the total cost of the financing

may exceed the prima facie cost of the borrowings because of the impact on the debt capacity

of the guarantor.

Shipping

Many of the private capital markets for the financing of exporting country facilities are open

also for LNG ships. In addition, as in the case of

the exporting country facilities, officially supported financing is available for LNG shipping

and may be provided by export credit agencies

such as Germany’s Hermes (Hermes Kreditversicherung) or by other government agencies

such as the U.S. Maritime Administration

(MarAd).

MarAd offers a loan guarantee program applicable to LNG ships if they are built in U.S.

shipyards, registered under the U.S. flag,

owned by U.S. entities, and crewed by U.S. citizens. Under these conditions, as much as 87.5

percent of the total cost of a ship can be financed by an issue of U.S. Government guaranteed serial or sinking fund bonds, either with

maturities up to 25 years. The cost to the borrower is the yield on the bonds plus the MarAd

guarantee fee (0.5 to 1.0 percent of the outstanding balance), amounting to a total in the

range of a Baa industrial.

The MarAd program is not subsidized, though

default claims are paid from a pool funded by

MarAd’s overall operations. Consequently, the

public does not contribute directly to defraying

the cost of funds to borrowers using MarAd

credit guarantees. However, the MarAd guarantee is valuable to potential borrowers in the

sense that MarAd may be better able to spread

the risk in ship financing than private capital

markets. In addition, the ability to issue U.S.

Treasury-backed bonds affords shipowners access to other capital markets that, because of institutional or legal barriers, would otherwise be

closed. Another advantage of the MarAd program is long repayment terms of up to 25 years,

although the maximum term might be unusual

in the case of a LNG ship.

If the owners of the ships are to be foreign to

the country where the ships are built, officially
94 ● The Future of Liquefied Natural Gas Imports

supported export credits may be available. Important LNG ship-exporting countries in the

OECD include France, the United States, Italy,

and Norway. Financing terms are determined

by the individual countries in accordance with

the OECD Arrangement on Ships, which supersedes the Arrangement on Guidelines for Officially Supported Export Credits in the case of

shipping and sets a minimum interest rate of 7.5

percent, a maximum repayment period of 8

years, and a maximum coverage of 80 percent

of ship cost.

While the interest rate allowed on officially

supported export credits for ships is preferential, the shortness of the repayment period constitutes a disadvantage of this type of financing.

The heavy debt requirements during the early

years of the project can, depending on the pricing or tariff provisions governing cash flow,

effectively postpone repayment of expensive

equity capital.

U.S. facilities

The cost of U.S. facilities, including the

marine terminal, LNG storage tanks, vaporization units, and transmission lines to deliver the

gas, can vary widely depending on location and

design. The proposed La Salle terminal facilities

and delivery lines to E] Paso United’s system

were estimated to cost approximately $700 million, while the proposed Tapco project, sponsored by Tenneco to bring LNG from Algeria

into New Brunswick, Canada and then to the

United States through a longer pipeline, would

have cost nearly $1.5 billion.

In the past, construction of U.S. facilities has

been accomplished through the credit of financially strong corporations. Examples include

Southern Natural Gas Company’s Savannah, Ga.,

terminal and the planned Trunkline terminal at

Lake Charles, La. Each of these facilities is

owned and operated by a subsidiary of a major

U.S. interstate pipeline company, and debt issues to finance LNG terminals are carried in

both cases on the balance sheets of the parents,

which provide substantial credit support.

Southern’s Savannah terminal illustrates

another feature of U.S. financing, the taxexempt bond market. Section 103(B)(4)(D) of the

U.S. Internal Revenue Code, which relates to

docks, wharfs, and storage facilities, may allow

the issue of debt securities that are exempt from

Federal, State, and local income taxes. For this

type of issue, the market yield cost to the borrower is less. Southern’s Savannah terminal, for

example, was financed partly through the issue

of tax-exempt revenue bonds by the Savannah

Port Authority. These bonds were marketed at

a price of 99.75 percent of par and with a coupon rate between 5.7 and 6.75 percent, depending on the maturity (serial and sinking fund

bonds were in combination to permit full amortization by equal payments over the lifetime of

the financing). At the time of the prospectus,

Aaa bonds were yielding around 9.5 percent,

considerably more than the Savannah Port Authority bonds.

Conclusion

The financing options open to LNG import

sponsors are strongly influenced by the magnitude of total capital requirements, as well as the

international character and multistage nature

of the projects. Generally, private capital markets are open to sponsors with strong credit

support, but financing costs may be high because of sheer scale.

In addition, low-cost subsidized financing is

available for particular stages of the project,

depending on such factors as ownership, location, the country supplying construction and

materials, and taxes. Also financing costs may

be high due to regulatory incentives, for example, to finance U.S. facilities independently. The

next section examines the effects of alternative

financing arrangements on the unit cost (costof-service) of moving gas from a remote source

to U.S. markets.
Ch. 4—Project Structure, Cost, and Financing ● 95

Cost-of-service

The cost-of-service calculated by project stage

for a hypothetical world-scale LNG project (approximately 1 Bcf/d), idealized in economic and

financial structure, is described below. This cost

was defined as the sum, for a particular year, of

operating costs, capital costs (debt and equity),

and taxes divided by the Btu’s delivered into the

U.S. pipeline system. The procedure allowed

direct comparison by project-stage in terms of

units ultimately delivered, and at the same time,

allowed determination of the wellhead value of

the gas given the price in the U.S. market, since

fuel and loss is included in the cost-of-service.

The capital charge (service on debt and equity) was assumed to be level in constant dollars

over the lifetime of the project and was calculated so that the net present value of the shareholders’ cash flow would equal zero at the assumed discount rate.

Also, the cost-of-service estimate here differs

from what would be typical in a regulatory proceeding in that the cost of gas expended as fuel

and loss was determined at the ultimate netback

wellhead value, while a “regulatory” calculation

usually assumes the value of fuel and loss to reflect a fixed price, for example, the contract sale

price f.o.b. the point of export. An advantage of

valuing the fuel and loss at the ultimate wellhead netback, is that it allows direct comparison

of the cost-of-service of LNG projects with the

cost-of-service of alternative technologies to

move gas from the wellhead to the market. A

peculiarity of this approach is that since capital

and nonfuel operating costs affect the ultimate

wellhead netback, the value of fuel and loss depends, in part, on these other components.

Base case

Parameter values for the base case cost-ofservice calculation were derived largely from

the testimony in recent LNG proceedings. This

calculation was performed for a project starting

in 1985, and costs were escalated to reflect the

difference in timing between the idealized base

case and recent proposals. The assumed 3,736

nautical miles approximates the shipping distance from Algeria to the United States. For

complete enumeration of all parameters, see

volume II (working papers).

For U.S. facilities, the financing was assumed

to reflect current market rates and terms for

large projects in U.S. capital markets on the balance sheets of gas utility companies. For shipping, MarAd financing was assumed with an interest rate in the vicinity of Baa industrial bonds

and a repayment term of 15 years. Exporting

country facilities were assumed to hav’e access

to export credit financing programs for the bulk

of their financing, and rates and terms represented here are those for the recent U.S. Eximbank credit to Algeria to help finance the Arzew

II liquefaction plant. The assumed rate of return

on equity is 17 percent.

Tables 33 and 34 show the results of a representative base case cost-of-service calculation,

expressed in constant 1978 dollars. As can be

seen, the bulk of the costs are in shipping and

liquefaction. Also fuel and loss represent a significant portion of the total and, for liquefaction, actually exceed the capital and operating

cost component. Overall, taxes constitute less

than 10 percent of the fifth year cost-of-service

for this idealized project. However, much of the

debt service is loaded toward the front end of

the project and since interest payments are deductible, taxes as a fraction of the total cost-ofservice increase over the lifetime of the project,

as shown in figures 17 and 18.

Sensitivity

The sensitivity of the cost-of-service to

changes in the debt ratio on U.S. facilities and

the repayment period for ship financing, and to
96 The Future of Liquefied Natural Gas Imports

Table 33.—Cost of Service of an LNG Project Beginning in 1985 in the Fifth Year of Operation”

(1978 dollars/million Btu delivered into U.S. pipeline system)

Capital and operating . . . . . . . . $0.226 $0.656 $0.564 $0.273 $1.719

Fuel and loss . . . . . . . . . . . . . . . 0.084 0.659 0.091 0.101 0.935

Income taxes . . . . . . . . . . . . . . . 0.053 0.106 0.038 0.017 0.214

Total cost-of-service. . . . . . . $0.363 $1.421 $0.693 $0.391 $2.868

statute miles

SOURCE Jensen Associates, Inc.

Figure 17.— LNG Cost of Service by Project Section

3.00

t

2.00

1.00

0 [

1;84 85 86 87 88 89 90 91 92 93 94 95

Year

SOURCE Jensen Associates, Inc

setting the interest rate on all debt at 12 percent

is relatively insignificant. These changes produced a net cost increase of $0.05 /MMBtu. However, the cost-of-service is more sensitive to

changes in the return on equity in all portions of

the project and to changes in the U.S. debt inter4.00

3.00

2.00

[

1984 85 86 87 88 89 90 91 92 93 94 95

Year

SOURCE. Jensen Associates, Inc.

est rate, Tables 35 and 36 show the effect of increming and reducing the return on equity and

the interest on U.S. debt by 2 percent. The effects are symmetrical, changing the total

charges, excluciing fuel and loss, by about

$0.21 /MMBtu (1978 dollars) or approximately 10

percent. However, when the fuel effects, which

offset the gross changes in capital and operating

cost portions of the project, are included, the

net effect is a change of about $0.16/MMBtu

(1978 dollars) or approximately 6 percent in the

total cost-of-service in the fifth year of operation

of an LNG project. Cost-of-service calculations

for shipping were based on an average distance

of 7,472 nautical miles. Tables 37 and 38 show

that when the distance is reduced by one-half or

doubled, the effect on the cost of shipping is in

the same proportion. However, the netback val-
Ch. 4—Project Structure, Cost, and Financing ● 97

Table 35.—impact of Fifth Year Cost of Service of Reducing Return on

Equity to 15 Percent and Interest on U.S. Debt to 10 Percent”

(1978 dollarsl million Btu ultimately delivered)

Field and pipeline

U.S. facilities Shipping Liquefaction plant facilities Total

Reduced return capital costs,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . $0.246 $0.546 $0.691 $0.244 $1.727

Base case capital costs,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . 0.290 0.602 0.763 0.279 1.934

Gross change in cost of

service . . . . . . . . . . . . . . . . . . (0.044) (0.056) (0.072) (0.035) (0.207)

Reduced return fuel and loss. . 0.106 0.095 0.692 0.088 0.981

Base case fuel and loss . . . . . . 0.101 0.091 0.659 0.084 0.935

Change in fuel and loss

component. . . . . . . . . . . . . . . 0.005 0.004 0.033 0.004 0.046

Net change in cost of service. . (0.039) (0.052) (0.039) (0.031) (0.161)

Table 36.—impact of Fifth Year Cost of Service of Increasing Return on

Equity to 19 Percent and Interest on U.S. Debt to 14 Percent”

(1978 dollarsl million Btu ultimately delivered)

Field and pipeline

U.S. facilities Shipping Liquefaction plant facilities Total

Raised return case capital

charges, operating costs,

and income taxes . . . . . . . . . $0.337 $0.662 $0.833 $0.314 $2.146

Base case capital charges,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . 0.290 0.602 0.763 0.279 1.934

Gross change in cost of

service . . . . . . . . . . . . . . . . . . 0.047 0.060 0.070 0.035 0.212

Raised return case fuel and

loss . . . . . . . . . . . . . . . . . . . . . 0.096 0.086 0.626 0.080 0.888

Base case fuel and loss . . . . . . 0.101 0.091 0.659 0.084 0.935

Change in fuel and loss

component. . . . . . . . . . . . . . . (0.005) (0.005) (0.033) (0.004) (0.047)

Net change in cost of service. . 0.042 0.055 0.037 0.031 0.165

aFrom 17 and 12 percent respectively.

