HomeMy WebLinkAboutAPA1621Decision and Report to Congress
on the Alaska Natural Gas
Transportation System
I!;;.Aa""utive Office of the· President
y Policy and Plan~ing
TO THE CONGRESS OF THE UNITED STATES:
Natural gas has become the Nation's .scarcest and
mo$t desired fuel. tt is in ·our interest to b�ing the
reserves in Alaska to market at the lowest possible price.
Conseq�ently, I am todaY: send·ing the Congress my decision
and report on an Alaska Natural Gas Transportation System.
The selection of the Alcan project w�s made after
an exhaustive review required by the Alaska: Natural Gas
Transportation Act of 1976 determine d that �he Alcan.
Pipeline System will deliver more natur.al gas at le·ss cost·
to a greater number of Americans than any other proposed
transportation system.
The Alcan proposal.,.taken together with the recently.
signed Agreement on Principles with Canada, demons·trates
that our two countries working together can transport more
energy mo.;-_e efficiently· than ei.ther Of us could transport
alone •.
·Unnecessary delay would greatly increase the total
cost of the pipeline system. I urge the Congress to act
expeditiously to approve this important ·project.
THE .. WHITE HOUSE, September: 2-2;· .1977
For sale by the Superintendent of Documents, U.S. G:overnment Printing 011lce, Wasbi.ngton, D.O. 20402
Stock No. 060-000--00084-1
TABLE OF CO NTENTS
Page
OVERVIEW •••••••••••••••• · ••••••••••••••••••••.••••••• .: • • • • i
DECI SION ON AN ALASKA NATURAL GAS TRANSPORTAT ION
SYSTEM ••••••••••••••••••••••••••••••••••••••••••••••••• • 1
Preface -Statutory Requirements for a Decision
on an Alaska Natural Gas Transportation
System •••• · •••••••••••••••••• �............ 2
Section 1 -Designation of the Person to Construct
and Operate (Applic ant)................ 4
Section 2 -Description of the Nature and Route of
the Approved System.................... 6
Alc an pipeline route in Alaska................ 6
Alcan pipeline r6ute through Canada........... 7
Alc an ·pipeline route in the continguous
Un ited States............................... 10
I
Section 3 --Identification of Facilities Included
Within "Con struction arid Initial
Operation"............................. 12
General project descriptio n ................... 12
Al dan compressor stations and refrigeration
faci 1 i ties in Alaska. • • • • • • • • • • • . •. • . • • • • • • • • 17
Other Alcan pipeline facilities in Alaska..... 18
Lo wer 48 facilities ••• �....................... 19
�\l'estern Leg. • • • • • • • • • • • • • • •.• • • • • • • • • • . • • • 20
Eastern Leg.............................. 21
Section 4-Identification of Provisions-of Law
That Have Been Subsumed Into This
Decision and Require Waiver............ 23
Section 5-Terms and Conditions and Enforcement... 26
Terms and Conditions •••• �..................... 27
Enforcement ••••••••••••••••• �................. 40
Section 6-Pricing of Alaska Gas.................. 44
Section 7 -� Agr eement on Principles Applicable to a
Northern Natural Gas Pipeline.......... 47
REPORT ACCOHPANYING A DECISION ON AN ALASKA NATURAL GAS
TRANSPORTATION SYSTEM. • • • • • • • • • • • • • • • • • • • • • • • • • . • • . • • • • • 8 4
Preface ••• . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
Chapter I-Desirability of an Alaska Gas Project •• 87
Natural gas supply.
United States ••••••
Canada •••••••••••••
Economic considerations.
Conclusion ••••••••••••••
. . . ... . . .
Chapter II -Financial Analysis. . . . . . . . . . . . . . . . . . . .
Conclusions ••••••••••••
Analysis ••••••••••••••••
Alcan financial plan ••••
Capital requirements and sources of funds
Capital markets ••••••••••••••••••••••••••
Cost overrun financing •••••••••••••••••••
Project participants and beneficiaries.
Transfer of financial risks •••••••
Variable rate of return. • ••••
Cost to the consumer •••••••••
Financeabili ty •••••••••••••••
Finding regarding financing.
Chapter III -Environmental and Socioeconomic
Considerations •••••••••••••••
The environmental advantages of Alcan.
Presidential finding-Environmental impact
. . .
statements ••••••••••• . . . . . . . . . . . . . . . . . .
Socioeconomic impact. . . . . . . . . . . . .
Conclusion ••••••••••••••
Chapter IV -Economic Considerations ••••••
Potential for cost overruns and time delay.
Comparisons with Alyeska ••••••••••••••
Cost overrun estimates under expected
conditions ••••••••••••••••••••••••••
. . .
...
87
87
92
93
98
100
100
101
104
106
108
114
115
119
122
124
125
127
128
128
131
13-3
134
136
136
138
149
3
Cost of service ••.•••••••••••••••••••••••••••• 158
Alcan and El Paso: Cost of service
comparison ............................. 160
Alcan cost of service pursuant to the
Agreement on Principles •••••••••••••••• 163
Net national economic benefit ••••••••••••••••• 174
Chapter V-Safety, Reliability and Expansibility .. 181
Safety of design and operation •••••••••••••••• 183
Potential for Service Interruption-
Reliability ................................. 191
Efficiency of design and capability
of expansion .................................. 193
Chapter VI -Organization of Federal Government
Involvement After System Selection •••• 197
Introduction •••••••••••••••••••••••••••••••••. 197
The organization of Federal involvement with
the Alcan project ..............•.............. 201
Implementation of organizational plan .•••••••• 204
·coordination with the States ••••••••••••••.•.• 205
Chapter VII -Impact on Competition in the Natural
Gas Industry ......................... 208
Gas transmission and distribution industry •••• 209
Gas producers ••••••••.•••••••••••.•••••..••••• 210
Chapter VIII-National Security •••••••••••••.•••.• 213
Chap t e r I X -\v e s tern L e g • • • • • • . • • • • • • • • • • • • • • • • • • • . 21 7
The authorization of facilities ••••••••••••••• 217
The Western share of Alaska gas •••••••.•• 219
Increased and accelerated Canadian
exports. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 21
4
Estimated excess capacity in existing
systems ••••••••••••••••••••.••••
Existing facilities of the
Western States •••••••••••
Direct delivery . . . ~ . . . . . . . . . . . . . . . . . . . . .
Displacement •••• ..............
Size and volume of a Western Leg.
Conclusion •••••••••••••••.•••••••
Chapter X -Relationship of the Decision to the
Recommendation of the Federal Power
Commission ••••..•.•••••
Chapter XI -Agreement with Canada.
Issues ....................... .
Taxes and impact assistance.
Native claims ••..•••.••••.••
"Canadian content" regulations.
Ernp loyrne n t .................... .
.....
Analysis of the agreement with Canada.
Chapter XII -Summary of Comments Received.
Comments on specific
Arctic gas.
El Paso.
Al can •••••••.
projects •••••••••
Comments on specific F~C recommendations.
Formula \•lellhead pricing •••••• · ••
Minimum throughput requirements.
Widespread distribution of gas.
Western leg.·~··················
. . . . .
.....
. . . . .
222
222
223
2 24
231
232
235
238
2 38
239
241
242
243
245
266
267
267
268
269
270
270
270
270
271
i
OVERVIEW
In the winter of 1967-68 a wildcat rig drilling
Prudhoe Bay State Well No. 1. struck a formation that,
when later delineated, proved to be the largest petroleum
reserve on the North American continent. The Prudhoe Bay
field contains over 20 trillion cubic feet of saleable
natural gas and more than 9 billion barrels of recoverable
oil. This gas represents approximately 10 percent of
the known gas reserves in the United States.
In 1969, the State of Alaska held a lease sale and
received almost $1 billion in lease bonuses. Shortly
thereafter, the three major leaseholders in the Prudhoe Bay
Oil Pool announced their intention to build an oil pipeline
through Alaska from Prudhoe Bay to a site on the Gulf of
Alaska. After an initial flurry of activity,~ the Trans-
Alaskan Pipe Line System (TAPS) became entangled in legal
disputes until November of 1973, when the Congress and
President approved the plan and provided for expedited
procedures. Construction was started immediately there-
after and the first flow of oil through the pipeline
commenced on June 20, 1977.
Another set of studies began in 1969 which eventually
\
resulted in applications to the Federal Power Commission
(FPC) in the u.s. and the National Energy Board (NEB) in
l.
ii
Canada for a certificate to construct a pipeline to move
Alaskan and Mackenzie Delta gas to United States and
Canadian markets, respectively, by Arctic Gas (Alaskan
Arctic Gas Pipeline Company and Canadian Arctic Gas
Pipeline Limited) in March 1974.
In September 1974, El Paso Alaska Company filed an
application to transport Prudhoe Bay gas by a pipeline
adjacent to TAPS to the Gulf of-Alaska, liquify it, and
ship it to California by LNG tanker. There the LNG would
be regasified and provided to its purchasers either directly
or by displacement through existing pipeline facilities.
Under the Trans-Alaska Pipeline Act Congress had
authorized and requested the President to determine the
willingness of the Government of Canada to authorize a
natural gas pipeline for Alaska gas across Canada and
whether intergovernmental agreements would be needed to
achieve th~t end. After discussions, the Government of
Canada indicated they were prepared to consider an agree-
ment of general applicability as opposed to an agreement on
a specific pipeline. Negotiations on a Transit Pipeline
Treaty were undertaken, and a treaty was finally signed on
January 28, 1977, and entered into force on September 19,
1977. It will govern all existing and future transit pipe-
' lines in the two countries for thirty-five years.
iii
On April 7, 1975, a proceeding before FPC Administrative
Law Judge Nahum Litt was initiated and over 45,000 pages of
testimony and more than 1000 supporting exhibits were com-
piled before it was concluded. Similar hearings were held
by the NEB in Canada.
On July 9, 1976, Alcan Pipeline Company and Northwest
Pipeline Company (Alcan) filed the third application with
the FPC for a certificate to transport Alaskan gas. The
Alcan plan, as modified in March 1977, calls for a pipeline
following existing utility corridors from Prudhoe Bay
through Canada to the U.S. markets.
Recognizing the shortages of natural gas, the large
reserves of natural gas in~Alaska, the benefits resulting
from the expeditious construction of a transportation
system for that gas, and the potentials for delay inherent
in the normal regulatory approach to a project of this
magnitude, on October 22, 1976, Congress passed the Alaska
Natural Gas Transportation Act of 1976 (ANGTA). Designed
to draw upon all relevant governmental, public and private
expertise in reaching a Presidential and Congressional
decision on construction of the best possible Alaska natural
gas transportation system, if any, the statute established
a unique process for reaching an expedited decision.
iv
This Decision and Report on an Alaska Natural Gas
Transportation System meets the statutory decision-making
requirements of the Alaska Natural Gas Transportation Act
and represents the culmination of the Executive Branch
function in the process established by the Bill.
The Act's Statement of Purpose clearly sets out the
Congressional objectives:
"Sec. 3. The purpose of this Act is to provide
the means for making a sound decision as to the selec-
tion of a transportation system for delivery of Alaska
natural gas to the contiguous States for construction
and initial operation by providing for the participa-
tion of the President and the Congress in the selec-
tion process, and, if such a system is approved under
this Act, to expedite its construction and-initial
operation by (1) limiting the jurisdiction of the
courts to review the actions of Federal officers or
agencies taken pursuant to the direction and author-
ity of this Act, and (2) permitting the limitation
of administrative procedures and effecting the limita-
tion of judicial procedures related to such actions.
To accomplish this purpose it is the intent of the
Congress to exercise its Constitutional powers to the
v
fullest extent in the authorizations and directions
herein made, and particularly with respect to the
limitation of judicial review of actions of Federal
officers or agencies taken pursuant thereto."
Shortly after the passage of ANGTA, Judge Litt
concluded the FPC hearing and on February 1, 1977 issued
the Initial Decision favocing the Arctic proposal. Accord-
ing to the provisions in the Act, on May 2, 1977, the FPC
made its Recommendation to the President in which it
reconLTtended an overland route through Canada but divided
2-2 on the choice between A~can and Arctic Gas.
As required in the Act, comments on the Recommendation
of the FPC were made to the President on July 1, 1977, by
ten interagency task forces and a wide spectrum of non-
Federal government officials and other interested persons.
While generally supportive of the FPC Recommendation, they
raised important questions regarding virtually every major
element of the Recommendation.
On July 4, 1977, Canada's NEB made its decision
regarding an overland pipeline system through Canada. It
found the Arctic Gas proposal "environmentally unacceptable"
and stated it was prepared to certify Alcan conditioned
upon several modifi'cations of the Alcan system recomr;,ended
vi
by the FPC. Within a few weeks, an interagency group of
U.S. negotiators began meeting with Canadian officials to
explore the ooundaries of the Canadian option to enable
the President to make an informed decision under the Act.
On September 1, the President announced a deferral
in transmitting the decision to the Congress to complete
negotiations with the Canadians. After intensive negotia-
I'
tions, President Carter and Prime Minister Trudeau announced
I II in Hashin']ton on September 8, that both countries had
reached &n ~greement in principle on a joint project for
the transportation of Alaskan and Canadian gas. The
President and Pri~e Mi~ister noted the superiority of a
joint project to any unilateral undertaking by either
government. In addition to announcing an intention to
sign a formal Agreement on Principles concerning the
project, both governments pledged to seek approval from
their respective legislatures of expedited provisions for
project construction and operation.
With the signing of the Agreement on Principles
applicable to a Northern Natural Gas Pipeline in Ottawa
on September 20, 1977, the President transmitted the
Decision favoring the Alcan project to the Congress for
its approval. The Congress has sixty legislative days within
which to act upon a joint resolution of approval.
vii
The Agreement on Principles, as incorporated in the
Decision of the President, provides the framework for a
clearly specified, economically efficient, and environ-
mentally superior means of transporting both u.s. and
canadian gas to markets through a joint pipeline system.
Approval of the Decision, which incorporates the Agreement
on Principles, will provide the same type of commitment
by the United States to this undertaking as will result
from passage of the implementing legislation which Prime
Minister Trudeau has announced will be submitted to
Parliament in October.
This Decision is supported by a strong record and
recommendation from the FPC, substantial comments from all
parties of interest and a clear and cogent agreement with
the Canadian government that provides significant benefits
for both countries.
?.· * * * *
The proposed Alcan system will deliver Alaska gas at
the lowest cost-of-service to U.S. consumers --probably
below the cost of imported_ oil and substantially below the
costs of other £uel alternatives. The average price of
distillate from imported oil over the life of the project
I
.,
il'
I
1:
Ill·
·II ,,,
I~~
Vlii
is expected to be in excess of $3 per million btu's (mmbtu)
in consLant 1975 dollars. The average delivered price of
Alaska gas for the same period will be substantially less
even with a significant allowance for cost overruns. The
Alcan system will deliver Alaskan gas at the lowest cost
to u.s. consuuers, but will do so directly to both the
~idwest and West Coast markets. Furthermore, the Alcan
system will increase the ability of Canada to develop its
own frontier gas reserves, particularly in the Mackenzie
Delta, through connection of the proposed Dempster Highway
lateral pipeline with the Alcan mainline from Alaska. If
Mackenzie 0elta gas is brought to Canadian ~arkets, u.s.
consumers might also benefit from the enhanced availability
of Canadian supplies.
Under almost all criteria, the Alcan system is clearly
superior to the proposal by the El Paso Alaska Company to
liquefy Alaska gas and ship it to the West Coast. Over a
20-year period, the Alcan system would deliver Alaska gas
to U.S. consumers at a significantly lower average cost-of-
service than El Paso. In 1975 constant dollars the 20-year
average cost of service foe Alcan is estimated to be $1.04
per mmbtu, and $1.21 per mmbtu for El Paso. This $.17
difference represents ultimate savings of $6 billion for
ix
American consumers over the life of the Alcan project.
Alcan also can move the same volume of gas with a higher
fuel efficiency, and will have much lower annual ope-
rating costs than the El Paso LNG system.
Alcan also has a markedly greater Net National Economic
Benefit (NNEB) than El Paso. The calculation of the NNEB
compares the present value of real resource expenditures
for a project with the present value of future benefits.
Alcan has an estimated NNEB of $5.77 billion, more than
$1.1 billion higher than the estimated NNEB of El Paso.
In addition to these economic advantages, Alcan has
significant technical and resource advantages over El Paso.
These include:
the superiority of pipeline transportation over LNG
transportation for the safest and most reliable
delivery of gas, and for expansibility of capacity
to deliver increased volumes from reserves other
than the Prudhoe Bay Pool;
the substantial advantage of pipeline facilities
over LNG facilities in having a useful life of over
40 years;
i
irl,
'I' r:l
'II
,1,
I ,'I,
1[1,
! I
X
the need to anticipate future shipment of natural
gas from the Gulf of Alaska which may require LNG
deliveries to the West Coast, thus preserving
LNG delivery potential on the West Coast.
Furthermore, virtually all Federal agencies and private
parties that compared the two projects determined that
the Alcan system is environmentally superior to El Paso.
The Agreement with Canada on the Alcan system assures
the cost-of-service advantages of the Alcan proposal. The
Agreement provides that the Alcan pipeline will follow the
original Alcan Highway route, without the route diversion
required by the NEB. This provision alone saves the U.S.
consumer up to $600 million in initial construction costs,
plus interest, or the 6 cents in cost of service that
would have been added by the route diversion. In return,
the u.s. agreed to pay a portion of the cost for an
extension of the Dempster Lateral from Dawson to Whitehorse
in the Yukon --if and when the lateral is built. This
limited extension, or "spur," would connect the Dempster
line with the main Alcan system. A higher capacity, more
efficient system will be installed south of Whitehorse,
with costs shared on a volumetric basis, to carry U.S. and
Canadian vo;umes.
xi
Significantly, under the Agreement, the U.S. share
of costs for the "spur" from Dawson to Whitehorse is tied
to the percent of actual cost overruns on the construction
of the Alcan main line in Canada. This element of the
Agreement creates a formidable incentive for Canada to
minimize cost overruns on the construction of the Alcan
line in Canada. In addition, the AJreement protects the
Alcan pipeline from unfair or discri~inatory ta~es that
might threaten the cost of service advantages of Alcan for
u-.s. consumers. The provisions in the Agreement frovide a
ceiling on the imposition of Yukon taxes, and supercede
the previous NEB recom.::nendation for a $200 million impact
assistance payment from U.S. consumers to the Yukon. Any
advance payment of tax by the pipeline will be treated as a
loan to the government, to be paid back with interest from
future tax revenues, but in no event will the loan affect
the cost of service to u.s. consumers. The fixed level of
overall tax is only a modest increase above the level of
tax included in the original estimates for Alcan's cost of
service, and has been fixed with reference to the tax
regime applicable in Alaska.
246-448 0 -77 - 2
xii
In this Agreement, the United States and Canada both
improved their positions from the original NEB decision,
and achieved a reduction in the cost of service price of
both Alaskan gas and Canadian gas from the Mackenzie
I
1,1' Delta. The modified Alcan system will also:
assist Canada to continue supplying gas exports
under existing contracts by providing it with
access to substantial Mackenzie Delta reserves;
provide the opportunity to obtain additional gas at
an earlier date by early construction of portions
of the southern Canadian and lower 48 sections of
Alcan, with delivery of gas from Alberta (where
there is temporary excess supply) in advance of
the delivery of Alaska gas;
encourage exploration for new reserves and stimulate
expansion of the gas industry in Canada, which
might ultimately benefit u.s. consumers through the
enhanced potential of Canadian supplies.
Furthermore, this joint U.S.-Canadian undertaking could
result in significant cooperation with Canada on a variety
of other energy issues, such as oil exchanges, p1pelines and
strategic reserves.
r .
xiii
The Alcan project will be one of the largest --if not
the largest privately financed international business
ventures of all time. The minimal risk of non-completion
will be borne by the private financial markets. There will
be no Federal debt guarantees, and consumers will not be
required to bear any portion of the risks of non-completion.
The Federal Government, however, will have an expanded
and significant role in monitoring and overseeing the con-
struction of the project. By enforcement of the terms and
conditions proposed herein and to be later specified, the
Federal Inspector for the construction of the project will
coordinate Federal involvement with the project, minimizing
cost overruns, preventing management abuses, and facilitating
the timely completion of construction. The u.s.-canadian
Agreement provides additional incentives to minimize cost
overruns on construction in Canada. The Decision, including
the Agreement, seeks to ensure that u.s. consumers will
have the enormous benefit of new Alaskan gas supplies
at a price significantly below that of alternative energy
sources.
. I
I .
I
. I
xiv
A superior project has now been selected as a result
of a thorough decision making process involving all the
resources of the Feder9l Government and a spirited competi-
tion between private alternatives. The nation sorely needs
new sources of economically competitive natural gas. Now
is clearly the time to approve the decision to undertake
the final planning and construction of this cost-efficient
system for bringing critical supplies of Alaska natural gas
to U.S. markets.
DECISION ON AN ALASKA
NATURAL GAS TRANSPORTATION
SYSTEM
2
PREFACE -STATUTORY REQUIREMENTS FOR A DECISIGN ON AN ALASKA
NATURAL GAS TRANSPORTATION SYSTEM
Section 7(a)(4) of the Alaska Natural Gas
Transportation Act of 1976 (ANGTA) states:
If the President determines ·to designate for
approval a transportation system for delivery
of Alaska natural gas to the contiguous States,
he shall in such decision-
(A) describe the nature and route of the system
designated for approval;
(B) designate a person to construct and operate
such a system, which person shall be the appli-
cant, if any, which filed for a certificate of
public convenience and necessity to construct
and operate such system;
(C) identify those facilities, the construction
of which, and those operations, the conduct of
which, shall be encompassed within the term
"construction and initial operation" for purposes
of defining the scope of the directions contained
in Section 9 of this Act, taking into considera-
tion any recommendation of the Commission with
respect thereto; and
(D) identify those provisions of law, relating
to any determination of a Federal officer or
agency as to whether a certificate, permit,
right-of-way, lease, or other authorization
shall be issued or be granted, which provisions
he finds (i) involve determinations which are
subsumed in his decision and (ii) require
waiver pursuant to Section 8(g) in order to
permit the expeditious construction and initial
operation of the transportation system.
3
As part of these determinations, an Agreement on
Principles concluded with the Government of Canada pre-
scribes various terms and conditions applicable to the
construction and operation of the pipeline. The Agreement
on Principles is attached hereto as Section 7 of this
Decision and made an integral part of the Decision by this
reference.
With the incorporation of the aforesaid Agreement,
and the finding that it is in the national interest to
expeditiously undertake to construct an Alaska Natural
Gas Transportation System, the system designation and
related statutory determinations are as follows:
4
SECTION 1 -DESIGNATION OF PERSON TO CONSTRUCT AND OPERATE
THE SYSTEM
The Alcan Pipeline Company, now a wholly owned
subsidiary of Northwest Pipeline Corporation11, or its
successor, is hereby designated to construct and operate
the portion of the system within the State of Alaska.
The Northern Border Pipeline Company, a partnership·
consisting of subsidiaries or affiliates of Columbia Gas
Transmission Corporation, Michigan-Wisconsin Pipeline
Company, Natural Gas Pipeline Company of America, Northern
Natural Gas Company, Panhandle Eastern Pipe Line Company,
and Texas Eastern Transmission Corporation, or its successor,
is hereby designated to construct and operate the portion
of the system from the United States-Canada border near
Monchy, Saskatchewan, to a point near Dwight, Illinois.
The Alcan Pipel~ne Company, or its successor, and the
Northern Border Pipeline, or its successor, shall be
publicly held corporations or general or limited partner-
ships, open to ownership participation by all persons
1/ Northwest Pipeline owns and operates a 4,300-mile
-pipeline system for transporting gas in the states of
/Colorado, Idaho, Nevada, Oregon, Utah, Washington, and
Wyoming. Northwest Pipeline is a wholly-owned subsidiary
of Northwest Energy Company, a holding company whose
principal asset is all the outstanding common stock of
Northwest Pipeline.
5
without discrimination, except producers of Alaskan
natural gas.
The Pacific Gas Transmission Company is hereby
designated to construct and operate the portion of the
system from the United States/Canada border near Kingsgate,
British Columbia, to the border between the States of
California and Oregon.
The Pacific Gas and Electric Company is hereby
designated to construct and operate the portion of the
system from the border between the States of California
and Oregon through the State of California.
6
SECTION 2 -DESCRIPTION OF THE NATURE AND ROUTE OF THE
APPROVED SYSTEM
The Alcan system is an overland pipeline system to
transport natural gas from the Prudhoe Bay area of Northern
Alaska through Alaska and Canada into the Midwest and
Western sections of the contiguous United States. See
Exhibit 1.
The expected volume of gas to be available initially
from the Prudhoe Bay field is 2.0 to 2.5 billion cubic feet
per day (bcfd). The system described herein is designed to
handle thjs throughput volume. The capacity of the system
could be increased in the future to accommodate additional
volume throughput by construction of additional facilities.
Alcan Pipeline Route in Alaska
The proposed Alcan pipeline will commence at the
discharge side of the gas plant facilities in the Prudhoe
Bay field. The pipeline will parallel-the Alyeska oil
pipeline southward from the North Slope of Alaska, cross
the Brooks Range through the Atigun Pass, and continue on
to Delta Junction.
At Delta Junction, the Alcan Pipeline will diverge from
the Alyeska oil pip~line and follow the Alaska Highway and
the Haines oil products pipeline right-of-way, passing
near the towns of Tanacross, Tok, and Northway Junction
' ·,
System Map of the
ALCAN Project
and
El Paso Alaska Project
7
in Alaska. The right-of-way of the Haines oil products
f pipeline is at present approximately fifty feet wide and
~
is closely parallel to the Alaska Highway. The Alcan
pipeline will then connect with the proposed new facili-
t1es of Foothills Pipe Lines (South Yukon} Ltd. at the
Alaska/Yukon Territory border.
From Prudhoe Bay to Delta Junction, Alcan expects to
construct its line approximately eighty feet from the
Alyeska oil pipeline. As proposed by Alcan, construction
will be carried out by extending the existing Alyeska work
pads. However, Alyeska advised Alcan that its "preliminary
general guidelines" indicate that the Alyeska and Alcan
lines must be separated by 100 to 200 feet where blasting
to build the pipeline trench would occur (approximately
350 miles of pipeline length}. Additional studies will
determine the minimum distance between the Alyeska oil
pipeline and the Alcan line that is necessary to permit
safe construction and operation.
Alcan Pipeline Route Through Canada
The Canadian portion of the Alcan Project will 6ommence
at the Alaska/Yukon border in the vicinity of the towns of
Border City, Alaska and Boundary, Yukon.
From the Alaska/Yukon border, the Foothills Pipe Lines
(South Yukon} Ltd. pipeline will proceed south until it,
8
reaches the White River (milepost 44), where it will take
a more eastward course across the Yukon Territory. The
pipeline will cross the Territory generally parallel to
the Alaska Highway. Along most of the pipeline route
through the Yukon, the separation between the pipeline
route and highway route will be approximately one mile.
There will be several points, however, where the pipeline
route will divert substantially from the route of the
Alaska Highway. These departures from the Alaska Highway
route will permit the pipeline to continue on a more direct
course than if it were to follow the Alaska Highway.
·At approximately milepost 246, the pipeline will
be routed north of Whitehorse and cross the Yukon River near
the intersection of the Alaska and Klondike Highways. Near
this intersection, approximately 9 miles northwest of
Whitehorse, the pipeline will be constructed to permit a
later connection with the proposed Dempster Line from
the Mackenzie Delta, if and when the Dempster Line is
constructed.
After it crosses the Yukon River north of Whitehorse, .
the pipeline will turn southeast and again travel parallel
to the Alaska Highway, entering British Columbia at approxi-
mately milepost 397 and reentering the Yukon Territory at
approximately milepost 435. The pipeline will continue
9
to follow the Alaska Highway eastward through the Yukon
Territory and again cross the border into British Columbia,
approximately twelve miles southwest of Watson Lake, Yukon.
At this point, the Foothills Pipe Lines (South Yukon) Ltd.
pipeline will terminate, and the Foothills Pipe Line (North
B.C.) Ltd. interconnecting pipeline will commence.
After it passes the British Columbia border, the
pipeline will proceed generally southeast across the
northeastern part of the Province to the British Columbia/
Alberta border, crossing the existing Westcoast Transmission
Company Ltd. main line some 35 miles south of Fort Nelson.
At Boundary Lake on the British Columb;ia-Alberta border,
the pipeline would connect with the Foo~hills Pipe Lines
(Alta.) Ltd. pipeline. In Alberta, the Foothills Pipe
Lines (Alta.) Ltd. pipeline will proceed generally southeast
from Boundary Lake to Gold Creek Junction. After Gold Creek
Junction, the pipeline will follow the existing Alberta Gas
Trunkline Co., Ltd. (AGTL) pipeline right-of-way to James
River Station.
From James River Station, the western leg of the
pipeline will proceed separately to the south, approximately
following the existing AGTL right-of-way to the Alberta/
British Columbia border near Coleman, Alberta. It will
then connect with the Foothills Pipelines (South B.C.)
II
; I
I 1
10
Ltd. pipeline, continue to the southwest across British
Columbia, and finally connect with the Pacific Gas
Transmission {PGT) pipeline at the United States/Canada
border near Kipgsgate, British Columbia. The pipeline
route through· southern British Columbia will generally
parallel the existing pipeline route of Alberta Natural
Gas Company Ltd.
For the eastern leg from the James River Station, the
pipeline will proceed generally t~ the southeast until it
reaches the Alberta/Saskatchewan border near Empress,
Alberta. The eastern leg will then connect with the
Foothills Pipe Lines {Sask.) Ltd. pipeline. The pipeline
will then continue to the southeast across Saskatchewan
and join with the Northern Border Pipeline system at the
United States/Canada border near Monchy, Saskatchewan.
Alcan Pipeline Route in the Contiguous United States
On the western leg, the Alaska gas will be transferred
at the United States-Canada border near Kingsgate, British .
Columbia, to the PGT system. ~he PGT system will transport
the gas through northern Idaho, southeast washington, and
central Oregon. At the Oregon/California border, the gas
will be transfe~red to enter the ~acific Gas and Electric
Company {PG&E) system and will then be transported through-
out California.
11
On the eastern leg the Alaska gas will be transferred
at the Saskatchewan/Montana border from the Canadian-owned
portion of the Alcan system to the Northern Border
Pipeline system. The Northern Border Pipeline system
will then transport the gas across the northeast corner
of Montana, the southwest section of North Dakota, the
northeast section of South Dakota, the southwest corner of
Minnesota, and the northeast section of Iowa, and finally
bring the gas just south of Chicago to Dwight, Illinois.
Exhibit 2 on the following page illustrates the
respective routes of the eastern and western legs of the
Alcan system and their relationship to ~he existing gas
pipeline network in the United States.
246-448 0 -77 - 3
-· r-·-·-·-· ~r·-· . I
I j j
I . . I I
"'()
/
/
' I
/
I
ALCAN Pipeline Project Location Relative
to Existing Natural Gas Pipeline Network
13
SECTION 3 -IDENTIFICATION OF FACILITIES INCLUDED WITHIN
"CONSTRUCTION AND INITIAL OPERATION"
General Project Description .
This section identifies the facilities for the Alcan
project which will be entitled to the expedited authoriza-
tion process prescribed in Section 9 of ANGTA. The
facilities which are to be covered are those in the u.s.
which are adequate for a throughput of up to 2.4 bcfd and
are included in the revised Alcan filing submitted to the
Federal Power Commission (FPC) in March 8, 1977. If any
modifications to those facilities.are required by the
Agreement on Principles between the u.s. and Canada, those
modified facilities will also be entitled to the expedited
authorization process in Section 9.
Uncertainties remain as to the future level of gas
exports from Canada's historical gas supply sources. The
actual division of Alaska gas among the various regions of
the contiguous United States awaits conclusion of gas sales
contracts. ·Routing and design work should be sufficiently
complete to allow final certification in late 1978 or early
1979. The final design and location of the facilities,
however, will be within the general description set forth.
The gas transportation system will utilize a 48-inch
diameter pipeline from Prudhoe Bay to James River, Alberta.
14
From James River, gas destined for the midwestern and
eastern states will be transported through a 42-inch
diameter pipeline to Monchy, Saskatchewan, and gas des-
tined for the western states will be transported through a
36-inch pipeline to Kingsgate, British Columbia. PGT and
PG&E will complete loopingl/as necessary of their existing
pipeline systems from the Idaho-British Columbia border to
Antioch, California (near San Francisco) with a 36-inch
diameter pipeline.
All of the pipeline in Alaska and the first forty-one
miles of pipeline in the Yukon lie in the continuous and
discontinuous permafrost region.l/ This section will be
operated in a chilled state (i.e., below 32°F.) to pre~
vent degradation of the permafrost regime. Gas chilling
Y "Looping" is construction of a pipeline parallel to and
interconnected with an existing pipeline. Looping may
extend to. part or all of an existing line.
ll By definition, permafrost consists of soil, rock, or
other earth materia1 6· the temperature of which remains
at or below 32°F. (0 C) continuously for two or more
years. Its distribution is not uniform. Factors con-
trolling the distribution of permafrost include the
glacial and climatic history of the area, thermal prop-
erties of· the earth material, ambient temperature, insu-
lation properties of overburden, and amount of exposure
to sun (e.g., shading caused by orientation of topographic
features). · The permafrost would be continuous along
approximately the first 240 miles of the pipeline (to
near the South Fork of the Koyohuk River). Along the
remaining pipeline route to the Yukon border, the perma-
frost would be discontinuous.
15
will be accomplished by propane refrigeration systems at
all compressor stations in Alaska.
The length of the various pipeline segments will be as
follows:
Company
Alcan Pipeline Company
Foothills Pipe Lines
(South Yukon) Ltd.
Foothills Pipe Lines
( Sask.) Ltd.
Foothills Pipe Lines
(North B.C.) Ltd.
Foothills Pipe Lines
(South B.C.) Ltd.
Foothills Pipe Lines
(Alta.) Ltd.
Location
Alaska
Yukon
Saskatchewan
Yukon/B.C. Border to
B.C./Alberta Border
Coleman to Kingsgate
B.C./Alberta to
James River
James River to Colemen
James River to Empress
Total Alaska and Canada
Pacific Gas Transmission Co. Kingsgate to Malin
Pacific Gas & Electric Co. Malin to Antioch
Northern Border Pipeline Co. Monchy to Dwight
Total Contiguous States
Length
(Miles)
731
517
160
439
106
395
176
235
2,759
612
299
1,117
2,028
Total System Length 4,787
Exhibit 3 on the next page identifies and locates the.
various pipeline segmen~s.
Alc:an Pipeline
Company
731 Miles, 48"Line
Foothills Pipe Lines
(South Yukon) Ltd.
517 Miles, 48"Line
Foothills Pipe Lines
(Alta) Ltd.