SOURCE. Jensen Associates, Inc

ue of the gas and thus the cost of fuel are reduced, which tends to offset the changes in capital and operating costs. Another effect of shortening shipping distance is a reduction in the

amount of LNG boiled-off and used as transportation fuel. Consequently, less LNG needs to be

loaded at the liquefaction plant to maintain the

same deliveries to ultimate destinations. For this

reason, liquefaction plants and field and pipeline facilities can be reduced somewhat in scale,

as shown in table 37. on the other hand, increasing shipping distances will produce the opposite effects.

Ironically, the total fuel and loss portion of the

cost-of-service for the short voyage case is higher than for the base case and similarly, total fuel

and loss for the long voyage case is lower than

for the base case. This result is contrary to what

one would expect but comes about because of

the convention adopted in this analysis, that the

cost of fuel and loss is calculated at the netback

S9-406 O - 80 - 8
98 ● The Future of Liquefied Natural Gas Imports

Table 37.—impact on Fifth Year Cost of Service of Reducing

the Round Trip Voyage Distance to 3,274 Nautical Miles’

(1978 dollars/million Btu ultimately delivered)

Field and pipeline

U.S. facilities Shipping Liquefaction plant facilities Total

Short-voyage capital charges,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . $0.290 $0.300 $0.754 $0.276 $1.620

Base case capital charges,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . 0.290 0.602 0.763 0.279 1.934

Gross change in cost of

service . . . . . . . . . . . . . . . . . . . — (0.302) (0.009) (0.003) (0.314)

Short-voyage fuel and loss. . . . 0.110 0.053 0.709 0.090 0.962

Base case fuel and loss . . . . . . 0.101 0.091 0.659 0.084 0.935

Change in fuel and loss

component. . . . . . . . . . . . . . . 0.009 (0.038) 0.050 0.006 0.027

Net change in cost of service. . 0.009 (0.340) 0.041 0.003 (0.287)

aBase case distance IS 7,472 nautical miles.

SOURCE: Jensen Associates, Inc

Table 38.—impact on Fifth Year Cost of Service of Increasing

the Round Trip Voyage Distance to 16,694 Nautical Miles’

(1978 dollars/million Btu ultimately delivered)

Field and pipeline

U.S. facilities Shipping Liquefaction plant facilities Total

Long-voyage capital charges,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . $0.290 $1.294 $0.784 $0.287 $2.655

Base case capital charges,

operating costs, and income

taxes. . . . . . . . . . . . . . . . . . . . 0.290 0.602 0.763 0.279 1.934

Gross change in cost of

service . . . . . . . . . . . . . . . . . . —— 0.692 0.021 0.008 0.721

Long-voyage fuel and loss . . . . 0.082 0.149 0.546 0.070 0.847

Base case fuel and loss . . . . . . 0.101 0.091 0.659 0.084 0.935

Change in fuel and loss

component. . . . . . . . . . . . . . . (0.019) 0.058 (0.1 13) (0.014) (0.088)

Net change in cost of service. . (0.019) 0.750 (0.092) (0.006) 0.633

value at the wellhead. Since most of the fuel is value at the wellhead and thus the cost of fuel

used in the liquefaction plant, the short voyage and losses. When the shipping distance is reraises the netback value of the fuel and loss duced by half the total cost-of-service for the

which in turn increases the fuel and loss prices project is reduced by 10 percent, and when the

at the liquefaction facility. The opposite is true distance is doubled, the cost-of-service is inwhen LNG is shipped over long distances. High- creased by 22 percent.

er capital costs of boil-off reduce the netback
Ch. 4—Project Structure, Cost, and financing 9 9

Financial risk

Because of the size and complexity of LNG investments as well as the unpredictability of future events during a project’s life, the nature

and distribution of financial risk and uncertainty are important to consider. From a government policy standpoint, public exposure deserves particular attention.

Individual investments in single liquefaction

facilities, import terminals, or ships separate

from integrated projects are not yet possible,

except perhaps in Japanese trades. In the future, if more trade develops and facilities become more widespread, such investments will

occur. But now only a complete project with

long-term contractual commitments and simultaneous construction of liquefaction facilities,

ships, and the receiving/regasification terminal

is economically feasible.

The money invested in LNG projects is at risk

from a variety of perils, including technical feasibility, project failure, project interruption or

delay, cost overruns, and market uncertainties.

These problems are described below and illustrated in a discussion of the proposed Pac-Indonesia project.

Technical feasibility

The financiers of an LNG project are first interested in its technical feasibility, which they

assess in historical terms. In January 1959, the

first shipload of LNG left Lake Charles, La., on

the Methane Pioneer and arrived at Canvey

Island, England—near London. This shipment

was part of a project sponsored by the British

Gas Council, Continental Oil Company, and

Union Stockyards to test equipment and to examine the feasibility of international LNG trade.

In 1964, the first baseload, long-term commercial project started with shipments from Arzew,

Algeria, to Canvey Island and Le Havre, France.

Today 12 LNG projects are in operation, and the

technical and economic feasibility of the technology has been demonstrated. Several shipyards and engineering/construction firms have

shown their ability to build reliable LNG ships

and facilities. Technical and construction risks

are perceived as no greater than those for other

large sophisticated international engineering

and construction projects.

Project failure

Of greatest concern to the owners and financiers of an LNG project is the possibility for project failure after significant amounts of money

have been spent. For example, the Eascogas

Project, which was to bring LNG from Skikda,

Algeria, to the east coast of the United States,

was originally expected to begin some years

ago. A receiving terminal at Staten Island was

completed at a cost of over $100 million (1974

dollars), and two ships intended for the project

were built at the General Dynamics shipyard at

Quincy, Mass. Government authorities in the

United States have refused to allow operation of

the Staten Island terminal, which is now a complete financial loss unless the facilities are used

to store LNG for peak shaving. One of the ships

has subsequently been incorporated into an

LNG trade from Indonesia to Japan while the

other is unemployed, and thus far a loss to its

owners.

As mentioned earlier, some supply contracts

contain explicit provisions for periodic review

of prices, while others may have to be renegotiated under changed circumstances because the

parties are in separate countries not governed

by a common legal jurisdiction. In either case,

although producers and purchasers both face

substantial incentives to come to terms, negotiations could conceivably break down after the facilities have been built and put into operation.

Project failure can also occur if facilities are

destroyed by natural causes, civil strife, or war,

or if a major change in attitude within one country causes project termination. For example, the

Khomeini government in Iran is reported to

have canceled the IGAT 11 project scheduled to

sell gas to the U. S. S. R., which would in turn sell

gas to Czechoslovakia and gas companies in Germany, France, and Austria, beginning in 1981.

Unfortunately, Iran canceled the project after

considerable investment in pipelines.
100 ● The Future of Liquefied Natural Gas Imports

Project interruption or delay

Technical problems can delay or interrupt

LNG projects. Normally, when any complex

plant starts up, problems arise. In LNG liquefaction plants, typical problems include clogging of

cooling water intakes by sand, seaweed, jellyfish, or debris; failures in the blading in turbines, compressors, or pumps; fouling of heat

exchangers on the water side due to buildup of

algae; clogging, possibly by ice, of spray rings,

for cooling the storage tanks; or bearing failures

in pumps. 19

However, other technical problems can cause

longer delays or force cessation of LNG projects,

causing severe financial impacts. For example,

when the Libyan LNG plant was first started in

1969, several problems arose in the pipeline

bringing gas to the liquefaction plant, resulting

in additional delay of over a year. Libya also interrupted the LNG project by government edict

when negotiations over prices broke down.

In another case, the main heat exchangers in

the liquefaction train of the Skikda, Algeria,

plant were shut down for extended periods due

to a combination of mechanical wear caused by

vibration, which ruptured heat exchanger

tubes, and corrosion caused by mercury in the

heat exchangers.

Delays have also occurred in ship construction, and at least two yards have been unable to

fabricate the LNG containment systems on

schedule. However, a surplus of LNG ships,

some in layup and awaiting employment, could

compensate for delays in the construction of

new ones.

Cost overrun

The cost of any project, especially during an

inflationary period, can be greater than anticipated. If construction costs rise too fast and financing for the overrun cannot be found, the

project will not be completed and all investments are lost. More likely, the project will be

completed with added financing, but the cost

overrun must ulimately be borne by someone.

Operating costs can also exceed expectations

and cause either the sales price to rise or the

earnings of project sponsors to fall.

Market uncertainties

Since the projects involve long-term contracts

and investments, losses will result if the LNG

should not be marketable up to 20 years in the

future at prices that cover the sponsors’ costs.

Factors that contribute to uncertainty in this

area are the possibility of increased domestic

fuel production and conservation, the unpredictability of long-term economic growth rates,

the unknown future course of world oil prices,

possible changes in regulatory policy, and the

outcome of any supply contract renegotiations.

Who bears the financial risk?

The costs of project failure, operating or capital cost overruns, supply interruption or reduction, damage to facilities, or adverse governmental decisions, are borne by the various parties in an LNG project. These parties are the

owners of the liquefaction plant, the ships, and

the receiving/regasification terminals; the lenders to the project; the guarantors of financing;

the various governments who tax or otherwise

receive revenues from the project; the insurers

of the facilities; and the consumers of the regasified LNG. The distribution of risk is determined

by contracts among the parties; the financing

agreements binding owners, lenders, and those

who guarantee financing; the tariffs established

by regulatory agencies; tax codes; and insurance agreements. The precise way in which

these contractual instruments and tariffs divide

the risk will vary according to negotiations and

regulatory decisions which take place when the

project is financed.

In order to reduce the capital costs of the project and thus increase profits and reduce the final price of LNG to the consumer, a substantial

portion of the investments need to be financed

by lenders who provide long-term loans at modest rates of interest. Lenders include banks, insurance companies, and governmental finance
Ch. 4—Project Structure, Cost, and Financing . 101

organizations such as MarAd and Eximbank,

and their need to minimize exposure strongly

shapes the risk distribution of an LNG project.

Banks and insurance companies lend other peoples’ money, that of their depositors, other creditors, or policyholders, and they are obliged to

repay in full. Therefore, lenders, especially private banks and insurance companies, want their

money back no matter what happens to the LNG

project. They insist on guarantees of loan repayment from creditworthy parties, who can be

governments, natural gas consumers through

“all events” tariffs, * or large corporations with

ongoing businesses out side of the LNG project.