176 Miles, 36"Line
Foothills Pipe Lines
(South B.C.) Ltd.
1 06 Miles, 36"Line
Pacific Gas
Transmission Co.
612 Miles
Partial 36"Looping
Pacific Gas &
Electric Company
299 Miles
Partial 36''Looping
---
--
---
I
/
/
---;:·--
····· --~:r--·
)-., I
,/ ............ /
/ L
---
r-------
1
I
' I
I
I -
, __ _
-;
--
--
----Foothills Pipe Lines
(North B.C.) Ltd.
439 Miles, 48"Line
---------Foothills Pipe Lines
(Alta) Ltd.
395 Miles, 48"Line
-------Foothills Pipe Lines
(Alta) Ltd.
236 Miles, 42''Line
----
Foothills Pipe Lines
(Sask) Ltd.
160 Miles, 42''Line
Northern Border
Pipeline Company
1,117 Miles, 42"Line
DESCRIPTION OF
ALCAN PIPELINE PROJECT
17
Peak-day capacity utilizing nine compressor stations
(see item 4 below) will be 2.6 bcfd, with an average daily
volume of 2.4 bcfd. By installation of intermediate corn-
pressor stations, the system could be increased to 3.4 bcfd
peak capacity, with an average day capacity of 3.2 bcfd.
The system capacity could be further increased by addition
to the compressor horsepower at each station.
Alcan Compressor Stations and Refrigeration
Facilities in Alaska
Centrifugal compressors, powered by natural gas-fueled
turbine engines, will be used on the Alcan system. In order
to minimize thawing of the permafrost S?il, the discharge
gas at each compressor station in Alaska will be chilled by
a propane refrigeration plant. The following describes the
required compression and refrigeration facilities. All of
these facilities are required for construction and initial
operation. Number of 'lbtal Installed Horsepower( ISO)
Gas Gas Gas
Station Milepost Compressors Compression Refrigeration
AL-l 75.0 1 26,500 7,660
AL-2 133.0 1 26,500 7,660
AL-3 242.3 1 26,500 13,830
AL-4 331.8 1 26,500 13,830
AL-5 418.8 1 26,500 13,830
AL-6 504.7 1 26,500 13,830
AL-7 589.9 1 26,500 13,830
AL-8 ()73.4 1 26,500 13,830
'IOTAL 8 212,000 98,300
18
Other Alcan Pipeline Facilities in Alaska
Metering facilities for the measurement of gas flow
and gas quality will be required in Alaska at the Prudhoe
Bay receipt point, at the Fairbanks sales point, and at the
transfer point on the Alaska-Yukon border.
A central operating center, located in Fairbanks, will
monitor and control all compressor station operations.i/
Alcan will utilize staging areas established for the
Alyeska oil pipeline at Prudhoe Bay, Fairbanks, and Valdez.
Material storage sites .will be located at Anchorage, Seward,
and Whittier, and at selected locations along the pipeline
route.
Existing transportation and communication facilities
will be utilized to the fullest extent practicable. Short
lateral roads will be constructed to pipeline facilities
as required.
Permanent bases for operating and maintaining the system
will be selected and located after defining areas in which
·common problems may occur due to similarities of terrain and
il The compressor stations will be automated for remote
control of all normal functions, including discharge gas
temperature.
19
climate. The bases will be located at or near compressor
stations to avoid duplication of permanent above-ground
facilities. Materials and various spare parts will be
located at the bases to facilitate maintenance and repair
operations.
All of these facilities will be required for construe-
tion and initial operation.
Lower 48 Facilities
For purposes of this part of the Decision, the facilities
described generally below are deemed necessary for construe-
tion and initial operation, and will be entitled to expedited
issuance of authorizations pursuant to'Section 9 of ANGTA,
provided that the final certification of such facilities
shall be determined by reference to the ~ize necessary to
provide the transportation capacity certified to the FPC 5/
by the Secretary of Energy, as set forth in the .terms and
conditions section.
The final certification function currently resides with
the Federal Power Commission under the Natural Gas Act.
On October 1, 1977, the Department of Energy will be
activated pursuant to the Department of Energy Organiza-
tion Act, Public Law 95-91, and the functions of the FPC
under the Natural Gas Act will be transferred in part to
the Federal Energy Regulatory Commission (FERC). There-
fore, where reference is made herein to future actions
of the FPC, they will be carried out by either the
Secretary or the FERC, as the case may be, as of
October 1, 1977.
20
In order to deliver gas contemporaneously to points both
east and west of the Rocky Mountains in the lower continental
United States, the Alcan system will bifurcate at James River,
Alberta and form a Western Leg and an Eastern Leg. First, the
Western Leg is described below, and then the Eastern Leg.
Western Leg
Alaskan gas will be transferred at the Canada/United
States border near Kingsgate, British Columbia, to Pacific
Gas Transmission Company (PGT}. PGT will transport the
gas through Idaho, Washington, and Oregon. At the Oregon/
California border, the gas will enter the intrastate
facilities of Pacific Gas and Electric Company (PG&E}.
The gas will be transported throughout much of California
through existing and expanded intrastate gas pipelines.
The additional Western Leg facilities which are part
of the Alcan project are those covered by the "1580 Design."
The major component of this expansion will add approximately
873 miles of looping and result in complete looping of the
917-mile PGT/PG&E system from the Canada/United States
border to Antioch, California (near San Francisco}. The
two parallel lines will be operated as a single system.
Various modifications to the existing compression facili-
ties will be required. However, the increase in system
21
capacity of 659 mmcfd could be achieved without ·installation
of additional compression horsepower or increase of compres-
sion fuel usage. A minor addition of facilities south of
Antioch may be made at a later date, depending on conditions
prevailing at that time. All Western Leg facilities which
are part of the Alcan project are subject to Section 9 of
ANGTA.
The Eastern Leg
The Alcan system will transport Alaskan gas for
delivery to Midwestern and Eastern markets in the lower
continental United States through an Eastern Leg. The
Eastern Leg will commence at the bifurcation point of the
main express line at James River, Alberta and terminate
i at Dwi~ht, Illinois (near Chicago). Total length of the
Eastern Leg will be 1,352 miles, including 235 miles in
Canada and 1,117 miles in the United States. All pipeline
for the Eastern Leg will be 42 inches in diameter.
Alaskan gas will be transferred at the Saskatchewan/
Montana border from the Canadian-owned portion of the Alcan
system to the Northern Border Pipeline system (Northern
Border). The Northern Border system will_travel diagonally
across Montana, North Dakota, South Dakota, Minnesota, and
Iowa, and terminate near Chicago, Illinois. Along this
22
route, direct deliveries of gas will be made by Northern
Border into the systems which cross the pipeline: Natural
Gas Pipeline Company of America, Northern Natural Gas
Company, and Michigan-Wisconsin Pipeline Company. Other
purchasers will receive Alaska gas by displacement.6/
The specific facilities that will be required to
interconnect the various pipelines to receive gas from the
Northern Border system, either by direct delivery or by
displacement, will be determined when gas sales contracts
have been executed. Final design of the required facilities
will depend upon the division of Alaskan gas among the
various pipeline companies and various regions of the
contiguous States. Final design will be complete at the
time of final system certification in late 1978 or early
1979. All facilities which are part of the Northern Border
system are necessary for construction and initial operation,
and all facilities which are part of the Northern Border
system as finally certified by the FPC-are subject to
Section 9 of ANGTA.
"Displacement" of gas is a method by which gas may
be supplied to a purchaser from close by in exchange for
gas sold to the purchaser elewhere. Displacemerit, which
is a commonly used method in the gas industry, eliminates
the cost of physically transferring gas between markets.
23
SECTION 4 -DELINEATION OF PROVISIONS OF LAW THAT ARE
SUBSUMED IN THIS DECISION AND REQUIRE WAIVER
Under Section 7(a)(4) (D) of ANGTA, the President shall
identify those provisions of law, relating to any
determination of a Federal officer or agency as to
whether a certificate, permit, right-of-way, lease,
or other authorization shall be issued or be granted,
which provisions the President finds (i) involve
determinations which are subsumed in his decision and
(ii) require waiver pursuant to section 8(g) in order
to permit the expeditious construction and initial
operation of the transportation system.
At this time, however, there are only two statutory
provisions that involve determinations subsumed in this
de9ision and require waiver pursuant to section 8(g) of
ANGTA.l/
Under Section 3 of the Natural Gas.Act (15 u;s.c.
717b), the Feder~l Power Commission must issue an order to
authorize any export of natural gas; such an order shall
7/ Section 8(g)(l) of ANGTA states that the President
will have the oppo~tunity at a later date to identify
and seek waiver of additional provisions of law.
This subsection states:
At any time after a decision designating a
transportation system is submitted to the Congress
pursuant to this section, if the President finds
that any provision of law applicable to actions to
be taken under subsection (a) or (c) of section 9
require waiver in order to permit expeditious con-
struction and initial operation of the approved
transportation system, the President may submit
such proposed waiver to both "Houses of Congress.
24
issue unless the Commission finds that the export is not
consistent with the public interest.
In addition, under Section 1D3 of the Energy Policy
and Conservation Act, the President is required to promul-
gate a general rule proh1biting exports of natural gas
from the u.s., except that he may permit those exports
which he determines to be consistent with the national
interest and with the purposes,of the Act (Section 103{b)
(1)). To make such a determination, Section 103(d)(l)
directs the President to take into account the need to
leave uninterrupted or unimpaired "exchanges in similar ,
quantity for convenience or increased efficiency of trans-
portation with persons or the government of a foreign
state."
As a result of the recent Agreement on Principles
between the United States and Canada, Alcan will be
I.
! I
required to make available limited quantities of Alaskan
gas to communities in the Yukon Territory and the western
II provinces, subject to provision of replacement gas down-
stream in Canada. This transaction will be an export
requiring separate authorizations under the above
mentioned two statutes.
25
The requirements arising under Section 3 of the
Natural Gas Act and under Section 103 of the Energy Policy
and Conservation Act could be met without waiver of these
provisions, but additional, and unnecessary, FPC and
Presidential action would be required. Accordin9ly, both
of these statutory subsections shall be waived for the
exchange of gas mentioned herein.
26
SECTION 5 -TEffi1S AND CONDITIONS AND ENFORCEMENT
To ensure the proper management and timely completion
of the construction of the designated transportation system,
, 1 the following general terms and conditions shall be appro-
priately incorporated into any certificate, right-of-way,
lease, permit or authorization directed to be made by any
Federal officer or agency.
As described more fully below, these terms and conditions
will be followed by a set of stipulations establishing
general standards of environmental and construction perfor-
mance, and the procedures for the submission and approval
of construction plans and environmental safeguards, and then
by site specific terms and conditions issued prior to actual
construction of any pipeline segment. The terms and condi-
tions described here a~e not meant to limit or foreclose
the adoption of such stipulations and terms and conditions
but are intended to begin the process by which a set of
effective and workable safeguards are evolved. There is
contemplated cooperative action by the Federal and Alaska
State Governments in the development and enforcement of
stipulations and site specific terms and conditions.
Similar cooperative action is contemplated with the
governments of all affected states.
27
Under the proposal made at the end of this section for
the organizational involvement of the Federal Government
with the successful applicant, the Federal Inspector for
construction of the transportation system shall have
supervision authority over the enforcement of these terms
and eonditions subject to the ultimate authority of the
Executive Policy Board described below.
Terms and Conditions
The terms and conditions proposed for inclusion into this
Congressional authorization are set forth, by category,
as follows:
I. Construction Costs and Schedule
Management and Organization
246-448 0 -77 - 4
1. Prior to the issuance of the certificate,
the successful applicant shall provide a
detailed overall management plan, to be approved
by the Federal Inspector, for the preconstruction
and the construction phases of the transportation
system project. The successful applicant shall
define its relationship with the execution
contractors, and shall give consideration to
various management approaches --such as Fast
Track, Stage Design, and other management
28
approaches --that will facilitate the cost-
effective, environmentally sound, and timely
construction of the project.
2. The successful applicant may not use cost-
plus type contracts with execution contractors,
except where the Federal Inspector determines
that special conditions warrant this type of
contract. Otherwise, the applicant shall use
fixed-price contracts, including the firm fixed-
price, the fixed-price with escalation, and
fixed-price incentive type of contract.
3. The successful applicant shall specify for
approval of the Federal Inspector the insurance,
bonding, and any other prequalification require-
ments for all consultants and execution contractors.
Construction Cost and Schedule Control Techniques
4. Prior to the initiation of construction,
the successful applicant shall provide· a
detailed analysis and description of its
proposed cost and schedule control techniques.
The applicant shall give particular consideration
to cost and manpower control and manpower
estimating techniques.
29
5. Prior to the initiation of construction,
the successful applicant shall develop and
submit to the Federal Inspector a final design,
design-cost estimate, and construction schedule.
This design cost estimate and schedule must
represent a construction design of at least
70 percent (or greater) of the total system,
and the remainder may not represent any one
contiguous or specific type of construction or
geologic situation (e.g., river crossings, dis-
continuous permafrost, or elevated pipeline).
The Federal Inspector may relax the above speci-
fied minimum percentage requirement, with the
consent of the Executive Policy Board, if he
finds there are extenuating circumstances that
warrant such an action.
General Operating Strategies
6. The successful applicant shall develop
and submit to the Federal Inspector cost-
effective and feasible methods for supplying
general and specializ~d equipment, as well as
repair facilities and spare-part inventories,
to the execution contractors. The applicant
30
shall give consideration to various techniques
of equipment provision, including use of equip-
ment pools, equipment leasing or buy-backs.
7. Prior to the initiation of construction,
the successful applicant shall supply detailed
information to the Federal Inspector on its
labor relations procedures, and indicate the
proposed means to address and resolve disputes
arising under collective bargaining agreements.
8. In entering into contracts with execution
contractors, the successful applicant shall
seek to incorporate techniques for resolving
disputes arising under such contracts without
recourse to litigation.
Quality Assurance and Control Procedures
9. The successful applicant shall provide to
the Federal Inspettor a detailed description
of quality assurance and control procedures
'• that will be implemented prior to the start
I
of construction. Such a description must at
least include provisions for quality assurance
and control procedures for environmental protec-
tion, corrosion, pipeline and compressor-station
31
welds, pipeline placement, equipment and other
appropriate matters.
Procedures for Enforcement of Terms and Conditions
10. The successful applicant may not initiate
activity on any aspect of the pipeline until
authorization to proceed with construction,
including site-specific teims and conditions
for that aspect of the pipeline, has been issued
and procedures for enforcement of terms and
conditions have been established by the appro-
priate Federal officers.
Minority Business Enterprise Participation
11. The successful applicant shall develop and
submit to the Federal Inspector for approval a
plan for taking affirmative action to ensure that
no person shall on the grounds of race, creed,
color, national origin or sex be excluded from
receiving or partic1pating in contracts for
management, engineering design or construction
activity. The successful applicant shall require
each of his contractors ·and subcontractors having
contracts valued at $150,000 or more to develop
similar plans providing the assurances specified
in the preceding sentence.
32
II. Safety and Design
1. The successful applicant shall construct,
operate, maintain and terminate the pipeline
in accordance with Federal gas pipeline safety
regulations. The applicant shall ensure that
construction and operating specifications are
in accordance with good engineering practice,
both to maintain the safety and the integrity
of the pipeline and to protect the health and
safety of project personnel and the general
public.
2. The successful applicant may not begin
construction of any pipeline segment until
the Federal Inspector has approved the design
of that segment, including technical construc-
tion specifications, having had sufficient
time to review the design.
3. The successful applicant shall establish a
procedure for briefing the Federal Inspector,
or his designated representative, on a regular
basis concerning the status of the project
during the design, construction, testing and
start-up phases.
33
4. The successful applicant shall establish
a procedure to ensure access to all project
facilities by the Federal Inspector, or his
designated representative, in the performance'
of official duties.
5. The successful applicant shall submit a
plan or procedure for conducting its own
inspections of project facilities during
construction, to be approved by the Federal
Inspector.
6. The successful applicant shall provide a
seismic monitoring system, to be approved by
the Federal Inspector, and shall ensure that
there are adequate procedures for the safe
shut~down of the project under severe seismic
conditions.
III. Environment
1. The successful applicant shall construct,
operate, maintain and terminate the pipeline with
maximum concern for the protection of environ-
mental values. A set of stipulations containing
the general standards of environmental and con-
struction performance, and the procedures for the
34
submission and approval of construction plans
and environmental safeguards will be developed
by the concerned government agencies and must
be accepted by the applicant as a condition of
his right to proceed over public lands. Addi-
tional "site-specific" terms and conditions will
be incorporated in authorizations to proceed
with construction· issued by the appropriate
Federal agency, into particular certificates,
rights-of-way, permits and other authorizations
to protect and enhance environmental values
during the design, construction and operation of
the pipeline. These additional "site specific"
terms and conditions'will be issued as appropri-
ate to minimize disturbance from construction
and operation of the pipeline to rivers and other
water bodies and adjacent land and vegetation; to
protect wildlife and endangered species and
maintain forest, agricultural and other resource
productivity; to control the risks of pipeline
ruptures, leaks and hazards; to maintain air
and water quality values; to make provision for
control and disposal of sewage, garbage, wastes
35
and toxic substances; and take other measures
necessary for protection of the environment
during the design, construction and operation
of the pipeline.
2. The successful applicant shall prepare a
plan of operations which integrates environ-
mental protection with the proposed schedule of
construction and operations, the proposed super-
visory and technical staffing, the proposed
quality control programs, and the proposed
£Uality assurance programs. In preparation and
implementation of this plan, the successful
applicant shall provide for timely integration
of environmental mitigation and restoration
practices with the activity which creates the
need for the restoration or mitigation.
3. The successful applicant shall develop and
submit to the Federal Inspector an effective
plan for implementation of specific environmental
safeguards through an ·educational program for
field personnel prior to and during construction,
operation, maintenance and termination of the
pipeline.
I
'' I
,j
j!
I
IV.
36
4. The successful applicant shall establish an
effective pipeline-performance monitoring system
of inspection and instrumentation to insure per-
formance in keeping with environmental concerns.
Finance
1. The successful applicant shall provide for
private financing of the project, and shall make
the final arrangement for all debt and equity
financing prior to the initiation of construction.
2. If the direct capital cost estimates excluding
interest during construction for the ove~all pro-
ject in 1975 constant dollars filed with the FPC
immediately prior to certification, adjusted to
reflect design changes to increase capacity that
result from the Agreement on Principle between
the United States and Canada, materially and
unreasonably exceed the comparable capital cost
estimates filed by ~lean with the Federal Power
Commission on March 8, 1977, Section 6, page 2,
the FPC may not issue a certificate for the
project. If these final capital cost estimates
are not excessive under the above standard, the
FPC may use these final estimates for the u.s.
37
segments as the basis for fixing a variable rate
of return on equity that will reward the applicant
for project completion under budgeted cost and
penalize the applicant for project completion
above budgeted cost. The variable return shall
be set to provide substantial incentives to
construct the project without incurring overruns.
These final capital cost estimates need not
be the design-cost estimates based on the system
design which must subsequently be submitted to
the Federal Inspector. The applicant shall,
however, submit to the FPC for approval on a
timely basis all components of construction work
in progress.
3. Neither the successful applicant nor any
purchaser of Alaska gas for transportation
through the system of the successful applicant
shall be allowed to make use of any tariff by
which or any other agreement by which the
purchaser or ultimate consumer of Prudhoe Eay
natural gas is compelled to pay a fee, surcharge,
or other payment in relation to the Alaska
38
natural gas transportation system at any time
prior to completion and commissioning of opera-
tion of the system.
4. The Alcan Pipeline Company, or its successor,
and the Northern Border Pipeline, or its suc-
cessor, shall be publicly held corporations
or general or limited partnerships, open to
ownership participation by all persons without
discrimination, except producers of Alaskan
natural gas.
v. Antitrust
1. The successful applicant shall exclude and
prohibit producers of significant amounts of
Alaska gas, or their subsidiaries and affiliates,
from participating in the ownership of the Alaska
natural gas transportation system, except that
such producers may provide guarantees for pro-
ject debt. The aforesaid producers of Alaska
gas may not be equity members of the sponsoring
consortium, have any voting power in the project,
have any role in the ,management or operations of
the project, have any continuing financial obli-
gation in relation to debt guarantees associated
39
with initial project financing after the project
is completed and the tariff is put into effect,
or impose conditions on the guarantees of
project debt permitted above which may give
rise to competitive abuse, including power to
veto pro-competitive policies.
2. All agreements for the sale of Alaska gas
made between the aforesaid producers and pur-
chasers who are shippers through the Alaska
natural gas transportation system shall be fully
disclosed to the Federal Power Commission, and
all collateral agreements made between the same
parties with respect to the sale of Alaska gas
shall also be fully disclosed. All contracts
for sale of Alaska gas, for all collateral agree-
ments to these contracts, shall be submitted for
approval by the Federal Power Commission.
VI. Certification of Facilitjes
1. Prior to the issuance of a certificate of
public convenience and necessity to Northern
Border Pipeline or to Pacific Gas Transmission
Company, the Secretary of Energy shall certify
to the Federal Power Commission whether there
40
has been any material change in the facts
regarding future potential.gas supplies for the
East or West since the date of this Decision
that would warrant certification of such facili-
ties at a different rated capacity than authorized
herein. If the Secretary certifies that there has
been a material change in the facts, he shall
instead certify to the Commission the capacity
at which he has determined a certificate of public
convenience and necessity should be issued and
the reasons therefor, which capacity shall be
determined in a manner that is as consistent as
possible with the reasons for the initial authori-
zation, as set forth in the Report submitted to
the Congress pursuant to Section 7(b) of the
Alaska Natural Gas Transportation Act, Public Law
94-586. The certificate issued by the FPC shall
be consistent with ·the Secretary's determination.
Enforcement
To enforce the terms and conditions proposed above,
and to carry out the duties of the office assigned and set
forth by section 7(a)(S)(A)-(E) of ANGTA, an appropriate
and qualified individual shall be appointed by the President
41
'td serve as the Federal Inspector, with the advice and
consent of the Senate. Upon approval of the Presidential
designation of an Alaska natural gas transportation system,
the Federal Inspector shall:
{A) establish a joint surveillance .and moni taring
agreement, approved by the President, with the State of
Alaska similar to that in effect during construction of
the trans-Alaska oil pipeline to monitor the construc-
tion of the approved transportation system within the
State of Alaska;
{B) monitor compliance with applicable laws and
·the terms ahd conditions of any applicable ~ertificate,
rights-of-way, permit, lease, or other authorization
issued or granted;
{C) monitor actions taken to assure timely
completion of construction schedules and the achieve-
ment of quality of construction, cost control, safety,
and environmental protection objectives and the results
obtained therefrom;
{D) have the power to compel, by subpoena if
necessary, submission of such information as he deems
necessary to carry out his responsibilities; and
~E) keep the President and the Congress currently
informed on any significant departures from compliance
and issue quarterly reports to the President and the
Congress concerning existing or potential failures to
meet construction schedules or other factors which may
delay the construction and initial operation of the
system and the extent to which quality of construction,
cost control, safety and environmental protection
objectives have been achieved.
In addition to these duties and responsibilities,
the President will submit to Congress, upon approval of
the Presidential decision, a limited executiv~ reorgani-
zation plan to transfer to the Federal Inspector field-level
42
supervisory authority over enforcement of terms and
conditions from those Federal agencies having statutory
responsibilities over various aspects of an Alaska natural
gas transportation system. The respective Federal agencies
would retain their existing statutory authority pursuant
to section 9(a) of ANGTA, to issue on an expedited basis the
necessary certificates, permits, rights-of-way and other
authorizations, and to prescribe any appropriate terms and
conditions that are permissible under present law. The
Agency Authorized Officers would directly represent the
statutory authority of the respective Federal agencies in the
field on all matters pertaining to construction of the
pipeline. However, the Federal Inspector would have the
necessary field-level supervisory authority to overrule the
enforcement action of an Agency Authorized Officer, whenever
the Federal Inspector determined that such a decision was
warranted.
The President's supervision of the Federal Inspector
will be carried out by an Executive Policy Board. The Board
would be made up of the Secretaries of the Interior, Energy,
Transportation, the Administrator of the Environmental
Protection Agency, and the Chief of the Army Corps of
Engineers, or their Deputies (or senior officers who have
43
been delegated authority over gas pipeline matters), as well
as.the Federal Inspector, who is the non-voting Chairman of
the Board. The Board will provide policy guidance to the
Federal Inspector, and act as an· appellate body to resolve
rlifferences among the agencies and the Federal Inspector,
including differences that may arise when the Federal
Inspector overrules an enforcement action of an Agency
Authorized Officer. The Board shall expeditiously resolve
any such appeal with a limited period of time that shall be
prescribed. The President will authorize by Executive Order
:the creation of the Executive Policy Board pursuant to his
power under Section 301 of Title 3, and will delegate the
necessary authority to the Board to carry out its functions.
The Board shall be paramount for policy-making purposes on
all matters pertaining to construction of an Alaskan natural
gas transportation system; the Federal Inspector shall
shall be the agent or conduit of the Board in such matters,
and shall also have the necessary supervisory power over
.field level decisions.
246~448 0 -77 - 5
44
SECTION 6 -PRICING OF ALASKA GAS
Final financing for an Alaska natural gas transportation
project cannot be arranged until the producer-owners of the
Prudhoe Bay gas execute sales contracts. Without such.con-
tracts, no gas can be transported, and financing consequently
would be unobtainable. Producers cannot be expected to
negotiate sales contracts until a price has been established
with a reasonable degree of certainty~ If this project is
to proceed expeditiously, the field price of the gas should·
be established as soon as possible.
Because no contracts for gas sales in interstate
commerce have been concluded and submitted to the FPC for
approval, the FPC has not, to date, attempted to determine
the costs of providing the gas in order to establish what
might be a just and reasonable (cost-based) wellhead price.
The FPC, in fact, has excluded the Alaska gas from its
national rate proceedings; Alaska costs and related reserve
data have been excluded from all statistics underlying FPC
rate determinations.
Alaska gas is produced in association with oil;
therefore, it is impossible to determine precisely the
costs of finding, developing and producing only the gas.
Cost allocation and, therefore, cost-based pricing is
45
-somewhat arbitrary. Because of the difficult and arbitrary
nature of the allocation problem, the FPC in recent years
has priced gas on the basis of the cost of only non-
associated gas in each producing area, and then allowed the
same price to be paid for associated gas produced in that
area as well. Were the FPC to initiate a price proceeding
under the Natural Gas Act, it is expected that its pro-
cedures and subsequent litigation over cost allocation and
other matters would likely exceed a period of 18 months.
The Administration's proposed National Energy Act is
before the Congress. That Act provides a basis for moving
from cost-based pricing to commodity-value pricing. That
transition is essential to restoring the balance between
natural gas supply and demand. Under the gas pricing pro-
visions in the National Energy Plan, Alaska gas w6uld be
classified as "old gas under a new contract" subject to a
$1.45 per mcf ceiling price.
If, on the other hand, proposals to deregulate natural
gas prevail, serious uncertainties and delays concerning the
development of any Alaskan riatural gas transportation
46
project could result. If producers are inclined to insist
on prices of $2.00 per mcf or higher; questions concerning
the saleability of the gas and the financeability of the
project will arise. Such price levels could result in an
additional $20 billion in consumer charges, as well as the
added costs of any delays in project construction.
This decision, therefore, calls for enactment of a
gas pricing approach similar to that contained in the
National Energy Plan. That approach also provides a mech-
anism for allocating the cost of more expensive supplies to
lower-priority users, rather than the residential and
commercial users who have less capacity to convert to other
fuels. The gas pricing policies which are part of the
National Energy Plan are fair and equitable, and should
apply to both the production and sale of Alaska gas.
i I
47
:!SECTION 7 -AGREEMENT BETWEEN THE UNITED STATES OF AMERICA
~AND CANADA ON PRINCIPLES APPLICABLE TO A NORTHERN NATURAL
GAS PIPELINE
The Government of the United States of America and
the Government of Canada,
Desiring to advance the national economic and energy
interests and to maximize related industrial benefits of
each country, through the construction and operation of
a pipeline system to provide for the transportation of
natural gas from Alaska and from Northern Canada,
_ ...... .,.'
Hereby agree to the following principles for the
construction and operation of such a system:
1. Pipeline Route
The construction and operation of a pipeline for the
transmission of Alaska natural gas will be along the route
set forth in Annex I, such pipeline being hereinafter referred
to as "the Pipeline". All necessary action will be taken
to authorize the construction and operation of the Pipeline
in accordance with the principles set out in this Agreement.
2. Expeditious Construction; Timetable
a) Both Governments will take·measures to ensure the
prompt issuance of all necessary permits, licenses, certi-
ficates, rights-of-way, leases and other authorizations
48
required __ for the expeditious constructio'"n and commencement
of operation of the Pipeline, with a view to commencing
construction according to the following timetable:
Alaska -January 1, 1980
Yukon -main line pipe laying January 1, 1981
Other construction in Canada to provide for
timely completion of the Pipeline to enable
initial operation by January 1, 1983.
b) All charges for such permits, licenses, certificates,
rights-of-way, leases and other authorizations will be just
and reasonable and apply to the Pipeline in the same non-
discriminatory manner as to any other similar pipeline.
c) Both Governments will take measures necessary to
facilitate the expeditious and efficient construction of
the Pipeline, consistent with the respective regulatory
requirements of each country.
3. Capacity of Pipeline and Availability of "Gas
a) The initial capacity of the Pipeline will be
sufficient to meet, when required, the contractual require-
ments of United States shippers and of Canadian shippers.
It is contemplated that this capacity will be 2.4 billion
cubic feet per day (bcfd) for Alaska gas and 1.2 bcfd for
northern Canadian gas. At such time as a lateral pipeline
49
transmitting Northern Canadian gas, hereinafter referred
to as "the Dempster Line", is to be connected to the Pipeline
or at any time additional pipeline capacity is needed to
meet the contractual requirements of United States or
canadian shippers, the required autho~izations will be
provided, subject to regulatory requirements, to expand
the capacity of the Pipeline in an efficient manner to
meet those contractual requirements.
b) The shippers on the Pipeline will, upon
demonstration that an amount of Canadian gas equal on
a British Thermal Unit (BTU) replacement value basis will be
made available for contemporaneous export to the United
States, make available from Alaska gas transmitted througH
the Pipeline, gas to meet the needs of remote users in the
Yukon and in· the provinces through which the Pipeline
passes. Such replacement gas will be treated as hydro-
carbons in transit for purposes of the Agreement between
the Government of Canada and the Government of the United
States of America concerning Transit Pipelines, hereinafter
referred to as "the Transit Pipeline Treaty". The shippers
on the Pipeline will not incur any cost for provision of
such Alaska gas except those capital costs arising from the
following provisions:
50
i) the owner of the Pipeline in the Yukon will
make arrangements to provide gas to the communities
of Beaver Creek, Burwash Landing, Destruction Bay,
Haines Junction, Whitehorse, Teslin, Upper Liard and
Watson Lake at a total cost to the owner of the
Pipeline not to exceed Canadian $2.5 million;
ii) the owner of the Pipeline in the Yukon will
make arrangements to provide gas to such other remote
communities in the Yukon as may request such gas
within a period of two years following commencement
of operation of the Pipeline at a cost to the owner
not to exceed the product of Canadian $2500 and the
number of customers in the communities, to a maximum
total cost of Canadian $2.5 million.
4. Financing
a) It is understood that the construction of the
Pipeline will be privately financed. Both Governments
recognize that the companies· owning the Pipeline in each
country will have to demonstrate to the satisfaction of
the United States or the Canadian Government, as applicable,
that protections against risks of non-completion and
interruption are on a basis acceptable to that Government .
before proof of financing is established and construction
allowed to begin.
51
b) The two Governments recognize the importance of
constructing the Pipeline in a timely way and under effec-
tive cost controls. Therefore, the return on the equity
investment in the Pipeline will be based on a variable
rate'of return for each company owning a segment of the
Pipeline, designed to provide incentives to avoid cost
overruns and to minimize costs consistent with sound
pipeline management. The base for the incentive program
used for establishing the appropriate rate of return will
be the capital costs used in measuring cost overruns as
set forth in Annex III.
c) It is understood that debt instruments issued in
connection with the financing of the Pipeline in Canada
will not contain any provision, apart from normal trust
indenture restrictions generally applicable in the pipeline
industry, which would prohibit, limit or inhibit the
'
financing of the construction of the Dempster Line; nor
will the variable rate of return provisions referred to
in subparagraph (b) be continued to the detriment of
financing the Dempster Line.
5. Taxation and Provincial Undertakings
a) Both Governments reiterate their commitments as
set for~h in the Transit Pipeline Treaty with respect to
52
non-discriminatory taxation, and take note of the state-,
ments issued by Governments of the Provinces of British
Columbia, Alberta and Saskatchewan, attached hereto as
Annex V, in which those Governments undertake to ensure
adherence to the provisions of the Transit Pipeline Treaty
with respect to non-interference with throughput and to
non-discriminatory treatment with respect to taxes, fees
or other monetary charges on either the Pipeline or
throughput.
b) With respect to the Yukon Property Tax imposed
on or for the use of the Pipeline the following principles
apply:
i} The maximum level of the property tax, and
other direct taxes having an incidence exclusively,
or virtually exclusively, on the Pipeline, including
taxes on gas used as compressor fuel, imposed by the
Government of the Yukon Territory or any public
authority therein on or for the use of the Pipeline,
herein referred t6 as "the.Yukon Property Tax", will
not exceed $30 million Canadian per year adjusted
annually from 1983 by the Canadian Gross National
Product price deflator as determined by Statistics
Canada, hereinafter referred to as the GNP price
deflator.
53
ii) For the period beginning January 1, 1980,
and ending on December 31 of the year in which leave
to open the Pipeline is granted by the appropriate
regulatory authority, the Yukon Property Tax will
not exceed the following:
1980--$5 million Canadian
1981--$10 million Canadian
1982--$20 million Canadian
Any subs~quent year to which this provision
applies--$25 million Canadian.
iii) The Yukon Property Tax formula described
in subparagraph (b)(i) will apply from January 1
after the year in which leave to open the Pipeline
is granted by the appropriate regulatory authority
until the date that is the earlier of the following,
hereinafter called the tax termination date:
A) December 31, 2008, or
B) December 31 of the year in which leave to open
the Dempster Line is granted by the appropriate
regulatory ~uthority.
iv) Subject to subparagraph (b) (iii), if for the
year ending on December 31, 1987, the percentage increase
of the aggregate per capita revenue derived from all
I'
'I
I
I
54
property tax levied by any public authori~y in the Yukon
Territory (excluding the Yukon Property Tax) and grants
to municipalities and Local Improvement Districts from
the Government of the Yukon Territory as compared to
aggregate per capita revenue derived from such sources
for 1983 is greater than the percentage increase for
1987 of the Yukon Property Tax as compared to the Yukon
Property Tax for 1983, the maximum level of the Yukon
Property Tax for 1987 may be increased to equal the
amount it would have reached had it increased over
the period at the same rate as the aggregate per
capita revenue.
v) If for any year in the period commencing
January 1,_ 1988, and ending on the tax termination
date, the annual percentage increase of the aggregate
per capita revenue derived from all property tax
levied by any public authority in the Yukon Territory
(excluding the Yukon Property Tax) and grants to
municipalities and Local Improvement Districts from
the Government of the Yukon Territory as compared to the
aggregate per capita revenue derived from such sources
for the immediately preceding year exceeds the per-
centage increase for that year of the Yukon Property
55
Tax as compared to the Yukon Property Tax for the
immediately preceding year, the maximum level of the
Yukon Property Tax for that year may be adjusted by
the percentage increase of the aggregate per capita
revenue in place of the percentage increase that
otherwise might apply.
vi) The provisions of subparagraph (b)(i) will
apply to the value of the Pipeline for the capacities
contemplated in this Agreement. The Yukon Property
Tax will increase for the additional facilities
beyond the aforesaid contemplated capacity in direct
proportion to the increase in the gross asset value
of the Pipeline.
vii) In the event that between the date 6f this
Agreement and January 1, 1983, the rate of the
Alaska property tax on pipelines, taking into account
the mill rate and the method of valuation, increases
by a percentage greater than the cumulative percentage
increase in the Canadian GNP deflator over the same
period, there may be an adjustment on January 1, 1983,
to the amount of $30 million Canadian described in
subparagraph (b) (i) of the Yukon Property Tax to
reflect this difference. In defining the Alaska
I
,i
I!
56
property tax for purposes of this Agreement, the
definition of the Yukon Property Tax will apply
mutatis mutandis.
viii) In the event that, for any year during the
period described in subparagraph (iii), the annual
rate of the Alaska property tax on or for the use of
the Pipeline in Alaska increases by a percentage over
that imposed for the immediate preceding year that is
greater than the increase in percentage of the Yukon
Property Tax for the year, as adjusted, from that
applied to the immediately preceding year, the Yukon
Property Tax may be ·increased to reflect the percentage
increase of the Alaska property tax.
ix) It is understood that indirect socioeconomic
costs in the Yukon Territory will not be reflected in
the cost-of-service to the United States shippers other
than through the Yukon Property Tax. It is further
understood that no public authority will require
creation of a special fund or funds in connection with
construction of the Pipeline in the Yukon, financed
in a manner which is reflected in the cost of service
to u.s. shippers, other than through the Yukon
Property Tax. However, should public authorities ·
57
in the State of Alaska require creation of a special
fund or funds, financed by contributions not fully
reimbursable, in connection with construction of the
81 Pipeline in Alaska, the Governments of Canada or
(·; :·the Yukon Terri tory will have the right to take
;·similar action.
c) The Government of Canada will use its best
e:n.c::leavors to ensure that the level of any property tax
illlposed by the Government of the Northwest Territories
on,ror for the use of that part of the Dempster Line that
is with in the Northwest Territories is reasonably compar-
aple to the level of the property tax imposed by the
Gpyernment of the Yukon Terri tory on or for the use of
that part of the Dempster Line that is in the Yukon.
6. Tariffs and Cost Allocation
It_~s_agreed that the following principles will apply
for purposes of cost allocation used in determining the
cost of service applicable to each shipper on the Pipeline
in Canada:
a) The Pipeline in Canada and the Dempster Line will
be divided into zones as set forth in Annex II. Except
for fuel and except for Zone 11 (the Dawson-Whitehorse
portion of the Dempster Line), the cost of service to each
58
shipper in each zone will be determined on the basis of
volumes as set forth in transportation contracts. The
volumes used to assign these costs will reflect the original
BTU content of Alaskan gas for u.s. shippers and Northern
Canadian gas for Canadian shippers, and will make allowance
for the change in heat content as the result of commingling.
Each shipper will provide volumes for line losses and line
pack in proportion to the contracted volumes transported in
the zone. Each shipper will provide fuel requirements in
relation to the volume of his gas being carried and to the
content of the gas as it affects fuel consumption.
b) It is understood that, to avoid increased
construction and operating costs for the transportation
of Alaskan gas, the Pipeline will follow a southern route
through the Yukon along the Alaska Highway rather than a
northern route through Dawson City and along the Klondike
Highway. In order to provide alternative benefits for the
transportation of Canadian gas to replace those benefits
that would have been provided by the northern route through
Dawson City, u.s. shippers will participate in the cost of
service in Zone 11. It is agreed that if cost overruns on
construction of the Pipeline in Canada do not exceed filed
costs set forth in Part D of Annex III by more than 35
59
u.s. shippers will pay the full cost of service in
11. u.s. shipper participation will decline if over-
'on the Pipeline in Canada exceed 35 percent; however,
the minimum the u.s. shippers' share will be the greater
either two-thirds of the cost of service or the proportion
~ontracted Alaska gas in relation to all contracted gas
in the Pipeline. The proportion of the cost of
ice borne by u.s. shippers in Zone 11 will be reduced
overruns on the cost of construction in that Zone
35 percent after allowance for the benefits to U.S.
derived from Pipeline construction cost savings
zones. Notwithstanding the foregoing, at the
.the u.s. shippe~s' share will be the greater
."either two-thirds of the cost of service or the
>~~0oo· rtion of contracted Alaska gas in relation to all
gas carried in the Pipeline. Details of this
location of cost-of-service are set out in Annex III.
c) Notwithstanding the principles in subparagraphs (a)
;(b), in the event that the total volume of gas offered
r sqipment exceeds the efficient capacity of the Pipeline,
e method of cost allocation for the cost of service for
hipments of Alaskan gas (minimum entitlement 2.4 bcfd) or
thern Canadian gas (minimum entitlement 1.2 bcfd) in
60
excess of the efficient capacity of the Pipelin~ will be
subject to review and subsequent agreement by both
Governments; provided however that shippers of either countr
may transport additional volumes without such review and
agreement, but subject to appropriate regulatory approval, i
such transportation does not lead to a higher cost of servic
or share of Pipeline fuel requirem~nts attributable to
shippers of the other country.
d) It is agreed that Zone 11 costs of service
allocated to u.s. shippers will not include costs addit-
ional to those attributable to a pipe size of 42 inches.
It is understood that in Zones 10 and 11 the Dempster Line
will be of the same gauge and diameter and similar in other
respects, subject to differences in terrain. Zone 11 costs
will include only facilities installed at the date of issuan
of the leave to open order, or that are added within three
years thereafter.
7. Supply of Goods and Services
a) Having regard to the objectives of this Agreement,
each Government will endeavor to ensure that the supply of
goods and services to the Pipeline project will be on
generally competitive terms. Elements to be taken into
account in weighing competitiveness will include price,
reliability, servicing capacity and delivery schedules.
61
b) It is understood that through the coordination
procedures in Paragraph 8 below, either Government may
institute consultations with the other in particular cases
where it may appear that the objectives of subparagraph
(a} are not being met. Remedies to be considered would
include the renegotiation of contracts or the reopening
o( bids.
8. Coordination and Consultation
Each Government will designate a senior official
for the purpose of carrying on periodic consultations
on the implementation of these principles relating to
the construction and operation of the Pipeline. The
designated senior officials may, in turn, designate
additional representatives to carry out such consulta-
tions, which representatives, individually or as a group,
may make recommendations with respect to particular
disputes or other matters, and may take such other
action as may be mutually agreed, for the purpose of
facilitating the construction and operation of the
Pipeline.
9. Regulatory Authorities: Consultation
The respective regulatory authorities of the two
Governments will consult from time to time on relevant
62
matters arising unde~ this Agreement, particularly-on the
matters referred to in paragraphs 4, 5 and 6, relating to
tariffs for the transportation of gas through the Pipeline.
10. Technical Study Group on Pipe
a) The Governments will establish a technical $tudy gro
for the purpose of testing and evaluating 54-inch 1120 pounds
per square inch (psi), 48-inch 1260 psi, and 48-inch 1680
psi pipe or any other combination of pressure and diameter
which would achieve safety, reliability and economic effic-
iency for operation of the Pipeline. It is understood that
the decision relating to pipeline specifications remains
the responsibility of the appropriate regulatory authorities.
b) It is agreed that the efficient pipe for the
volumes contemplated (including reasonable provision for
expansion), subject to appropriate regulatory authoriza-
tion, will be installed from the point of interconnection
of _the Pipeline with the Dempster Line near Whitehorse to
the point near Caroline, Alberta, where the Pipeline
bifurcates into a western and an eastern leg.
11. Direct Charges by Public Authorities
a) Consultation will take place at the request of
either Government to consider direct charges by public
63
thorities imposed on the Pipeline where there is an
lement of doubt as to whether such charges should be
in the cost of service.
b) It is understood that the direct charges imposed by
,,uu~·~ic authorities requiring approval by the appropriate
.9ulatory authority for inclusion in the cost of service
ill be subject to all of the tests required by the appro-
iate legislation and will include only
i) those charges that are considered by the
regulatory authority to be just and reasonable on
the.basis of accepted regulatory practice, and
ii) those charges of a nature that would
normally be paid by a natural gas pipeline in
Canada. Examples of such charges are listed in
Annex IV.
12. Other Costs
It is understood that there will be no charges on the
~Pipeline having an effect on the cost of service other
··'than those:
i) imposed by a public authority as contemplated
in this Agreement or in accordance with the
Transit Pipeline Treaty, or
64
ii) caused by Acts of God, other unforeseen
circumstances, or
iii) normally paid by natural gas pipelines in
Canada in accordance with accepted regulatory
practice.
13. Compliance with Terms and Conditions
The principles appl~cable directly to the construction,
operation and expansion of the Pipeline will be implemented
through the imposition by the two Governments of appropriate
terms and conditions in the granting of required authoriza-
tions. In the event of subsequent non-fulfillment of such
a term or condition by an owner of the Pipeline, or by any
other private person, the two Governments will not have
responsibility therefor, but will take such appropriate
action as is required to cause the owner to remedy or
mitigate the consequences of such non-fulfillment.
14. Legislation
The two Governments recognize that legislation will
be required to implement the provisions of th.is Agreement.
In this regard, they will expeditiously seek all required
legislative authority so as to facilitate the timely and
efficient construction of the Pipeline and to remove any
delays or impediments thereto.
65
Entry Into Force
This Agreement will become effective upon signature
shall remain in force for a period of 35 years and
until terminated upon 12 months' notice given in
one Government to the other, provided that those
of the Agreement requiring legislative action
become effective upon exchange of notification that
legislative action has been completed.
66
IN WITNESS WHEREOF the undersigned representatives,
duly authorized by their respective Governments, have
signed this Agreement.
DONE in duplicate at Ottawa in the English and French
languages, both versions being ~qually authentic, this
day of -------------------
For the Government
of the United States:
' 1977.
For the Government
of Canada:
\
\
67
The Pipeline Route
rn Alaska:
-The Pipeline constructed in Alaska by Alcan will
commence at the discharge side of the Prudhoe Bay Field gas
plant facilities. It will parallel the Alyeska oil pipeline
southward on the North Slope of Alaska, cross the Brooks
Range through the Atigun Pass, and continue on to Delta
Junction.
At Delta Junction, the Pipeline will diverge from
the Alyeska oil pipeline and follow the Alaska Highway and
Haines oil products pipeline passing near the towns of
Tanacross, Tok, and Northway Junction in Alaska. The Alcan
facilities will connect with the proposed new facilities of
n0,oothills Pipe Lines (South Yukon) Ltd. at the Alaska-Yukon
border.
In Canada:
In Canada the Pipeline will commence at the Boundary
of the State of Alaska, and the· Yukon Territory in the
vicinity of the towns of Border City, Alaska and Boundary,
Yukon. The following describes the general routing of the
Pipeline in Canada:
8j
From the Alaska-Yukon border, the Foothills Pipe Lines
(South Yukon) Ltd. portion of the Pipeline will proceed in
a southerly direction generally along the Alaska Highway to
ANNEX I
68
a point near Whitehorse, Yukon, and thence to a point on
the Yukon-British Columbia border near Watson Lake, Yukon,
where it will join with the Foothills Pipe Lines {North B.C.)
Ltd. portion of the.Pipeline.
The Foothills Pipe Lines {North B.C.) Ltd. portion of
the Pipeline will extend from Watson Lake in a southeasterly
direction across the north eastern part of the Province of
British Columbia to a point on the boundary between the
Provinces of British Columbia and Alberta near Boundary Lake
where it will interconnect with the Foothills Pipe Lines
{Alta.) Ltd. portion of the Pipeline.
The Foothills Pipe Lines {Alta.) Ltd. portion of
the Pipeline will extend from a point on the British Columbia·
Alberta boundary near Boundary Lake in a southeasterly direct
to Gold Creek and thence parallel to the existing right-of-wa:
of the Alberta Gas Trunk Line Company Limited to James River
near Caroline.
From James River a "western leg" will proceed in a
southerly direction, generally following the existing right-
of-way of the Alberta Gas Trunk Line Company Limited to a
point on the Alberta-British Columbia boundary near Coleman
in the Craw's Nest Pass area. At or near Coleman the Foothil
Pipe Lines {Alta.) Ltd. portion of the Pipeline will
interconnect with the Foothills Pipe Lines {South B.C.) Ltd.
portion of the Pipeline.
69
I
ANNEX I
The Foothills Pipe Lines (South B.C.) Ltd. portion of
pipeline will extend from a point on the Alberta-British
near Coleman in a southwesterly direction
across British Columbia generally parallel to the existing
facilities of Alberta Natural Gas Company Ltd. to a
the International Bounda~y Line between Canada
the United States of America at or near Kingsgate in
Province of British Columbia where it will inter-
connect with the facilities of Pacific Gas Transmission
Also, from James River, an 11 eastern leg .. will proceed
southeasterly direction to a point on the Alberta-
Saskatchewan boundary near Empress Alberta where it will
interconnect with the Foothills Pipe Lines (Sask.) Ltd.
portion of the Pipeline. The Foothills Pipe Lin~s (Sask.)
Ltd. portion of the Pipeline will extend in a southeasterly
direction across Saskatchewan to a point on the Inter-
national Boundary Line between Canada and the United States
of America at or near Monchy, Saskatchewan where it will
interconnect with the facilities of Northern Border Pipeline
Company.
ANNEX II
70
Zones for the Pipeline and the Dempster Line in Canada
Zone 1
i
Foothills Pipe Lines (South Yukon) Ltd.
I!
II ,,
Alaska Boundary to point of interconnection with
the Dempster Line at or near Whitehorse.
Zone 2 Foothills Pipe Lines (South Yukon) Ltd.
Whitehorse to Watson Lake.
Zone 3 Foothills Pipe Lines (North B.C.) Ltd.
Watson Lake to point of interconnection with
Westcoast's main pipeline near Fort Nelson.
Zone 4 Foothills Pipe Lines (North B.C.) Ltd.
Point of interconnection with Westcoast's main
pipeline near Fort Nelson to the Alberta-B.C.
border.
Zone 5 Foothills Pipe Lines (Alta.) Ltd.
Alberta-B.C. border to point of bifurcation near
Caroline, Alberta.
Zone 6 Foothills Pipe Lines (Alta.) Ltd.
Caroline, Alta. to Alberta-Saskatchewan border
near Empress.
zone 7
zone 8
zone 9
ANNEX II
71
Foothills Pipe Lines (Alta.) Ltd.
Caroline to Alberta-B.C. border near Coleman.
Foothills Pipe Lines (South B.C.) Ltd.
Alberta-B.C. border near Coleman to B.C.-U.S.
border near Kingsgate.
Foothills Pipe Lines (Sask.) Ltd.
Alberta-Saskatchewan border near Empress to
Saskatchewan-u.s. border near Monchy.
zone 10 Foothills Pipe Lines (North Yukon) Ltd.
Mackenzie Delta Gas fields in the Mackenzie
Delta, N.W.T., to a point near the junction of
the Klondike and Dempster highways just west
of Dawson, Yukon Territory.
Zone 11 Foothills Pipe Lines (South Yukon) Ltd.
A point near the junction of the Klondike and
Dempster hi<Jhways near ·Dawson to the connecting
point with the Pipeline at or near Whitehorse.
ANNEX III
72
Cost Allocatiop in Zone 11
The cost of service in Zone 11 shall be allocated to
United States shippers on the following basis:
i) There will be calculated, in accordance with
(iii) below, a percentage for Zones 1 - 9 in
total by dividing the actual capital costs by
the filed capital costs and multiplying by
100. If actual capital Qosts are equal to or
less than 135% of filed capital costs, then
United States shippers will pay 100% of the
cost of service in Zone 11. If actual
capital costs in Zones 1 - 9 are between 135%
and 145% of filed capital costs, then the
percentage paid by United States shippers
will be adjusted between 100% and 66 2/3% on
a straight-line baais, except that in no case
will the portion of cost of service paid by
United States shippers be less than the pro-
portion of the ~ontracted volumes of Alaskan ga
at the Alaska-Yukon border to the same volume c
Alaskan gas plus the contracted volume of
Northern Canadian gas. If the actual capital
ANNEX III
73
costs are equal to or exceed 145% of filed
capital costs, the portion of the cost of
service paid by United States shippers will
be not less than 66 2/3% or the proportion as
calculated above, whichever is the greater.
ii) There will be calculated a percentage for the
cost-overrun on the Dawson to Whitehorse
lat·eral (Zone 11). After determining the
dollar value of the overrun, there will be
deducted from it:
(a) the dollar amount by which actual capital
costs in zones 1,7,8 and 9 (carrying u.s.
gas only) are less than 135% of filed
capital costs referred to in (iii) below;
(b) in each of Zones 2, 3, 4, 5 and 6 the
dollar amount by which actual capital
costs are less than 135% of filed capital
costs referred to in (iii) below,
multiplied by the proportion that the
u.s. contracted volume bears to the
total contracted volume in that zone.
ANNEX III
74
If the actual capital costs in Zone 11, after
making this adjustment, are equal to or less
than 135% of filed capital costs, then no
adjustment is required to the percentage of
the cost of service paid by United States
shippers as· calculated in (i) above. If,
however, after making this adjustment, the
actual capital cost in Zone 11 is greater
-than 135% of the filed capital cost, then the
proportion of the cost of service paid by
United States shippers will be a fraction
(not exceeding 1) of the percentage of the
cost of service calculated in (i) above,
where the numerator of the fraction is 135%
of the filed capital cost and the denominator
of the fraction is actual capital cost less
the adjustments from (a) and (b) above.
Notwithstanding the adjustments outlined
above, in no case will the percentage of the
actual cost of service borne by United States
ANNEX III
75
shippers be less than the greater of 66 2/3%
or the proportion of the contracted volumes
of Alaskan gas at the Alaska-Yukon border to the
same volume of Alaskan gas plus the contracted
volume of Northern Canadian gas.
iii) The "filed capital cost" to be applied to
determine cost overruns for the purpose of
cost allocation in (i) and (ii) above will be:
"Filed Capital Cost"
Estimates for the
Pipeline in Canada
The Pipeline in Canada (Zones 1 -9)_!/
(millions of Canadian
dollars)
.!/
48" -1260 lb. pressure pipeline -3,873
or 48" -1680 lb. pressure pipeline -4,418
or 54" -1120 lb. pressure pipeline -4,234
These filed capital costs include and are based upon (a)
a 1260 psi, 48-inch line from the Alaska-Yukon border
to the point of possible interconnection near Whitehorse;
(b) a 1260 psi, 48-inch; or 1680 psi, 48-inch; or 1120
psi 54-inch line from the point of possible inter-
connection near Whitehorse to Caroline Junction; (c)
a 42-inch line from Caroline Junction to the Canada-u.s.
border near Monchy, Saskatchewan; and (d) a 36-inch
line from Caroline Junction to the Canada-u.s. border
near Kingsgate, British Columbia. These costs are
escalated for a date of commencement of operations of
January 1, 1983.
246-448 0 -77 - 7
\
76
Zone 11 of the Dempster Line~
30" -Section of Dempster line
from Whitehorse to Dawson
or 36" -Section of Dempster line
from Whitehorse to Dawson
or 42" -Section of Dempster line
from Whitehorse to Dawson
ANNEX III
"Filed Capital Cost"
Estimates for the
Pipeline in Canada
(millions of Canadian
dollars)
549
585
705
Details for Zones 1 - 9 are shown in the following table:
~/ The costs are escalated for a date of commencement of
operations of January 1, 1985.
1\NNEX I I I
77
Filed Capital Costs for the Pipeline in Canada
48" 48" 54"
1260 psi 1680 psi 1120 psi
$ million $ million $ million
zone (Canadian) (Canadian) (Canadian) -
1 707 707 707
2 721 864 805
3 738 850 803
4 380 488 456
5 677 859 813
6 236 236 236
7 126 126 126
8 83 83 83
* 9 205 205 205 --
Total 3,873 4,418 4,234
Zones
1-9
*The last compression station in Zone 9 includes facilities
to provide compression up to 1440 psi.
ANNEX III
78
It is recognized that the above are estimates of
capital costs. They do not include working capital,
property taxes or the provision for road maintenance in
the Yukon Territory (not to exceed $30 million Canadian).
If at the time construction is authorized, both
Governments have agreed to a starting date for the opera-
tion of the Pipeline different from January 1, 1983, then
the capital cost estimates shall be adjusted for the
difference in time using the GNP price deflator from
January 1, 1983. Similarly at the time construction is
authorized for the Dempster Line, if the starting date for
the operation agreed to by the Canadian Government is
different from January 1, 1985, then the 'capital cost
estimate spall be adjusted for the difference in timing
using the GNP price deflator from January 1, 1985. The
diameter of the pipeline in Zone 11, for purposes of cost
allocation, may be 30", 36" or 42", so long as the same
diameter pipe is used from the Delta to Dawson (Zone 10).
The actual capital cost, for purposes of this Annex
' will be the booked cost as of the date "le~ve to open" is
granted plus amounts still outstanding to be accrued on a
basis to be approved by the National Energy Board. Actual
ANNEX III
79
capital costs will exclude working capital, property taxes,
and direct charges for road maintenance of up to $30 million
canadian in the Yukon Territory as specifically provided
herein.
For purposes of this Annex above, actual capital
costs will exclude the effect of increases in cost or
delays caused by actions attributable to the o.s. shippers,
related u.s. pipeline companies, Alaskan producers, the
Prudhoe Bay deliverability or gas conditioning plant
construction and the United States or State Governments.
If the appropriate regulatory bodies of the two countries
are unable to agree upon the amount of such costs to be
excluded, the determination shall be made in accordance
with the procedures set forth in Article IX of the Transit
Pipeline Treaty.
The filed capital costs of facilities in Zones 7 and
8 will be included in calculations pursuant to this Annex
only to the extent that such Facilities are constructed
to meet the requirements of u.s. shippers.
ANNEX IV
80
Direct Charges by Public Authorities
*1. Crossing damages (roads, railroad crossings, etc.; this
is usually covered in the crossing permit).
*2. Road damages caused by exceeding design load
limits.
*3. Required bridge reinforcements caused by exceeding
design load limits.
4. Airfield and airstrip repairs.
5. Drainage maintenance.
6. Erosion control.
7. Borrow pit reclamation.
8. Powerline damage.
9. Legal liabilityfor fire damage.
10. Utility system repair (water, sewer, etc.)
11. Camp waste disposal.
12. Camp site reclamation.
13. Other items specified in enviromental stipulations.
14. Costs of surveillance and related studies as required
by regulatory bodies or applicable laws.
* In the case of these items and all other road related
charges by public authorities, total charges in the Yukon
Territory shall not exceed Canadian $30 million.
······-w
ANNEX V
81
British Columbia Statement
The Government of the Province of British Columbia
agrees in principle to the provisions contained in the
canada-United States Pipeline Treaty of January 28, 1977,
and furthermore British Columbia is prepared to cooperate
with the Federal Government to ensure that the provisions
of the Canada-United States Treaty, with respect to non-
interference of throughput and non-discriminatory treatment
with respect to taxes, fees or other monetary charges on
either the pip~line or throughput, are adhered to. Specific
details of this undertaking will be the subject of a
Federal-Provincial Agreement to be negotiated at as early
a date as possible. Such Agreements should guarantee
that British Columbia's position expressed in its telegram
of August 31 is protected.
ANNEX V
82
Alberta Statement
The Government of the Province of Alberta agrees in
principle to the provisions contained in the Canada-United
States Pipeline Treaty of January 28, 1977, and further-
more, Alberta is prepared to cooperate with the Federal
Government to ensure that the provisions of the Canada-
United States Treaty, with respect to non-interference of
throughput and non-discriminatory treatm~nt with respect
to taxes, fees, or other monetary charges on either the
Pipeline or thoughput, are adhered to. Specific details of
this undertaking will be the subject of a Federal-Provincial
Agreement to be negotiated when the Canada-United States
protocol or understanding has been finalized.
ANNEX V
83
saskatchewan Statement
The Government of Saskatchewan is willing to cooperate
with the Government of Canada to facilitate construction of
the Alcan Pipeline. through southwestern Saskatchewan and,
to that end, the Government of Saskatchewan expresses its
concurrence with the principles elaborated in the Transit
Pipeline Agreement signed between Canada and the United
States on January 28, 1977. In so doing, it intends not to
. take any discriminatory action towards such pipelines in
respect of throughput, reporting requirements, and environ-
mental protection, pipeline safety, taxes, fees or monetary
charges that it would not take against any similar pipeline
passing through its jurisdiction. Further details relating
to Canada-Saskatchewan relations regarding the Alcan
Pipeline will be the subject of Federal-Provincial agree-
ments to be negotiated after a Canada-United States
understanding has been finalized.
REPORT ACCOMPANYING A
DECISION ON AN ALASKA
NATURAL GAS TRANSPORTATION
SYSTEM
85
PREFACE
The Alaska Natural Gas Transportation Act (ANGTA)
a unique and comprehensive process designed to
the collective expertise of various branches
·and departments of government in reaching a final decision
on an Alaska Natural Gas Transportation System. By statu-
tory direction, after months of hearings, the Federal Power
commission issued on May 1, 1977, a one-volume report,
Recommendation to the President, which urged the designa-
tion of an overland pipeline system. After the FPC Report,
pursuant to Section 6(a) of ANGTA, ten Federal interagency
task forces were organized to report, ~ot later than July 1,
1977, on the impacts and considerations of an Alaska natural
gas transportation system. The July 1 Reports submitted by
these task forces covered the following subjects:
1. The energy policy impacts of an Alaska natural gas
project;
2. Environmental considerations;
3. Sources of financing for capital costs;
4. The impact on competition;
5. Safety and design;
6. International relations;
86
7. National security, particularly security of
supply;
8. Impact on the national economy;
9. Potential cost overruns and time delay; and
10. Socioeconomic impact of the transportation system.
Pursuant to Section 6(d) of ANGTA, the Council of
Environmental Quality submitted a report on July 1, 1977,
which found that the environmental impact statements
submitted by the FPC with respect to Alcan, pursuant to
Section S(e) of ANGTA, are legally and factually sufficient.
In the preparation of this decision, all the inter-
agency reports, the FPC Recommendation, and many other
submissions and public comments received from Governors,
local officials and other interested individuals have been
carefully considered. This Report to the Congress on an
Alaska Natural Gas Transportation System, as well as the
President's decision which precedes it, are the product of
this collective study process. As required by the Alaska
Natural Gas Transportation Act, this Report explains in
detail the basis for the decision favoring the Alcan
project.
87
CHAPTER I -DESIRABILITY OF AN ALASKA NATURAL GAS PROJECT
Natural Gas Supply
united States
There is currently estimated to be a potential natural
gas demand in the United States of 25 to 30 trillion cubic
feet per year. The U.S. will have to use every source it
can to maintain the early 1970 production level of approxi-
mately 20 trillion cubic feet per ye~r. As our dependence
on foreign sources of energy continues to rise, the nation
can use all the reasonably priced domestic natural gas it
can produce to displace oil imports. Because of its premium
nature, the more gas the U.S. produces, the more it will
be able to use.
Looking toward 1990, even under the most optimistic
conservation and production assumptions, natural gas short-
ages are a very real possibility, even with the delivery
of Alaska gas. This is so because of the expected tapering
off of domestic gas production in the lower-48 states, and
I
a reversal in the decline of natural gas demand when censer-
vation measures have had their full effect and the nation
experiences a renewed increase of demand growth from normal
economic activity. This situatlon could be further_aggra-
vated by the expiration and nonrenewal of Canadian gas
88
export contracts through the 1980's. The Alcan project
maximizes our chances for avoiding such curtailments.
The most optimistic 1985 projection for u.s. domestic
production of gas is 17.5 tcf without Prudhoe Bay gas.
This is 15 percent less production than in 1970. Yet
during this same period -1970 to 1985 -it is estimated
that total energy demand will increase by over 40 percent.
Further, a more pessimistic but sti-ll plausible estimate
of the domestic resource base would reduce 1985 production
of gas by an additional 0.9 tcf per year.
On the demand side, it is apparent that this nation
could use all the reasonably priced natural gas it can
produce. Even with the .ambitious coal conversion program
proposed earlier this year by the Administration, pro~ec
tions indicate that Alaska natural gas will be needed to
meet demand in the coming decade.
Additionally, such projections do not make any allowance
for unusually cold weather, such as that experienced last
winter. The increase in gas demand last winter for space
heating in the residential sector alone was estimated to
be over 0.4 tcf. Under these probabilities, gas shortages
are likely in the near future and throughout the 1980's
with or without substantial new sources of supply.
89
In general, there are three economically attractive
means to supplement traditional domestic gas supplies by
1985. The first is to accelerate OCS leasing in the Gulf
of Mexico, which could produce as much as an additional
0.2 tcf per year by 1985 and 0.6 tcf per year by 1990.
The second is to import gas from Hexico, which could be as
much as 0.5 tcf per year by 1985 and 0.7 tcf per year by
1990 if the recently-announced gas sales contracts should
be completed and approved. The third is to proceed with
an Alaska gas project.
Proved saleable gas reserves of 20.6 to 22.8 trillion
cubic feet (tcf) in the Main Pool accumulation in the
Prudhoe Bay Field represent more than a full year of
natural gas consumption at the current consumption'rate
of about 17.5 tcf per year. Prudhoe Bay production at 2.4
bcfd of gas will include production from other reservoirs
which have been identified in the field, the Kuparuk and
the Lisburne. Production at that rate would increase
domestic gas production by approximately 5 percent in the
years when Alaska gas first becomes available. Additional
gas discoveries on the North Slope, or in other areas of
Alaska through which the pipeline passes, would increase
potential deliverability even further.
246-448 0 -77 - 8
90
The certain increase in supply from an Alaska gas
project is estimated to be 0.7 tcf per year (2.0 bcfd)
by 1985. By 1990, a volume greater than 0.9 tcf per
year (2.4 bcfd) might be produced.
Under the best of circumstances -which assume the
most optimistic supply projections, demand reductions
and fuel substitutions -the addition of Alaska gas to
domestic production will make a subst~ntial contribution
toward closing the gap between natural gas supply and
demand. Such additional gas supplies could allow some
industries with special processes to continue burning natural
gas longer, and allow more residential use of natural gas,
further displacing oil imports.
By 1990, use of every conceivable supply option under
any scenario may still leave us with serious domestic gas
shortages. By 1990, oil imports are projected to be 9.6
mmbd, provided that supplemental supply sources can furnish
gas in the following volumes:
0.9 tcf per year from Alaska gas;
0.7 tcf per year from Mexican gas exports;
0.6 tcf per year from accelerated ocs leasing
in the Gulf of Hexico.
91
clearly, each of these gas supply options will become
more desirable and important as conventional gas supplies
decline in the years after 1990.
Our best efforts will only temporarily stem the decline
in conventional onshore gas production in the lower-48 states.
The u.s. may increasingly need supplemental sources of gas
supply to meet demand. These will include:
geopressurized methane
Devonian shale
deeper, tighter, formations
coal gasification
imports of liquefied natural gas (LNG)
synthetic natural gas (SNG).
Although Alaska gas will add about 5 percent to total
domestic gas production, it will be a larger proportion
of supply for consumers in the Middle West and on the west
Coast. For these regions, it will be between 6 and 10 per-
cent of their supply depending on the distribution which
is reflected in the final gas sales contracts. These
volumes will be important to the availability of gas
in these regions, and should be delivered at a competitive
Price with other supplemental sources of supply.
92
Canada
One of the most significant effects of the Alcan
project on gas supply will be its effect on Canada's
natural gas sales policies. In its July 4th decision
on a northern pipeline project, the Canadian National
Energy Board (NEB) found that unless the project gave
Canadians access to their frontier gas reserves, Canada
might not have sufficient supplies availab~e to fulfill
its existing gas export commitments to the u.s. If the
frontier gas reserves were made available, however,
increased supplies would exist to allow continuation of
current export levels.
A possibility offered by the Alcan project is the
effective availability of Alaska gas to the u.s. before
completion of the project through pre-delivery of Canadian
gas under existing export licenses~ The southern portions
of the Alcan project could be constructed first, and
deliveries of excess gas from Alberta could reach as much
as 1.1 bcfd by the winter of 1979 -1980. As currently
proposed, the pre-deliveries would be repaid by reduced
export commitments in the late 1980's, or by time-swaps
for Alaska gas. The pre-deliveries would make extra gas
available over the next few years when th~ Nation faces
93
serious and immediate natural gas shortages, prior to the
time when supply stimulation and demand reduction measures
under the National Energy Plan have had any effect in help-
ing bring natural gas supply and demand back into balance.
A pre-delivery arrangemen~ involving Alberta gas
would provide stimulus to exploration for additional
supplies in that province by providing producers with
additional markets for their gas. Similarly, agreement on
a project which brings a major pipeline effectively within
500 miles of the Mackenzie Delta region should stimulate
further exploration activity there. If that additional
exploration is undertaken, the possibility of obtaining
additional volumes of Canadian gas i~ future years will
be enhanced. The joint project will thus ensure maximum
availability of Canadian gas in the near term, through
continued exports under existing contracts and possible
pre-deliveries. It ~ill also give the u.s. its best chance
of obtaining longer-term supplies of Canadian gas by
providing the impetus for broad-scale exploration programs.
Economic Considerations
An economic analysis of the Alaska gas projects can
be made from both a private market perspective and from a
national economic perspective. The utility of the project
94
from a private market perspective is determined by whether
there are less expensive alternative fuels available.
This depends on the field price of the gas and the trans-
portation cost. The reliance upon the National Energy
Plan (NEP) for setting of a field price is discussed in
Section 6 of the Decision. For illustrative purposes here,
the $1.45 price that would be set under the NEP is used.
The transportation cost of service will be d~termined by
the capital and operating costs of the delivery system.
The project applicants have filed cost estimates that
produce a 20-year average cost of service which ranges
from $.80 to $1.07 per mmbtu (1975 dollars).