The owners of the project, who provide the

equity capital, money which is their own, will

typically absorb more risk in an LNG project

than lenders, provided the potential return is

greater by virtue of their so doing. If the return

to the owners is limited, as it is in the United

States for regulated utilities, the owner will also

seek limitations of risk. The balance of risk and

return that the project owners will accept is influenced by their own special circumstances

and by other investment opportunities which

are competing for the equity capital needed by

an LNG project. Finally, as a genera] rule, those

parties who control the LNG facilities usually assume risk on it.

The Pac Indonesia project—

An example of risk distribution

The Pac Indonesia case illustrates how risk is

distributed among the parties in an LNG project.

While this project is somewhat different from

early U.S. LNG import projects, it represents an

appropriate example, since it is the only project

to be approved under the new organization of

DOE. The estimates are current and typical of

recent LNG proposals, and the contractual relationships reflect more than a decade of experience. However, the reader should remember

that the distribution of risk in any project is in

part determined by the environment at the time

of negotiations,

Although generally representative, the Pac Indonesia project is unique in sevreral ways. First,

Indonesia currently is completely dependent on

Japan as its primary LNG customer. Also, the

California gas utilities would like to use the

same west coast terminal for an additional project to bring LNG from the Cook Inlet in Alaska,

and the proposed American shiponmer’s have

expressed reservations and have not yet committed their resources. Finally, the revolution in

Iran and the subsequent rapid increase in world

crude oil prices during the first half of 1979

have sharply altered perceptions about world

oil availability and price from the time the project was first negotiated and approved by DOE/

ERA.

LIQUEFACTION AND LOADING FACILITIES

Indonesian liquefaction and loading facilities

are estimated to cost about $869 million representing the largest single capital portion of the

project. Pertamina, the national oil company of

Indonesia, is the owner. Mobil Oil Indonesia

Inc., owns the producing facilities and bears the

financial risk associated with them.

The instruments that distribute the risk are

the contract for the sale and purchase of LNG

between Pertamina and Pac Indonesia, and the

security agreement for financing the liquefaction and loading terminal facilities. Two parts of

the sales contract are important: the take-or-pay

and the force majeure clauses. The take-or-pay

clause requires Pac Indonesia to pay for the

LNG tendered at the annual contract amount,

whether or not the LNG is taken. The burden of

marketing the LNG is thereby placed on Pac Indonesia, which is in a position to control its risk

in this area. However, the force majeure clause

is broad and provides for cessation of contract

obligations for acts of God, industrial strife, or

governmental decisions interrupting the operation of Indonesian facilities, ships, or U.S. facilities. This clause places most of the risk for the

investment in Indonesia on Indonesian interests. Lenders to Pertamina for the liquefaction
102 ● The Future of Liquefied Natural Gas Imports

trains and base terminal are protected from financial loss by a guarantee of repayment from

the Indonesian Central Bank.

Table 39 summarizes the risks and their distribution for the liquefaction trains and loading

terminal. The perils that can occur, the mechanisms by which risk is transferred, the criteria

governing the transfer, the amount transferred,

who pays, and a reference to the source of the

information are included in the table.

Force majeure events are borne solely by Pertamina and other Indonesian interests. If cost

overruns occur in the construction of Indonesian facilities, they are borne by Indonesian interests, since the LNG price is not based on cost.

An academic exception is that if the price of

crude oil falls, and if the United States reverses

its inflation and enters a deflationary period,

the f.o.b. price for LNG may fall below a minimum established to ensure repayment of the

lenders to the Indonesian facilities. In such a

case, U.S. consumers are guaranteeing repayment of lenders, a risk most observers of oil

markets and price behavior in industrial nations

view as insignificant.

However, LNG contracts do transfer some

risk to the buyer, and through the tariff, ultimately to the U.S. gas consumer. If the U.S.

dollar falls on foreign exchange markets, the

LNG price is adjusted to ensure that Indonesia

recovers real value for LNG relative to a market

basket of currencies. Also, Pertamina will not

accept the risk that the buyer will desire for

whatever reason not to take future LNG. Thus,

if the LNG becomes unmarketable, the risk of

failure in marketing the LNG is transferred to

the buyer and will be passed on through the tariff to the gas consumers.

SHIPPING

The six ships for the Pac Indonesia project, to

be constructed in U.S. shipyards for delivery in

1983-84, are estimated to cost approximately

$155 million (1978 dollars) each, excluding the

construction differential subsidy by MarAd. A

total of approximately $93o million to be paid by

their owners and lenders will thus be at risk.

Three other foreign ships have already been

constructed at costs that are unknown but estimated at an average of $100 million (1976 dollars) each. In this project, the ships will be

owned by independent shipowners, Ogden Marine and Zapata, who provide the equity financing, and chartered to Pac Indonesia.

MarAd will guarantee loans of up to 75 percent of the yard cost of a U.S. ship if a construction differential subsidy is provided, or up to

87.5 percent of the yard cost if no construction

differential subsidy is involved. These loan

guarantees are available only to ships built in

American yards, for American owners, to haul

goods in a trade that includes America. However, MarAd may negotiate with the shipowner

for additional money beyond the 25-percent

equity interest to help protect the Government

Table 39.—Distribution of Financial Risk for Liquefaction and Loading Facilities of the Pac Indonesia Project

Risk transfer

Event mechanism Criteria Amount Paid by References

1. Supply reduction or Sales contract Force majeure All Indonesian LNG sales

interruption interests contract

2. Project failure before or Force majeure All Indonesian LNG sales

after startup, liquefaction, interests contract

or terminal problems

3. Cost overrun on Indonesian None. Price not If price drops, All Indonesian LNG sales

facilities cost-based minimum bill interests contract

4. Ship unavailable—no fault Sales contract, Not force majeure Difference in Shipowner limited LNG sales

of Pac Indonesia, e.g., delay take-or-pay, LNG price when to 10% of capital contract,

in ship construction charter hire, quantities made cost remaining charter hire

minimum bill customers

5. Dollar depreciation in Tariff Automatic Ft~l U.S. consumers ERA 2, P.15

foreign exchange markets

aERA refers to an Opinion of the U.S. Department of Energy/Economic Regulatory Administration
Ch. 4—Project Structure, Cost, and Financing . 103

guarantee. For example, MarAd required U.S.

shipowners (Lochmar) in the Trunkline LNG

project to finance the 25-percent equity portion

of the ships and to put up initial working capital

equivalent to 1 M years’ operation to provide

added protection in case the ships are not employed immediately after they have been delivered. Marine insurance covers losses from sinkings, collisions, acts of God, and hull and machinery failures.

Pending a resolution of who bears the financial risk, the proposed American shipowners for

Pac Indonesia have not yet committed themselves to providing the ships. If the proposed

owners decide not to provide the shipping, Japanese firms are expected to do so. However, in

this discussion it is assumed that the American

firms will build the ships in American shipyards, using a construction differential subsidy.

The risk of failure of other parts of the project, which would leave ships unemployed, are

controlled by the charter arrangements between the shipowners and Pac Indonesia, and

by the U.S. tariff which governs how Pac Indonesia passes on its costs to consumers of natural

gas. Pac Indonesia has signed time charters for

20 years with the various owners, under which

the shipowner guarantees to deliver a ship of

specified speed, fuel consumption, and boil-off

rates. Pac Indonesia pays for the capital, maintenance, and the operating costs of the ship.

These payments are reduced if the ship does not

meet technical requirements or is not available,

and the shipowner also assumes all costs when

the ship is not available for service and the fault

is not Pac Indonesia’s.

Through the time charter mechanism, many

of the risks are transferred to Pac Indonesia.

However, the arrangements also specify that

Pac Indonesia need not assume the risks if they

are passed on to the LNG consumer via an approved tariff for foreign ships, or in the case of

a fall in the foreign exchange rate, offset by a

currency adjustment clause.

ERA and the administrative law judge in their

opinion and initial decision recommended a

“minimum bill” provision of the tariff by which

Pac Indonesia would charge Southern California

Gas and Pacific Gas & Electric for the LNG. This

provision specifies the costs that can be passed

on even if the full amount of gas is not flowing,

and includes the time charters or other arrangements for ocean transportation. In this way, the

cost of shipping automatically passes to the gas

consumer after the project has begun,

Table 40 shows the sources of risk, the contractual instruments for distributing them, the

amounts, and who pays. As the table shows, as

long as the project is operating and the ships are

available, the charter-hire agreement and the

tariff pass all costs of supply interruption or reduction, increases in operating costs, or reduction in the value of the dollar relative to a market basket of currencies, on to the gas consumer

via minimum bill provisions. However, for

events that occur before the gas begins to flow,

such as cost overruns on U.S. ships during construction, or project failure before or after

startup, passthrough of costs to the consumer is

not automatic. In the latter case, FERC will decide if and to what extent gas consumers pay

after an appeal under section 4 of the Natural

Gas Act. Thus, what costs the consumer and the

shipowner assume will be determined by an administrative ruling following an evidentiary

hearing to determine, for example, whether

cost overruns were “prudent. ”

The proposed U.S. shipowners in the Pac Indonesia project have complained that they bear

undue risk if they must depend on the outcome

of an administrative appeal in the event of cost

overruns or project failure. The shipowners

(ERA Decision No. 6, p. 9) have argued that unless the customers are required through the tariff to pay for the charter obligations in the event

of project failure, MarAd title XI financing will

not be available. However, ERA and the administrative law judge did not find sufficient evidence to support this claim. This finding is supported by the fact that ship financing and construction for the Trunkline LNG project is proceeding with MarAd loan guarantees. However,

the interests, objectives, and perceptions of the

proposed Pac Indonesia shipowners, which are

otherwise independent of the project, may be

different from those of their Trunkline counterparts; Panhandle Eastern Pipeline Company, the
.

104 ● The Future of Liquefied Natural Gas Imports

Table 40.—Distribution of Financial Risk for Ships of the Pac Indonesia Project

Risk transfer

Event mechanism Criteria Amount Paid bv References

1. Supply reduction or Minimum bill

interruption

2. Project failure before or Sec. 4 type filling

after startup, liquefaction,

Sec. 4 hearing

Charter contract

Tariff

Tariff

DOE review, tariff

Charter contract,

minimum bill

-Automatic

Facts surrounding

project failure

Prudent

Foreign ships Customers

Charter fee, minus Customers

ERA 6, p. 8

parent of Trunkline LNG; General Dynamics

Corporation, builder of the ships; and Moore

McCormack Bulk Transport, Inc., the operator

of the ships.

RECEIVING/REGASIFICATION TERMINAL

The import terminal and regasification facilities, with an associated pipeline to move the revaporized natural gas to existing pipelines, represent the smallest of the investments in an LNG

project but are the ones on U.S. soil. In the case

of the Point Conception plan, these facilities

would cost approximately $700 million (1978

dollars) and could be used as an import terminal

for about 560 to 600 MMcf/d of Indonesian LNG

with remaining capacity for an Alaskan LNG

project of approximately 350 MMcf/d. In addition, the Point Conception site is intended to

store LNG for peak shaving.

Approximately 75 percent of the costs of the

terminal are expected to be financed by debt,

primarily from banks or insurance companies,

and the rest by equity capital. The distribution

of risk is determined by the tariff and the security arrangements between the lenders and

owners of the terminal as shown in table 41.