The large cost overruns of the Alyeska pipeline have
raised new concerns regarding the accuracy of base capital
cost estimates for such major projects. For the Alaska
gas project, cost overrun assessments have been made which
allow for capital cost increases by factors from about 1.3
to· 2.0.
The expected 20-year average cost of service for
the Alcan project described in the Decision, and including
an expected case 40 percent cost overrun, is estimated at
approximately $1.04 per mmbtu in constant 1975 dollars.
95
The cost of service under similar assumptions for the El
Paso project is $1.21 per mrnbtu. The "worst case" estimates
for both projects result in a 20-year average cost of
service of about $1.80 to $2.00 per rnmbtu. In addition,
the transporters (i.e., the project sponsors) will probably
be required to bear a portion of the "conditioning" or pro-
cessing cost of the gas. When the cost of service price
of the Alcan project is added to a wellhead price of $1.45
to $1.75 per mrnbtu (depending on the amount the FPC will
allow producers for their processing costs), the wholesale
or "city gate" price of the gas should be about $2.50 to
$2.80 per mmbtu in constant 1975 dollars. The delivered
cost of Alcan gas under three different overrun assumptions
is:
Field Price
Processing
Transportation
20 Year Average Alcan Delivered Cost
(1975 Dollars)
Expected
Filed Costs Cost Overrun
$1.45 $1.45
0 to .30 0 to .30
0.80 1.04
2.25 to 2.55 2.49 to 2. 79
Worst Case
Cost Overrun
$1.45
0 to .30
1.57
3.02 to 3.32
96
The conservatively projected costs of imported LNG
and other alternative non-conventional gas supplies would
be at least $3.25 per mmbtu (in 1975 dollars). SNG would
be at least $3.75 per mmbtu. Only if there were a "worst
case" cost overrun and high processing costs would Alaska
gas be more expensive than imported LNG~ it would still
be considerably less expensive than SNG. One of the most
important objectives of the Federal Government's involve-
ment during the planning and construction period will be
to avoid such "worst case" overruns.
Estimates of availability and cost of gas from coal
gasification and other unconventional sources must be con-
sidered speculative at this time. However, as there are
no confirmed estimates which put the city gate price of
marketable amounts of gas from these sources below $3.50
to $4.00 per mmbtu, the Alcan project would appear to be
competitive for the life of the project.
The measure of the project's value to the nation is
the Net National Economic Benefit (NNEB), which compares
the present value of real resource expenditures for the
project with the present value of its future benefits.
The resource expenditures are measured by the capital and
operating expenses. The benefits are measured by the costs
97
of alternate fuel displaced by the gas, such as imported
oil or LNG. The benefit value which has been used for
evaluating this project is approximately $2.60 per mmbtu
(1975 dollars). This analysis shows that both the El
Paso and Alcan projects would have net benefits of almost
$5.0 billion at the expected overrun cost. This clearly
indicates that construction of some project is preferable
to the no project option. Significantly, the benefits of
either project remain positive, although smaller, at the
"worst case" cost overrun level.
Most significantly, the NNEB of the Alcan project is
over $1.1 billion more than that of El Paso under the
expected overrun case as indicated below:
"Expected" Costs
Alcan Project $5.7 billion
El Paso $4.6 billion
"Worst Case"
Costs
·$1.8 billion
$700 million
If the resource value assumption is changed to take
account of the reasonable potential for an increasing
world oil price over the. 25 year accounting life of the
project, or if the price of supplemental gas supplies
such as SNG (now at $3.75 or more per mmbtu) is used,
98
and if the benefits of the project beyond its 25 year
accounting life are included, the expected case NNEB
more than doubles.
Conclusion
This analysis indicates the importance and superiority
of the Alcan project as compared to either the El Paso proj-
ect or the no project option. It appears that/Alaska gas
will be one of our cheapest sources of supplemental gas
supply and will assure at least near-term continuation of
our access to Canadian gas supplies.
Even if we achieve the ambitious coal· conversion,
conservatio~ and production goals outlined in the ~ational
Energy Plan, Alaska gas provides us with a needed addi-
tional resource for helping reduce oil imports while
heating more of our homes and running more of our factories
with a premium domestically produced fuel. If we fall
short of our goals, Alaskan gas is essential in the effort
to minimize imports and help fill the gap between natural
gas supply and demand.
A realistic assessment of all the supply and demand
potentials indicates that Alaska gas delivered by the Alcan
system will be an important source of energy. The Alcan
99
project has a high expected net national economic benefit.
It should provide transportation services at a projected
cost that will assure the sale of Alaska gas. The Alcan
project is both a good investment for the United States
as a matter of national energy policy, and a good invest-
ment for the private interests that will manage and finance
its construction.
100
Chapter II -FINANCIAL ANALYSIS
Conclusions
As indicated by the terms and conditions in Section 5
of the Decision, the Alcan project is required to be
privately financed. As such, it will be the largest pri-
vately financed energy project ever undertaken, requiring
between $10 billion and $15 billion by the time it is
completed. This Chapter addresses the reasons fo~ C9h-
cluding the project can be privately financed and the
1
, conditions under which a private financing is expected to
occur.
To effectuate such a private financing, a plan that
equitably and carefully balances the project's benefits and
risks is required. The following plan to share the risks
and benefits of the Alcan project is proposed:
1. The equity investment in the project would be
placed at risk under all circumstances and the
budgeted equity investment be considered the
first funds spent. The rate of return on equity
would compensate sponsors for bearing this risk.
2. Producers and the State of Alaska, as direct and
major beneficiaries of this project, should
101
participate in the financing either directly or
in the form of debt guarantees.
3. The burden of cost overruns be shared by equity
holders and consumers upon completion through the
application of a variable rate of return on common
equity. This would provide a strong incentive for
the project to be constructed at the lowest
possible cost.
4. Provision of debt service in the event of service
interruption would be borne by consumers through a
tariff that becomes effective only after service
commences.
Analysis
Given the large volumes of proven reserves in the
Prudhoe Bay Oil Pool, the high degree of experience and
excellent performance record of gas pipeline transmission
facilities, the support and best efforts of Canada, and the
clear need for additional natural gas supplies throughout
the United States, there is good reason to expect this
project will be finarlced by the capital markets without
the use of consumer noncompletion agreements. This deter-
mination takes into account the following considerations:
102
1. The risks associated with the construction and
operation of the Alcan project must be assumed by
creditworthy parties in order to achieve private
financing. There is sufficient credit support
capacity among the direct beneficiaries of the
project to assure completion of the pipeline
without assistance from consumers. Such benefi-
ciaries are the gas transmission companies, gas
producers, and the State of Alaska. The benefits
of these parties sufficiently outweigh the risks
associated with the project so that it is reason-
able to expect them to provide support at small
additional cost to consumers. Once operation
begins, however, consumers must expect to pay the
full cost of service based upon certified
expenditures.
2. To reduce uncertainty to a minimum, the Federal
Government should:
ll ~ ~
a) specify clearly the terms and conditions that
are to be imposed on the pipeline during its
i! i ' construction and operation prior to commencement
of construction;
103
b) provide a mechanism to coordinate engineering
and environmental regulation and permit rapid
and unambiguous resolution of any difficulties
which may be encountered;
c) provide for timely approval of outlays for
incorporation into the project's rate base;
d) provide a mechanism to permit a high degree
of cooperation with Canada and rapid resolu-
tion of any difficulties which are encountered;
e) allow sufficient time to plan, coordinate and
manage procurement, logistics and construction.
3. To hold the total direct cost of the project to
a minimum and the project on schedule, it is
desirable to:
a) develop a variable rate of return on equity
that provides for a realizable high return if
actual costs are near or below budget and a
reduced return if cost overruns occur;
b) provide for similar treatment of the return
on equity in both the u.s. and Canada;
c) provide an incentive to the Canadian Govern-
ment and its regulatory authorities to achieve
104
all possible cost savings and promote
management efficiency •.
The Terms and Conditions in Section 5 of the
Decision, along with the Agreement on Principles
included as Section 7, provides the requisite
processes and assurances for the reduction of both
uncertainty and costs.
The conclusion reached here regarding prjvate financing
without consumer noncompletion guarantees differs substan-
tially from the position taken by most parties in the
Federal Power Commission proceeding and by representatives
of El Paso in their most recent statements. These state-
ments were made prior to the significant steps that have
been taken in recent weeks to reduce uncertainty and create
proper planning, control and incentives. While the funda-
mental economic potential of the project has not changed,
the likelihood of achieving that potential is greater.
Alcan Financial Plan
The Alaska natural gas transportation project proposed
by Alcan will involve a large and complex financing which
will be arranged prior to the commencement of construction.l/
1/ A detailed financial analysis of the competing proposals
can be found in Report to the President, Financing an
Alaskan Gas Transportation System, Department of the
Treasury, Lead Agency, and other participating Agencies:
July 1, 1977.
105
view of the size of the project relative to the financing
capacity of its sponsors, Alcan has proposed that the
required capital be raised and secured_by means of "pro-
j~ct financing" as distinguished from the more traditional
"balance sheet financing" used in the ga~ pipeline industry.
That is, a new project entity will be created which will be
expected in and of itself to generate sufficient revenues
to pay for its operating costs, interest and principal on
debt, and a return on, and ultimately a return of, equity
to its investors.
It is expected that the equity funds for the project
entities wil~ be provided by the sponsoring consortium
companies):/ Debt capital will come from a variety of
lenders.
The basic requirement for a successful financing is the
economic viability of the project. In Chapter IV of the
Report, the basic economic soundness of the project is
demonstrated. Even under extreme cost overruns, the
delivered cost of Alaska gas will be economically attrac-
tive. Appropriate incentives will encourage the
£1 For the sake of simplicity, the new interdependent pro-
ject entities will hereafter be referred to collectively
as "the project."
246-448 0 -77 - 9
106
minimization of cost overruns. Pipeline and gas
distribution companies can be expected to purchase the
Alaska gas from Prudhoe Bay producers under long-term con-
tracts and sign transportation contracts with Alcan.
The conclusion that Alcan can be privately financed is
founded on the basic economic desirability of Alaska gas and
the viability Alcan transportation system; nevertheless,
skillful financial packaging and risk-~enefit balancing will
be required. It is therefore necessary to explore the
boundaries of the financing problem by considering Alcan•s
likely capital needs and sources, relating those needs to
the capital market in general, and reviewing the list of
beneficiaries and examining the roles each might be expected
to play in the financing.
Capital Requirements and Sources of Funds
Alcan has estimated the capital costs of its system
under varying design, route and completion date assumptions.
It has also made two capital requirements and source of
funds projections under its 48-inch proposal: one was filed
with the FPC in March 1977, and was based upon an "express"
1260 psi line carrying no Canadian gas; the other was based
upon the July 4, 1977, NEB-recommended modifications of that
system to divert to Dawson in order to carry Canadian gas
107
and make $200 million in socioeconomic payments. Both of
these projections assumed delivery beginning October 1,
1981.
The Agreement on Principles with Canada has altered
the system from that specified by the NEB. This alteration
has little affect on the basic total capital needs of the
system as compared with the needs estimated for the system
including the NEB recommendations~ the capital saved by
rerouting from the Dawson diversion back to the prime route
is almost exactly offset by the additional cost of instal-
ling a higher-capacity pipeline system from Whitehorse to
caroline Junction.l/ Thus by simply adjusting the Alcan
financial plan for the NEB recommended system to reflect a
more realistic commencement date of January 1, 1983, a
financial plan consistent with the ~greed-upon system
design, route and commencement date results. Exhibits 1
and 2 display the original and adjusted Alcan plans.
Alcan is expected to require approximately $10.3
billion according to cost estimates filed with u.s. and
l/ On the basis of filed costs, moving back to the prime
route saves $444 million while putting in 1680 psi
pipe adds $472 million. The overrun estimate was $630
million for the Dawson diversion and $565 million for
the increase in the capacity of-the system.
108
Canadian regulatory bodies, adjusted to reflect commencement
of operations on January 1, 1983. The projected sources for
these funds are the following:
u.s. Banks
Canadian Banks
U.S. Long-Term Debt
Canadian Long-Term Debt
u.s. Common Stock
Canadian Common Stock
-
$ 1,233 million
542
5,865
445
1,362
855
$10,302 million
With cost overruns, the requirements would be higher.
For example, if the projected cost overrun percentage
detailed elsewhere in this report of approximately 32 per-
cent is used, the total capital requirements would rise to
approximately $13.6 billion.
Capital Markets
The capital requirements of the Alcan project are so
large that the project cannot be viewed in conventional
terms by its pipeline sponsors and other potential inves-
tors. At the end of 1976, the total assets of the gas
transmission industry were $26 billion. The project must
be seen as a corporate entity in itself, capable of issuing
and servicing its own debt and equity.
109
Exhibit 1
Financing Requirements
of Companies Associated with
THE ALCAN PIPELINE PROJECT*
(1978-1982)
(Dollars in Millions)
1979 1980 1981 1982 Total Basic
Requirements
110
Exhibit 2
Adjusted Financing Requirements
of Companies Associated with
THE ALCAN PIPELINE PROJECT*
(1979-1983)
(Dollars in Millions)
1979 1980 1981 1982 1983 Total Basic
Reguirements
ALCAN PIPELINE
u.s. Banks $ $ 38 $ 590 $ 297 $ 925 u.s. Long Term Debt 744 638 478 1,860 u.s. Common Stock 372 287 276 935
$1,154 $1,515 $1,051 $3,720
FOOTHILLS GROUP
Canadian Banks 117 319 106 542 u.s. Long Term Debt 341 --1,103 782 2,227
Canadian Long Term Debt 80 106 106 153 445
Canadian Common Stock ..; 234 183 272 158 7 855
314 747 1,800 1,046 160 4,069
PG&E
u.s. Banks
u.s. Lon·9 Term Debt 412 412 u.s. Common Stock
412 412
PG&E
u.s. Banks
o.s. Long Term Debt 87 218 82 387 u.s. Common Stock
87 218 82 387
NORTHERN BORDER
u.s. Banks 308 308
'u.s. Long Term Debt 49 436 494 979
u.s. Common Stock 17 145 266 427
68 581 1,068 1, 714
TOTAL
Canadian Funds 314 406 697 265 160 1, 8"42
u.s. Funds 1,649 3,416 3,396 8,460
$314 $2,055 $4[113 $3,661 $160 $10,302
* Based upon financial plan presented to White House Staff on August 2, 1977, adjusted
to reflect one and one-quarter year lag in outlays and 5 percent inflation factor.
111
While this investment is large for the industry, its
importance in terms of aggregate investment or total capital
markets is modest. To put these requirements into perspec-
tive, U.S. gross private investment in 1976 was $241 billion.
Alcan's peak year capital needs for u.s. funds, expressed in
1976 dollars, are only 1.1 percent of total u.s. gross
private investment for that year, which was not a particu-
larly good one for the economy.
It is anticipated that most, if not all, of the u.s.
common equity will come from u.s. shippers (i.e., u.s.
transmission or distribution companies). A broad consortium
of companies would have sufficient financial capacity to
make the required $1.4 billion investment. The transmis-
sion sector of the industry alone had almost double that
amount in annual cash flow in 1976. While the industry
must continue to make other investments, its internal cash
flow, plus the ability to issue new securities, provides
ample capacity to fund the necessary equity investment,
including the equity portion of potential cost overruns.
The Canadian equity is expected to be provided by the
four companies supporting the project in Canada: Westcoast
Transmission Company, Ltd., Alberta Gas Trunkline Company,
112
Ltd. (AGTL), Alberta Natural Gas Company, Ltd., and Trans-
Canada Pipelines, Ltd. While the first two companies are
the major and previously the only firms in the Canadian con-
sortium, the addition of the latter two in recent weeks has
contributed additional financial strength to the Alcan
. 4/ proJect.-
As to the debt portion of financing this project,
Alcan's impact on the u.s. debt market cannot be con-
sidered burdensome. In 1976, non-government long-term debt
offerings in the u.s. totaled $62.9 billion. Ignoring the
state of the economy in 1976 and not including the likely
positive real growth of the long-term debt market from
1976 until the Alcan debt is issued, Alcan~s projected
total u.s. long-term debt requirement (including the
Foothills Group debt sold in the U.S.) in its peak year is
only 3 percent of the market (both expressed in 1976
dollars). Over the five year period, 1978 through 1982,
the aggregate requirement is less than approximatley 1.4
percent.
if The Alcan project is relatively more important to
Westcoast and AGTL; together they have total assets of
$1.6 billion at the end of 1976. Their equity invest-
ment in the project will be a major investment for
them.
1
I
113
Similarly, the Canadian long-term debt to be issued by
the Foothills group expressed as a fraction of all corporate
bonds issued in Canada in 1975 is approximately 5 percent
for the peak year and 3percent overall.~/
It is also worth noting that even though the financing
requirements expected for the Alcan system are large in an
absolute sense, peak year requirements as a percentage of
total market capacity are about the same as the peak year
requirements for the Alyeska project in 1975. Yet no
question of capital market capability was raised with
respect to Alyeska.~/
~/ It is not necessary to restrict the supply to these
two domestic markets. Other international capital
markets could be utilized. For example, in 1974
Canadian net foreign liabilities reached $3.0 billion
in mid-year, up from $1.7 billion one half year earlier,
when business loan demand rose abruptly and exceeded
domestic liability expansion.
Alyeska's peak year financial requirements, in light
of capital market capability, were as follows:
1975 Alyeska Debt Issued
1975 Total Corporate Debt
Issued
Peak Year as a Percent
of Total Issues
$3.0 billion
$27.2 billion
11.0 percent
114
The above analysis shows that the Alcan project would
not squeeze out most other investment. It is true it will
have to compete for funds with different investments in the
energy as well as other fields, but if tbe project offers a
competitive return for the perceived risk, its securities
will be purchased. The capital markets are probably the
most competitive element in our economic system.
Cost Overrun Financing
The question of how to finance cost overruns is
closely related to the question of noncompletion. Once
sponsor equity is invested, construction has started,
and the lenders have committed to the project, it is
unlikely that the capital markets would cease to provide
funds simply because of higher than expected costs. The
real consideration here is not the absolute level of costs,
but the probability that the project ·would be ultimately
successful. Analysis of the Alyeska experience shows that
although the ultimate cost of the project was not known, as
costs escalated lenders increased the amount of funds they
were willing to provide on several occasions because they
were convinced that the project would deliver oil at com-
petitive prices. As a result, the risk of noncompletion
due to cost overruns is insignificant once the project is
115
under way, and is only a problem at the initial stage of
financing. It is at that time that the lenders must be
convinced that the sponsoring group will follow the'project
through to completion. Committing equity funds at the
outset provides the basis for that assurance.l/
The project sponsors alone cannot be expected to
provide such assurances because of their limited assets,
liabilities and cash flows; as a result, it is desirable to
include in the sponsor group other beneficiaries as parti-
cipants in the financing.
Project Participants and Beneficiaries
Tradition and equity suggest that the parties who
stand to benefit directly from a transportation system
participate in the financing and share the burden of these
risks. The direct beneficiaries include the equity inves-
tors, namely a consortium of gas transmission companies;
21 An important element of this financial plan will likely
be the commitment of equity capital 11 UP front.11 In order
to provide for the risk-bearing characteristic of having
the equity component of budgeted cost be invested before
debt, while simultaneously keeping the interest during
construction as small as possible, it is contemplated
that debt and equity shall be obtained simultaneously in
their long-run proportion with equity commitments to be
honored even in the event of noncompletion.
116
the producers of the gas; and the State of Alaska with its
royalty interest in the gas.
Equity Investors
The Alcan proposal was initially developed by North-
west Pipeline in conjunction with two Canadian transmission
corporations, Westcoast Transmission Company and Alberta
Gas Trunk Line and their subsidiary, Foothills Pipe Lines
(Yukon) Ltd. Subsequently, the Alcan proposal has acquired
the support of many large U.S. and Canadian gas transmission
firms. An important advantage of the Alcan project over
the El Paso alternative is the equity investment by Canadian
transmission companies which will total at least $800
million.
The strength of the sponsoring consortium of gas
transmission companies is a significant element of the
financing. The consortium must have the ability to pro-
vide the sizable equity funds as well as the equity com-
ponent of any cost overrun requirements. From the outset,
Alcan will enjoy a strong consortium with participation by
most of the large natural gas transmission corporations in
both countries.
117
After careful study of their financial capacity, the
conclusion has been reached that the natural gas transmis-
sion industry has ample capacity to provide the requisite
equity commitments to the Alcan transportation project.
The current members of the Alcan consortium are judged to
be capable of meeting the equity requirements as proposed
in the financing plan.
Producers of Alaskan Natural Gas
The owners and potential producers of Alaskan natural
gas are primarily Exxon, Atlantic Richfield, and the
Standard Oil Company of Ohio. These companies stand to
benefit directly from the sale of their Prudhoe Bay natural
gas reserves. Timely development of the Alcan system is in
their best interests.
1. At the NEP price of $1.45 per mmbtu, the producers'
constant 1977 dollar value of 23 Tcf of saleable
reserves, net of royalty and severance taxes, is
more than $30 billion.
2. Because of the time value of money, a field
price that escalates more slowly than the
amount producers could otherwise earn on the
funds makes it more profitable to produce gas
now rather than defer production for later.
118
Producer participation in the financing of the project
is warranted due to their beneficiary status and their
financial strength. The producing companies have the
investment capacity to participate in the financing of a
transportation system, especially as full returns from their
North Slope oil and the Alyeska pip~line investment are
realized. These three companies had total assets of $51.5
billion in 1976 and net income of $3.4 billion. Financial
participation by the producing companies, most likely in the
form of debt guarantees, can be structured consistent with
the terms and conditions placed upon the producers in
Section 5 of the Decision.
The State of Alaska
The State of Alaska could realize as much as $7.5
billion (1977 dollars) from the sale of Prudhoe Bay natural
gas in the form of royalties and severance taxes. The State
would also realize about $50 million per year in property
taxes. Furthermore, the State will be able to utilize the
pipeline for natural gas distribution and development within
the State. Prudhoe Bay gas, including the State of Alaska's
royalty gas, will be made available to local Alaskan com-
munities along the route of the Alcan Pipeline System.
Installation of additional pipeline facilities connecting
119
with the Alcan system could provide natural gas to other
areas of the State, particularly the Cook Inlet region and
southeastern Alaska, and thus supply the energy base
required for long-term economic development. The Alcan
system also will offer a readily accessible transportation
service for a number of potential Alaska gas reserves
located in interior Alaska, Cook Inlet and the Gulf of
Alaska.
The State of Alaska has indicated a willingness and
ability to guarantee up to $900 million of the El Paso
project debt, with the final amount depending upon the
percentage of royalty revenues that the State Legislature
votes to have placed in a permanent capital account that
can be used for such purposes. While no comparable commit-
ment has been received from the State for the Alcan project,
such participation by the State in the financing would be
in the interest of the State, the Nation and the expeditious
construction of the project.
Transfer of Financial Risks
Gas Consumers
The issue of gas consumers bearing some or all of the
financial risk of this project was widely discussed in the
Federal Power Commission hearing and has been carefully
120
considered in reaching the Decision. The most frequently
discussed mechanism for consumer support would involve ~
consumer financial guarantee through an "all-events" tariff
with noncompletion arrangements. The noncompletion guaran-
tee would include a consumer guarantee of at least debt
service, and possibly a return of" equity, in the event the
project was not completed.
The financial advisors and sponsors of the El Paso
project continue to believe that consumer guarantees through
the "all-events" tariff with noncompletion features is
required to finance an Alaska gas transportation project.
The Alcan financial advisors and sponsors, however, have
stated in correspondence that in their professional opinion
the Alcan project can be financed under certain conditions
with a more traditional tariff, that is without consumer
noncompletion guarantees or Federal financial assistance.~/
They now propose a tariff arrangement similar to previously
approved arrangements for major projects which would provide
for maintenance of debt service through consumer charges in
. ~ Memorandum from Mark Millard, Vice Chairman of Loeb
Rhoades, dated August 10, 1977, attached to a letter dated
August 10, 1977, from John McMillian, President of the
Alcan Pipeline Company, to Secretary of Energy, James
Schlesinger.
121
the event of interruption only after the project is completed
and initial operation of the delivery system has commenced.
The Agreement on Principles reached with Canada and the
terms and conditions imposed in the Decision satisfy the
conditions specified by the Alcan financial advisors. Their
finding appears supportable and reasonable. Extraordinary
consumer guarantees prior to completion of the project are
judged to be unne·c,essary.
Federal Government Financial Assistance
Federal Government support to the project in the form
of loan guarantees or insurance has also received extensive
scrutiny. The El Paso proposal anticipated approximately
$1.5 billion of Federal loan guarantees for the financing
of the LNG tanker fleet through the existing Maritime
Administration Shipbuilding Program (under Title XI of the
Merchant Marine Act of 1936). The Lead Agency Report to
/
the President on financing demonstrated that new and spe-
cial Federal financing assistance was not necessary.~/ El
Paso did not request new forms of Government assistance for
this project. The Alcan financial advisors believe there
is no need for any Federal financial assistance.
2/ Report to the President, Financing an Alaskan Gas
Transportation System; Department of the Treasury Lead
Agency, and other Participating Agencies; July, 1977.
246-448 0-77 -10
~~.:·1 I' i '
'I
I I'
122
I
In addition to being unnecessary, Federal financial
I I assistance for this project is considered undesirabie for
the following reasons:
1. Serious questions of equity result from the
transfer of risks to taxpayers, many of whom are
not gas consumers or will not receive additional
gas supplies as a result of the Alaskan project.
2. Federal financial support substitutes the
Government for private lenders in the critical
risk assessment function normally performed by
pr~vate lenders.
3. A subsidy in the form of lower interest rates
yields an artificially low price for gas.
4. The incentive for efficient management of the
project is reduced.
5. The Government is placed in conflicting roles as
guarantor and as regulator of the proj~ct.
6. Providing unnecessary Federal assistance to this
project would set a precedent with respect to other
large energy projects that is misleading and
counterproductive.
Variable Rate of Return
Since the tariff will require gas consumers to pay for
123
all costs except those found unreasonable by the regulatory
authority, incentives to minimize cost overruns must be
ensured. In order to give sponsors an incentive to control
costs, the rate of return on equity should be tied to the
size of the cost overruns. Within certain maximum and
minimum levels, return on equity would increase were the
project to come in at or under budget but decrease were
costs to exceed budget. Were the project under budget,
consumers would pay a lower price for gas and sponsors
would receive a higher return on equity.· Were the pro-
ject over budget, the higher total invested capital would
be partially offset by a lower allowed rate of return on
that capital, so that equity investors would assume part
of the cost overrun. The variable rate of return offers
consumers the possibility of lower costs and the sponsors
compensation for risking their equity, and may assist in
making this project attractive to equity investors. The
details of how the variable rate of return will be imple-
mented are left to the FPC and NEB to balance the economic
incentive with administrative feasibility.
The-combination of an economic project, adequate com-
pensation of risk capital, and contingent financing agree-
ments appear to minimize the risk of cost overruns as it
124
relates to financing and the delivered cost of gas. With
the cost overrun risk reduced to manageable proportions, the
project will have a high probability of being successfully
financed.in the private sector.
Cost to the Consumer
The aspect of the financing plan adopted here which will
have the greatest effect on the total transportation cost
paid by consumers is the assumption of the entire noncomple-
tion risk by the project sponsors and other beneficiaries.
The alternative would be to let consumers or taxpayers bear
part or all of that risk through a noncompletion guarantee
or through Federal government guarantees.
In the capital markets additional risks are assumed
only if additional rewards are provided, and that principle
is likely.to operate in this instance. If the State of
Alaska and the producers provide assurances for cost overrun
financing, they would expect to receive some commitment or
guarantee fee, although the amount of such fee should be
relatively small given the small risk they are bearing.
Insofar as there is any risk, most of it will be
assumed by the sponsors as equity capital investors. Under
the plan recommended here, their equity would finance the
•125
first $2 billion of investment. They would, therefore, bear
what little risk the~e is of project abandonment.
While it is difficult to give a precise value to this
risk-sharing principle, the rate of return on equity used
in developing all the numerical analysis has been 15 percent
rather than the more normal 12.5 to 14.0 percent found in
recent FPC decisions. Thus, for example, the effect of
changing the rate of return on equity from 13.5 percent to
15 percent is an increase in the average cost of service of
·about 4 percent.
This risk-sharing principle, however, provides an
important incentive for efficient management and cost
control that would be foregone if consumers. or the Federal
Government were to assume noncompletion guarantees. The
effect of this incentive on total project costs may more
than offset the direct effect on the rate of return asso-
ciated with avoidance of consumer completion guarantees.
Overall, therefore, the objective of placing the risk of
noncompletion on sponsors and beneficiaries other than
consumers appears equitable and cost-effective.
Financeability
In its Recommendation to the President, the FPC found:
126
El Paso would be the easiest system to finance
because of its slightly lower initial cost and
because of Federal guarantees of bonds for its
tankers under Title XI of the Merchant Marine Act.
This finding is no longer accepted in view of several
recent developments. First, while El Paso requires less
total initial outlay, approximately 20 percent of Alcan•s
total capital requirements are now anticipated to be drawn
from the Canadian capital market. This sharing of the
raising and servicing of Alcan•s capital by the strong
Foothills group makes the total u.s. capital requirements
less for Alcan than El Paso.
Second, the .cornerstone of financeability is economic
viability. There is no doubt that Alcan•s superior economic
efficiency (lower operating cost and higher fuel efficiency),
which has now been further assured by the Agreement on
Principles, will make its financial instruments more attrac-
tive than those of the El Paso system.
In general, El Paso's dependence upon Federal Government
support for financeability is not a, particularly desirable
characteristjc. Overall, it is reasonable to conclude that
Alcan will be at least as easy and probably easier to
finance privately than El Paso.
127
presidential Finding That the Alcan System Can be Privately
Financed
The Alcan sponsors and financial advisors have stated
the Alcan project can be privately financed. The financial
analysis above supports th{s conclusion. Therefore, it is
reasonable to anticipate that the Alcan project can be
financed in the private sector.
Novel regulatory schemes to shift this project's
risks from the private sector to consumers are found to
be neither necessary nor desirable. Federal financing
assistance is also found to be neither necessary or
desirable, and any such approach is herewith explicitly
rejected.
128
CHAPTER III -ENVIRONMENTAL AND SOCIOECONOMIC CONSIDERATIONS
The Environmental Advantages of Alcan
It is significant to note that the Alcan proposal was
originally presented to the FPC after the preliminary
-
environmental impact statements had been critical of both
the El Paso and Arctic Gas proposals. The "environmentally
preferred route" suggested by the FPC staff early in the
proceeding was followed closely by Alcan in developing
its system. The success of the Alcan proposal is in large
measure a result of its attention to environmental impact.
The environmental impact of large-scale construction
in a northern environment is a particularly sensitive issue.
The tundra and permafrost are delicate and slow to heal;
the fauna is unaccustomed to the presence of large-scale
human activities, and the breeding patterns and survival
rate are easily upset. Endangered wildlife species cling
precariously to existence; aquatic life is as sensitive as
terrestrial life; and native populations must subsist on
this fragile environment for their economic and physical
well-being.
Many parties in both the u.s. and Canada contended
\
that the Arctic Gas proposal, even if it was, as som~
claimed, superior on economic grounds, had the potential
129
substantial environmental and socioeconomic impact.
Arctic Gas route would not have followed existing
utility corridors and would have cut through the Arctic
National Wildlife Range in the northeast corner of Alaska.
While Arctic Gas proposed mitigating measures that included,
among other things, all-winter construction across the North
Slope and above the 60th parallel wit~ snow roads and work
pads, some parties considered these measures technically
unfeasible. The State of Alaska also opposed construction
in the Range.
The Canadian National Energy Board found that the
Arctic Gas route in Canada was "environmentally unacceptable"
because it would have impacts "which could not be avoided,
which could not be accepted, and for which mitigative
measures are unknown or uncertain of d~velopment." This
finding of the NEB effectively forced the withdrawal of
the Arctic Gas proposal from further consideration.
On environmental and socioeconomic grounds, both El
Paso and Alcan are superior to Arctic Gas because they·
generally follow existing utility corridors where the
incremental environmental impacts tend to be small.
In this respect, the Alcan proposal is particularly
advantageous. The Alcan route follows the Alyeska oil
130
pipeline in Alaska until it turns to follow along the Alaska
Highway into Canada at Delta Junction; from Delta Junction
the pipeline will generally make use of the Alaska Highway
right-of-way or the now-abandoned Haines-Fairbanks pipeline
right-of-way (a line built during World War II to transport
oil products to ~airbanks from Haines, which is north of
Juneau, Alaska).
The environmental impact of the El Paso proposal, on
the other hand, would be more adverse than Alcan's. After
departing from the Alyeska corridor near Valdez, the El
Paso route would traverse the wild and mountainous Chugach
National Forest for about 40 miles, an area of great beauty
which supports many forms of wildlife and has no roads. A
gravel haul road and LNG plant could affect the bald eagles
!
and Sitka black-tail deer that inhabit the area. Further-
more, El Paso would also have an adverse impact on the
marine biota of Prince William Sound from the thermal,
chlorine and other toxic material discharge of its LNG
plant. The impact of this LNG plant would have to be
mitigated by the addition of cooling towers -which have
their own environmental impact -at an estimated 1975
dollar cost of $75 million. Similarly, El Paso's
California regasification facility also has the potential
for adverse impact on marine biota with its cold water
131
discharge into the Pacific Ocean. By comparison to these
impacts, no particular impact of Alcan has been singled
out for the same degree of concern.
The environmental impacts of Alcan's eastern and west-
ern legs in the lower-48 states have never been considered
serious. In the FPC hearing,· Alcan showed sensitivity to
a myriad of local impacts and suggested mitigative measures
that appear adequate.
Finally, Alcan's far superior fuel efficiency means
that the system will deliver more units of clean-burning
and efficient natural gas than El Paso for the same amount
of wellhead deliveries. Alcan is expected to consume only
about ~hree-fourths as much gas for fuel as the El Paso
system.
Presidential Finding -Environmental Impact Statements
In its Recommendation to the President, the Federal
Power Commission found after months of hearings and_ evalu-
ations of impact statements that 11 no doubt, the Alcan route
\
promises the least environmental impact.11 In its subsequent
July 1 Report, the Interagency Task Force on Environmental
Issues, under the lead of Department of the Interior, con-
eluded that Alcan appeared to have the least environmental
( \
impact of the proposed routes,.provided tha~roper mitiga-
tive actions are taken. The conservationist intervenors in
132
the proceedings (Sierra Club, The Wilderness Society,
National Audubon Society, and the Alaskan Conservation
Society) also stated a clear preference for the Alcan
proposal.
Pursuant to Section 6(d) of ANGTA, the Council on
Environmental Q~ality submitted a report on July 1, 1977,
which found that the environmental impact statements
submitted by the FPC with respect to Alcan, pursuant to
1 Section S(e) of ANGTA, are legally and factually
sufficient.
After four days of public hearings, and extensive study,
the CEQ reached the following conclusion: "Alcan is the
environmentally preferable route. Its impacts are largely
restricted to existing transportation corridors ••• and
involve no large-scale intrusion into wilderness values."
The CEQ also found that the information was insufficient
to determine whether the El Paso project is environmentally
acceptable. It is clear from the FPC hearings, the environ-
mental impact statements prepared by the FPC and Department
of the Interior the certification of those impact statements
by the CEQ, and many other submissions from many parties
that the Alcan rout~ is clearly the superior system on
environmental grounds. '
I
j
133
The President hereby determines pursuant to the
direction of Section B(e) of ANGTA, that the required
.environmental impact statements relative to an Alaska
natural ~as transportation system have been prepared, that
they have been certified by the CEQ and that they are in
compliance with the National Environmental Policy Act of
1969.
Consequently the enactment of a joint resolution
approving the Decision shall be conclusive as to the legal
and factual sufficiency of the final environmental impact
statements as provided by Section 10(c)(3) of ANGTA.
Socioeconomic Impact
The socioeconomic impacts of both systems are roughly
the same in Alaska. Under either proposal, the royalty,
severance tax, property tax and income tax revenues to the
State of Alaska will increase substantially. The Department
of Commerce's Report on Socioeconomic Impacts found the
El Paso proposal would provide a greater impetus to the
Alaskan economy, but if factors such as adverse effects on
native communities and local lifestyles are given primary
importance, the Department concluded that the El Paso pro-
posal would then suffer in comparison with Alcan.
134
On the basis of relative growth, Cordova, 13 miles
southeast of Gravina Point, will suffer the most change
with the El Paso project. Because of LNG plant and con-
struction, the population would be expected to fluctuate
from 2400 in 1977 to 9100 in 1979 to 4100 in 1982. As a
result~ the character of the town itself might change
from a fishing village to an industrial town. The State
of Alaska has noted that the socioeconomic costs to small
communities will be greatest for the El Paso project.
Otherwise, it should be noted that both proposed
pipelines follow existing utility corridors; the native
communities near these corridor have already been affected
by the pressures created from major construction activity.
Accordingly, the socioeconomic impact of Alcan's construe-
tion, which more closely follows these corridors, should
not be as great as El Paso's.
Conclusion
To sum up, environmental values have been extensively
considered and evaluated throughout the certification and
decision process. In the future, Federal oversight of
!' design and construction of the Alcan system should
,II strengthen and implement the environmental priorities
IIi
"I
,,,,
established in this decision process. Significantly,
both the Administrator of the Environmental Protection
135
Agency and the Secretary of the Interior will be repre-
sented on the Executive Policy Board. The Board, as
discussed in Chapter VI of the Report and specified
in Section 5 of the Decision, will provide policy direc-
tion through the Federal Inspector to the Agency Authorized
Officers, including those from the EPA and Interior, who
will directly represent and exercise the statutory author-
ities of their respective agencies. The strong represen-
tation of EPA and Interior on the Executive Policy Board
will help ensure the protection of environmental interests
through the enforcement activities of the Federal Inspector.
As required by ANGTA, environmental concerns have been
paramount in the study and decision process, and will be
translated into a responsive permitting and enforcement
mechanism for implementation of the Decision. Federal
oversight will seek to avoid "trade-offs" between protec-
tion of environmental priorities and construction economics
by seeking through advance planning by the Government and
the applicant for the coordinated enhancement of both.
136
CHAPTER IV -ECONOMIC CONSIDERATIONS
Potential for Cost Overruns and Time Delay
The cost overruns that occurred in construction of the
Alyeska oil pipeline naturally raise questions about the
potential of any Alaskan natural gas transportation system
I i[ for cost overruns. Such overruns can result from poor ini-
L tial cost estimates, waste, institutional delays, .inflation,
I~' I ll low construction productivity, or management inefficiency.
t While it is difficult to assess the likelihood of such :f!:!
'i 1.1
I
problems prior to the start of construction, they provide a
useful basis on which to compare the respective projects.
The major causes of cost overruns appear to be the following:
1. Incentives to make a low initial cost estimate.
In projects where institutional approval must be obtained
prior to the start of construction, the project applicant
may try to increase the chances for approval by conservative
estimates of the project costs.
2. Use of new complex technology or scaled increases
in design size. Technologically uncomplicated systems are
less expensive and have fewer uncertainties that increase
capital costs.
137
3. Labor productivity and equipment capacity. There
well-recognized inverse correlation between productivity
and the increasing utilization of the capacity in an industry.
AS the use of labor capacity, equipment capacity, or manage-
ment availability approaches 100 percent, productivity begins
to decline rapidly. Furthermore, the more complex the pro-
ject, the greater the loss in productivity or efficiency
as the project capabilities are reached or exceeded •. When
large-scale projects experience equipment and material short-
ages, they generate their own internal, demand-pull inflation,
resulting in an increase in equipment and material costs.
4. Cost of service tariffs and cost-plus contracts.
Cost increases during construction of public utility projects
merely expand the rate base of the utility; absent a variable
rate of return, they do not result in any loss to investors.
The same effect occurs from use of cost-plus contracts; the
contractors' profit will not be adversely affected by cost
overruns.
5. Construction schedule pressure. In most situations,
accelerated construction schedules can be accomplished only
at a high premium in cost.
246-448 0 -77 -11
138
6. Long delays after project start-up. Large scale
projects are frequently delayed because of litigation, labor
grievances, and cumbersome bureaucratic actions or regulations.
7. Remote areas or inhospitable environments. Remote
locations create severe logistical problems and magnify the
costs of poor planning. Breakdown of equipment that would
cause only minor delays in well settled areas may result in
considerable delays in remote areas. Furthermore, new
techniques, methods, and materials are frequently required
when work is done in an inhospitable environment. Such
conditions often cause on-site modifications of equipment or
design.
8. Unforeseen geotechnical factors. Even to experienced
geologists, the earth holds many surprises --especially in
the Arctic. Unexpected water flows or earth movements can
create severe construction problems and cause expensive delays.
The unstable permafrost soils in the Arctic regions are parti-
cularly troubling for large-scale construction.
Comparisons with Alyeska
Both the Alcan and El Paso projects would encounter
these problems to one degree or another. Like Alyeska, they
have the potential for significant cost overruns. But when
139
the Alyeska experience is examined, a convincing case can
be made that the cost overruns for Alcan and El Paso would
not be as great. The major problems described above provide
a useful framework for comparison.
1. Low cost estimates. The early cqst estimates by
Alyeska were made for a system smaller than the one Alyeska
finally built. Alyeska had no appreciation at the time of
these estimates for the vast changes in construction tech-
niques that would be required for arctic construction by
subsequently enacted environmental laws. Alyeska also
had no experience with the logistics problems and low labor
productivity characteristic of arctic construction. By
1974, Alyeska had become aware of the increased costs of
environmental requirements, but still had no data on labor
or contractor productivity in arctic conditions. By mid-
1975, when Alyeska submitted its first design cost estimate
of $6.3 billion, it had developed considerable experience
with pipeline construction.
El Paso's cost estimates for Alaska construction of its
2.3614 bcfd case were submitted to the Federal Power Commis-
sion in late 1975 and Alcan's estimates were submitted in
mid-1976. Thus, El Paso and, to an even greater degree,
140
Alcan had the opportunity to factor into their cost estimates
the Alyeska experience. While there are valid reasons to
expect both Alcan's and El Paso's estimates to be conserva-
tive, there is little reason to expect that their initial
estimates are as grossly under-estimated as the early
estimates of Alyeska. Both projects had too much data and
experience available to them to have made large errors, and
excessive underestimates would have been challenged by
competitors.
2. New technology and increases in scale. While El
Paso and Alcan involve some new technology and increases in
scale, the problems from these factors will be of an order
of magnitude less than Alyeska's. The large capacity
systems of both projects require an increase in operating
pressu!es. DOT has concluded, however, that subject to
testing to be conducted by the applicant in conjunction
with the u.s. and Canadian governments, such increases
are within current technological capability and safety
standards.
In addition, no scale-up in construction equipment
(e.g., building equipment to handle 48-inch pipe} will be
required for the gas pipeline.
were mostly solved by Alyeska.
The problems of scale-up
Thus, El Paso with its
1
141
42-inch pipe, or Alcan, with its 48-inch pipe, would have
the benefit of using field-proven equipment.
The Alyeska pipeline also required a large amount of
automated and sophisticated equipment. Remotely controlled
"topping plants" (i.e., miniature refineries) and storage
areas at pumping stations were used to provide the turbine
fuel to drive the pumps. A separate gas pipeline was con-
structed to bring the fuel to the northernmost pump stations.
In addition, Alyeska could not bury a hot oil line in the
thaw-unstable permafrost. It had to employ considerably
sophisticated and advanced technology to design the vertical
support members and heat exchangers necessary to insulate
the oil line from the surrounding environment. Approximately
400 miles or 50 percent of the line is elevated.
By contrast, a natural gas pipeline is a far more
simple, less sophisticated system. Fuel for the compressor
turbines is drawn directly from the gas stream, and controls
are simple and easily automated. The chilled gas pipeline
is compatible with the permafrost environment even in a
buried mode. There are uncertainties regarding the best
design and engineering to eliminate frost heave potential
in discontinuous permafrost areas. However, this problem
is not comparable in complexity or size with the problem of
adapting a hot oil pipeline to the arctic environment.
,,
I'
I
I r I,
I
I
142
Scale-up problems might generate cost overruns during
construction of the El Paso natural gas liquefaction plant.
The proposed LNG plant would require a significant scale-up
from existing plants and involves lower fuel usage than has
heretofore been achieved in practice. In addition, the
techniques proposed to protect the proposed plant and
storage tanks from earthquake damage would also require a
size scale-up. Consequently, the LNG plant and terminal
appear to have a potential for significant cost overruns.
3. Labor and equipment capacity. The Alyeska project
is a classic example of a construction project that exceeded
its predetermined labor and equipment capacity. Alyeska was
forced to use inexperienced labor and contractors, and there-
by incurred significant increases in the size of management
and engineering staffs. This resulted in low productivity,
management inefficiency, and created the project's own
internal demand-pull inflation for some critical items.
Construction of a gas pipeline in Alaska should present
fewer problems. Less labor is required for a continuous
buried mode of construction and the Alyeska experience
expanded the pool of skilled workers and contractors avail-
able for arctic construction.
143
The Alcan project may encounter skilled-labor shortages
Canada. Anticipated shortages in skilled labor and
experienced subcontractors could reduce productivity and
raise costs. However, training programs and proper project
planning would mitigate this problem.
Alcan has been criticized because it will not have an
overall project manager. The Canadian companies, however,
can control construction in their respective segments of
the system without the large increases in management or
engineering required for a single project. In addition,
the companies will be using control and accounting procedures
with which they are familiar. It is reasonable to expect
that Alcan will not suffer from the management and control
inefficiencies that plagued Alyeska.
I
4. Incentives to minimize construction costs. The
El Paso and Alcan projects would have stronger incentives
to control costs than are normally present in a public-
utility type project. The variable rate of return will link
I
the earnings of equity investors directly to the cost control
performance of management. In Canada, the costs to Canadian
consumers for Canadian gas will be materially dependent upon
the level of cost overruns in the main Alcan line, providing
Canadian regulatory agencies with an incentive to control
costs.
I !
144
One of the terms and conditions contained in the decision
will limit the use of cost-plus contracts unless approved by
the Federal Inspector. Contractors will thus have incentives
to hold down costs. The magnitude of the project investment
and the generally limited availability of capital at present
will also create financial constraints that should act to
minimize costs. Furthermore, the managements of the various
gas companies also have a substantial incentive to show that
a major arctic project can be constructed with relatively
minor cost overruns.
5. The time factor. With a simpler construction mode,
fewer environmental problems, a more experienced labor force
available, and more favorable terrain in most of Canada, con-
struction of the Alcan system should pose fewer problems, and
have a longer lead time to deal with them. While Alyeska had
a long delay from 1969 to late 1973, there is little evidence
that intensive planning occurred during that period. After
Congressional approval came in late 1973, Alyeska carried
out its final planning and construction in three and one-half
years. The final planning and execution period for either
gas project is at least five years and the overrun analyses
herein have allowed for six to six and one-half years.
145
6. Delays. The Alyeska project suffered excessive
delays because of strict new environmental laws enacted
after it had initially ordered the pipe and some construc-
tion equipment. Government agencies required considerable
time to write regulations and to staff operations. In
addition, after construction started, numerous government
inspectors monitored contractors and subcontractors,
.occasionally shutting down construction.
Conditions should be considerably better during
construction of the gas pipeline. First, the government
itself is now more knowledgeable about the inspection
process and can be expected to make fewer errors. The
Office of Federal Inspector is designed to achieve greater
coordination of the government monitoring and enforcement
process. The occasionally conflicting orders given by
different departments or agencies during construction of the
Alyeska project will be avoided. Second, contractors have
learned to some extent to adapt to the government inspection
process.
problems.
Third, the gas line will raise fewer environmental
Overall, delays resulting from environmental
regulations and government oversight and inspection should
be much less during construction of a gas pipeline.
146
The projects will also be much less constrained by
institutional delays of the type that confronted Alyeska
from 1969 until enactment of the TAPS Act in 1973. Simi-
lar to the TAPS Act, Section 11 of ANGTA contains tight
restrictions on judicial review of the authorization and
certification process. While private litigants can still
challenge Government actions, such claims must be brought
within 60 days of such action, and filed only in the u.s.
Court of Appeals for the District of Columbia. This Court
will act as a Special Court with exclusive jurisdiction over
such matters. There are no specific limitations on judicial
review of Federal enforcement actions, but it is not fore-
seen that such litigation will result in injunctions or
restraining orders that increase the potential for delays
and cost overruns.
El Paso and Alcan each face institutional barriers
other than potential judicial delays. For El Paso, the
problem of siting an LNG facility in California has high
potential for delay. The Western LNG Terminal Company has
been investigating proposed locations for approximately
two years, and no final decision has yet been reached.
Recently, an offshore LNG facility has been receiving con-
sideration, but gas companies and State officials estimate
147
8 to 10 years of design development and construction
work would be required before it could be operational.
For Alcan, the problem of resolving native claims
in the Yukon Territory in Canada had once threatened to
delay construction. However, the Government of Canada
has recently assured the U.S. that resolution of these
claims will not delay construction and will not result in
any monetary cost or claim against the Pipeline. Under the
Agreement, it is expected that construction in the Yukon
will commence by January 1, 1981.
In general, the magnitude of these projects virtually
ensures some delay in the start of full operations --either
because of material supply, logistics, reduced labor produc-
tivity or other problems. Therefore, this Report estimates
that commencement of full operations for Alcan could be
delayed to January 1, 1984, and for El Paso to July 1, 1984.
By comparison, the Task Force Report on Cost Overrun and
Construction Delay estimated a starting date of July 1984
for Alcan and February 1985 for El Paso.
7. Remote and inhospitable location. Both projects
would experience many of the same problems associated with
remote locations as did Alyeska. The benefit of the
Alyeska experience, however, should assist in coping more
I' I ,
h li
,II
I
148
infrastructure--e.g., roads, camps, communications--
created by Alyeska. In Canada, the southern portions of
the Alcan system would be in less remote locations and
present fewer problems.
8. Geotechnical considerations. Alyeska encountered
many unexpected geotechnical conditions, but had done rela-
tively little advance coring and soil testing which could
have reduced the unexpected problems that arose later and
allowed for improved engineering design and scheduling of
work requirements.
Either of the gas pipeline projects will be able to
reduce its number of site-required design changes by using
the construction data generated by Alyeska and by carrying
out a more extensive coring and soil testing program prior
to construction. In addition, the site-specific design
changes that were required will probably be less expensive.
Unexpected geological conditions could significantly
increase the cost of constructing an El Paso LNG plant and
shipping terminal. Similarly, Alyeska experienced signifi-
cant cost ove~runs in constructing the Valdez terminal.
149
El Paso probably would escape such problems if, as expected,
it finds shallow bedrock at the Gravina Point terminal site.
If not, El Paso could duplicate or exceed the Valdez terminal
overrun.
cost Overrun Estimates Under Expected Conditions
Comparison of the El Paso and Alcan projects under
expected conditions with Alyeska indicates that both projects
would be able to avoid or minimize many problems that led to
high cost overruns for Alyeska. Cost estimates of both pro-
jects appear to be based on much more reliable data and
experience. There are also fewer uncertainties than were
associated with Alyeska's early estimates, or even its
estimates made as late as 1974 or early 1975. In addition,
several problems that significantly contributed to cost
overruns on the Alyeska project will not be as serious for
these projects. While overruns can be expected, they will be
of relatively lower magnitude than Alyeska's.
Obviously, any prediction of future cost overruns is
highly judgmental. Specifically, it depends on judgments
about future productivity, future supply-demand relation-
ships, and geological and technical problems. But despite
these uncertainties, for the purpose of this analysis some
judgments must be made.
150
Overall, it has been estimated that cost overruns of
30 percent or more should be expected in Alaska and Canada
for construction of a gas transportation system. But in
many areas, the managers of a gas transportation project
should benefit from the Alyeska experience and hold down
overruns. This conclusion is based on careful comparison
with the Alyeska experience and proceeds from the findings of
the July Task Force Report on Cost Overruns and Construction
Delays.
Certain distinctions, however, should be drawn between
Alcan and El Paso with regard to cost overruns. For Alcan,
the cost estimates in Canada are substantially lower than
the cost estimates for equivalent work done in Alaska. These
estimates are highly uncertain. Alcan offers several expla-
nations for the significant differential between costs to do
the same job in Alaska and Canada. It contends that wage
rates in Canada are about one-half the level in Alaska and
that the productivity of labor in Canada has historically
~
been higher. Furthermore, with the exception of the Yukon
section, the Canadian terrain is typically much better.
Below the 60th parallel, the requirement for gravel work
pads is minimal. As the line moves into British Columbia
and Alberta, the Alcan construction conditi0ns will not vary
151
materially from those encountered in the Northern United
states, and lower construction costs can be expected.
On the other hand, the NEB closely examined Alcan's
costs in Canada and concluded that cost overruns in the
range of 20 to 30 percent were "not unlikely". Furthermore,
it is significant that the Alcan productivity estimates
for Alberta are substantially higher than the estimates of
Arctic Gas for comparable terrain. The Alcan cost estimates
must be substantially adjusted to enable a realistic compari-
son between Alcan and El Paso. Therefore, the cost estimates
used herein provide for a 40 percent increase in the filed
costs of Alcan for Canada.
The cost estimates of El Paso are in turn, subject to
two major uncertainties. The first is El Paso's cost esti-
mates for pipeline construction in Alaska. El Paso estimated
these costs, including interest during construction, at $2.204
billion ($1975) --$242 million less than Alcan's Alaska
estimates of $2.446 billion. The relation between the El
Paso cost estimates and the Alcan cost estimates is simply
not consistent, however, with the physical plant require-
ments, but may be partially explained by the fact that the
El Paso estimates were made several months earlier.
I
152
The higher Alcan estimates represent 731 miles of
pipeline in Alaska, 9.6 percent less mileage than El Paso's
809 miles.!Q/ While Alcan would use a larger diameter pipe
(48-inch for Alcan, 42-inch for El Paso), it would also have
a thinner wall (0.60 inch for Alcan, 0.752 inch for El Paso).
Consequently, Alcan would require about 17 percent less pipe
steel in Alaska than El Paso. This differential is reflected
in the respective cost estimates of the parties. The El
Paso estimated materials cost for pipe was $805 million.
Alcan estimated $659 million, or some 18 percent less.
Finally, El Paso could have 10 compressor station sites in
Alaska: Alcan would have only 8 sites. El Paso would have
234,000 installed compressor horsepower; Alcan would have
212,000 horsepower.
On the other hand, Alcan would have more installed
refrigeration horsepower than El Paso, and installation
costs for 48-inch pipe would be slightly higher than those
for 42-inch pipe. The following Exhibit summarizes the
comparisons.
!QI There would be 831 miles for the realignment which El
Paso now proposes to build. The comparisons here
consider only the base cases of El Paso and Alcan. El
Paso estimated the realignment to have a net cost of
about $70 million additional.
1
153
EXHIBIT 3
Comparison of El Paso & Alcan Pipeline
Facilities in Alaska
El Paso (2.4 Bcfd) Alcan (2.4 Bcfd)
Miles (L)
Pipe
Relative Steel Factor
(7( DTL)
Pipe Material Est.
.oampressor Stations
oampressor HP
Installed
Refrigeration Camp.
Installed
246-448 0 -77 -12.
42 11
809
(D) X .75 (T)
8.006
$805,171,000
10
234,000
53,690
731
I
48" (D) X .60 (T)
6.614
$659,239,000
8
212,000
84,470
%
-9.6%
-17.4%
-18.1%
-20.0%
-9.4%
+57.0%
! i
154
By way of further comparison, Alcan and El Paso propose
virtually identical alignments for the first 539 miles in
Alaska. The overall costs of the two systems should be com-
parable to that point. At Delta Junction, the Alcan line
departs from the Alyeska corridor and proceeds southeast
along the Alcan Highway. The El Paso line continues along
the Alyeska corridor to a point about 40 miles from Gravina
Point, from which it creates a new right-of-way through the
mountainous Chugach National Forest. From the common point
of Delta Junction southward, Alcan would traverse 192 more
miles in Alaska, while El Paso would traverse about 265
miles and some significantly more difficult terrain.111
There is no readily apparent reason that the 192 miles of
Alcan pipeline should cost significantly more than the 265
miles of El Paso pipeline.
The proper relationship between El Paso and Alcan is
reflected in the recently released Aerospace, Inc., study of
June 1977 that was prepared for the Department of the Interior.
The direct cost estimates therein for the El Paso pipeline
in Alaska are $1.963 billion. The cost estimate for a
11/ The El Paso realignment case has about 285 miles beyond
Delta Junction.
155
48-inch, 1680 psig~/ pipeline along the Alcan base route
in Alaska is $1.812 billion.
To allow for cost overruns the El Paso estimates were
escalated by the same amount used by the Cost Overrun Task
porce to arrive at $2.5 billion in direct costs (1975 dol-
lars) or $2.85 billion (1975 dollars) including interest
during contruction (!DC). The overrun case f~ Alcan used
here is $2.38 billion in direct costs, $2.67 billion including
!DC. These figures provide a better comparison between
Alcan and El Paso in Alaska.
The second major uncertainty for El Paso is the cost
of the LNG liquefaction plant and marine terminal on Prince
William Sound, Alaska. The scale up factor and the geotech-
nical uncertainties create a high risk of substantial cost
overruns. The Cost Overrun Task Force estimated the cost of
these facilities to be $2.0 billion. The Aerospace, Inc.,
study estimated $1.59 billion. The estimates here used
allow for $1.8 billion, plus $75 million to cover cooling
towers that would likely be required to minimize the thermal
pollution of Prince William Sound.
12/ This would be more expensive than Alcan•s 48-inch,
1260 psi system because of more pipe steel.
I
'I
;!I
156
El Paso would also construct eight LNG tankers of
165,000 to 175,000 cubic meter capacity (m 3 ) with roughly
125,000 tons displacement.ll/ El Paso estimates the LNG
tanker cost at $1.365 billion. The Cost Overrun task force
estimated $1.65 billion; Aerospace, Inc. uses $1.234 billion.
The evidence submitted by Arctic Gas in the FPC proceeding
shows an 8.8 percent overrun or $1.485 billion, and in fact,
the most probable estimate is $1.45 billion.
In the lower 48 States, the facilities for El Paso and
Alcan present no unique construction problems. Therefore,
the cost overrun case used herein assumes only a few per-
cent overrun for these facilities.
The following table sets forth the estimated capital
costs for the base and overrun cases. The capital cost or
the gross plant in service is a dominant element in the cost
of service and net national economic benefit calculations.l4/
lll The ultimate size of the El Paso ships would be
determined by the siting of the regasification facility
in California. For 3 example, if Point Conception was
the site, 165,000 m wo~ld be adequate. If Oxnard
was the site, 175,000 m would be required. See FPC,
Recommendation to the President, pp. VIII-26-28.
14/ NNEB calculations, however,,use only the direct capital
costs, without interest during construction.
l
I
'
157
Capital Costs
(Billions of Dollars)
Base Case-~/ Overrun Case
(Current $) (Current $) (1975 $)
ALCAr¢_/
Alaska 3.335 4.1471/ 2.673
canada 4.365 6.501 4.191
Northern Border 1.427 1.573 1.014
PGT, PG&E .914 .983 .634
subtotal 10.041 13.204 8.511
u.s. Share of
Dempster Line .431 .653 .382
Subtotal 10.472 13.857 8.893
Less Canadian
11 Share 11 (1.000) (1.489) ( .960)
u.s. 11 Share 11 of
Capital Cost 9.472 12.368 7.933
EL PASO
Alaska Pipeline 3.050 4.419 2.849
Alaska LNG 2.385 3.289 2.120
Ships 2.027 2.285 1.473
Regas Plant .542 .674 .434
Lower-48 .991 1.032 .665
Total 8.995 11.699 7.541
~ Based on a 48 inch 1680 psi system between Whitehorse and
James River capable of transporting 3.6 bcfd. If a 54
inch 1120 psi system was constructed, the capital costs
could be slightly less.
~ Derived from the 1975 Direct Capital Costs submitted by
the applicant.
l/ The Base cases assume completion one year earlier than
the overrun cases which accounts for a portion of the
difference.
158
The foregoing table includes all capital costs in
canada in which the u.s. shares. If the Dempster Line is
never constructed, the capital cost on the main line in the
overrun case would be $6.111 billion (1984 dollars) because
of the reduced compression horsepower requirements. Total
u.s. share of capital cost would be $12.767 billion.
Cost of Service
The cost of service advantage of the Alcan overland
pipeline system is substantial and constitutes a crucial
element of this decision. Cost of service is perhaps the
principal factor in determining the value of the project to
individual consumers. If the cost of service is not suffi-
il,
,4 ciently low enough to ensure that the delivered cost of the
gas will be below the cost of alternative fuels, the value
of the project is greatly reduced.
A cost of service calculation generally includes all
transporation charges other than fuel expense. The major
categories of expense include the return on invested capital
''1 (interest and dividends), return of invested capital (through
I
[: annual depreciation charges), Federal and State income
I
taxes, other taxes, and operating and maintenance expenses
(O&M). While annual depreciation charges are constant
159
throughout the depreciable life of the-project and O&M
expenses tend to increase with the rate of inflation, the
other items decline over time as the amount of net invested
capital (gross plant less accumulated depreciation) falls.
These declining items usually result in a project
cost of service that decreases steadily over time, with the
extent of the decrease dependent upon the rate of inflation.
Although this decreasing cost of service is customary, a
downward-sloping service charge to the consumer over the
life of the project is not essential. Payments from con-
sumers can be adjusted to a more constant or stable level
over the accounting life of the project.
However, to compensate investors for deferral of their
return in the early years of the project, and to cover the
resultant increase in the total interest burden, the average
delivered cost of the gas to consumers must be increased
substantially; a complete leveling would increase the
average cost about 20 percent over the life of the project.
The decision whether to "level out" the tariff must be made
by the FPC in the context of the actual financing and tariff
proposals made by the applicants prior to final certification.
I
:li • ' • 'li
' ii
d '
160
Alcan and El Paso: Cost of Service Comparison
The fundamental difference between El Paso and Alcan
is that an overland pipeline system is inherently more effi-
cient than an LNG transportation system. The liquefaction
process involves significant energy losses that have a
multiplying adverse effect upon cost of service. First, the
direct cost15/ for the natural gas consumed by El Paso is 34
percent higher than Alcan or equivalent to 3 cents per mmbtu
(1975 dollars). Second, the volumes of gas delivered are
reduced thus leaving a 3.4 percent smaller base over which
to spread the capital costs. The increase in cost of service
for this volume differential is about 4 cents per mmbtu.
The El Paso system also has 100 percent higher operating
costs, or the equivalent of another 9.5 cents per mmbtu
increase in the cost of service. This operating cost
differential is attributable to the added labor required to
operate the Alaska LNG plant and the LNG tankers. In sum,
the Alcan pipeline system has a 16.5 cent direct advantage
apart from capital cost of financing consideration.
~/ Consistent with practice throughout the Report the fuel
cost is assumed to be $1.00 per mmbtu (1975 dollars).
This unquestionably is lower than actual cost will be.
A higher fuel cost would increase El Paso's cost of
service to a relatively higher degree than Alcan's.
161
The El Paso cost of service would approach the Alcan
cost of service only if the more technologically complex El
paso system could be constructed for about 25 percent less
than the portion of the Alcan system attributable to the
u.s. There is no basis for such a conclusion. No reason-
ably plausible independent assessment of capital costs,
suggests that to be a possibility~/. On the basis of filed
costs, the El Paso 20-year average cost of service is $1.09
per mmbtu; Alcan's is $.81 per mmbtull/, or $.28 less.
The Cost Overrun task force "expected case" cost of service
was $1.26 for the El Paso system and $1.09 for the Alcan
system, or $.17 less.
As indicated in the following Table, the overrun cases
used in the Decision and Report place the cost of service at
$1.21 for El Pas~/ and $1.04 for Alcan.~/ This is a $.17
difference. Over the first 20 years alone, the overland
pipeline system will save consumers conservatively about
16/ The overrun case used herein places El Paso 5 percent
lower; the July 1 task force "expected case" placed El
Paso 4.2 percent lower, of course, not including the
adjustments resulting from the Agreement on Principles
with Canada.
17/ Not including a u.s. share of the Dawson Spur which on
filed costs would be $.0479.
[Footnotes continued]
COMPARATIVE SYSTEM COST ECONOMICS
COST OVERRUN CASE
Direct cost ($1975)
Interest During Construction
Total Capital Cost ($1975)£/
Annual O&M Costs ($1975)
Annual Fuel Cost @ $1/mmbtu
Annual u.s. Delivered Volumes~/
Fuel Efficiency
Average u.s. Cost of Service ($1975)
El Paso
$6.800 billion
0.740
$7.540 billion
$ 168 million
'106 million
8 ~~.i~1~
First 5 years $ 1.84
1.28
• 9 5
.77
1.21
Second 5 years
Third 5 years
Fourth 5 years
Twenty year average
Net National Economic Benefit $ 4.63 billion
Alcan~/
$7.166 billion
0.767
$7.933 billion
$8. Oll billion
0.882
$8.893 billion
$ 84 million~!/
79 million
918 Tbtu
92.1%
$ 1. 71
1.13
• 77
.57
1.04
$ 5. 77 billion
a/ Direct and total capital costs are complete Alaska and lower-48 costs plus the u.s. share of
these costs for the section of the system in Canada plus 83.3% of the Dawson-to-Whitehorse sec-
tion of the Dempster line.
b/ The direct and total capital costs are the complete cost of the entire system, including the
Canadian section of the main line in its entirety, plus 83.3% of the Dawson-to-Whitehorse sec-
tion o~ the Dempster line.
c/ In current dollars, at an assumed inflation rate of 5%, the total capital costs are $11.7
billion for El Paso and $12.4 and $13.9 billion for the U.S. allocated and total Alcan system,
respectively. Seep. 157.
d/ Based on u.s. share of costs in the sections of the system carrying both u.s. and Canadian
volumes, plus 83.3% of O&t-1 costs on the Dawson-Whitehorse section of the Dempster line.
e/ Based upon 2.4 bcfd at 1138 Btu/cf input at Prudhoe Bay and each system's fuel efficiency.
The El Paso system as filed is designed to transport and liquify slightly lower volumes (2.3614
bcfd) at slightly lower Btu content (1130).
f/ Excludes bunker oil consumption by El Paso tanker fleet which would further reduce overall
system energy efficiency to 87.5%.
163
$6 billion (nominal), an average of $300 million per year.
Further, savings will continue long into the future. The
prudhoe Bay field is expected to produce gas in significant
volumes for more than 25 years. The pipeline facilities
will have a useful life in excess of 40 years.
Alcan Cost of Service Pursuant to the Agreement on Principles
The Alcan cost of service must be analyied from the
perspective of both the Canadian National Energy Board (NEB)
Decision and the Agreement on Principles between the United
States and Canada.
(continued from'page 160)
~I Apart from cost overruns, the principal variable in the
El Paso cost of service is financing costs. The $1.21
per mmbtu cost of service is based upon 8.5 percent cost
of debt for the LNG tankers on the assumption that the
MARAD guaranteed loans be available. The return on
equity for the ships is 17 percent calculated on a dis-
counted cash flow basis, as filed by El Paso. The over-
all cost of the remainder of the capital is dependent
upon the debt-equity ratio assumed and whether and how
much preferred stock could be used. These matters have
been the subject of considerable debate thrugh the pro-
ceeding. The capital structure used here is the same as
that assumed for Alcan, 75-25 debt-equity ratio, 15 per-
cent return on equity, 10 percent cost of debt. Under
various other assumptions,the cost of service could be
between $1.19 and $1.21.
~/ Including the cost of the u.s. share of the cost of the
Dawson Spur.
164
The NEB decision provided for a rerouting of the Alcan
main line through Dawson City, Yukon, to facilitate the
transportation of up to 1.2 bcfd of Mackenzie Delta
reserves. That rerouting would have compelled the expendi-
ture of $600 million at least two to three years prior to
the time it would be needed and would have added further
interest costs of $150 to $240 million. If Canada did not
construct the Dempster Line, the U.S. consumer would have
paid more than $2 billion over the life of the project for
no reason.
If the Dempster Line had been constructed, and 1.2 bcfd
of Canadian gas flowed, the U.S. cost of service would have
increased from $1.07 to $1.12 per mmbtu because of system
inefficiencies. The amount of natural gas delivered to the
u.s. would have decreased by about 40 Tbtu annually. As a
result of these lost volumes and inefficiencies, the cost
to American consumers would still have been $2 billion
more over the first 20 years than the project which emerged
from the Agreement on Principles.
The project authorized in the Agreement on Principles
also represents one of those unique, rare negotiating
results in which both parties can justifiably claim to have
165
improved their position over the starting point -the
original NEB decision. This is apparent from the following
comparison.
Dempster Line
Not Constructed
cost of Servicea/
Fuel usage
Dempster Line
Constructed
cost of Service
Fuel Usage
Agreement
on Principles
u.s. Canada
1.00
6.1%
1.04 1.23
7.7% 7.3%
NEB
Decision
U.S. Canada
6.7%
1.12
11.2%
1.43
9.7%
a/ u.s. cost of service is the 20-year average in 1975
dollars. Canadian cost of service is for 1985, in nomi-
nal dollars.
b/ Including the $200 socioeconomic payment recommended
by the NEB.