In its decisions, DOE/ERA very clearly distinguishes between risk before startup and risk

that might occur after the gas is flowing.

Before project startup, ERA requires a section

4 filing with FERC in order to determine what

costs would be passed on to consumers. In the

case of a cost overrun, ERA suggests that only

prudent costs be passed on to customers, and

that shareholders bear imprudent costs. For

project failure before startup, no explicit criteria for passing on costs have been established.

The ERA decision clearly states that the credit

before completion should be provided by private creditworthy parties, who guarantee loans.

Elsewhere, the FERC staff and others argue that

if the project fails, in no case should the equity

costs be passed on to consumers.

ERA recommends a minimum bill portion of

the tariff providing that after gas first flows, the

debt portion of the terminals and other cost be

passed on automatically to gas consumers even

if the project fails. In the event of failure, supply

reduction, or interruption after project completion, the ERA opinion (in contrast to the Trunkline LNG decision) will also consider possible re-
Ch. 4—Project Structure, Cost, and Financing . 105

Table 41 .—Distribution of Financial Risk at the Receiving/Regasification Terminal of the Pac Indonesia Project

Risk transfer

Event mechanism Criteria

1. Supply reduction or a. Minimum bill Automatic

interruption

b. Sec. 4 type Extraordinary

proceedings circumstances

2. Project failure before

startup

3. Cost overrun

4. Ships unavailable—no

fault of Pac Indonesia or

Terminal Associates

5. Project failure after

startup

Sec. 4 filing Circumstances

Sec. 4 filing Prudent

Minimum bill is Automatic

90% deliveries

Minimum bill Automatic

Sec. 4 filing Circumstances

Amount Paid by

a. When less than Customer

900/. delivered,

no return of or

on equity on undelivered volumes. Recovery

of other allowed

costs.

b. Pro rata return Shareholders

of and on equtiy and perhaps

customers

As determined Customers

Allowed Customers,

Disallowed Shareholders

Costs and equity Customers,

on deliveries. Pro Shareholders

rata equity

Non-equity, Customers

Equity Shareholders

and customers

References

ID p. 81

ERA 6, p. 13

ERA 1, p. 30

ERA 1, p. 32

ERA 1, PP.32-33

ERA 6, p. 11

ERA 6, p. 16-17

ERA 1, p. 30

ERA 6, pp. 11-14

ERA 1, P.33

ERA 6, p. 13

turn of equity costs in the terminal regasification facilities in a section 4 proceeding if extraordinary circumstances can be shown.

SUMMARY OF RISK DISTRIBUTION

The distribution of risk in an LNG project, as

exemplified by Pac Indonesia is as follows:

.

Financial risk of the producing country facilities: ($869 million, 1976 dollars)

● Most risks are borne by the owner of the

liquefaction facility, Pertamina, the gas

producer, Mobil, or the Indonesian Government through loan guarantees.

● Risk of the marketability of the LNG is born

b-y the U.S. gas companies and gas consumers.

Financial risks of shipping: ($1,230 million,

1978 dollars)

● Insurance companies take normal shipping

risks such as damage to the ship, grounding, storm, etc. Gas consumers ultimately

pay the insurance premium.

● While the project is in operation, gas consumers bear costs if LNG flow is interrupted or reduced.

●

●

●

If the project fails, the shipowner may bear

the risk, at least on his equity in the ship, although FERC, after evidentiary hearings,

may pass on some costs to the gas consumer.

Cost overruns may be borne by the shipowner, unless after evidentiary hearings

FERC decides to pass on prudent costs to

the gas consumer.

If all else fails, the lenders for U.S. ships

with financing guaranteed by MarAd receive payment from the MarAd Federal

Ship Financing Fund, and if that is exhausted, from the U.S. Treasury.

Receiving/regasification terminal: ($437 million, 1977 dollars)

●

●

Loss due to project failure before gas flows

may be fully borne by shareholders, unless

FERC, after an evidentiary hearing, decides

to pass some or all costs on to gas consumers.

After gas flows, the non-equity costs of the

terminal are borne by gas consumers.

Shareholders bear risk of loss of equity and

return on it in proportion to the reduction

of LNG flows except that FERC may pass on
106 . The Future of Liquefied Natural Gas Imports

equity costs to consumers in extraordinary

circumstances.

● Cost overruns may be borne by shareholders unless FERC, in an evidentiary hearing,

passes on prudent costs to gas consumers.

Risk of LNG embargo by the producing

country

Four of the six largest actual or potential exporters of natural gas from the Eastern Hemisphere—Algeria, Iran, Indonesia, and Nigeria—

are members of OPEC. The U.S.S.R. is an adversary superpower. Only the last, Australia, is a

member of OECD. As oil exporters, OPEC members have demonstrated their readiness to impose increases in price at short notice on existing contract terms. Some of them, also, have

embargoed crude exports for political reasons.

On the other hand, the supplier as well as the

purchaser experiences dependence on LNG

trade and faces incentives not to interrupt shipments. LNG exports characteristically involve

substantially greater capital investment than exports of oil of comparable energy content. Contracts for 15 to 25 years of deliveries after at

least 5 years of negotiation and plant construction, are necessary in order to amortize huge

initial financial outlays. A large proportion of

this investment, in gathering and trunk pipelines, liquefaction, plants, and terminals, is in

the exporting country, and in all cases so far,

host governments have participated in the financing. If performance under a long-term contract were interrupted, alternative exports that

would maintain revenues to pay capital charges

would be very hard to arrange. The projects are

technically integrated, and the only mobile capital involved, the cryogenic tankers, will often be

under the effective control of foreign joint-venture partners or import customers, and until

now, no “merchant trade” in LNG has developed. (Some LNG tankers have been built speculatively, and as the international trade expands,

a fringe of uncommitted tonnage will no doubt

become available for the occasional balancing

transaction between customers with terminals.)

Furthermore, selling the gas in the exporter’s

domestic market would be disadvantageous, because local customers do not use LNG and may

not be located close to the pipelines leading to

liquefaction terminals, and export volumes are

generally surplus over domestic consumption

anyway,

These characteristics of present international

gas trade seem to lock all parties to an LNG supply contract into a closed economic loop. The

costs of interruption, and of insurance against it

(technical as well as financial), will be heavy.

The resource is not lost (in the case of nonassociated gas), but all parties will share all the cost

of downtime on a large accumulation of costly,

dedicated capital.

This generalization in no sense precludes arguments over price while a contract is in force.

It simply increases the pressure on all parties to

settle short of interrupting the gas flow. Also,

20-year contracts in an environment of rapid inflation and rising real prices for alternative

fuels require effective escalation and review

clauses.

In extreme circumstances, the high cost of interruption will not necessarily prevent gas

being cut off for political purposes. one of the

few cases on record of an LNG contract’s actually being interrupted was Libya’s action against

the EXXON trade to Italy and Spain, which indeed involved associated gas and was thus more

costly for both sides. * That arbitrary action may

have been at once commercially and politically

motivated. Although interrupting a gas operation for political purposes is demonstrably more

costly than interrupting oil exports, it is nonetheless possible.

The risk of supply curtailment can be reduced

through policies that require the “exchange of

economic hostages, ” as suggested by Resources

for the Future. Under such a policy, “the producing country would own liquefaction facilities and tankers, and would finance them with

borrowings other than from U.S. parties or government entities such as the Export-Import

Bank. ’)zo
Social Costs and Benefits
5 ●

Social Costs and Benefits

Under current regulation, the added cost of

gas from sources such as imported liquefied

natural gas (LNG) is not necessarily borne by the

same consumers that benefit from increased

fuel supplies. Since the distribution of costs and

the extent to which prices reflect them are central to part of the debate over LNG policy, this

chapter addresses the question of who receives

additional gas by virtue of an import project and

who pays for it.

The determination of which consuming sectors will ultimately benefit from an LNG import

project is complex. The answer depends not

only on which pipeline or distribution company

delivers the regasified LNG through its network, but also on such specific circumstances as

the location of the supplier’s customers, the

relative sizes of the consuming sectors it serves,

the quantity and seasonality of its other supplies, and the availability of storage facilities.

Given projected natural gas production, new incremental supplies, such as those provided by a

baseload LNG project, ultimate consumption

will probably be in the industrial and electric

power generation markets, where sales of gas

would he curtailed in the absence of such supplies. In some situations, however, residential

and commercial markets could benefit directly

from LNG imports. For example, in the event

that a specific project allows a utility to remove

U.S. consumers of LNG

its restrictions on new customer additions, the

recipients of at least part of the LNG would be

new residential and commercial consumers.

The question of how LNG project costs are allocated among consuming sectors is even more

difficult to answer. In the absence of incremental pricing, the cost of a supplemental project would be simply rolled-in with other gas acquisition costs, and all consuming sectors would

be affected equally. However, under the pricing

rules of the Natural Gas Policy Act of 1978

(NGPA), certain categories of industrial customers are subject to a special surcharge reflecting

incremental prices of gas from specific sources.

The addition of an incremental supply not only

increases the average pipeline cost of gas, but it

also enlarges the base of customers over which

the surcharge is spread and lowers the unit

transmission and distribution cost. These effects have been analyzed with the aid of a computer model, which simulates the markets of

hypothetical transmission companies.

Additional issues addressed below include the

impacts of supply curtailments and possible

measures to mitigate them. Finally, the chapter

concludes with a discussion of effects of LNG

imports on the balance of international payments and on local employment and air quality.

The issues addressed in this section are, “who Modeling of pipeline systems

gets the additional gas from a baseload LNG

project?” and “who pays for it?” A computer A computer model that simulates the operamodel that simulates the operation of a gas pipe- tion of a gas pipeline under various conditions

line company was used to answer these ques- of supply and demand has been constructed, intions. The section begins with a brief review of corporating existing curtailment plans, assumed

the pipeline model, followed by a discussion of allocation rules for distribution companies, and

the two issues in the light of the analytical pricing provisions of NGPA. Customers of the

results.

109
110 The Future of Liquefied Natural Gas Imports

pipeline are grouped according to broad characteristics as follows:

Group 1 Large distribution companies that

have gas supplies in addition to

those of the subject pipeline. These

may include gas from other pipelines, baseload synthetic natural

gas projects, imports, own production, etc.

Group 2 Smaller distribution companies

that rely solely on the subject pipeline for their gas supply.

Group 3 Direct mainline industrial sales by

the subject pipeline.

Eleven consuming sectors are defined for the

model as follows:

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

residential

commercial

exempt industrial (including agricultural)

industrial priority 2

new industrial priority 2

industrial priority 3

new industrial priority 3

industrial boilers—medium

power generation—gas only

industrial boilers—large

power generation–gas/oil.

By specifying demand profiles (and supplementary supplies for Group 1) for the three groups,

data can be assembled to simulate a prototypical

load for a pipeline. Two such systems have been

utilized in the current project:

Pipeline A Single customer group (Group 2)

with heavy industrial and power

generation load.

Pipeline B Heavy residential and commercial

load in Group 2, plus significant direct pipeline sales to industry

(Group 3).

The distribution companies that are served

by more than one pipeline are not included in

the analysis of pipeline B because of the indeterminate nature of the allocation of the surcharge

gas costs required by NGPA. When a pipeline is

attempting to allocate its surcharge gas cost, it

utilizes the data provided by each distribution

company it serves to determine the ability of

that distributor to absorb a surcharge. In the

case of a distributor supplied by several pipelines, the Federal Energy Regulatory Commission (FERC) has not yet determined how the absorptive capacity of that distributor is to be divided among its various suppliers. If, for instance, one of the pipelines develops a large surcharge account early, it could theoretically utilize all of a distributor’s absorptive capacity. Alternatively, if each pipeline is assigned a share

of the distributor’s absorptive capacity (proportional to its deliveries to the company), then the

distributor’s absorptive capacity may not be

fully utilized. Lacking a surcharge allocation

rule, multisupplied companies were not analyzed in these simulations despite the fact that

such distributors are not uncommon.

Brief descriptions of the program modules follow in the order in which they are applied. For a

more detailed description of the model, see the

Background Reports volume.

Market share model.—Gas demands are

calculated for each consuming sector from total

energy demand forecasts using gas prices, alternate fuel price, and specified demand functions.

Since NGPA incremental pricing rules make gas

prices a function of the gas consumption pattern, market shares for gas must be calculated

dynamically within the model.

Entitlements model.—Total pipeline supplies for a given year are allocated among the

various customer groups on an entitlements basis. Supplies are distributed monthly according

to historic base period demands in conformance

with existing curtailment plans. Since actual demands change significantly over time, the model

provides for rolling the base period forward.

Within each customer group, entitlements are

compared with actual demands so that any surplus can be reallocated to other customer

groups.

Distributor allocation model.–Monthly

supplies are compared to the actual demand

profile for each customer group so that storage

requirements can be calculated to protect highpriority demand. A deficit of storage gas is made

up by curtailing low-priority customers; a sur-
Ch. 5—Social Costs and Benetits . 111

plus of storage gas is distributed to the highest

priority curtailed customers. Actual monthly

and annual deliveries are then determined for

each consuming sector.

pricing mode l .—Gas prices by consuming

sector are calculated for each group of customers in accordance with NGPA incremental pricing provisions. The pipeline’s surcharge account

is distributed among the non-exempt customers

and the excess surcharge is rolled into the base

price of pipeline gas. Any gas priced above the

ceiling prior to surcharge allocation causes an

additional cost spillover to all sectors not at the

ceiling price. The detailed logic of these cost allocations is extremely complex and is reviewed

in greater detail in the Background Reports

volume, and the implications of incremental

pricing are discussed later in this chapter.

The allocation issue: who gets the LNG?

This section addresses the question of who

would receive additional gas and for what use if

LNG imports were expanded. Tracing the physical flow from the point of regasification to consumption does not provide the answer. Assume,

for example, that the addition of LNG to pipeline

supply permits a distribution company to increase its summer storage injections, and that

the LNG is being put into storage whenever

summer deliveries from the pipeline exceed actual demand. Since storage volumes are used

primarily to protect high-priority demands, it

would then follow that the LNG stored during

the summer is being ultimately consumed by

residential and commercial customers, The

fallacy in this argument becomes apparent by

examining the normal behavior of a distribution

company. Typically, a company will manage its

supply to protect high-priority customers from

interruption, even if doing so requires curtailing industrial deliveries in the offpeak season in

order to build sufficient storage volumes. Thus,

high-priority customers will receive uninterrupted service with or without the addition of incremental LNG supply. With the exception of

price effects (discussed below), these customers

are indifferent to the existence of a supplemental gas project such as pipeline LNG.

Photo credit El Paso Co.

The correct way to answer the disposition

question is to analyze consumption patterns

both with and without the existence of an LNG

project, rationally allocating available supplies

in each case. The results of the analyses show

that the customers who receive the LNG are

those whose supplies would be curtailed if an

LNG project did not exist.

A number of cases illustrate who will be curtailed in the most common situations.

Case 1. The distributor endeavors to protect a certain priority level (industrial process gas, for

example) from interruption and because of

insufficient annual supply is unable to do so.

In this case, some minimum percentage of

the process gas users’ requirements would

be curtailed, and all lower priority customers would be 100-percent curtailed throughout the year. Any addition to pipeline supply
112 The Future of Liquefied Natural Gas Imports

Case 2.

would first reduce curtailments to the process gas users, and any excess gas would be

allocated at the discretion of the distributor.

The excess would most likely be sold in the

offpeak (summer) season to the lower priority customers. In this situation, the beneficiaries of the LNG project are high-priority industrial customers that gain supplies yearround and the lower priority offpeak customers that benefit seasonally. It should be

noted, however, that this case implies a

sharply reduced total pipeline supply, that

is, severe curtailment.

The distributor is able to protect his highpriority load with or without the LNG project,

In this case, the customers who would be

curtailed without the LNG project are lower

priority industrial consumers and electric

utilities. The curtailment is seasonal, as opposed to year-round in Case 1, Since the LNG

project provides a constant monthly addition to distributors’ supply, it produces the

following effects:

a.

b.

c.

Effect (c)

Winter storage withdrawals required to

protect high-priority load are reduced.

Overall industrial curtailments are reduced,

Summer storage injections are often (but

not always) increased.

occurs when summer supply exceeds

actual demand, a common situation that complicates the determination of who gets the LNG.

Since (a) and (c) act in opposite directions,

storage patterns strongly influence the distribution of supply to the various consuming sectors.

Since gas distribution companies typically

have some flexibility in their allocation of gas

supplies, * the question of who will receive an

incremental supply has no single answer. An allocation scheme typically employed during

moderate curtailments, when high-priority customers can be protected with or without the addition of new incremental supply is described

below.

Based on supply estimates from the pipeline

supplier, the distributor calculates the amount

of storage gas that will be required to service

high-priority customers in the winter months

and analyzes supply and demand for the summer months. If summer supply exceeds demand, the excess gas will be stored and used to

cover winter storage withdrawal requirements.

All available storage gas will be used to service

high-priority customers during the winter

months. As summer approaches, lower priority

customers will be served, and excess gas will be

injected into storage as the cycle continues.

This rather ideal load balancing rarely occurs

in practice. Summer storage of “excess” gas

usually is either insufficient or in excess of that

needed to protect seasonal heating loads. If storage gas is insufficient, the distributor will plan

to curtail deliveries to his lowest priority customers in the summer in order to increase storage injection. If storage is more rapid than necessary to meet requirements, the distributor

must decide to whom and when to sell the gas.

The most typical decision probably would be to

extend the period of service to the highest priority curtailed customers. For example, if the distributor is protecting industrial priority 2 and

curtailing priority 3 customers for five winter

months, he would reduce his period of nondelivery to priority 3 customers by as many

months as possible. If all priority 3 customer demands are satisfied, the distributor would move

on to priority 4 customers and extend their

service period, and so on.

If supplies increase by a fixed quantity each

month, as would occur with the addition of a

baseload LNG project, the effect is a reduction

in winter storage withdrawals and possibly an

increase in summer storage injections as well, If

the distributor allocates the resulting excess

stored gas in the manner described above, the

beneficiaries of that portion of the incremental

supply that increases storage volumes are highpriority industrial customers who were previously curtailed during the winter.

The rest of the answer is found by examining

summer delivery patterns. During the transition from winter heating to summer baseload

demand, the distributor will allocate his supply

on a priority basis, and additional gas will serve

to extend the summer service period for all

seasonally curtailed customers. At the height of
Ch. 5—Social Costs and Benefits ● 113

Photo credit Courtesy ot Columb/a Gas Transm/ss/on Corporation

Natural gas cooking, water heating, and house heating are utilized in these modular townhouse units

summer, the group that will benefit most from

the additional gas supply are the lowest priority,

severely curtailed customers, generally among

the electric utilities.

The pipeline model illustrates these effects.

Results for pipeline A appear first, in order to

avoid confusion due to the allocation of supply

to multiple consumer groups. As shown in figure 19, the model results illustrate that most of

the LNG in this case is distributed initially to the

electric power and priority 3 industrial sectors.

The industrial boiler fuel sector, the prioritoy of

which is between those of the other two, receives considerably less,

In the discussion so far, an even distribution

of demand across the industrial and power gen59-406 0 - 80 - 9

eration sectors has been tacitly assumed. In actuality, a distributor’s load is frequently (and

sometimes rather sharply) skewed in favor of

one or more sectors. This unevenness of demand affects the disposition of an incremental

supply. For example, if a certain industrial

category represents a very small total demand,

its consumption of an incremental supply is obviously also very small. Figure 19 shows how

following 1990, gas demand in the electric

power generation sector drops off sharply because of the Power Plant and Industrial Fuel Use

Act (FUA). As actual demand declines, LNG consumption declines too, making more supplies

available to the boiler fuel market. Figure 20

illustrates the same data in a different perspective.
114 ● The Future of Liquefied Natural Gas Imports

Photo credit Courtesy of Northern Natural Gas Company

Natural gas enables the exact amount of chocolate to

cover these tortes as they pass through machine

Thus far, the discussion has concerned the allocation of an incremental supply at the distributor’s level. Since an LNG project would normally be a fixed addition to a pipeline’s supply, the

question of how the pipeline allocates its supplies among its various distribution companies

and direct industrial customers remains. The

pipeline model incorporates a Rule 467 B type of

curtailment plan based on end-use priorities.

Since actual gas demands change over time

while entitlements remain fixed, “inequities” in

the levels of service to different consuming sectors can easily arise. For example, current conservation levels have enabled distributors with

large residential and commercial sales to develop a supply of “conservation gas” that can be

sold to their industrial customers. However, distributors who lack such a residential/commercial cushion and customers served directly by

the pipeline are not nearly so well off. For this

Figure 19.–Disposition of LNG (pipeline “A”)

“Priority 3 indus trial

1984 85 86 87 88 89 90 91 92 93 94 95 2000

Industrial

Electric p

gene ratio

boilel

lower

In

rs

Year

SOURCE: Jensen Associates, Inc.
Ch. 5—Social Costs and Benefits ● 115

Figure 20.—Consumption of LNG (pipeline “A”)

500

400

300

200

100

(-l

Total Industrial

Powerplants

from

regular supply

LNG

Regular

supply

1 1 I I I I I I I

19~7 78 { I 82 84 86 88 90 92 94 96

Year

SOURCE Jensen Associates, Inc

reason, each pipeline would have to be modeled

separately to obtain perfectly precise results.

Pipeline B provides an example of two of the

effects discussed above, inasmuch as it is characterized by significant direct sales to industry

and heavily weighted residential and commercial sales. “Because of fixed base period entitlements, the pipeline’s distribution company customers develop a large surplus of high-priority

"conservation gas, ” which can be reallocated to

the industrial sector. In this case, a high level of

service is maintained to the industrial customers of the distributors served by the pipeline

throughout the period that was simulated. Following the introduction of an LNG project in

1981, even the large boiler customers receive

virtually their entire requirement for the following 9 years, and in 1995 they are less than 40

percent curtailed. In contrast, pipeline B’s direct

industrial customers are never serviced beyond .

priority 2.