166
The Agreement on Principles contemplates that a higher
capacity syste~/ will be constructed from Whitehorse to
the James River. If Canada does not construct the Dempster
Line, the United States would bear the full additional cost
of the higher capacity system. The cost of service data
contained in this analysis is based upon a 48-inch, 1680 psi
system from Whitehorse to James River. The 1680 psi system
is slightly more efficient in the 3.6 bcfd range than the
54-inch, 1120 psi system. Thus, if the 54-inch system
ultimately is installed, the u.s. cost of service would be
higher by about 1 percent in all cases except where Canada
does not construct the Dempster Line.~/
If a 1680 system is installed and Canada does not build
the Dempster Line, the 20-year average U.S cost of service
would be about $1.00. The system would have lower fuel and
operating expenses than a 1260 system but the savings would
not be quite sufficient to offset carrying charges on the
increased capital outlays. On the other hand, the·system
~/ Either a 48-inch, 1680 psi or a 54-inch, 1120 psi are
the most likely alternatives. The selection will be
determined after a joint testing program is completed.
21/ At 2.4 bcfd, the 54-inch, 1120 psi system would be
slightly more economically efficient. It has a lower
initial capital cost.
167
does provide a large amount of inexpensive expansibility that
would be used in the event significant new finds of natural
gas are made in Alaska.
If Canada builds the Dempster Line and deliverability
from the Mackenzie Delta is 1.2 bcfd, the cost of service
will vary with the level of cost overruns on the mainline
system in Canada and on the Dawson Spur. From a 0 to 35
percent cost overrun, the u.s. would pay 100 percent of the
Whitehorse to Dawson section. At the expected 40 percent
case, the U.S. would pay 83 1/3 percent or the ratio of u.s.
to joint volumes at Whitehorse, whichever is higher. At
45 percent and over the u.s. would pay e6 2/3 percent, or
the ratio of U.S. to joint volumes at Whitehorse, whichever
is higher.
In the cost overrun range of 35 to 45 percent, the
u.g. share would vary linearly from 100 percent to 66 2/3
/
percent, unless the actual volumes of U.S. gas in the line
commit the u.s. to provide a greater share.
In the lower cost overrun case of 35 percent or below,
under which the u.s. would be required to pay the entire
cost of the Dawson spur, the cost of service reduction from
such overrun savings on the main line would more than offset
, 1
168
any increase in cost of service resulting from increasing
i to 100 percent the u.s. share of the Dawson to Whitehorse
! '
segment. For example, with an overrun of 25 percent in
Canada, the u.s. pays 100 percent. In this example, the
average u.s. cost of service over a twenty year period would
be approximately $1.00 per me£ (1975 dollars), or 4 cents
less than the expected overrun case of 40 percent under
which the u.s. would pay only 83 1/3 percent of the Dawson
spur instead of the 100 percent the u.s. would pay in the
25 percent overrun case.
The agreement also imposes a ceiling on u.s. liability
for the Dawson spur of 35 percent above filed costs. The
Canadians, in turn, can credit all the cost overrun savings
they achieve on the main line system carrying just Canadian
gas, and 2/3's (or relative volumes) of such savings on the
shared system, against their cost overruns on the Dawson to
Whitehorse section. Finally, the u.s. share of the Dawson
spur cost of service can never be less than the u.s. percent-
age of actual volumes at Whitehorse, multiplied by the actual
costs of the Dawson spur, notwithstanding the Dawson spur
ceiling and the overrun formula. This last condition is only
relevant in the case where substantial overruns in excess of
50 percent are experienced on the entire system.
169
This agreement creates new incentives -on a portion of
the project within Canada's jurisdiction and not otherwise
subject to our control -which could significantly lower the
cost of service to the U.S. and at the same time enhance the
project's financeability.
The application of these principles in varying factual
situations is illustrated by the following table.
Main Line
Cost
Overrun
1. 25%
2 0 30%
3. 30%
4 0 30%
50 35%
6 0 40%
7 0 40%
8 0 45%
9 0 45%
10 0 50%
11. 50%
Dawson Spur
Cost
Overrun
25%
30%
50%
100%
35%
35%
40%
35%
45%
50%
100%
u.s.
Base/ co#
.9556
.9679
.9679
.9679
.9822
.9927
.9927
1.0047
1.0047
1.0130
1.0130
Dawson Spur
cos
u.s.
.0567
.0601
.0717
.0692
.0606
.0505
.0505
.0404
.0436
0 048 0
.0582
Total
u.s.
cos
1. 0122
1.0280
1. 0396
1.0371
1.0478
1.0432
1.0432
1.0451
1.0483
1.0610
1.0712
~/Assumes volumes of 2.4 bcfd from Prudhoe Bay and 1.2 bcfd
from the Mackenzie Delta.
246·448 0 .. 77 .. 13
170
Lines 1 and 2 represent 25 percent and 30 percent cost
overrun cases for both the main line and the Dawson Spur.
Under the Agreement, the u.s. would pay 100 percent of the
Dawson spur cost of service.
Line 3 provides an example of the crediting mechanism
between the main line and the Dawson spur. The 30 percent
cost overrun would result in a capital savings of about $245
million below the 35 percent cost overrun. Assuming that
u.s. and Canadian volumes are 2.4 bcfd and 1.2 bcfd, respec-
tively, and all of the cost reduction is on the main line
south of Whitehorse, Canada would have a credit of $163
million to apply to the cost of the Dawson Spur. A 50
percent cost overrun on the Dawson spur would be only $81
million greater than a 35 percent cost overrun. Thus,
Canada would have a sufficient credit to hold the u.s.
share to 100 percent.
The case in Line 4 assumes a 100 percent cost overrun on
the Dawson spur.~/ The Canadian credit here also would be
$163 million. The Dawson Spur (DS) adjustment is determined
by the following formula:
~/ This assumes a very unlikely occurrence in light of
the cost of the main line.
171
1.35 Filed DS Cost (Base)
Actual DS Cost minus Credit
Applied to this case, the formula is:
733 = .7959 x DSCOS(.0869) = 1084 -163
for the Dawson Spur cost of service.
.0692
Note that the u.s. contribution to the Dawson Spur is
slightly less in this 100 percent Dawson Spur overrun case
than in the 50 percent overrun case. Under the agreement,
the u.s. share of the Dawson spur cost of service decreases
from 100 percent to 66 2/3 percent in this instance depend-
ing on the over~un level of the Dawson Spur. This increase
in capital costs of the Dawson spur above a 35 percent over-
run level has a greater impact under the formula in reducing
U.S. cost of service share than it has in increasing the
full Dawson Spur cost of service. This is so because full
cost of service contains fixed costs that do not vary with
capital cost overruns (e.g., operating and maintenance
expenses). The greater the percentage of fixed costs, the
less cost the overall cost of service will increase because
of a given addition to capital costs.
While this precise effect (i.e., reduction in u.s.
share where cost overruns are higher) would not obtain if
the system was more capital intensive, e.g., a 36-inch or
172
42-inch pipe was installed, the general direction would be
the same. Cost overruns on the Dawson Spur will not have
a significant impact on u.s. cost of service in any case
where the 66 2/3 percent floor is not reached.
The case in Line 5 is the "base" case. There are no
credits available from main line construction. The Dawson
Spur overrun is 35 percent. The U.S. would pay 100 percent
of the Dawson Spur.
In the example on Line 6, the U.S. share of the Dawson
Spur is at 83 1/3 percent because of the 40 percent overrun
on the main line.
In the case represented by Line 7, the base u.s. share
is 83 1/3 percent, but the Dawson Spur adjustment operates
since Dawson Spur overruns are above 35 percent. The result
is:
733
760 = .9645 X .833 = .8034 X .0629 = $.0505
for the Dawson Spur cost of service, and $1.0432 overall.
In Case 8, the u.s. share of the Dawson Spur has
declined to 66 2/3 percent (or a volumetric share) because
of overruns on the main line.
173
In Cases 9, 10 and 11, the mainline overruns have
caused the u.s. share of the Dawson Spur to decline to
66 2/3 percent. Since the 66 2/3 percent floor has been
reached, the u.s. pays that percent of total Dawson Spur
cost of service, or .667 x .0650 = $.0436 for the Dawson
spur cost of service in the 45 percent case. In the 50
percent case, the Dawson Spur cost of service would be
.667 x .0717 = $.0480. In the 100 percent case, it would
be .667 x .0869 = $.0582.
All of the above capital cost and cost of service data
assume that the input volumes of gas will be 2.4 bcfd for
the u.s. and 1.2 bcfd for Canada. On the basis of present
geological information, 2.4 bcfd from Prudhoe Bay is more
likely than 1.2 bcfd from the Mackenzie Delta. Delivera-
bility from the presently proved reserves in the Mackenzie
Delta more likely would be in the range of .7 to .8 bcfd.
A reduction in Canadian volumes would, of course, substan-
tially increase. the u.s~ share of the system in Canada.
However, it would not materially alter the U.S. cost of ser-
vice. If the joint system was designed for 3.1 to 3.2 bcfd,
the capital costs would be lower by about $100 million,
the u.s. operating expenses would be lower, fuel consump-
tion would be lower in absolute and relative terms, and
174
the delivered volumes would be higher. These cost reduction
factors would offset the increase caused by the larger u.s.
share of the base capital costs of the mainline system. For
example, at 1.2 bcfd from Canada with 1a 40 percent overrun
I
in Canada, the base u.s. cost of serv~ce would be $.9927.
With the system redesigned for .7 bcfd from Canada, the u.s.
cost of service would be $.9950.
The capital cost, operating expenses and delivery
factors operate as well with respect to the cost-sharing on
the Dawson Spur. To illustrate, the estimated overall u.s.
cost of service at 3.6 bcfd (2.4 plus 1.2) in the overrun
case is $1.0432. With 3.1 bcfd (.07 bcfd of Canadian gas)
the u.s. cost of service would be slightly lower, about
$1.035.
Net National Economic Benefit
The net national economic benefit (NNEB) to the United
States of the Alcan project also substantially exceeds that
from the El Paso project. The NNEB measures the desirability
of a project from the public perspective. The NNEB of a
project is the present value of the benefits derived less
the present value of the resources employed in undertaking
the project. The benefit is measured by the value of energy
175
delivered to the lower-48 states. A value of $2.62 per
mmbtu for natural gas in 1975 dollars was used throughout
the FPC hearings and is based upon a study done for the
oepartment of the Interior that was market oriented rather
than resource oriented. This value also formed the basis of
the NNEB calculation contained in the National Economic
Impact Task Force Report of July 1977.
To ascertain the reasonableness of this value, the
resource cost of the most probable substitute for natural
gas, No. 2 distillate, was determined. Based upon a mid-1977
price of $14.50 per barrel for imported oil and plausible
assumptions regarding producer taxes and. the resource
investment that is required to refine crude to obtain No. 2
distillate, $2.60 per mmbtu is a fair measure of the current
resource cost of this substitute for natural gas.~/
Further, the real value of natural gas is likely to
increase over time as the real cost of imported oil
increases. If the real value of gas increases at a rate
of only 2 percent per year, the value of the gross benefits
23/ The value of gas is undoubtedly higher since the
intrinsic value of gas is greater than that of oil
(clean, efficient, etc.) and a continuation of gas
supply avoids the capital costs of conversion.
176
determined herein would increase approximately 35 percent,
and the NNEB would approximately double.
There are five general categories of resource costs
used in the NNEB calculation: the Prudhoe Bay field costs
of conditioning the gas and using water injection in place
of reinjected gas to pressurize the field; the initial capi-
tal costs of the transportation systems; annual operating
and maintenance costs; the costs of public services used to
support the project (measured in terms of the property taxes
the project will be required to pay); and, in the case of
Alcan, the annual cost of service payments to Canada for
transporting the gas.~/
The components underlying these benefit and cost
factors are displayed in Exhibits 4 and 5, and the NNEB
components are summarized in Exhibit 6 for El Paso and
Alcan under the cost overrun case herein. Alcan's NNEB
exceeds that of El Paso by over $1.1 billion, which is
approximately 25 percent of the El Paso NNEB. Most of that
difference is attributable to the reduced volumes of gas
24/ Fuel costs are not included. The u.s. will supply its
share of fuel used to transport the gas through Canada
and that cost is reflected automatically in the benefit
calculation.
·'"'·~·."·,. .. , ...... -""~"~"~l'~f!!P"'~·1.·¥.WMISWAftf®~#W~,;Q£,t,Q
.. ,
.' ·.·.,
'' :
Exhibit 4
AI. CAN NNF.:tl CQI'tt'IJNENTS
u, S,.
OELIVE~ED FIELD rlf:Lo u. s. u. ··s. u. s. OTHER SM.RE
GAS GATrlERING & UPE.RATION 1!. TrlANSPn~r. WOioii<ING LJPf:.RA T ION R. u. s. . CANAO.IAN
YE•R CTRII.LtONS CONOITlONING MAIN TEr·JA:IiCE F"ACJLITlf:S c•.PITAI. ·MAINTENANCE TAXES COSTS
8TU 1 S) ($MIL I. t 1.1111 ). ($M!ll.l0N) ($MlLLt(lN) (SMILL!O"l) C !&MILL TOtn ( S.MILI. ION) (SMILLION) -------·----------------- -------------------------------·--·---------------~-----------·-------··· 1977 o.o o.o o.o o.o-o.o o.o 0,0 0,0
1978 o.o 0. 0 o.o to.o o.o o.o o.o 0,0
1979 o.o o.o o.o uo.o c.o o.o o.o ·0. 0
1980 o.o 200.0 0. 0 . 21JO,O o.o 0,0 0,0 0. 0.
19i!t o.o 34/J,O o.o !12d.O o.o c.o o.o o.o
1982 o.o 400,0 o.o !tJCI7,0 o.o '!!' o.o o.o o,o
1983 ,: 0. c. soo.o o.o 1259,q 0 •. o o.o o.o o,o
1q84 rnr:;.s o.o ~.o o·. o 16,1J 37.4 13b,IJ 1330,4
1985 936,1 o.o 1\,0 o.o o.o . H,?. 128,7 1239,8·
198b q1LI,7 o.o a.o 0~0 o.o Ill. 2 121.2 117/J,IJ :I-'
1987 q!b,O o.o e.o o.o o.o 113.3 l!IJ. 2 1109,b "-..J
1q8e 915.9 o.o 8,0 o.o o.o tJ'),U 107,6 1051,8 -,.J
1989 9tb,7 o.o 11.0 o.o o.o l.l'f. 7 101,3 1019,4
1990 'Q17.4 o.o 8.0 24.3 o.o 50.1 95,11 992,5
1991 918.0 o.o A,O 18.11 o.o S2.b 79.7 9b7.7
1992 917. b o.o 8,0 17.7 o.o 55.2 73,11 91JI.I,8
19q3 918,3 o.o e.o 14,1 o.o sa.o b8,2 923,11
19911 918,b o.o 8.0 o.o o.o bO,q 63,3 903,5
19qc; q18,9 o.o a.o o.o o.o b3,9 58,!) 88S,o
199b 919.0 o,o 8,0 o.o o.o b7,1 511,0 868,0
199·7 9!9,b o.o 8,0 o.a o.o ·7 0. 5 49,b 852.2
1998 920,0 o.o· e.o o.o o.o 74.0 45,5 837 .b
1999 920,6 o.o R,O (1,0 o.o 77.7 111,'! :825,3
2000 920.5 o.o 8,0 o.o o.o 81.b 37,5 812,b
2001 q2o,s o.o a.o ·o. o o.o 85.7 34. s. 812.8
2002 919.7 o.o 8,0 o.o o.o 89,9 30,o 799,2
200'3 919,4 o.o e.o o.o o.o 9LI,I.I 2b,8 7b7,1
20011 919~0 . 0. 0 8,0 0,0 o.o 99,2 22,8 73b,S
2005 9tq,o o.o a.o 0,0 o.o 104,1 19,0 707,0
200b 9tq,o o.o a.o o.o o.o 109,3 15,2 678.'7
2007 9!9,0 o.o 8,0 o.o o.o 114,8 11.5 b51,b
2008 919,0 o.o 8,0 o.o o.o 120.5 7,7 b25,S
2009 o·. o o.o o.o 0 •. 0 o.o 0,0 o.o o.o
2010 o.o o.o o.o o.o o.o o.o 0,0 o,o
TOTAL. 22998,0 111411,0 200,0 3949,4 lb,ll 1783,7 1544,0 22516,4
Exhibit 5
EL PASO NNFo CO~IPQ~IF.:NTS
u. s. DELIVERED FlfLO FIELn 1), s, U, s. u. s. OT~E~ SH6RE
GAS. GATHfRlNt. & OPEQA TIW4 ll. TlhNSPnRT, W\.I~K PIG O~E:RATinN "' u. s. CAN6Dla\N
YEAR (TRILLIONS CONDITID~IJNG "'A HITfNlllllCE FAC:ILITIES CAPITAL MA!NTEIIii>NCE TAXES COSTS
BTU'S> (!MILLION) C $MIl. l I 0 N ) (ibMILI..ION) ($t-'ILLION) f:tit>1lLLIQN) t$MILLION) ($MILLION)
-------------------------··---------------------------------------------------------·-------···· 1917 . 0,0 o.o 0,0 o·,_o o.o o.o 0,0 o.o 1978 0,0 o.o o.o AO,O o.o o.o 0,0 o.o 197Q 0,0 o.o 0,0 180,0 0,(\ o.o 0,0 0,0
1980 0,0 200,0 0,0 530,0 0,0 0,0 0,0 o.o 1981 0,0 34'1,0 0,0 1275,0 o.o 0,0 0,0 o.o 1982 0,0 400,0 0,0 23 75', 0 OiO ·~ 0. 0 0,0 o.o 1983 o.o soo.o o.o 1880.-0 0,(\ o.o 0,0 o,o
198'1 '144,0 o,o 4,0 48.0. 0 o.o 130.3 !20:,,6 o,o
198'5 888,0 o,o ~.o 0,0 o.o 273,6 270,8 o,o 1-' 1981; 888,0 o.o A,O 0,0 o.o 287,3 260,3 o.o -...J 1'987 888,0 o.o A,O 0,0 1),0 :SO I, 6 24q,8 o,o co 1988 888,0 o.o 8,0 0,0 o.o 3tt>,7 239,3 o,o
19M 888,0 0,0 8,0 0,0 0,0 332.5 228,8 o.o 1990 888,0 o.o e.o 0,0 o.o 34q 1 2· 218,3 o.o 1991 888,0 0,1) 8,0 0,0 1),0 3fl6,6 207,8 o,o
1992 888,0 o.o e.o 0,0 o.o 384,9 1q7,2 o.o
1993 88 8. 0 . o.o 8,0 0,0 o.o liOU,2 186,7 0,0
199'1 888,0 o.o 8,0 0,0 0,0 '124,4 176,2 o,o
1995 88A,O o.o e,o 0,0 o.o LILI5,6 165,7 o,o
199& ~88,0 o.o 8,0 0,0 0,0 467,'1 155,2 o.o
1997 888,0 o.o 8,0 0,0 o.o UQ!,3 1114,7 0,0
1998 888,0 0,1) 8,0 o.o o.o 515,8 134,1 o.o
1999 888,0 o.o 8,0 0,0 o.o 541,7 123,6 0,0
2000 888,0 o,o 8,0 0,0 o.o 568,7 11 3. 1 o.o
2001 888,0 o.o a.o 0,0 0,0 597.2 102,6 o.o 2002 888,0 o.o 8,0 0~0 0,0 627,0 92,1 0,0 2003 888,0 o.o 8,0 0,0 0,0 658,'1 81,6 o,o
20011 888,0 o.o 8. 0. 0,0 0,0 691,3 71,1 o,o
200'5 888,0 o,o 8,0 0,0 o.o 725,9 60,5 o.o 2006 888,0 o.o 8,0 0,0 o.o 762.2 50,0 . 0. 0
2007 888,0 o.o 8,0 0,0 o.o 800,3 39,5 o,o
2008 888,0 0,0 e.o 0,0 o.o 8110,3 29,0 o.o 2009 1111'1,0 o.o 4,0 0,0 o,o 11111,2 9,i o.o
2010 o.o o.o o.o 0,0 o.o o.o 0,0 o,o
TOTAL 22200,0 111114,0 200,0 6800,0 o.o 12746,2 3732,8 o.o
179
EXHIBIT 6 -NNEB COMPARISON
( $ Billions 1975)
El Paso~/ Alcana/
Value of Gas $10.849 $11.791
Less:
Field Capital Costs • 8 73 • 8 73
Transport Facilities 4 .o 74 2.334
u.s. Working Capital 0 .008
u.s. 0 & M (field and system) • 8 20 .157
u.s. Other Taxes .456 .222
Canadian Cost of
Service 0 2.431
NNEB $ 4. 6 26 $ 5.766
~/ Based upon 2.4 bcfd input at 1137.8 Btu/cf.
180
that El Paso would deliver because of its high fuel
consumption. The real resource costs associated with the
transportation are nearly equal, with the higher sum of the
Alcan facilities, plus Canadian cost of service for Alcan,
being offset by El Paso's large operating and maintenance
expenditures.
While both projects exhibit the ability to absorb
substantial cost overruns without becoming uneconomic,
Alcan's ability is greater than that of El Paso. Assuming
that the elasticity of cost of service with respect to
direct cost overruns is about 0.8, Alcan's direct costs
could increase almost 124 percent over the cost overrun case
before it would become socially uneconomic; the comparable
figure for El Paso is 114 percent.
In conclusion, the economic considerations over-
whelmingly favor the Alcan overland pipeline measured
against the El Paso LNG transportation system. The cost of
service will be significantly less; the net national eco-
nomic benefits will be significantly higher; the amount of
energy delivered will be significantly higher; and the
ability to absorb cost overruns is greater.
1
181
CHAPTER V -SAFETY, RELIABILITY AND EXPANSIBILITY
Considerations of safety, reliability and expansi-
bility favor the Alcan overland pipeline system in com-
parison to the LNG system proposed by El Paso.
The safety record for LNG storage and transportation
has been excellent during the past quarter of a century.
Nevertheless, LNG facilities present marginally higher
risks of a major accident than overland pipelines. An
LNG project requires a careful approach to facility siting.
The United States may need to rely more upon LNG in the
future. However, the use of LNG should be chosen where
there is no economically and environmentally feasible
alternative.
The greater reliability of the Alcan system should be
emphasized. The El Paso system is a multiple-mode system
that would be sized and operated at very close capacity and
operational tolerances, a factor that tends to decrease
reliability. Further, the El Paso pipeline would cross
several major geologic faults--the Alaska LNG facility and
the California regasification facility would be sited in
some of the most seismically active areas in the world.
Although the faciliites can be designed and constructed
to survive structurally a major seismic event, there
182
inevitably would be interruption in service during repair.
By contrast, the seismic risk to the Alcan system is very
small. It will approach relatively few seismically active
areas and will cross no known active faults in Alaska.
Finally, expansibility of capacity also weighs in
favor of the Alcan system. The capacity of a properly
designed all-pipeline system can be expanded incrementally
up to a point simply by the addition of compression at
relatively low capital cost. The capacity of an LNG system,
on the other hand, must be expanded in large increments
that may be excessive in relation to the actual need.
The specific safety and design areas which have been
addressed by u.s. and Canadian authorities and to which
Alcan must now properly respond as the project moves
forward include:
Safety of Design and Operation
Potential for Service Interruption --Reliability
Efficiency of Design and Capability of Expansio~
Monitoring Construction and Joint U.S./Canadian
Coordination
183
These safety and design issues, involving new tech-
nologies for the Alaska gas system, were reviewed by
an Interagency Task Force under the lead of the Department
of Transportation (DOT), with participation by the Depart-
ments of the Interior and Commerce, the Federal Energy
Administration, the Energy Research and Development
·Administration, and the Environmental Protection Agency.
Safety of Design and Operation
The technical problems in operating a pipeline at
high pressures and the transportation of natural gas at
chilled temperatures have been carefully considered by
government and industry officials. Specific issues
include:
high strength pipe metallurgy,
-the possibility of frost heave effects on the
pipeline in permafrost soils,
-the choice of pressure testing methods, and
-development of advanced valve designs.
Final resolution of these technical issues will be
need.ed before there can be site specific approvals of
system design and initiation of construction.
184
Pipe Metallurgy. The principal factors that affect
safety of the pipeline system are the type, design, phy-
sical properties, the metallurgy of the pipe used, and
quality control for the pipe.
Alcan initially proposed to operate its 48-inch system
at 1260 psig pressure with the pipeline buried and the gas
chilled below 32°F before shipment through permafrost
regions. It is probable that Alcan will redesign its system
between Whitehorse, Yukon, and Caroline Junction, Alberta,
to increase capacity and allow for the economical transpor-
tation of Canadian gas from the Mackenzie Delta. The
principal alternatives are a 48-inch, 1680 psi system or a
54-inch, 1120 system. In addition, if a 1680 system is
installed south of Whitehorse, consideration will be given
to installation of a 1680 psi system in Alaska, perhaps with
a pipe diameter less than 48-inch. The higher pressure
system is generally more economically efficient than lower
pressure designs.
To date, the highest pipeline operating pressure has
been approximately 1000 psi. From the evidence submitted
~
at the FPC hearings, the DOT and the Safety and Design Task
Force tentatively have concluded that the higher operating
pressures (1670 to 1680 psi) could be safely achieved with
185
adequately designed pipe. However, further testing and
evaluation will be required. The Agreement on Princi-
ples between the United States and Canada provides for a
jointly conducted testing and evaluation program to deter-
mine which system would offer the highest degree of safety,
reliability and efficiency. Upon completion of the test-
ing program, the respective re9ulatory authorities of each
country will make a final decision as to which type of
system might be installed in each country.
Another issue pertaining to high pressure pipe is
whether special "crack arrestors" will be required to
stop fracture propagation in the event a ·fracture should
occur. The Safety and Design task force concluded that
the fracture toughness properties designed into the pipe
specified by the various operators should be sufficient to
prevent the initiation of a propagating crack even at arctic
temperatures. It therefore concluded that crack arrestors
were merely a precaution to ensure that in the remote chance
a crack were to initiate, any resulting propagation would be
controlled. The task force also reported that with proper
246-448 0 -77 -14
186
design and installation, the arrestors would introduce no
problems of corrosion control or stress concentration.
However, if Alcan uses crack arrestors, the particular
design and installation plans will be reviewed on a site-
specific basis by the DOT to assure that they are consis-
tent with the Federal gas pipeline safety standards.
Alcan plans to use high-strength, grade X-70 pipe.
The grade has been rated acceptable ln the most recent
survey of pipe specifications published by the American
Petroleum Institute (API). However, a reference specifi-
cation for X-70 pipe is not presently incorporated in
the Federal gas pipeline safety regulations. Reports
of operating experience with X-70 pipe and its approval
under liquid pipeline safety standards, as well as in the
standards and regulations of many other countries, make it
probable that the DOT will incorporate the API X-70 pipe
specifications into its regulations before commencement of
'i the construction on the Alaska portion of the system. The
economic benefits from the use of X-70 pipe provide an
incentive to incorporate it into the design of the Alaska
gas system.
187
Potential for "Frost Heave." The problem of frost
heave (i.e., the upward movement of a buried pipeline
resulting from freezing and thawing conditions), which
pipelines can experience when buried in areas of discon-
tinuous permafrost, must be adapted for the particular
conditions encountered on a site-specific basis. Depending
upon soil characteristics, some discontinuous permafrost
areas are more subject to frost heave than others. Given
the time to finalize the route survey, field testing to
determine soil conditions, and engineering design capabil-
ity, Alcan should be able to solve the frost heave problem
satisfactorily although costs for doing so may vary from
initial estimates.
Alcan has stated that it expects to encounter 80 miles
of frost-susceptible soil along its right-of-way. It plans
to use a passive system which consists of loose fitting
insulation and select backfill. This will be supplemented
by cycling flowing gas temperatures, thermistor monitoring
of the pipeline to detect frost heave problems for correc-
tive action, and periodic patrol and visual inspection
based upon accessibility of its right-of-way.
The DOT will review the frost heave site-specific design
approach for the Alaska section to assure that the final
188
design will provide the required pipe support, and meet the
other pertinent provisions of the Federal gas pipeline safety
standards in 49 CFR Part 192. Because frost heave problems
occur over a period of time, monitoring of the design, con-
struction, and operation of the Alaska gas transportation
system by Alcan and government agencies should detect problem
areas early and provide the high level of safety and reliabi-
lity required.
Pressure Testing. Once the pipeline is installed,
Federal pipeline safety standards require that pipeline
systems be pressure tested before initial operation. Alcan
proposes to use a hydrostatic test and preheat the test
water to prevent its freezing in the line where buried in
permafrost areas. This procedure proved workable on the
Alyeska crude oil pipeline. However, the Alyeska pipeline
was buried only in areas of thaw-stable material and was
designed, from a thermal expansion standpoint, to carry
warm oil. The Alcan pipeline, on the other hand, will be
buried in varied types of soil conditions and de~igned to
carry chilled gas.
The Task Force on Safety and Design concluded that "the
proposed Alcan procedure for hydrostatic testing with heated
water would not be appropriate in sections traversing perma-
frost or discontinuous permafrost unless stringent control
189
of test water temperatures is maintained and adequate
temperature sensing devices are installed adjacent to the
buried pipe." That report also concluded that an approach
similar to the one proposed by Arctic Gas, i.e., a hydro-
static test using a water/methanol freeze-depressant
solution at stress levels approaching 100 percent specified
minimum-yield strength, provided the best assurance that any
defects present in the pipe will be disclosed prior to
placing the line in service.
Extensive studies were performed by Arctic Gas on the
procedures to be used, the manpower to be expended, and
the equipment and costs associated with both air and
methanol/water testing. The proposed Arctic Gas test plan
included procedures for disposing of the methanol after
testing and safeguards to be used in the event of a pipe-
line test failure. Reports to the DOT confirm that there
are very few test failures on newly constructed gas pipe-
lines. In the remote event of failure, environmental
concerns can be alleviated through development of a spill
containment contingency plan and proper method of methanol
disposal. Alcan should utilize hydrostatic testing research
data developed by Arctic Gas; such information should be
made available to Alcan.
190
Valve Design and Performance. If Alcan constructed
a 1260 psi system, it would face few problems with regard
to design of valves for chilled service. However, if
Alcan increases pressure to 1680 psi, either for the
Alaska segment of its line alone or for sections in Canada,
additional valve design evaluation will be necessary.
Valves currently installed in operating pipelines have not
had service experience at those higher pressures with
chilled gas temperature conditions even though some devel-
opment and test work has been done at the ranges of pressure
which were anticipated for the Arctic Gas and El Paso sys-
terns. If higher-pressure service is used, valving plans
will be reviewed by DOT on a site-specific basis to assure
that the designs are consistent with Federal gas pipeline
safety standards.
Correlation Between Canadian and U.S. Gas Pipeline
Safety Standards. To assure the overall integrity
of the Alaska natural gas transportation system and the
continued reliability of service to the u.s., it will be
necessary to coordinate specific elements of the Canadian
and U.S. gas pipeline safety standards. A review is under-
way to identify and correlate the various specific features
of the Canadian and u.s. standards, and with effective
technical liaison between the u.s. and Canadian regulatory
191
agencies, these slightly differing standards should not
create any problems. It will be necessary for those
regulatory officials monitoring construction of the u.s.
pipeline system to be aware of and resolve differences in
design, particularly as they relate to acceptable levels
of safety and reliability of service.
Design and Active Seismic Areas. The proposed Alcan
route encounters relatively few active seismic areas and
the risk of damage to the Alcan system from earthquake
activity is small. Alcan crosses no known active faults
in Alaska. The Denali fault is approximately 30 miles
away at its closest point. In Canada, Alcan traverses the
Shakwab fault which is large but not likely to be active.
Alcan plans to provide for earthquake prote9tion by wide-
shallow ditch design and granular backfill to provide
support for the pipe to an 8.5 Richter scale, and to
install valves at either ·side of the fault.
Compressor stations for the Alcan system will incor-
porate_ structural design for anticipated earthquake stres-
ses and utilize heavier wall pipe where appropriate.
Potential for Service Interruption --Reliability
Accessibility of the Alcan route by the Alyeska haul
road and existing highways in Alaska and in Canada will
192
facilitate proper maintenance of the pipeline system. In
certain tundra areas where conflicts may arise between
requirements of the Federal gas pipeline safety standards
and the environmental protection rules of Federal or State
agencies, trade-offs between environmental considerations
and pipeline safety and reliability will need to be care-
fully weighed in specific instances.
The FPC concluded earlier that each of the three sys-
tems originally proposed could be operated with a reliabil-
ity acceptable to the gas consumers of the United States.
The record of pipelines generally shows that their contin-
uity of service is by far the best of any mode of transpor-
tation in the United States, and Canadian experience,
including experience with the pipelines, in the far north is
comparable.
The FPC and the Task Force on Safety and Design also
concluded that repair of a pipeline outage on any of the
systems as originally proposed would normally be very rapid.
Again, the accessibility of the Alcan route to haul roads,
work pads, and existing highways would facilitate rapid
repair. Special techniques and equipment will be required
for repairs in remote tundra areas during the period of
summer thaws. Techniques originally planned to be used by
Arctic Gas for such repair should be considered by Alcan
in its maintenance and repair plans.
193
Efficiency of Design and Capability of Expansion
It was also suggested in the safety and design report
that for economic reasons, Alcan should consider increasing
the operating pressure and wall thickness of its 48-inch
diameter pipeline in order to allow for more efficient
increases in throughput rate for additional reserves which
might be committed to the system from either Alaska or
Canadian sources.
These physical factors determine the capacity of a
gas pipeline:
diameter of pipe,
operating pressure,
the rate (velocity) at which gas moves through the
line.
For any new system the first two items are selected in
relation to the expected "throughput" of the gas and are
then fixed. Any subsequent increase in the capacity of
that pipe requires movement of gas at a higher rate. The
velocity of gas is increased by adding compression to the
pipeline. Compression requires fuel essentially in propor-
tion to the horsepower added. Thus, as more throughput is
'!!
194
required in an existing pipeline, horse power (capital cost)
and fuel use (operating cost) will increase.~/
The introduction of the additional gas also allows the
division of fixed costs by more units of throughput. If the
line is operating at less than optimal capacity, the decline
in unit fixed costs will be greater than the increase in
unit costs for additional horsepower and fuel, and the
overall unit cost will decrease. On the other hand, if the
pipeline is forced beyond its optimal capacity by addition
of yet more compression, the reverse is true: horsepower
and fuel increases faster than the declining unit fixed
costs, resulting in an increase in overall unit cost of
service. Exhibit 4 illustrates the problem.
Overall, considering the arctic construction, inflation-
ary impacts, and environmental impacts, the ultimate cost to
consumers of providing capacity for increased gas throughput
would be much lower if the capacity is provided initially by
increasing the diameter or working pressure of the pipe,
than if it is provided later by adding compressor horsepower
or looping the pipeline.
~/ Horsepower and fuel requirements increase roughly as the
the difference between the squares of the relative
throughputs. Doubling the throughput would require about
4 times as much fuel.
.·
5
41
3
2
1
y\
.195
RELATIVE COST vs RELATIVE RATE
DIFFERENT DESIGN CAPACITY
~A .. -Increased Costs 1:'' (Oversizing)
' •f\ .