Figure 21 shows the disposition of LNG among

consuming sectors for pipeline B. Because pipeline B’s market includes very little power generation demand, it is not significantly influenced

by FUA, and the disposition of LNG over time is

relatively constant. While the direct industrial

customers receive only about 15 percent of the

LNG, this amount represents approximately 40

percent of their total supply. As a result of the

LNG project, the priority 2 demands of the

direct industrial customers are almost completely satisfied.

One last issue concerning the disposition of

LNG needs to be addressed. During the early to

mid- 1970’s, when supplies of natural gas began

to fall short of demand, a great many distributors restricted the addition of new customers.

These “moratoria” were sometimes self-imposed

or were mandated by the State Public Utility

Commissions, and their eventual lifting was

brought about by the introduction of new supplies, including baseload LNG. To the extent that

these events are associated, the residential and

commercial markets definitely benefit from a

mnv LNG project. If future LNG imports prevent

the reimposition of moratoria at least part of

the LNG will be ultimately consumed by new

residential and commercial customers. Finally,

to the extent that the rate of delivery from a receiving terminal can be increased for brief periods, LNG can contribute to meeting short-term

peaks in residential demand.

The price issue— who pays for

the LNG?

In the absence of the congressionally mandated incremental pricing requirements, the

question of the distribution of LNG costs among

various users would be a relatively simple exercise for a project permitted to roll-in the price of

LNG, The addition of LNG volumes at a price

greater than the average acquisition cost of all

other gas supplies would simply raise the cost of

the gas to all consumers purchasing gas from

that supplier. However, if the addition of LNG

volume permits greater utilization of existing

transmission and distribution facilities, the

average fixed charges included in the delivered

retail price would decline. If the increase in the
116 ● The Future 01 Liquetied Natural Gas Imports

—

Figure 21 .—Disposition of LNG (pipeline “B”)

dil :ts

3 ir

Industrial boilers

Electric power

generation

1981 82 83 84 85 86 87 88 89 90 91 92 93 94 95 2000

Year

SOURCE: Jensen Associates, Inc

commodity cost of gas exceeds the decline in the

average fixed costs, all gas customers who are

supplied by the LNG importer, would incur

some of the LNG costs. However, if the decline

in the fixed charges exceeds the increase in the

commodity cost of gas, all customers would benefit from the LNG project through a reduction

in prices.

Under present incremental pricing regulations, however, the question of who pays for the

LNG becomes quite complex. NGPA requires interstate pipelines and interstate-supplied distribution companies to pass through the portion of

wellhead gas costs above a threshold level to

select non-exempt industrial users until the

price to these users rises to the cost of their

alternate fuel. The benefits of access to the less

expensive sources of natural gas have been reserved for residential, small commercial, electric utility, and certain other exempt users. As a

result, the effective commodity cost of gas will

no longer be the same to all users. Table 42 illustrates how the two pricing approaches differ.

An understanding of the incremental pricing

system is critical to the discussion of who pays

for the LNG. Without incremental pricing, the

transmission and distribution costs are added to

the average pipeline commodity cost of all gas in

order to arrive at consumer prices. With incremental pricing, the cost of gas above an established threshold price is assigned only to nonexempt industrial users. Excluding the surcharge cost therefore reduces the average pipeline cost of gas from $2.53 to $2.21 in the case illustrated in the table. The surcharge costs are

then allocated to non-exempt industrial users

until they have all been distributed, or until further surcharge costs would raise the industrial

costs above the alternate fuel ceiling price. In

the example in table 42, a surcharge of $1.01
Ch. 5—Social Costs and Benefits . 117

Photo credot Southern Ca//torn/a Ed/son Company

Southern California Edison Company’s El Segundo Generating Station has four generating units with

a combined effective operating capacity of 1,020,000 kilowatts. El Segundo is 1 of 13 oil- and gas-fired thermal

powerplants operated by SCE

brings industrial prices to the ceiling and other

gas customers must share the rest of the costs in

excess of the threshold level.

The manner of allocating the remaining costs

is not specified by NGPA. If the excess surcharge is distributed to all gas customers in a

fashion similar to a purchased gas adjustment,

the industrial gas price would exceed the alternate fuel price, and fuel stitching away from

gas would begin. Because of this shift, remaining users would have to bear both the surcharge costs and the fixed pipeline and distribution charges previously incurred by the customers who shifted to an alternate fuel. However,

Congress granted FERC discretion in selecting

the alternate fuel price for the precise purpose

of preventing load shifting. In order to avoid

loss of load and possibly additional oil imports,

once the industrial gas price reaches the alternate fuel ceiling, the excess surcharge costs

must be allocated solely to the residential, commercial, exempt industrial, and power generation customers who were initially excluded
118 ● The Future of Liquefied Natural Gas /reports

Table 42.—illustrative 1985 Residential and Industrial Gas Prices With and Without Incremental Pricing

(1978 dollars/million Btu)

Residential Nonexempt industrial

No incremental With incremental No incremental With incremental

pricing pricing pricing pricing

Average pipeline cost of all gas . . . . . . . . . . . . . . . . $2.53 $2.53 $2.53 $2.53

Credit of costs above NGPA threshold price . . . . . — (.32) — (.32)

Average pipeline cost of gas excluding surcharge

costs (artificial gas cost). . . . . . . . . . . . . . . . . . . . 2.53 2.21 2.53 2.21

Surcharge. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — 1.01

Excess surcharge . . . . . . . . . . . . . . . . . . . . . . . . . . . — .09 —

Commodity cost of gas. . . . . . . . . . . . . . . . . . . . . . .

—

2.53 2.30 2.53 3.22

Transmission and distribution costs. . . . . . . . . . . . 1.50 1.50 1.34 1.34

Retail price of gas . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.03 3.80 3.87 4.56

Alternate fuel ceiling price . . . . . . . . . . . . . . . . . . . . — — $4.56 $4.56

SOURCE: Jensen Associates, Inc.

from incremental pricing. In the example, the

“excess surcharge, ” raises the residential prices

by $0.09.

NGPA allows the price of gas from currently

approved LNG projects to be averaged or rolledin with other pipeline supplies, while new projects for which import authority had not been

applied for by May 1, 1978, are subject to incremental pricing under the Act. * The effects of

these provisions on the distribution of added

LNG costs among groups of consumers are discussed more fully in the Background Reports volume, and some general observations appear

here.

Suppose the non-exempt gas customers are

paying less than the alternative fuel ceiling

price when LNG supplies are introduced. If LNG

prices are rolled-in, charges to all consumers

will tend to reflect equally the cost of LNG, adjusted for any improvement in utilization of

fixed transmission and distribution facilities.

The cost of incrementally priced LNG will fall

more heavily, but not exclusively on nonexempt customers, while exempt purchasers

will share equally the benefit of greater capacity

utilization.

The distribution of costs is quite different if

non-exempt customers have already reached

the alternative fuel price ceiling, and part of the

incremental surcharge is being paid by exempt

customers. In this case, with an exception noted

*Exemptions may be granted by the Department of Energy

below, the price paid by non-exempt purchasers

does not change in response to LNG supplies

from either old or new projects, and the net cost

or saving is reflected exclusively in the exempt

prices. The exception occurs if non-exempt

sales increase sufficiently to absorb all surcharge costs within the price ceiling, in which

case, non-exempt prices could decline slightly at

the expense of exempt users. Obviously, if nonexempt prices reach the ceiling as a result of an

LNG project, the effect will be a combination of

the effects just described.

The foregoing discussion assumes that LNG

enters the country at or near the price ceiling,

since import contracts are written with the objective of making LNG competitive with alternative fuels. If import costs were above or below

the ceiling, these conclusions could change.

Table 43 illustrates the effect of rolled-in LNG

on residential and industrial prices in 1985,

based on the pipeline A model analysis. The addition of the LNG to the gas supply raises the

pipeline’s average cost, However, since the LNG

volume (in this particular case) improves the utilization rate for the existing facilities, the fixed

charges of the pipeline and distribution network are allocated over a greater volume,

thereby reducing the unit cost of delivered gas.

This decline in throughput charges for pipeline

A offsets the increase in the commodity cost of

gas. As a result, despite the higher gas costs, the

delivered price to the residential sector declines

marginally, while the industrial sector remains
Ch. 5—Social Costs and Benefits 119

Table 43.—lllustrative 1985 Residential and Industrial Gas Prices With LNG Rolled.in and Without LNG”

(1978 dollars/million Btu)

Residential Industrial

Without LNG With LNG Without LNG With LNG

Average pipeline cost of all gas . . . . . . . . . . . . . . . .

Credit of costs above NGPA threshold price . . . . .

Average pipeline cost of gas excluding surcharge

costs (artificial gas cost). . . . . . . . . . . . . . . . . . . .

Surcharge. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Excess surcharge . . . . . . . . . . . . . . . . . . . . . . . . . . .

Commodity cost of gas. . . . . . . . . . . . . . . . . . . . . . .

Transmission and distribution costs. . . . . . . . . . . .

Retail price of gas . . . . . . . . . . . . . . . . . . . . . . . . . . .

Alternate fuel ceiling price . . . . . . . . . . . . . . . . . . . .

$2.53

(.32)

2.21

—

$2.68

(.28)

2.40

.05

2.45

1.33

3.78

$2.53

(.32)

2.21

1.01

$2.68

(.28)

2.40

.98

$4.56 $4.56

at the alternate fuel price ceiling due to a reallocation of the surcharge.

The cost of future LNG projects will probably

not be rolled-in with that of other sources, and

table 44 indicates how the components of table

43 would differ for an incrementally priced supply. Although the average cost to the pipeline

would not change, a larger portion of it would

be included in the surcharge account. However,

the industrial price would remain the same,

since it cannot rise above the alternate fuel ceiling, so the net effect is that retail prices do not

depend on the pricing mechanism, as long as

the industrial sector is paying maximum prices

before LNG supplies become available.

The fact that the retail industrial prices in

tables 42 through 44 are at the ceiling level is

not assumed but derived from projected gas

costs and alternate fuel prices by the model.

Based on the projections, described in the Background Reports volume, the industrial sector is

generally likely to pay the ceiling price during

most of an LNG project’s economic life.

Figure 22 summarizes for pipeline A which

sectors receive the LNG and which pay for it. Although the relative allocation of the costs approximates the distribution of the LNG supplies,

the sectors that buy the LNG generally incur

costs in excess of the marginal cost of the supply. As a consequence, the residential, commerTable 44.—lllustrative 1985 Residential and Industrial Gas Prices With LNG Rolled-In and

With LNG Incrementally Priced’

(1978 dollarslmillion Btu)

Residential Industrial

With LNG With LNG

With LNG incrementally With LNG incrementally

rolled-in priced rolled-in priced
120 ● The Future of Liquefied Natural Gas Imports

Figure 22.— Percent Distribution of LNG Volumes

and Costs (pipeline 66A”)

1 13“/0 n

SOURCE: Jensen Associates, Inc

cial, and exempt industrial customers (which receive no LNG) benefit from a reduction in their

delivered price. In the early years of the project,

power generation receives a small subsidy from

the other sectors that receive LNG, as does the

priority 2 industrial sector.

For pipeline B, the allocation of LNG supplies

and costs is shown in figure 23. Again, the sectors that buy additional gas generally provide a

subsidy to the residential, commercial, and exempt industrial customers, but not throughout

the life of the project. After 1990, the subsidy,

which has grown quite large, declines rapidly,

so that by 1995, the revenues from those customers that receive LNG are approximately

equal to the project costs. Although the load

characteristics of pipeline B are quite unlike

those of pipeline A, the dissimilarity in the distribution of costs in 1995 is due primarily to differences in the LNG pricing formulas of the supplying country. Pipeline A incorporates a pricing scheme similar to the Indonesian formula,

whereas pipeline B’s LNG costs are based on the

100 ”/0 1050/o

100 ”/0

/

100 ”/0 100 ”/0

LNG L NG – “ ‘“

deliveries costs

LNG

costs

u

Power generation

Industrial boilers

Industrial priority 3

Pipeline directs

Resident ial/commercial/exempt

SOURCE Jensen Associates. Inc

Algerian formula. As a result, the delivered

price of the LNG is higher for pipeline B than for

pipeline A. The effect of this differential is

reflected in the relative subsidy position of the

residential, commercial, and exempt industrial

customers in 1995. For pipeline A, the increase

in the average cost of gas due to the LNG project

is more than offset by the decline in the unit

costs of transmission and distribution and in the

excess surcharge. The addition of the LNG

therefore results in a lower cost to the residential, commercial, and exempt industrial customers. For pipeline B, with higher LNG costs, the

increase in the average price of gas due to the

LNG is approximately equal to the decline in

unit delivery costs and excess surcharges, so the

addition of the LNG has little effect on the retail

price of gas for the exempt categories of customers.

For another LNG project, with different customer characteristics, pipeline utilization rates,

alternate fuel markets, surcharge gas accounts,

and pipeline supplies, the answer to the ques-
Ch. 5—Social Costs and Benefits . 121

tion of who pays for the LNG could be different

from that found in either pipeline A or pipeline

B. In these simulations, however, although the

high-priority customers never receive any LNG,

they frequently benefit from the project

through a subsidy that lowers the retail price of

gas. In certain years, the LNG project generates

no benefits for the high-priority customers and

occasionally imposes a small price penalty, but

this occurrence is the exception and not the

rule.

Supply impact of LNG interruption

The impact of supply interruption must be assessed within the context of the role of LNG in

the total supply of natural gas to a region. The

actual flow of LNG sales does not indicate who

would lose natural gas in case of an interruption, since imported LNG is only part of the

overall supply to a natural gas distribution company. While- the revaporized LNG may flow

physically to a relatively small area, remaining

supplies of gas from other sources would be reallocated to diffuse the impact of a shortfall.

Federal and State curtailment plans to allocate

natural gas in the event of a shortage were established in the early and mid-1970’s, when the

supply fell below expectations and contracts

could not be fulfilled. In the event of an LNG interruption this system would serve to reallocate

the remaining available gas. Alternatively, the

companies in the natural gas industry of an area

could arrange for transfer of gas or for increased production to protect high-priority customers—homes, schools, hospitals, and stores.

Under NGPA, the President also has the authority to allocate gas supplies among interstate

pipelines during a gas shortage. Who would lose

gas during an LNG interruption is, therefore, a

question of how the remaining supply would be

redistributed.

The ease or difficulty of managing an LNG

shortfall will depend to some extent on how dispersed the final markets are. Table 45 shows

the distribution by State of the LNG sales from

each of the operating and approved projects.

Both the Pac Indonesia and Distrigas projects

import gas on behalf of distribution companies,

and their volumes tend to be localized. on the

other hand, in the Algeria I and Trunkline projects, gas flows through long-distance transmission pipelines that serve wide areas. Thirty-two

States will probably receive natural gas from approved import projects, as shown in table 46 in

which the flow of LNG to each State is compared with 1977 total deliveries.

Finally, the gas industry can protect against

cessation of LNG deliveries by expanding storage volumes. Since this form of insurance is expensive, its appropriateness will depend on the

availability of alternatives to the transmission

and distribution companies and to the users

whose supply would be curtailed. The preceding analysis does not include provisions for increased storage, which would add to the transportation cost reflected in final prices.
122 . The Future of Liquefied Natural Gas Imports

Table 45.—Distribution of Imported LNG by Consuming State for Each Pipeline Importer

(percent)

Algeria I Pacific Indonesia

Southern Pacific Gas Southern

States ColumbiaConsolidated Natural Distrigas & Electric California Trunkline

Alabama . . . . . . . . . . . . . . . . . . . . . . . . — — 26.40 – —

Arizona . . . . . . . . . . . . . . . . . . . . . . . . . —

— —

— — —

Arkansas. . . . . . . . . . . . . . . . . . . . . . . . —

— —

— 0.01 : — 0.23

California . . . . . . . . . . . . . . . . . . . . . . . — —

—

— — 100.0 100.0

Colorado . . . . . . . . . . . . . . . . . . . . . . . . — —

—

— — — — 0.06

Connecticut . . . . . . . . . . . . . . . . . . . . . — — 0.10 3.87 –

Delaware . . . . . . . . . . . . . . . . . . . . . . . . —

— —

— — — —

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . —

— —

— 3.86 – —

Georgia . . . . . . . . . . . . . . . . . . . . . . . . . —

— —

— 44.03 — — — —

Idaho . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — — —

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . — — 0.03 – — 14.18

Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . —

—

— 0.01 – — — 12.22

lowa. . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — 0.04

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . —

—

— — — — 1.60

Kentucky, . . . . . . . . . . . . . . . . . . . . . . .

—

4.33 — 0.03 – — — 0.28

Louisiana . . . . . . . . . . . . . . . . . . . . . . . — — 0.87 – — 0.67

Maine . . . . . . . . . . . . . . . . . . . . . . . . . . . —

—

— — —

Maryland . . . . . . . . . . . . . . . . . . . . . . . .

— —

11.56 — 0.04 : — 0.56

Massachusetts . . . . . . . . . . . . . . . . . . . —

—

— 0.19 46.40 —

Michigan . . . . . . . . . . . . . . . . . . . . . . . . —

— —

— — — — — 51.28

Minnesota . . . . . . . . . . . . . . . . . . . . . . . — — — — —

Mississippi . . . . . . . . . . . . . . . . . . . . . . —

— —

— 4.96 – — 0.36

Missouri . . . . . . . . . . . . . . . . . . . . . . . . —

—

— 0.03 – — 6.94

Montana . . . . . . . . . . . . . . . . . . . . . . . . —

—

— — — — — —

Nebraska . . . . . . . . . . . . . . . . . . . . . . . . — — — — — — 0.06

Nevada . . . . . . . . . . . . . . . . . . . . . . . . . — — — — —

New Hampshire . . . . . . . . . . . . . . . . . . —

— —

— — — —

NewJersey . . . . . . . . . . . . . . . . . . . . . .

— —

0.18 – 0.29 5.42 – 0.01

New Mexico . . . . . . . . . . . . . . . . . . . . . —

—

— — — —

New York. . . . . . . . . . . . . . . . . . . . . . . .

— —

3.10 30.61 0.42 36.41 – — 0.15

NorthCarolina . . . . . . . . . . . . . . . . . . . — — — — —

North Dakota . . . . . . . . . . . . . . . . . . . . —

— —

— — — —

Ohio. . . . . . . . . . . . . . . . . . . . . . . . . . . .

— —

44.26 43.67 0.51 – — 6.82

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . —

—

— — — — 0.22

Oregon . . . . . . . . . . . . . . . . . . . . . . . . . —

—

— — — — — —

Pennsylvania . . . . . . . . . . . . . . . . . . . . 15.34 16.75 0.53 – — 0.74

RhodeIsland. . . . . . . . . . . . . . . . . . . . . —

—

— 0.05 7.90 —

SouthCarolina . . . . . . . . . . . . . . . . . . . —

— —

— 14.61 — —

South Dakota . . . . . . . . . . . . . . . . . . . . —

— —

— — —

Tennessee . . . . . . . . . . . . . . . . . . . . . . . —

— —

— 2.83 – — — 0.40

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 0.04 – — 0.61

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . –

—

— — — —

Vermont . . . . . . . . . . . . . . . . . . . . . . . . —

— —

— — —

Virginia . . . . . . . . . . . . . . . . . . . . . . . . .

— —

7.43 — 0.02 : — 0.36

Washington . . . . . . . . . . . . . . . . . . . . . —

—

— — — — — —

West Virginia . . . . . . . . . . . . . . . . . . . . 7.22 8.94 0.10 – — 0.35

Wisconsin . . . . . . . . . . . . . . . . . . . . . . . —

—

— — — — 0.36

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . —

—

— — — 0.02

Washington, D.C. . . . . . . . . . . . . . . . . .

—

1.87 — 0.01 = — 0.09

Other . . . . . . . . . . . . . . . . . . . . . . . . . . .

—

4.71 0.03 0.02 – — — 1.51
Ch. 5—Social Costs and Benefits . 123

Table 46.—Estimated LNG Sales by State

(in billion cubic feet)

1977a LNG 1977a LNG

State consumption 1985 LNG percent State consumption 1985 LNG percent

Alabama. . . . . . . . . . . 234.07 33.74 14.4 Nebraska . . . . . . . . . . 144.20 0.10 0.1

Arizona. . . . . . . . . . . . 170.41 — — Nevada. . . . . . . . . . . . 65.47

Arkansas . . . . . . . . . .

— —

221.78 0.40 0.2 New Hampshire. . . . . 8.32

California. . . . . . . . . . 1,664.59

— —

184.0 11.1 New Jersey . . . . . . . . 274.88 2.94 1.1

Colorado . . . . . . . . . . 242.39 0.10 0.1 New Mexico. . . . . . . . 191.56

Connecticut. . . . . . . .

— —

66.63 1.81 2.7 New York . . . . . . . . . . 598.74 59.14 9.9

Delaware . . . . . . . . . . 13.79 — — North Carolina. . . . . . 82.67 — —

Florida . . . . . . . . . . . . 267.93 4.93 1.8 North Dakota. . . . . . . 23.38

Georgia. . . . . . . . . . . .

— —

289.19 56.27 19.5 Ohio . . . . . . . . . . . . . . 909.50 116.38 12.8

Idaho. . . . . . . . . . . . . . 49.76 — — Oklahoma. . . . . . . . . . 689.49 0.37 0.1

Illinois. . . . . . . . . . . . . 1,135.71 23.86 2.1 Oregon . . . . . . . . . . . . 92.12 – —

Indiana . . . . . . . . . . . . 447.24 20.37 4.6 Pennsylvania. . . . . . . 676.24 40.12 5.9

lowa . . . . . . . . . . . . . . 282.39 0.07 0.0 Rhode Island . . . . . . . 23.98 3.50 14.6

Kansas . . . . . . . . . . . . 464.45 2.69 0.6 South Carolina. . . . . . 99.67 18.67 18.7

Kentucky . . . . . . . . . . 192.67 5.25 2.7 South Dakota. . . . . . . 27.47

Louisiana. . . . . . . . . . 1,518.64

— —

2.24 0.1 Tennessee . . . . . . . . . 208.03 4.29 2.1

Maine . . . . . . . . . . . . . 2.11 — — Texas . . . . . . . . . . . . . 3,954.01 1.07 0.0

Maryland & D. C.. . . . . 169.41 15.86 9.4 Utah . . . . . . . . . . . . . . 122.45 — —

Massachusetts . . . . . 167.08 20.42 12.2 Vermont . . . . . . . . . . . 4.52

Michigan . . . . . . . . . .