'~
'· '~
'A c-Total Costs
·~ ...! ..... ,
·~--
·~ ~~
·~~
··~
• • • • • ' .. .. . .. • • .I
Increased Costs •• •••
_,.... (Undersizing) .·'it:___
~-...... ···~·Y': ... ·_--.. ~ .. ....... . .. ........ · ..•. _ ................... , ;/
'-''• ... ··-· ... ~'-' .. .>"" ..._._ -..... .........,. -.__.
/ •
. •• .
..... .~ .. _..,.,.,..
. ~·-.. .....,...,-.----. .. . . ___...
0 _...... ••• --::;::::...... -
Fuel Costs and
Operating Expenses
1 2 3 4 5
THROUGHPUT RATE (RELATIVE)
.................. " Total Costs -Design Rate 3
--___.. ----.. Total Costs/Mcf -Design Rate 4
--........ ...... -...... Fuel Costs & Operating Expenses -Design Rate 3
--._..... . .__.... ____ Fuel Costs & Operating Expenses -pesign Rate 4
196
The routing of the Alcan system provides future
access to reserves which might be discovered in the
Beaufort Sea or eleswhere on the North Slope. Alcan
similarly could transport gas from other areas of Alaska
or even from the Gulf of Alaska by means of somewhat
longer supply laterals. Further, the Agreement with Canada
provides for the use by Canada of the Alcan main line at
a throughput up to 1.2 bcfd. Therefore, redesign of the
system to enable inexpensive expansibility up to 3.9 to
4.0 bcfd south of Whitehorse, Yukon Territory, is essential.
197
CHAPTER VI -ORGANIZATION OF FEDERAL INVOLVEMENT AFTER SYSTEM
SELECTION
Introduction
A frequently cited problem with construction of the
Alyeska pipeline was the multitude of Federal Government
agencies that severally prescribed and enforced terms and
conditions with only minimal coordination of purpose or
effort. Uncoordinated government actions can cause need-
less construction delays and cost increases. Coordinated
Federal oversight of project management and construction
would:
-provide coherent and uniform rules; and make them
clear to the applicant;
-provide consistent enforcement of the rules;
-avoid rules and bureaucractic procedures that are
merely cumulative and would be sources of delay.
ANGTA provides for creation of a new Federal officer,
the Federal Inspector for construction of an Alaska natural
gas transportation system. Under Section 7(a)(5) of ANGTA,
this Federal Inspector shall-
(A) establish a joint surveillance and monitoring
agreement, approved by the President, with the
State of Alaska similar to that in effect during
construction of the trans-Alaska oil pipeline to
monitor the construction of the approved transpor-
tation system within the State of Alaska;
198
(B) monitor compliance with applicable laws and the
terms and conditions of any applicable certificate,
rights-of-way, permit, lease, or other authorization
issued or granted;
(C) monitor actions taken to assure timely completion
of construction schedules and the achievement of
quality of construction, cost control, safety,
and environmental protection objectives and the
results obtained therefrom;
(D) have the power to complete, by subpoena if necessary,
submission of such information as he deems necessary
to carry out his responsibilities; and
(E) keep ~he President and the Congress currently
informed on any significant departures from
compliance and issue quarterly reports to the
President and the Congress concerning existing or
potential failures to meet construction schedules
or other factors which may delay the construction
and initial operation of the system and the extent
to which quality of construction, cost control,
safety and environmental protection objectives
have been achieved.
While the Federal Inspector can "monitor" the enforcement
and compliance actions of the various Federal agencies, he
does not have any specffic enforcement powers. A coordi-
nated regulatory approach will be elusive unless the Federal
Inspector has the necessary supervisory authority at the
field level over enforcement of terms and conditions to
ensure that coordination occurs.
Therefore, as set forth in the Presidential decision,
the President will submit to Congress upon approval of the
199
Decision a limited executive reorganization plan for the
very specific purpose of transferring to the Federal
Inspector field-level supervisory authority over the
enforcement of stipulations and terms and conditions from
those Federal agencies having statutory responsibilities
over various aspects of an Alaska natural gas transportation
system. This coordinated field level authority over com-
pliance and enforcement activities of the respective Federal
agencies is essential to avoid project delays and minimize
cost overruns.
However, the Federal Inspector will be subject to the
ultimate policy direction and supervision of an Executive
Policy Board, made up of the Secretaries of Interior, Energy,
and Transportation, the Administrator of the Environmental
Protection Agency and the Chief of the Army Corps of Engi-
neers. Furthermore, all Federal agencies will retain their
existing authorities, pursuant to section 9(a) of ANGTA, to
issue original certificates, permits, rights-of-way and
other authorizations, and to prescribe any appropriate
stipulations and terms and conditions to such authorizations
that are permissible under existing law. Finally, the
Agency Authorized Officers, who will exercise the delegated
200
authorities of their respective agencies, will directly
enforce the stipulations and terms and conditions--subject
to the field-level supervisory direction of the ~ederal
Inspector.
With these organizational proposals, and with the
general terms and conditions set forth in the Decision, the
Federal Government will have an expanded role in the
oversight of project management and construction. The
oversight authority conferred by the terms and conditions
set forth in the Decision will be far more comprehensive
than the limited Federal monitoring effort over Alyeska's
project management. If these general terms and conditions
are effectively enforced, most of the management abuses
associated with the Alyeska project should not recur. The
general terms and conditions, however, do not hold the
successful applicant to any specific management approach,
but merely provide certain minimum standards for cost and
quality control and timely completion of construction,
which reflect the collective experience and knowledge
gaineq by the various Federal agencies from involvement
with the Alyeska project.
,
201
The Organization of Federal Involvement with the
Alcan Project
As noted above, the Federal Inspector will have the
field-level supervisory authority over the Agency Authorized
Officers who will be assigned on a full-time basis to
administer the authorities of their respective agencies
over various aspects of the Alcan project. The Federal
Inspector and the Agency Authorized Officers will consti-
tute an Alaskan Natural Gas Pipeline Office.~/ This
Office will consist of administrative and field inspection
and monitoring staff working under the direction of the
Federal Inspector. The Executive Policy Board will
approve the level of staff support, and determine Agency
Authorized Officer participation in providing such staff
support to the Federal Inspector.
Essentially, the organization of Federal involvement
with the Alcan project has three elements:
1. The Federal Inspector. The Federal Inspector
will be a Presidential appointee confirmed by the
~/ The Office should be located in Alaska, at least for
·the construction phase of the project, and later in
reduced form for the operational phase. It is probable
that preconstruction planning and design will necessi-
tate an Alaska-based pipeline office (e.g., to coordinate
site-specific terms and conditions) even-though the
size of the Washington, D.C.-based staff will be
larger in the earlier phases of the project.
246-448 0-77 -15
202
Senate and is an officer independent of other
existing Federal agencies. In addition to his
statutory duties under section 7(a)(S), the
Federal Inspector will have supervisory authority
at the field level over enforcement of terms and
conditions, and will otherwise coordinate Federal
involvement with the pipeline operator during the
design and construction phases of the project. The
Federal Inspector is designed to be the principal
point of contact with the pipeline owners, the con-
tractors, State agencies, and Canadian entities on
matters pertaining to Federal oversight of the pro-
ject. As chairman of the Execut"ive Policy Board,
he should be the executor of its policy decisions.
The Federal Inspector also has the power to compel
information by subpoena and to issue quarterly
reports to the President and Congress concerning
existing or potential failures to meet construction
schedules and other matters.
2. The Executive Policy Board. Presidential super-
vision over the Federal Inspector will be delegated
to an Executive Policy Board. The Board would be
made up of the Secretaries of Interior, Energy,
Transportation, the Administrator of the Environmental
l
203
Protection Agency, and the Chief of the Army Corps
of Engineers, or their Deputies (or senior officers
who have been delegated authority over gas pipeline
matters). The Federal Inspector shall serve as
the non-voting chairman of the Board.
The Board will provide policy guidance through
the Federal Inspector to the Agency Authorized
Officers and will be paramount in all policy mat-
ters. It will also act as an appellate body to
resolve any differences between the agencies and
the Federal Inspector, including differences that
may arise when the Federal Inspector overrules an
enforcement action of an Agency Authorized Officer.
In such cases, the Board shall expedit.iously resolve
any appeal within a specified time period. Other-
wise, the Board shall confine itself to policy-
making matters, and the Federal Inspector will be
the conduit of the Board in carrying out policy.
3. The Agency Authorized Officers. These officers
will represent and exercise the internally dele-
gated authorities of their respective agencies
in matters pertaining to the project. Although
these authorities can be exercised only by the
204
respective Agency Authorized Officers, they will
be subject to supervision of the Federal Inspector
at the field level, and receive policy direction
from the Executive Policy Board through the
Federal Inspector on enforcement matters.
The Agency Authorized Officers should have no other
administrative duties that would require less than
full attention to the project, unless the Executive
Policy Board consents to waive this requirement
in a particular case. It is hoped that the use of
Agency Authorized Officers to represent the various
agencies will minimize coordination problems between
the project applicant and the Federal Government.
Implementation of Organizational Plan
The proposed transfer of field-level supervisory
authority to the Federal Inspector should be submitted for
approval by Congress in a government reorganization plan,
rather than implemented by executive order. This plan
will propose a limited, single-purpose transfer of field-
level supervisory authority over enforcement of terms and
conditions for the duration of the preconstruction and con-
struction phases of the Alcan project. No other transfer
of existing authority, or transfer of any coordination
function, will be proposed in the reorganization plan.
205
To avoid the possible overlap with Congressional
action on the Presidential decision itself, the reorgan-
ization plan will not be submitted to Congress until that
decision has been approved. Congress would then have 60
legislative days in which to consider the merits of the
plan under the special parliamentary procedures provided
by the Reorganization Act of 1977, 5 USC 901 et seq.
The President can immediately issue an executive
order creating the Executive Policy Board and by his power
pursuant to Section 301 of Title 3, delegate the necessary
authority to the Board to carry out its functions. The
Board can then make certain initial administrative deci-
sions regarding the Office of Federal Inspector--e.g., the
level of staff support for the Federal Inspector, and the
'-possible use of the Army Corps of Engineers for such staff
support. In the interim, the Federal Inspector can imme-
diately exercise his responsibilities under existing ANGTA
authority to "monitor" compliance by Alcan with applicable
laws and authorizations.
Coordination with the States
In addition to the duty of organizing Federal
involvement, the Federal Inspector has the substantial
responsibility under ANGTA to establish a joint surveillance
206
and monitoring agreement with the State of Alaska and other
affected States. The strengthened field level supervisory
authority proposed for the Federal Inspector will be of
great assistance in the performance of this statutory
responsibility.
The Alcan system will pass through hundreds of miles
of land owned by the States, particularly by the State of
Alaska. Officials of the State of Alaska have previously
declared that the State will issue a right-of-way lease to
the gas pipeline for crossing these lands, regardless of
which project is approved, and have indicated that envi-
ronmental terms and conditions will be part of this lease.
The States and the Federal Government share respon-
sibility to ensure that lands, water and wildlife are not
unnecessarily disturbed by the gas pipeline and that where
disturbed, maximum restoration is carried out. The Federal
Inspector and Agency Authorized Officers will therefore
work with the State of Alaska and with other States in a
cooperative fashion both for the protection of the environ-
ment and for the expeditious construction of the pipeline.
The terms and conditions and stipulations which pertain to
State and Federal lands should be as similar as possible.
A reasonable accommodation of State and Federal interests
207
is expested with the Federal Government having primary
responsibility where the pipeline crosses Federal land
and private lands, and with the State Governments having
primary responsibility where the pipeline crosses State
lands. Cooperative agreements based on these principles
have been successful in the recent past, and should be the
point of departure for further strengthening the Federal
and State cooperation during construction of the gas
pipeline.
208
CHAPTER VII -IMPACT ON COMPETITION IN THE NATURAL GAS
INDUSTRY
The antitrust and competitive impact effects of an
Alaskan natural gas system have been thoroughly studied
by the Federal Power Commission and by the Justice
Department under Sections 6 and 19 of the Alaska Natural
Gas Transportation Act of 1976. Under section 19, the
Attorney General prepared and submitted to Congress on
July 14, 1977, a detailed analysis of potential antitrust
issues and problems. Under Section 6, the Attorney General
submitted that same report to the Alaskan Natural Gas Task
Force, along with a commentary on the FPC's findings with
-
respect to competitive impact. In addition, the Justice
Department submitted a letter on August 9, 1977, which
elaborated its views concerning possible participation by
the gas producers in financing the transportation system.
A copy of the letter is appended to the end of of this
Chapter.
Based on these studies, it can be concluded that the
Alcan project will have no harmful effect on regional or
national competition in the natural gas industry, and that
any potential of competitive abuse can be cured by proper
proper federal regulation. In addition, consistent with
209
the Administration's antitrust objectives, producers of
Alaskan gas could participate in financing this expensive
transportation system through guaranteeing some portion of
the project debt.
Gas transmission and distribution industry
The Federal Power Commission and the Justice Department
agreed that certification of a transportation system for
Alaskan gas will not have a significant impact upon compe-
tition in the natural ga~ transportation and distribution
industries.
Based on statistics presented in the Justice
Department's Report to Congress, the American sponsors of
the Alcan project, including PGT, PGE and the Northern
Border companies, transport approximately 40 percent of all
the interstate natural gas shipped in the u.s. However, in
an industry as heavily regulated as natural gas, indices of
concentration tend to overstate the potential for anti-
competitive behavior. In the presence of effective regula-
tion, the actual prospect of anticompetitive behavior ~s
minimized, and there is only a small risk that the Alcan
sponsoring companies could control national or regional gas
markets.
210
Gas producers
Alcan has no oil companies or subsidiaries of oil
companies among its sponsors. This fact in itself sharply
reduces potential antitrust concerns.
Nevertheless, since elsewhere in this Report it is
urged that the gas producers participate in financing
this project, it is necessary to examine the competitive
considerations associated with producer participation. The
Attorney General concluded that "present Federal Power
Commission regulation appears to preclude an opportunity
for competitive abuse by the gas producers." However, the
Department warned that if wellhead prices were decontrolled
or substantially relaxed, some opportunity might arise for
producers, if they owned or controlled the transportation
system, to transfer profits from the regulated transporta-
tion operation to their unregulated upstream production
operations.
The Department of Justice indicated that its concern
about producer ownership or control of the pipeline does
not preclude producer participation in financing the
system. For example, consistent with antitrust objectives,
producers could be involved in guaranteeing a portion of
the project's initial debt or cost overrun debt. To assure
211
antitrust insulation, any producer role in the management
of the transportation system prior to its becoming opera-
tional should be the minimum necessary to protect the
producers' investment interest but in any event should not
permit producers to engage in anticompetitive conduct. In
addition, producer debt guarantees should terminate upon
completion of the project and commencement of the tariff.
Finally, the Federal Power Commission should utilize its
approval power over gas purchase contracts, and more gen-
erally, over project financing plans, to ensure thqt any
conditions producers impose in exchange for debt guaran-
tees do not create situations which might permit abuses of
competition.
Thus, as is urged elsewhere in this report, gas
producers could guarantee portions of the project debt
consistent with this Administration's antitrust objectives.
* * * * * *
Overall, we conclude that the potential for anticom-
petitive abuse by either the gas transmission and distri-,
bution industry or the gas producers (to the extent they
might participate in guaranteeing project debt) is small,
especially under a co~tln~ing system of price regulation.
l
212
Any potential competitive problems can be guarded against
through (l) imposing proper conditions in the license
to construct the transportation system (including the
' nondiscriminatory conditions under section l3(a) of the
!.
Act); (2) monito~ing gas purchase contracts between gas
producers and gas transmission companies; (3) requiring
the disclosure of any collateral agreements between pro-
ducers and transmission companies; (4) requiring govern-
ment scrutiny and approval of any plans for gas realloca-
tion or displacement, and government monitoring of any
industry discussions to derive such plans; and (5) impos-
ing regulatory sanctions in any specific cases of abuse
that may arise.
iSTfl..Nr .. _.:·TOFf.JEY GE:'-JE!l.::\L
ANTITRC.:ST 01\'ISION
EXHIBIT
mrpnrtmrnt of Justice
Washington, D.C. 20530
August 9, 1977
Mr. Leslie J. Goldman
Assistant Administrator
Energy Resources Development
The White·House
Washington, D. C. 20500
Dear Mr. Goldman:
The Attorney General submitted his Reports on the competi-
tive aspects of the Alaska natural gas transportation system
to the President and to the Congress on July 14, 1977. One of
the conclusions drawn in those Reports was that producers of
substantial amounts of natural gas should not be permitted to
own any portion of or participate in any manner in the selected
Alaska natural gas transportation system~
The Department has been requested by the Alaska Natural
Gas Task Force to consider whether this recommendation precludes
the participation of the Alaskan natural gas producers in the
financing of the selected project. We have been requested to
focus our attention on the two routes still under active con-
sideration --the all-pipeline route proposed by Alcan Pipe-
line Company and the pipeline-LNG route proposed by El Paso
Alaska Company.
The Department's recommendation concerning gas producer
ownership and participation was based on the premise that such
ownership or participation under a regime of deregulated or
relaxed wellhead price regulation could lead to the evasion of
effective pipeline regulation and create the opportunity for
the earning of monopoly profits through anticompetitive activity.
Despite the continuation of wellhead price regulation and the
present lack of gas producer ownership or participation in either
the Alcan or El Paso projects, we continue to express our con-
cerns on this important issue, since the long term status of
wellhead price regulation appears uncertain and it is not now
clear who will be the ultimate owners of these projects. How-
ever, our concern about gas producer ownership of the projects
does not mean that there would necessarily be antitrust objec-
tions to participation in project financing on the part of
Alaskan gas producers.
From consultation with other members of the Alaskan
Natural Gas Task Force, we understand that gas producer
participation in the financing of the selected project may
be essential to the success of the project. We believe,
therefore, that consistent with our recommendations producers
could be involved in the guarantee of a portion of the project
debt. We view this guarantee as consistent with our recom-
mendations so long as the gas producers would not be equity
members of the sponsoring consortium, would not have any
voting power, would not have any role in the management or
operations of the transportation system once the system would
become operational and would be obliged to terminate their
guarantor roles upon completion of the project and the tariff's
going into effect. Any role in the management of the trans-
portation system prior to the system becoming operational would
be minimal and consistent with the size of the guarantee and
would not lead to the types of anticompetitive conduct indi-
cated in the Attorney General's Report on the Alaskan natural
gas transportation system and in this letter.
Although not opposed to some financial backstopping under
these conditions, we reiterate our opposition to any type of
financial participation by producers that would enable them
to engage in any form of anticompetitive conduct, such as the
restriction of pipeline throughput, the denial of access to
nonowners, or the resistance or denial of future expansion of
pipeline capacity.
The Department recognizes that if the gas producers were
to act as debt guarantors they would have the right to request
conditions to protect their financial involvement. The Depart-
ment would not oppose conditions to this effect so long as the
conditions would not give rise to the potential for competitive
abuse, including the power to veto procompetitive policies,
referred to above. In this regard, we would expect to urge
the Federal Power Commission, or its successor agency, at the
appropriate time, to utilize its approval power over gas pur-
chase contracts and, more generally, over project financing
plans, to ensure that producer-imposed conditions do not con-
flict with the antitrust objectives outlined in the Attorney
General's Reports.
In addition, as a further safeguard, the Department
suggests that it review all the terms and conditions of
any financial guarantee of a portion of the project debt
negotiated with the Alaskan gas producers. You are assured
2
l
of our willingness to assist in exploring and developing an
appropriate method of gas producer financial participation
in an Alaskan natural gas transportation system that will
not subvert the competitive spirit and intent of the recom-
mendations contained in our Reports.
cc: Roger C. Altman
Sincerely yours,
6':$.er~~
Acting Assistant Attorney General
Antitrust Divi$ion
Assistant Secretary
(Domestic Finance)
Department of the Treasury
washington, D. c. 20220
213
CHAPTER VIII -NATIONAL SECURITY
The Department of Defense (DOD) provided a study on the
national security implications of the proposed Alaska gas
transportation systems both to the Department of Interior,
for its report required by the Trans-Alaska (Oil) Pipeline
Act (P.L. 93-153)11/, and to the Federal Power Commission
(FPC) for its use in evaluating the proposals. The conclu-
sions of the DOD study were that analysis of military
factors alone would not indicate an overriding preference
for one route over another.
A DOD representative testified on the study before the
FPC and was cross-examined by representatives of both El
Paso and Arctic Gas, after direct examination by the FPC's
Administrative Law Judge Litt and a staff attorney. As
reported by Judge Litt:
•••• the evidence shows each system has its
advantages and disadvantages. El Paso's entire
pipeline portion of its system is under u.s. con-
trol, and thus defense strategy may be facilitated.
However, £1 Paso's project tends to concentrate
potential targets, like its liquefaction and regas-
ification plants, whose destruction would present
major, long-term outage problems. Similarly, both
the oil and gas pipelines would be susceptible to
concentrated attack or sabotage on the Yukon River
27/ "Alaska Natural Gas Transportation Systems, A Report to
the Congress Pursuant to P.L. 93-153," U.S. Department
of the Interior, December, 1975.
246-448 0 -77 -16
214
Bridge. Arctic Gas and Alcan, while not concen-
trating vulnerable facilites at single locations
or subjecting their systems to interdiction at sea,
suffer somewhat from the length and location of
their pipelines. Moreover, these projects must
rely on Canadian security force2 8 7or defense over
much of their pipeline lengths.--
The consensus was that each of the proposed systems has
some national security problems which are peculiar to that
system, and that the extremely modest danger due to hostile
acts is of some concern, whether such acts are in wartime or
are acts of sabotage. However, such danger was considered
to to be far less likely to disrupt pipeline operations than
system failures of a purely natural or mechanical nature.
DOD also submitted a report to the President on July 1
commenting on the national security implications of the
FPC's Recommendation to the President.~/ In that report,
DOD reiterated its conclusion that there is no overriding
preference for one route over another when analysis is based
on military factors alone. However, the report pointed out
that dependence on imported oil presents a grave danger to
the national security, and stressed that completion of a
transportation system for delivery of Alaska North Slope
~/ Initial Decision on Proposed Alaska Natural Gas
Transportation Systems, Federal Power Commission,
February 1, 1977, p. 411.
~/ Recommendation to the President, Federal Power Commission,
May 1, 1977.
1
215
natural gas to the contiguous 48-states must be considered
an important national security objective.
With the Alcan joint project with Canada, we believe
Canada will have a major interest in maintaining a uninter-
rupted flow of gas through the pipeline as well as a treaty
obligation to do so under the recently ratified pipeline
treaty. First, the Canadian companies which will be the
owners of the Pipeline in Canada will have a substantial
investment which they will want to have protected. Canadian
investors would be adversely affected by any interruption in
throughput. Second, remote communities in both the Yukon
Territory and the western provinces will be served by the
Pipeline, and any interruption in flow will directly affect
availability of gas to those communities. Finally, a much
larger number of Canadian gas consumers will have a direct
interest in uninterrupted throughput when the Dempster Line
comes into service from the Mackenzie Delta. The Canadians
expect the Dempster Line to be built within several years of
initiation of service on the main line.
I
i
216
Provision for access to the Mackenzie Delta reserves
will have beneficial effects on the national security of
both countries due to decreased dependence on imported oil.
Canadian oil import requirements will be directly reduced
by availability of gas to Canadian consumers. Access to
frontier gas reserves will allow Canada to fulfill its
current gas export commitments, preventing an increased
degree of u.s. oil import dependence due to curtailment of
Canadian gas supplies. Attaching Canadian frontier gas and
providing a stimulus to the Canadian oil and gas producing
industry may ultimately allow some increase in the level of
Canadian gas exports, which would allow even further reduc-
tion in oil import dependence.
217
CHAPTER IX -THE WESTERN LEG
The Authorization of Facilities
There are two basic methods for delivering Alaskan
natural gas to the West Coast. The first method is to
construct a ~Western Leg" to the Alcan system by con-
structing a new pipeline and some looping in Canada from
Caroline Junction to Kingsgate, and by incr~asing the
capacity of the existing Pacific Gas Transmission (PGT)
and Pacific Gas and Electric (PG&E) pipeline, also through
looping. A fully looped system would cost about $770
million (1975 dollars).
The second method is to deliver the gas to the West
by "displacement." The Northern Border section of the
Alcan project to Chicago could be sized to deliver all
Alaska gas to the Midwest. Natural gas from West Texas
and New Mexico that otherwise would flow to the Midwest
could then be diverted to the West Coast through the El
Paso, Transwestern and Northwest pipeline systems.
As set forth in the Presidential Decision,
construction of a Western Leg will be authorized for
direct delivery of Alaskan gas to the west Coast. See
page 20 of the Decision. The Western Leg facilities
proposed by the sponsors in the FPC hearings (i.e.,
! I ,
218
the "1580 Design") will be authorized for "construction
and initial operation." All such facilities will be
entitled to the special mandatory certification and
expediting procedures provided by ANGTA.
However, the facilities proposed in the "1580 Design"
will be subject to a final review and possible adjustment
prior to final certification by the FPC. As in the case
of the Northern Border system, the Secretary of Energy
shall determine at the time of certification whether the
facilities proposed in the "1580 Design" are larger or
smaller than necessary to handle the contracted supplies
of Alaskan gas and Canadian exports and whether "pre-
construction" is necessary to accommodate short-term
excess deliveries of Canadian gas from Alberta. The "1580
Design" facilities would be needed to handle exports from
Canada continuing beyond current contract expiration dates
or if new gas supplies from Alaska are developed. Further-
more, complete delivery by displacement would not be
feasible if Mexican gas becomes available and the 30 inch
gas pipeline that is part of the El Paso system between
/'
Texas and California is converted to an oil pipeline for
use in the Sohio project to transport surplus Alaskan
crude oil.
219
At the time of certification, however, when there
will likely be better information upon which to project
future gas supplies, the "1580 Design" may prove not to be
the appropriate size. Therefore, the Decision does not
make an irrevocable commitment to construct new capacity
that is either too small or too large for the projected
needs. Prior to final certification of a Western Leg, the
Secretary of Energy shall make the precise determination
of facility size and volume to account for material changes
in the facts, if any, since the Presidential decision.
The Western Leg may also be utilized in connection with
short-term deliveries from Canada.
The Western Leg facilities required for direct delivery
will depend on several estimates --the estimated Western
share of Alaskan gas, the estimated volume of Canadian
exports, the amounts of Mexican gas, and the abandonment of
the El Paso gas line in favor of the Sohio oil transport
system. These estimates provide the basis for the decision
to authorize the Western Leg.
The Western Share of Alaskan Gas
The proportion of natural gas that is distributed to
a particular region of the country is ordinarily determined
/
by private contract between the producers, on the one hand,
,
I
I
220
I,
and the purchasers which are usually interstate pipeline
or local distribution companies, on the other.
There is no reason to change these rules for Alaskan
gas. A region of the country that is arbitrarily and
inequitably deprived of its share of Alaskan gas will
have the opportunity to seek relief from the FPC. But,
in the absence of such discrimination, regional distri-
bution of Alaskan gas will be made by the usual means of
private agreement.
Since contracts for the purchase and sale of Alaska
North Slope gas have not yet been executed, it cannot now
be determined .with precision how much of that gas will
eventually be destined for the western states. However, in
the absence of sales contracts, it is reasonable to assume
that 30 percent of the Alaskan gas will be purchased by
parties served by the Western Leg. It is also assumed
that deliveries of Alaskan gas to the lower 48 States will
begin at 2 bcfd in 1983 and increase to about 2.4 bcfd
within a few years. For purposes of this analysis, then,
approximately 700 mmcfd will be considered the maximum
Western share of Alaskan gas through this period.
221
Increased and Accelerated Canadian Exports
In its July 4th decision authorizing the Alcan
proposal, the Canadian National Energy Board (NEB) assured
the continuation of current Canadian supplies to the West.
It rejected outright any suggestion that existing Canadian
agreements to export gas to u.s. markets not be honored.
The NEB also concluded that gas production from the estab-
lished fields of Alberta and British Columbia would exceed
-----------
total demand, including exports, by as much as 400 bcf in
1978, and had created a temporary excess supply.
It proposed that the current Canadian "gas bubble" be
sold to export customers, either as "predeliveries" on
contract volumes that would otherwise be delivered in the
1984-90 period, or under an "ironclad" guarantee that it
would be replaced later by Alaskan gas delieved in Canada.
And finally, in order to assure the delivery of these addi-
tional volumes, it recommended the "preconstruction" of
that portion of the total system that would be located in
southern Canada.lQ/
lQ/ See NEB, Reasons for Decisions: Northern Pipelines,
Vol. 1 pp. 1-69 to 1-83, 1-161, June 1977.
222
The recently signed Agreement on Principles makes it
i even more likely that there will be an increase or acceler-
ation of gas exports from Alberta. By providing Canada
with access to frontier gas reserves in the Mackenzie Delta,
the Alcan proposal stimulates the gas industry in Canada,
and enhances the availability of Canadian supplies for
absolute increases in exports to the United States.
The following sections set forth the analysis of the
capacity available in existing pipeline systems to transport
these additional volumes of Alaskan or Canadian gas directly
or by displacement to the Western States.
Estimated Excess Pipeline Capacity in Existing Systems
Existing Facilities of the Western States
At the present time, the West is provided with most of
its natural gas via interstate pipelines from two major
producing areas --the established gas fields of the south-
western United States, particularly in the Permian and San
Juan Basins, and the Alberta and British Columbia reserves
in Canada. For purposes of this analysis, there are two
principal interstate pipeline systems that should be con-
side red in evaluating. the capacity requirements of Western
States. They are: (1) the Pacific Gas Transmission and
223
Pacific Gas & Electric systems from Kingsgate, B.C. to
Antioch, California, which supply Washington, Oregon and
Idaho markets, as well as California, with Canadian gas, and
(2) the El Paso and Transwestern systems in the Southwest
(referred to collectively hereafter as the Southwest
pipeline system), which deliver gas from the Permian and
San Juan Basins to California, Arizona and New Mexico.
As will be seen below, the full share of Alaskan gas plus
additional Canadian supplies could not be delivered directly
by the PGT and PG&E systems for at least several years and
in the interim might well use up and exceed the capacities
of the El Paso and Transwestern systems that would be used
for displacement.
Direct Delivery
As noted, the Western Leg proposal would amount
principally to looping of the existing pipeline facilities
from Alberta to California. The existing system could not
itself be utilized for direct deliveries of any Alaskan or
additional Canadian gas because it is now being utilized to
capacity and will be until at least later 1985.
There are four principal contracts pursuant to which
Canadian gas is now delivered via the PGT and PG&E systems
224
directly to California, their volumes and the expected
expiration dates are as follows:
Authorized Average
Daily Volume
(in mcfd)
184.9
419.9
205.0
213.0
Expiration
Date
10-31-85
10-31-86
10-31-89
10-31-93
Thus, even if none of these contracts is renewed --the
likelihood of which is reduced as a result of the Agreement
on Principles --direct delivery of substantial volumes in
existing facilities will be impossible for the first three
or four years of an Alaskan gas transportation system.
I
Displacement
Under the "displacement" option, the Western share
of Alaskan gas would not be directly delivered to the West
but moved there indirectly through exchange arrangements
with customers of the Northern Border system.
In order to carry out the displacement scheme, the
capacity of the Northern Border system would have to be such
as to accomplish the direct delivery of both the East's and
West's share of North Slope gas. Full displacement would
225
require either that the proposed 42-inch Northern Border
line south of Empress, Alberta, be fully-powered or that a
48-inch line be constructed over this segment to carry the
same volume of gas, at an additional capital cost but with
the flexibility to increase capacity.
On the surface, displacement appears to be the
most cost effective method. The $770 million (in 1975
dollars) cost of a fully looped WBstern Leg could be
avoided. Increasing the capacity of the Northern Border
system would be much less capital intensive; $258 million
for fully powering the 42-inch Northern Border System, and
$404 million for increasing the pipe diameter to 48-inch.
In either case the cost of service for the displacement
plan would be about $50 million per year less than direct
delivery. However, there are several reasons why displace-
ment is not a desirable long term method in this situation.
(a) Any displacement plan would consume more energy
than direct delivery to the West. The West's Alaska gas
essentially would move east to Chicago and then back west
from the Permian or San Juan basins. By contrast, the'
looping of the PGT and PG&E systems would increase the overall
fuel efficiency for those systems. The difference is about
25 bcf of gas per year, worth $68 million at $2.60 per mmbtu.
246-448 0-77-17
226
(b) Use of displacement to transport all of the West's
Alaskan gas would create capacity constraints on the existing
El Paso and Transwestern lines if:
o one El Paso 30 inch line is converted to an oil line
by the Sohio Project;
o substantial volumes of Mexican gas become available
for transportation to the west Coast;
o there are any advanced or increased deliveries of
Canadian gas to the u.s. which would also have to be
moved West by displacement; and
o the Algeria II LNG project is completed on schedule.
For purposes of analysis, all four of these conditions should
be regarded as reasonably likely to occur.
While the Federal Government has not specifically
endorsed the Sohio Project, it has endorsed generally the
need for the expeditious construction of a pipeline to
transport surplus Alaskan crude oil from the west Coast
to refining markets east of the Rocky Mountains.ll/ Such
a system is needed to provide economic and efficient
transportation of Alaska North Slope oil to markets in the
31/ See Executive Office of the President, The National
Energy Plan, April 29, 1977, p. 55.
1
227
u.s. The conversion of the El Paso pipeline by the Sohio
Project, which is assumed in the present analysis, will
result in a substantial decrease in overall capacity of
the Southwest gas pipeline system.
Recent events have given cause for considerable
optimism about increased exports from Mexico which would
enter through the Southwestern and El Paso system. Petroleos
Mexicanos (Pemex), the government-controlled oil and gas
monopoly in Mexico, has recently expressed its intention
to construct a 48-inch, 850-mile pipeline from the Reforma
fields in Chiapas and Tabasco to the u.s. border near
McAllen, Texas. Pemex expects initially to deliver 1 bcfd
to the u.s. upon completion of the pipeline (probably not
before 1980), and to increase the flow to 2 bcfd by about
1982. On August 3, 1977, Pemex and six u.s. companies
signed a memorandum evidencing their intention to enter
into supplier-purchaser relationships for 6 years, renew-
able for another 6-year term if the purchasers meet the best
tender Pemex may have for the gas at the §_Qq of the first
term.
Notwithstanding several remaining uncertainties, it now
appears likely that the Mexican Project will soon become a
significant new source of gas supply in the Southwest.
228
Between El Paso and Transwestern, the West could reasonably
expect to receive about 220 mmcfd of Mexican gas by 1980 and
a total of 440 mmcfd beginning in 1982.