— —

866.48 86.15 9.9 Virginia . . . . . . . . . . . . 108.44 8.77 8.1

Minnesota . . . . . . . . . 267.83 – Washington . . . . . . . . 153.74 —

Mississippi . . . . . . . .

—

202.20 6.94 ;4 West Virginia.. . . . . . 175.22 20.05 11.4

Missouri. . . . . . . . . . . 334.43 11.70 3.5 Wisconsin . . . . . . . . . 322.18 0.60 0.2

Montana. . . . . . . . . . . 66.66 — — Wyoming . . . . . . . . . . 71.56 0.03 0.0

SOURCE Jensen Associates, lnc

Air quality benefits of gas utilization

With present pollution control technology,

natural gas is the cleanest burning fossil fuel. As

shown in table 47, burning gas generally produces significantly less sulfur dioxide (S02

) and

particulate and somewhat less hydrocarbon

emissions than either oil or coal because of the

lower proportion of carbon in methane. Although natural gas combustion is not as environmentally acceptable as conservation, when

compared to other fuels, it causes the least air

quality impact. For more detailed discussions of

the health and climate effects of specific fossil

fuel combustion products, see OTA’s report on

The Direct Use of Coall and other recent

studies. z 3

4

1 The Direct Use of Coal (Washington, D.C.: U.S,.. Congress, Office

of Technology Assessment, April 1979), OTA-E-86.

Ninth Report of the Council on Environmental Quality v (Council

on Envirionmental Quality v, December 1978).

3National Air Aualityv and Emissions Trends Report, 1977 (Envi -

The contribution of additional gas availability

to meeting requirements for clean air will depend heavily on where it is used. Air quality and

capacity to dissipate pollutants vary from place

to place because of differences in climate, demography, and topography, as do nationaI air

quality standards. The latter are comprised of

three classes: Class I areas (national parks and

wilderness) are subject to the lowest allowable

change in ambient air quality; Class II and 111

areas (all other lands) are subject to varying

degrees of allowable change in ambient air quality and may be redesignated by States. Furthermore, the degree of compliance with national

air quality standards varies with locality and

time. Under the Clean Air Act, States can impose more stringent standards than the national

ones, and State Implementation Plans under the

Act impose different local requirements.

California represents an example of the variety of situations that can occur with air quality
124 ● The Future of Liquefied Natural Gas Imports

Table 47.—Air Pollution From Burning Gas Versus Other Fuels,

in Thousands of Metric Tons per Tcf/Equivalent

(percentages are of total estimated nationwide emissions of the pollutant, 1977)

Gas Oil Coal Conservation

Pollutant Quantity Percent Quantity Percent Quantity Percent Quantity Percent

Sulfur oxide. . . . . . . . . . . 0.3 0 385-427 1.4-1.6 306-2,035 1.1-7.4 0 0

Particulate. . . . . . . . . . . 2.3-7 0 65-334 0.5-2.7 28-4,378 0.2-35.3 0 0

Carbon monoxide. . . . . . 7.9-9.3 0 18.6 0 20-41 0 0 0

Hydrocarbons. . . . . . . . . 0.5-3.7 0 3.2 0 6-20 0 0 0

Nitrogen oxides . . . . . . . 37-325 0.2-1.4 60.2-352 0.3-1.5 311-1,131 1.3-4.9 0 0

NOTES. a) O means less than 0,1 percent.

b) The two numbers represent a range of available pollutlon control technology

SOURCES American Gas Assoclatlon, The Future for Gas Energy In the Un/ied States, June 1979; and the Environmental Protection Agency, National Air Quality and

Emissions Trends Report, 1977, December 1978. Conversion-assumptions: 22 lb per kg, 1,020000 Btu per MCF

compliance. The national and California ambient air quality standards are shown in table 48.

In most areas, California complies with the national and the more stringent State standards

for short-term exposure to SO, and other sulfur

compounds. However, California has had difficulty complying with air quality standards on

carbon dioxide, hydrocarbons, and photochemical oxidants. For example, in the Los Angeles

and San Francisco metropolitan areas, the level

of oxidants has on occasion approached dangerous levels. Furthermore, the SO2 level in the

South Coast Air Basin, which contains about 50

percent of the State’s population, has on many

occasions been higher than what is permitted

under the California standard and on some occasions has reached critical levels. Because of

these air quality problems, increased gas utilization would appear to be an attractive alternative

for that region.

In California the use of certain types of fuel oil

is already prohibited for air quality reasons, so

air quality standards might also preclude gas

customers from switching to more polluting

fuels. Consequently, if the demand for fuel increases where air quality standards are currentBalance of payments

ly violated, the availability of gas could permit

local employment to expand at a faster rate.

However, the effect on employment would

seem to be relatively small, although an early

study has predicted that 700,000 jobs would be

affected, at least temporarily, in the region if

Alaskan and Indonesian LNG were not available. 5 The sponsor, Southern California Gas Co.,

no longer supports the latter conclusion, and

three other studiesG 7 g indicated that a much

smaller number of jobs, probably less than

10,000 to 18)000 would be lost or interrupted.

On a national scale, the employment effect of

the availability of more total energy is uncertain

and probably small because higher economic

growth is offset by possible substitution of labor

for energy.

LNG, like oil,

an outflow of

is imported and thus represents The balance of payments is influenced by

dollars from the United States. many factors, including international trade

This negative contribution to the balance of in- agreements and tariffs, and is partly self-corternational payments affects the value of the recting through the mechanism of floating exdollar, which in turn accelerates inflation at change rates. Consequently, estimating the imhome and reduces the United States’ ability to pacts of a particular trade, such as LNG, runs

obtain credit on favorable terms abroad. the risk of oversimplification and should there-
Ch. 5—Social Costs and Benefits ● 125

1.

2.

3.

4.

5.

6.

7.

8.

9.

Suspended particulate matter

Annual geometric mean . . . . . . . . .

24-hour maximum. . . . . . . . . . . . . . .

Sulfur dioxide

Annual arithmetic mean . . . . . . . . .

24-hour maximum. . . . . . . . . . . . . . .

3-hour maximum. . . . . . . . . . . . . . . .

l-hour maximum. . . . . . . . . . . . . . . .

Carbon monoxide

12-hour maximum. . . . . . . . . . . . . . .

8-hour maximum. . . . . . . . . . . . . . . .

l-hour maximum. . . . . . . . . . . . . . . .

Nitrogen dioxide

Annual arithmetic mean . . . . . . . . .

l-hour maximum. . . . . . . . . . . . . . . .

Photochemical oxidants

l-hour maximum. . . . . . . . . . . . . . . .

Hydrocarbons (non methane)

3-hour (6 to 9 a.m.) . . . . . . . . . . . . . .

Particulate sulfate

24-hour maximum. . . . . . . . . . . . . . .

Hydrogen sulfide

l-hour maximum. . . . . . . . . . . . . . . .

Lead (in particulate matter)

75

260

80 (0.03 ppm)

365

—

—

—

10 mg/m3 (9 ppm)

40 mg/m3 (35 ppm)

100 (0.055 ppm)

—

160 (0.24 ppm)

—

30-day average . . . . . . . . . . . . . . . . . —

10. Visibility reducing particles

(Instantaneous) . . . . . . . . . . . . . . . –

60

150

60 (0.02 ppm)

260 (0.1 ppm)

1,300 (0.5 ppm)

—

—

Same as primary

Same as primary

Same as primary

—

—

Same as primary

—

—

—

—

60

100

—c

131 (0.05 ppm)d

—

1,300 (0.5 ppm)

11 mg/m3 (10 ppm)

—

46 mg/m3 (40 ppm)

—

470 (0.25 ppm)

200 (0.10 ppm)

—

25

42 (0.03 ppm)

1.5

10 miles at relative

humidity less than

7070

1,000 (or coefficient

of haze of 8) for 24 hr

2,620 (4 ppm) for 24 hr

50 ppm for 8 hr

75 ppm for 4 hr

125 ppm for 1 hr

3,750 (2 ppm) for 1 hr

or 0.5 ppm for 24 hr

0.4 ppm for 4 hr

0.6 ppm for 2 hr

0.7 ppm for 1 hr

fore be regarded as a crude approximation. For

example, choosing the lowest cost alternative

from among LNG, foreign oil, and domestic production and conservation may have a salutory

indirect effect on the balance of payments that

outweighs the influence of direct payments associated with any specific trade, With the foregoing caveats in mind, the following discussion

compares the immediate balance-of-payment

impacts of these three general alternatives.

Although importing LNG, involves a significant

outflow of U.S. dollars compared to domestic alternatitves, net foreign payments for imported

oil are greater. The total cost of importing oil is

almost all outflow and represents a sizable dollar amount. Over 95 percent of U.S.-bound oil

arrives in foreign tankers at a transportation

cost of about $0.19 per million Btu (M MBtu), g so

the total return or balance-of-payment inflow is

about 5 percent of the shipping costs, or $0.01/

MMBtu.

In the case of LNG, the most pessimistic assumption would be that the price to the final

customer is the same as that of imported oil

over the long term (see chapter 4 for discussion

of contractual terms). However, the outflow of

dollars would not include expenditures associ-
—. 

126 ● The Future of Liquefied Natural Gas Imports

ated with LNG receiving terminals and regasification facilities in the United States. In addition, the producing country may buy U.S. equipment, and a larger portion of the LNG is likely to

be carried in U.S. flag tankers. Based on cost

estimates in chapter 4, table 49 shows the

amount of a typical LNG project’s cost to be expended in the United States, provided the liquefaction plant is purchased here and 50 percent

of the tanker fleet is U.S. built and operated. In

contrast to oil, about $1/MMBtu of the cost of

service would be expended in this country.

The figures in table 49 consist largely of initial

capital expenditures in the United States amortized over time, so the favorable component of

the impact of importing LNG is actually immediate and short term. After the facilities and ships

are constructed, the balance-of-trade effects are

comparable to those of oil, although U.S. financing could spread payments out over a longer period of time. Finally, the worst case example discussed above is unlikely because the U.S. market will probably limit delivered gas costs to less

than world oil prices because of lower competing domestic oil costs. Even if f.o.b. price renegotiations produce the worst possible outcome,

the delivered price will still only reach this limit

occasionally (see the discussion of the Algeria II

contract in the last chapter).

In conclusion, importing LNG appears to have

a less unfavorable influence on the balance of

payments than importing oil to a significant but

uncertain extent, due to differences in project

structure and to the fact that lower LNG costs

relative to world oil may be the dominant factor. Nevertheless, LNG represents a significant

outflow of dollars compared to domestic alternatives.

Table 49.—Potential Expenditures in the United

States Included in the Cost of an LNG Import Project

in the Fifth Year of Operation in 1990

(1978 dollarslmillion Btu)

U.S. facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ .29

50-percent shipping. . . . . . . . . . . . . . . . . . . . . . . . . . .30

Capital cost of liquefaction plant. . . . . . . . . . . . . . . .43

Total return. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.02

SOURCE: Office of Technology Assessment.