As discussed above and throughout this Decision and
Report, the Alcan system will offer the potential for
accelerated delivery of Canadian exports under existing
contracts; it will also enhance the overall availability of
Canadian gas for absolute increases in exports. Since these
additional volumes of Canadian gas could not be delivered
directly in the PGT and PG&E systems, as noted above, they
would also have to be displaced through the El Paso and
Southwestern systems for delivery to the West.
Finally, the Algeria II project, El Paso's application
for which is pending before the FPC, would deliver up to
325 mmcfd of regasified LNG from the Texas Gulf Coast to the
Southwest by as early as 1983 and could deliver a total of
650 mmcfd by the following year.
Under these conditions, delivery of Alaskan gas
through the Northern Border system for displacement to the
West would preempt all the excess capacity now available in
the existing Southwest pipeline system from the Permian and
San Juan Basins. Any substantial new supplies from the deep
Permian formations --or increased supplies from coal
gasification projects would compound the problem.
f L
229
Indeed, under optimistic assumptions about future
gas supplies to the West and the existing capacity to
California which would be utilized, there is a serious risk
of a capacity shortage for the years 1983-87. This shortage
can be determined from the data set forth in Exhibit 1.
The Exhibit indicates that without a Western Leg,
a displacement scheme capacity shortage could exist in
1983-85 and would be uncomfortably close in 1986. If
current Canadian supply contracts are renewed, as it
is hoped they will be, a capacity shortage could exist
in 1983 and later years as well.
Finally, it should be noted that full utilization
of the Northern Border system for a displacement scheme
would preclude the ability to expand the Northern Border
system at a low capital cost for additional deliveries
to the East if more Alaska gas becomes available.
The Nation's gas delivery system must have the
overall flexibility to make a rapid and economic response
to many variables -the level of future exports from
Mexico, the level of future exports from Canada, the rate
at which new supplies of Alaskan gas can become available,
and the rate at which LNG and coal gasification projects
are developed. Therefore, to ensure sufficient capacity
Exhibit 1
1981 1982 1983 1984 1985 1986 1987
Ca12acity (mmcfd)
El Paso (after
abandonment) 3,274 3,272 3,274 3,274 3,274 3,274 3,274
Transwestern 785 785 785 785 785 785 785 ---
Total Capacity 4,059 4,059 4,059 4,059 4,059 4,059 4,059
SUJ2f2ly (mmcfd)
Permian Basin 1,551 1,448 1,358 1,271 1,190 1,114 1,042
San Juan Basin 1,253 1,247 1,209 1,176 1,144 1,113 1,083
Canadian Short-
Term (by
displacement) N
w
221 167 112 56 0
Mexican 220 440 440 440 440 440 440
Algeria II LNG 325 650 650 650 650
Coal Gas 70 140 280 ---
Total Supply 3,245 3,302 3,444 . 3,593 3,494 3,457 3,495
Excess Capacity 814 757 615 466 565 602 564
Less Alaskan Gas
by Displacement 522~/ 120~/ 700 700 700
Capacity Excess
(Shortage) 954 757 (85) (234) (135) 80 444
~/ Assumes that existing Canadian contracts will not be renewed.
__J,
231
for future supplies to California and other Western States,
provision should be made for direct delivery of Alaska gas
to the West.
Size and Volume of a western Leg
The approved facilities for the western Leg are
embodied in the so-called "1580 Design." It would require
a 36-inch, 176-mile pipeline, to be constructed by the
Alberta Gas Trunkline Ltd. (AGT), from James River Junction
in Alberta to Coleman on the British Columbia border, where
it would connect with the existing Alberta Natural Gas
Company Ltd. (ANG) line in British Columbia. One-hundred
and five miles of the existing ANG line, from Coleman to
Kingsgate on the u.s. border, would be looped with 36-inch
pipe. In the u.s., 612 miles of the PGT line from the
Canadian border to Malin, Oregon, and 297 miles of the PG&E
line from Malin to Antioch, California, would also be looped
with 36-inch pipe. No new compression would have to be
added to the existing systems.
With this project, 659 mmcfd of North Slope gas could
be delivered directly to the western U.S, which is roughly
the total expected volume of Alaskan gas delivered to the
West. PGT intends to deliver 22 mmcfd of this amount to
Northwest Pipeline Company for distribution in the Pacific
Northwest, and the remainder would be delivered to California,
232
where 200 mmcfd would be distributed by PG&E in the North and
437 mmcfd would be distributed by the Southern California Gas
Company in the South. Any share of Alaskan gas or additional
Canadian gas greater than 659 mmcfd would not require a new
facility but could readily be delivered to the West by dis-
placement. There would easily be sufficient capacity in the
Southwest system to absorb this relatively small volume of
Western gas.
Conclusion
The evidence clearly suggests that the natural gas
pipeline capacity available at present will not be adequate
to accommodate both the Sohio Project and the movement of
Alaskan gas to the West in the mid-1980's and perhaps
beyond. While this conclusion is based on optimistic
supply projections, it nevertheless is a significant prob-
ability on the basis of which a Western Leg Facility should
be planned.
There is some risk in authorizing a Western Leg that
it or other existing pipeline systems to the West could
at some time become somewhat underutilized, perhaps r~sulting
in some increase in per unit costs to gas consumers. But
the consequences of not authorizing a Western Leg are even
greater. Not only could failure to build a Western Leg under
the most reasonable supply projections cause higher direct
233
costs to the consumer, but it could also greatly reduce
the West's flexibility to receive new gas supplies if and
when they develop in the future. Indeed, whether gas
supplies in addition to what are presently projected will
be available from sources like Canada and Mexico may well
be dictated by whether gas pipeline capacity is available
to transport it. If the almost unamimous comments of
their elected officials are any indication, the people of
the West are willing to accept whatever additional cost
may be involved in order to be assured that pipeline
capacity will be adequate to meet all future contingencies.
Prior to final certification of a Western Leg, there
may be better information about potential supplies to
determine whether the proposed "1580 Design" is over-or
under-sized for the anticipated need. Before the issuance
of a final certificate of public convenience and necessity,
the Secretary of Energy will determine the size and volume
of the Western Leg to be certified, as well as review the
need for any pre-building to take direct deliveries for the
west Coast of any short-term increases in Canadians exports
from Alberta. Any deviation from the capacity of the "1580
Design will directly reflect any material changes in gas
I
234
supply or pipeline capacity projections that occur between
now anQ~he date the certificate is issued. The Secretary's
determination shall be communicated to the FPC and shall
be binding on it for purposes of its certification.
235
CHAPTER X -RELATIONSHIP OF THE DECISION TO THE
RECOMMENDATION OF THE FEDERAL POWER COMMISSION
Section 7(b) of ANGTA requires a statement of the
"reasons for any revision, modification of, or substitution
for the Commission (FPC) recommendation."
This Decision is consistent with the FPC recommendation
as set forth in its letter of transmittal dated May 2, 1977:
We recommend that an overland route through Canada
be selected, if such a route is made available by
the Government of Canada on acceptable terms and
conditions.
The condition has been met, and an overland route is selected
by this Decision.
Two FPC Commissioners recommended the Alcan system.
The other two FPC Commissioners recommended the Arctic Gas
sy~tem "conditioned upon timely affirmative decisions by
the Government of Canada to make the route available," but
they said that otherwise Alcan should be approved. There
was a failure of that condition with respect to Arctic Gas
when the Arctic Gas route was rejected by the Canadian
National Energy Board. Therefore, this Decision is in
accordance with the specific system recommendation of
236
all FPC members who participated in the May 2, 1977,
Recommendation to the President.~/
The Federal Power Commission recommended the deferral
for "one to two years the certification of any new facil-
ities for the western leg •••• " This Decision provides for
approval of the western leg facilities subject to the same
condition as other portions of the project. The Secretary
of DOE is authorized to make a determination of the neces-
sary capacity for both the western and eastern legs at
the time of the issuance of the final certificate of public
convenience and necessity. This approval is necessary to
entitle all such facilities to the expeditious authorization
pursuant to Section 9 of ANGTA.
This Decision differs from the Recommendation of the
Federal Power Commission in one other material respect.
The Commission suggested alternative financing plans - a
private risk bearing model and a consumer risk bearing
model. In conjunction with private risk bearing, the FPC
suggested the use of a "formula" price mechanism whereby
~/ The only difference between the Alcan system before the
Federal Power Commission and the Alcan system herein
approved is the contemplated expansion of pipeline capa-
city south of Whitehorse, Yukon, and a pipeline rerouting
near Whitehorse to facilitate any future connection of
Mackenzie Delta Reserves.
237
a city gate market value indicator (MVI) price would be
established. The wellhead price would be the difference
between the transportation cost and the MVI price.
This Decision requires a private assumption of the risk
of noncompletion. However, the determination of the well-
head price should be pursuant to the pricing provisions in
the pending National Energy Act. Those prov.isions, along
with the financing proposals made herein, will ensure an
equitable sharing of project risks and constitute the best
method for securing a private financing of the project.
~
I
238
CHAPTER XI -AGREEMENT WITH CANADA
Issues
There are certain potential risks associated with any
project involving more than one country. These derive from
complications which arise when a large scale construction
project is subject to the jurisdiction of two federal
governments, Canada and the u.s., and the interests of the
two governments are not always identical. The potential
risks involved were explored extensively during the FPC pro-
ceedings on Alaska gas, and further in the Senate hearings
and debates prior to ratification of the Transit Pipeline
Treaty with Canada. These debates served to crystallize the
most important of these issues.
An example of the divergence of interests of the two
countries was the re-routing of the main pipeline through
Dawson which was required by the NEB 1 s July 4th Decision.
That re-routing was designed from the Canadian perspective
to bring a major gas transportation system within reach of
their Mackenzie Delta reserves. From the u.s. perspective,
the re-routing was a costly alternative to accommodate an
uncertain eventuality -construction of the Dempster Line -
which might never occur.
239
During the course of the negotiations, a compromise
was worked out on this point which effectively serves the
interests of both countries. In return for routing the main
line along the original Alcan route, the u.s. agreed to
share the costs of extending the Dempster Highway lateral
from Dawson to Whitehorse. Whitehorse will be the point at
which the lateral pipeline from the Mackenzie Delta gas
fields connects to the main line when and if the lateral is
built.
Virtually all of the other issues which were raised
in the FPC proceedings and the Senate hearings and debates
were the subject of lengthy negotiations with the Canadians.
The discussion which follows covers the issues of primary
Canadian concern in reaching this decision, along with the
resolution of those issues which has been achieved through
the negotiations.
Taxes and Impact Assistance
The first risk witn a trans-Canada system is unantici-
pated costs arising from potential Canadian taxes and impact
assistance. The FPC proceeding considered the risk of
taxes imposed by the Canadian provincial governments, and
it was concluded that Canadian legislation or compacts
would be.necessary to bind the Canadian provinces directly
to the antidiscriminatory tax provisions of the Treaty.
240
The Canadian Government h·as un-dertaken to negotiate
Federal-Provincial agreements with the three western
provinces -British Columbia, Alberta and Saskatchewan -to
assure their implementation of the Treaty. The Federal
Government has obtained public statements from all three
provinces endorsing the principles of the treaty, and those
statements are annexed and made part of the Agreement.
These statements and subsequent Federal -Provincial Agree-
ments, backing up the unequivocal responsibility of the
Canadian Government under the Treaty, will provide adequate
assurance on this point.
The degree of practical protection afforded by the
Treaty was subject to some question in the Yukon Territory,
as there are currently no similar pipelines against which to
measure possible discriminatory treatment. Therefore, ad
valorem (property) taxation in the Yukon was negotiated as
part of the Agreement on Principles. The agreed rate of
property taxation is essentially comparable to that in
Alaska, and will continue for 25 years or until a similar
pipeline is built, at which time the Treaty protections will
apply. The only contingency which would change the agreed
taxation regime is if the State of Alaska changes its
property tax regime.
.,
241
A related issue was the $200 million socioeconomic
impact payment recommended by the NEB in its July 4th
decision. There are precedents in the United States for
socioeconomic impact assistance. Normally, however,
compensation for such impacts has been through federal
government loans and subsidies. In negotiations with
Canadian representatives, it was strongly urged that this
payment be structured as a loan from the pipeline company
to be repaid through reduction of future property-tax
liability. In fact, such an arrangement has been worked
out between the Canadian project sponsors and the Canadian
government. As a result, cost of ser~ice to u.s. consumers
will not be affected by this arrangement.
Native Claims
A source of additional concern is the settlement of
Canadian native claims. Some parties have questioned
whether the cost of the settlement --the cost was almost
$1 billion in the case of Alaska native claims --would be
imposed on consumers of Alaska gas through some type of
transit fee or tax. The Canadian Government has publicly
stated on a number of occasions that it considers settle-
ment of native claims as an internal Canadian matter
246-448 0 -77 -18
242
to be resolved separately from any trans-Canada pipeline
consideration. Canada has also undertaken to assure the
United States that no charges against the pipeline related
to the settlement of such claims will be levied.
Another concern has been that the uncertain status
of a Canadian native claims settlement may affect Alcan•s
ability to secure financing. Lenders might be reluctant
to commit funds without firm assurance on the final
schedule for completion of the pipeline.
The Agreement on Principles commits both countries to
a timetable which is specified in the Agreement. The
Agreement also commits both countries to seek legislation
as required to remove any delays or impediments to timely
//
and efficient construction. This legislation, particularly
when combined with the incentive scheme to reduce cost
overruns in Canada, will provide the strongest possible
assurances to lenders that both Governments intend for this
project to be completed as quickly, and at as low a cost, as
possible.
"Canadian Content" Regulations
It has been argued that the "Canadian content"
regulations, issued by the NEB to assure that Canadian
243
firms and workers receive the maximum economic benefits
from pipeline projects in Canada, could increase costs.
One part of the Agreement specifically addresses this point,
and commits each government to the principle that the supply
of good and services will be on generally competitive terms.
Specific remedies are included in that section of the
Agreement of consideration in the event that the competitive
terms of supply which are sought by the Agreement are not
being met.
Employment
Finally, a trans-Canada project would have fewer
employment opportunities for U.S. workers than the El Paso
project. It is estimated that during the construction
period, El Paso would account for 324,000 man-years of
employment in the United States compared to 221,000 for
Alcan. In the year of greatest employment, El Paso would
have a 121,000 to 84,000 man-year advantage over Alcan.
The El Paso project is also more labor intensive.
Such increased employment opportunities, however, show
up in a significantly increased cost of service for the
El Paso system. Labor costs in Canada are lower than in
the United States, and the operating costs of an all-
pipeline system through Canada will be significantly lower
244
than for the El Paso LNG system. Also, the lower cost and
higher fuel efficiency of a trans-Canada pipeline make its
NNEB substantially higher than that of El Paso.
The important point is that neither project will solve
the unemployment problems of either country. Although the
difference in man-years of employment between the two
projects is large in an absolute sense, it translates into
a 0.035 percent difference in the u.s unemployment rate.
This difference would be offset by the unemployment impacts
on the U.S. of curtailed Canadian gas deliveries in the
event that lack of access to the Mackenzie Delta reserves
reduced Canada's ability to meet existing export commitments.
* * *
The Agreement on Principles provides assurances on
routes, taxation levels, project delays, and other critical
matters. A section-by-section analysis is provided below.
This Agreement, along with the Transit Pipeline Treaty,
protects the project from unfair or discriminatory charges
that would otherwise threaten the savings to u.s. consumers.
Canada also has an excellent record of living up to its
commitments in similar joint agreements with the u.s. In
fact, the kind of assurance on time, taxes, routes, tariffs
245
tariffs and a host of other issues spelled out in the
Agreement on Principles probably exceeds the level of com-
mitment that would have been available at this time on any
all-American project.
Analysis of the Agreement with the Government of Canada
Paragraph 1: Pipeline Route
This paragraph defines the Pipeline which is the
subject of the Agreement as that which will follow the
route described in the first Annex to the Agreement, and
requires that all necessary action be taken to authorize the
construction and operation of the Pipeline consistent with
the principles of the Agreement.
Paragraph 2: Expeditious Construction; Timetable
Subparagraph (a) lays out a timetable for commencement
of construction and commits both Governments to take measures
to complete issuance of all authorizations in time to allow
initial operation of the Pipeline by January 1, 1983. The
timetable calls for construction beginning in Alaska by
January 1, 1980, and main line pipelaying beginning in the
Yukon by January 1, 1981. Although heavy pipeline construc-
tion activity in the Yukon cannot start before early 1981,
preconstruction activities, such as final routing studies
246
and highway bridge reinforcement for heavy equipment
traffic, can proceed prior to that date.
Subparagraph (b) assures that all charges for routine
authorizations, such as licenses and certificates, as well
as charges for right-of-way, will just be reasonable and
nondiscriminatory. Subparagraph (c) commits both
Governments to facilitating expeditious construction of the
/
Pipeline consistent with the respective regu"latory require-
//
ments of the two Governments, such as those in the areas of
worker safety, environmental protection,' and quality control.
Paragraph 3: Capacity of Pipeline and Availability of Gas
Subparagraph (a) deals with the initial throughput
capacity of the Pipeline, requiring that this capacity be
sufficient to meet the contractual requirements of shippers
when those requirements arise. The intention is that it
would initially be sized for 2.4 billion cubic feet per day
(bcfd) of gas from Alaska, with provision for up to 1.2 bcfd
of gas from Canada's Mackenzie Delta at the time the
Dempster Highway lateral pipeline (called "the Dempster
Line") is built to connect those reserves. It is expected
•
that this intention will be carried out by installing larger-
diameter or thicker-walled pipe south of the interconnection
247
point near Whitehorse, then adding additional compressor
capacity at the time the Dempster Line is constructed.
The choice between larger-diameter and thicker-walled pipe
will be made at the conclusion of a testing program to
assess the safety and reliability of the two alternatives.
The testing program is provided for in Paragraph 10.
Subparagraph (a) also provides that authorizations wilJ
be granted, subject to regulatory requirements, for the
Dempster Line and any further expansions of capacity (such
as that which may subsequently be requested to transport
additional Alaska gas).
Subparagraph (b) defines and limits arrangement whereby
the Pipeline will provide gas service to remote communities,
through or near which it passes. Prior to the time when the
Dempster Line is in service, the gas provided will be Alaska
gas, subject to contemporaneous replacement by equivalent
volumes of Canadian gas being made available for export.
There is a limit of $5 million Canadian on capital
costs to be incurred by u.s. shippers for provision of this
service. Costs outside that limit will be reflected in the
cost of service to the communities involved.
248
Paragraph 4: Financing
Subparagraph (a) states the understanding of both
Governments that the project will be privately financed.
It is also recognized that both Governments have to assure
themselves that the project can be so financed before
construction is allowed to begin.
Subparagraph (b) commits both Governments to use a
variable rate of return on pipeline company equity capital
as an incentive device to avoid cost overruns and to mini-
mize costs consistent with sound pipeline management. Under
this device, a higher-than-usual rate of return on pipeline
company equity capital is allowed in the cost of service if
the company is able to meet or better its estimates of
capital costs for the project. Conversely, a lower-than-
usual rate of return on equity is included in the cost of
service if the project overruns its capital cost estimates.
The base capital cost estimates which will be used for
administering the variable rate of return device in Canada
are set forth in the Agreement as Annex III.
Although the details of the variable rate of return
device remain to be worked out by the Federal Power
Commission and the Canadian National Energy Board, it will
have the effect of insulating the consumer somewhat from the
f f
249
effect of cost overruns in project construction. If the
amount of capital costs reflected in the cost of service is
relatively low, then the return-on-equity component of that
cost is allowed to be higher than usual. On the other hand,
if the total capital costs are higher than estimated, the
increased cost of service can be offset by reducing that
portion of it which is included for return on pipeline
company equity capital. The overall effect on the cost of
service is to narrow somewhat the expected range by trading
off return to the pipeline company against performance by
the company in holding down capital costs. Additional
information on the variable rate of return concept is given
in the section of the Decision dealing with financing.
Subparagraph (c) states that neither the variable rate
of return on equity nor any unusual provisions in the debt
instruments concluded in financing the main line will be
allowed to interfere with the financing of the Dempster
Line.
Paragraph 5: Taxation and Provincial Undertakings
Subparagraph (a) reiterates commitments of the two
Governments under the Transit Pipeline Treaty and attaches
statements by the Governments of the three western provinces
250
expressing their agreement with the principles in the
Treaty. In addition to guarantees against interruptions
in flow, the Treaty covers fees, duties, taxes or other
monetary charges, and assures that such charges will be the
same for transit pipelines as for similar pipelines located
within the jurisdiction of the responsible public authori-
ties within each country.
As there are no similar pipalines in the Yukon
Territory, it was desirable to reach an understanding on the
taxation regime applicable to ,the Pipeline in that Territory.
Subparagraph (b) lays out the principles of that taxation
regime, which is comparable to that in the State of Alaska.
Those principles are as follows:
ill
1. The Yukon Property Tax is defined as property
taxes and all other direct taxesll/which are
levied exclusively or virtually exclusively
on the Pipeline. (Clause i)
2. Prior to authorization of initial operation of the
Pipeline, the Yukon Property Tax will not exceed
the following:
Under Canadian law, the Yukon Territorial Government can
impose only direct taxes. Indirect taxes can only be
levied by the Canadian Federal Government, and are,
therefore, governed adequately by the Transit Pipeline
Treaty
251
1980 -$ 5 million Canadian
1981 -$10 million Canadian
1982 -$20 million Canadian
any year after 1982 during which operation of the
Pipeline is not yet authorized -$25 million
Canadian. (Clause ii)
3. From the first full year that the Pipeline is
authorized to open operation through 2008 (or until
the Dempster Line is authorized to open, if that
occurs earlier), the Yukon Property Tax will not
exceed $30 million Canadian, adjusted for inflation
after 1983 using the Canadian Gross National
Product price deflator (the GNP deflator).
(Clause i)
4. The $30 million maximum level of taxation applies
to the Pipeline at a throughput of 2.4 bcfd of u.s.
gas and 1.2 bcfd of Canadian gas. If the capacity
of the Pipeline is increased for U.S. gas prior to
the connection of the Dempster Line, the $30 mil-
lion base figure could be increased by the same
proportion as the increase in gross asset values
of the Pipeline facilities. (Clause vi)
252
5. If at the end of 1987 it is found that the per
capita revenues received from property taxes, other
than the Pipeline, plus grants to local governmen-
tal units, have increased during the period 1983
through 1987 at a faster rate than the GNP deflator,
the Yukon Property Tax may undergo a one-time
adjustment for the year 1987 to raise the permitted
maximum to the level it would have been, had it
been increasing at the rate of increase of other
YTG per capita revenue. (Clause iv)
6. After January 1, 1988, the Yukon Property Tax is
permitted to rise either with the GNP deflator or
with the rate of increase in YTG per capita revenue
(excluding tax on the Pipeline), whichever is
greater. (Clause v)
7. If the Alaska property tax rate on pipelines
increases between now and 1983 at a rate faster
than the Canadian GNP deflator, an adjustment in
the permitted $30 million maximum is allowed; and
after leave to open the Pipeline in the Yukon is
granted, the permissible Yukon property tax may be
adjusted to reflect increases of Alaska property
253
tax on the Pipeline greater than increases
otherwise permitted in the Yukon Property Tax.
(Clauses vii and viii)
8. Clause ix provides that the Yukon socioeconomic
fund costs will not be reflected in cost of service
to U.S. shippers. No other special fund having an
effect on cost of service will be permitted in the
Yukon unless such a fund is required by the State of
Alaska.
9. If the Dempster Line is connected, the Yukon
Property Tax will be governed by the tax treatment
applied to the Dempster Line, under the terms of
the Transit Pipeline Treaty (clause iii). In
Subparagraph (c) the Canadian Government will
endeavor to ensure that tax treatment of the
Dempster Line in the Northwest Territory is reason-
ably comparable to that in the Yukon Territory.
(Clause iii and Subparagraph c)
10. If the Dempster Line is not connected, the
permissible limit of the Yukon Property Tax
will expire on December 31, 2008 (25 years after
the date when the Alaska gas is expected to begin
254
flowing), at which time it will be renegotiated.
(Clause iii)
Paragraph 6: Tariffs and Cost Allocation
Subparagraph (a) outlines the general methods of cost
allocation for the portions of the Pipeline in Canada. The
Pipeline will be divided into zones (Annex II contains the
description of the zones) corresponding to segments of the
system delineated by any of the following boundaries:
-gas input and takeout points
h . . 1" h. 34/ - c anges 1n P1pe 1ne owners 1p.--
cost of service to each shipper in each zone will be
determined by allocating the total costs of constructing and
operating the Pipeline in that zone among the shippers
transporting gas through it in proportion to the volumes of
gas~/transported for each shipper.
111 In order to assure full Federal Government jurisdiction
over the Pipeline, the Canadian National Energy Board
required the sponsoring companies to restructure their
corporate form. The pipeline company sponsors are to
form a Federally-chartered umbrella company, Foothills
Pipe Lines, Ltd., which will own 51 percent of subsidi-
aries which will construct and operate segments of the
Pipeline within the different provinces. The other 49
percent of each subsidiary will be owned by the respec-
tive parent companies of Foothills in their traditional
business areas.
35/ Volumes of commingled gas streams will be adjusted to
reflect the original Btu content of the source gas and
such volumes will be used for allocating costs.
255
Subparagraph (b) describes the cost allocation method
for Zone 11 (the extension of the Dempster Line from Dawson
to Whitehorse known as the "Dawson Spur") if and when the
Dempster Line is constructed. In general, the cost of
service for the Dawson Spur is to be shared by Canadian and
u.s. shippers. The proportionate sharing is to be linked
to the degree of cost overruns sustained in constructing
the Canadian segments of the Pipeline. In no event is the
share to be paid by u.s. shippers less than the fraction of
the u.s. gas transported by the system after Canadian gas
has been connected to the system. The cost of service to
u.s. shippers will be affected more by reduced cost overruns
than by the u.s. share of the cost of service for the Dawson
Spur.
For a case with system transportation of 2.4 bcfd of
u.s. gas and 1.2 bcfd of Canadian gas, the u.s. shippers'
share of the Dawson Sp~r cost of service would be two-thirds
if cost overruns were 45 percent. If cost overruns are
reduced from 45 percent, the u.s. shippers' share of the
cost of service increases on a straight-line basis, until
at an overrun level Qf 35 percent, the u.s. shippers' share
is 100 percent.
256
If U.S. gas is a larger proportion than two-thirds of
the total gas carried in the Pipeline, the minimum propor-
tion of the cost of service on the Dawson Spur to be paid
by U.S. shippers is correspondingly higher. If the system
is carrying three-quarters u.s. gas, for example, then the
minimum proportion of the cost of service on the Daswon
Spur which will be paid by U.S. shippers is 75 percent.
From that minimum, the u.s. shippers' share of the cost of
service increases with reduced cost overruns until their
share reaches 100 percent at the 35 percent cost overrun
level. The degree of cost overrun between 35 and 45 per-
cent always corresponds to the same u.s. shippers' share
of the cost of service on the Dawson Spur: only the minimum
u.s. shippers' share varies with the proportion of total
gas transported which is u.s. gas.
This cost-sharing arrangement is intended to provide
benefits to transportation of Canadian gas which would have
been provided by diverting the Pipeline north through Dawson
City and along the Klondike Highway as required by the
National Energy Board. Had that diversion been impJemented,
·U.S. shippers would have been paying a volumetric proportion
of the cost of service of the main line between Dawson and
Whitehorse after the Dempster Line was connected, and all of
257
~ the cost of service for that segment if the Dempster Line
was never connected. Under the agreed arrangement, U.S.
shippers will pay a volumetric proportion of the cost of
service on a smaller, less expensive pipeline from Dawson to
Whitehorse only after the Canadian gas is connected, and will
pay nothing for that segment if the Dempster Line is never
built. The agreed arrangement provides the same transporta-
tion benefits to Canadian gas at lower cost to both Canadian
and u.s. shippers.
The agreed arrangement also imposes a ceiling on u.s.
liability for the Dawson Spur at 35 percent above filed
costs. The Canadians, in turn, can credit savings achieved
on the main line system against cost overruns on the Dawson
Spur prior to applying the ceiling. The savings that can
be credited against the cost overruns on the Dawson Spur
may be either of the following:
a volumetric proportion of savings achieved in
segments through which joint volumes will be trans-
ported; and
100 percent of savings achieved in segments which
will carry only u.s. gas.
However, at a minimum, the u.s. shippers• share of the cost
of service on the Dawson Spur will be the fraction of the
246-448 0 -77 -19
258
total gas carried in the Pipeline which is U.S. gas. More
detail on the specifics of cost allocation for the Dawson
Spur is given in Annex III to the Agreement.
Subparagraph (c) of this Paragraph in general provides
for review and subsequent agreement by both Governments on
cost allocation methods in the event that volumes of gas to
be shipped exceed the efficient transmission capacity of the
Pipeline. Subparagraph (d) limits costs for the Dawson Spur
allocated to u.s. shippers to those that would be incurred
for installation of a 42-inch system, plus those installed
within 3 years of the date when the system commences oper-
ation. Subparagraph (d) also requires the system installed
for the Dawson Spur to be the same as that for the Dempster
Line, in order to prevent loading of costs onto the Dawson
Spur.
Paragraph 7: Supply of Goods and Services
Subparagraph (a) ensures that contracting for supply
of goods and services to the Pipeline will be on generally
competitive terms. This provision is intended to prevent
cost overruns and time delays due to Canadian source restric-
tions on procurement for pipeline projects constructed
within Canada.
259
Subparagraph (b) provides a mechanism for presenting
grievances when the objectives with regard to competitive
terms in Subparagraph (a) are not being met. Subparagraph
(b) also specifies possible actions to be taken in the event
of a favorable determination on a plaintiff's grievance
including:
-renegotiation of corrtracts, or
-reopening oL~competitive bidding.
Paragraph 8: Coordination and Consultation
This paragraph provides for appointment by both
Governments of a senior official to represent that Government
in periodic consultations on progress in implementing this
Agreement. The respective senior officials may, in turn,
designate additional representatives to work out any
particular problems which may arise in the course of
constructing and operating the Pipeline.
Paragraph 9: Regulatory Authorities --Consultation
This paragraph provides for consultation between the
respective regulatory authorities in the U.S. and Canada,
primarily the U.S. Federal Power Commission and the Canadian
National Energy Board. In particular, the two authorities
will need to work out matters relating to financing, tariffs,
taxation and cost allocation as they relate to determination
of the cost of service for the Pipeline.
260
Paragraph 10: Technical Study Group on Pipe
The two Governments are agreed that a higher-capacity
pipeline system than was proposed by the sponsoring com-
panies is to be installed south of the interconnection
point for the Dempster Line at Whitehorse, in order to
carry joint gas volumes more efficiently. However, there
is some reservation, particularly on the part of the
Canadian Government and the Canadian pipeline company
sponsors, about the technical feasibility of a higher-
pressure system, such as had been proposed by the Arctic
Gas consortium. Although Canadian Government representa-
tives are agreed on the need for a higher-capacity system,
their preference on the grounds of expected safety and
reliability is for larger-diameter pipe, which has many
of the same advantages in increased efficiency as the
higher-pressure system.
Subparagraph (a) establishes a joint technical study
group for the purpose of evaluating the relative merits of
the larger-diameter and higher-pressure systems which have
been suggested, as well as any other combinations of pres-
sure and pipe size which might achieve objectives of
increased efficiency. The 48-inch, 1260 pounds per square
inch (psi) design which was proposed by the applicant and
261
will likely be installed from Whitehorse north to the
Prudhoe Bay field will also be evaluated by the group.
Final decisions based on the results of the testing program
will remain the responsibility of the respective regulatory
authorities in the two countries.
Subparagraph (b) states that whatever higher-capacity
system is chosen will be installed from the interconnection
point near Whitehorse to the point near Caroline, Alberta,
where the Pipeline bifurcates into a western and an eastern
leg.
Paragraph 11: Direct Charges by Public Authorities
Subparagraph (a) provides that either Government can
request consultations in the event that any public authority
seeks to impose a direct charge on the Pipeline which might
be considered properly the responsibility of the sponsoring
company, rather than an item which should be included in the
cost of service.
Subparagraph (b) identifies generally the types of
direct charges by public authorities which will be permitted
to be included in the cost of service. Such charges will
include only:
262
-those considered by the appropriate regulatory
authority to be just and reasonable on the basis of
accepted regulatory practice, and
-those normally imposed on natural gas pipelines in
Canada.
A list of examples of direct charges is attached to the
Agreement as Annex IV and includes:
-extraordinary highway maintenance due to heavy
vehicle traffic,
-airfield and airstrip repairs,
-drainage maintenance,
-erosion control, etc.
Direct charges will be subject to the tests in the
appropriate legislation prior to inclusion in the cost
of service.
Paragraph 12: Other Costs
This Paragraph provides that no charges will be
considered for inclusion in the cost of service other than
those:
-imposed by a public authority under the terms of
the Agreement or the Transit Pipeline Treaty,
-normally paid by natural gas pipelines in Canada
under accepted regulatory practice, or
263
-caused by Acts of God or other unforeseen
circumstances.
Paragraph 13: Compliance with Terms and Conditions
This Paragraph provides that each Government will
implement the principles directly applicable to construction,
operation and expansion of the Pipeline through imposition
of terms and conditions on the authorizations it issues. In
the event that a Pipeline owner does not fulfill one or more
of the terms and conditions, the Government will not be held
responsible for that non-fulfillment, but will take appro-
priate action to cause the owners to remedy or integrate the
adverse consequences of that non-fullfillment.
Paragraph 14: Legislation
This Paragraph commits both Governments to seek expedi-
tiously all legislative authorities which might be required
to implement the Agreement and to facilitate timely and
efficient construction of the Pipeline. This provision
specifically refers to legislation to remove delays to con-
struction of the Pipeline.
Paragraph 15: Entry into Force
This Paragraph provides that the Agreement will become
effective upon signature, and will continue in effect for 35
U4
years and thereafter until terminated on 12 months' notice
by either Government. The provisions of the Agreement which
require legislative action will become effective when the
required legislative action has been completed.
At the end of the Agreement there are several Annexes
which append specific information or explain a particular
feature of the Agreement in more detail.
Annex I: Description of the Route
(Self-explanatoiy)
Annex II: Zones for the Pipeline in Canada
This Annex specifically identifies the zones for cost
allocation under the method described in Paragraph 6. It
gives the boundaries of the zones.
Annex III: Cost Allocation in Zone 11
This Annex describes the cost allocation agreement for
the Dawson Spur, which was outlined in Paragraph 6, in more
detail. In particular, the computation of the ceiling on
U.S. shippers' liability for the cost of service on the
Dawson Spur is set forth in some detail.
The Annex also contains detailed specification of the
filed capital costs for Canadian portions of the system
which will be used to determine cost overruns for the
265
purposes of cost allocation for the Dawson Spur. Possible
adjustments of those costs in limited circumstances are also
covered.
Annex IV: Direct Charges by Public Authorities
This Annex is a list of typical direct cost items for
use with the limitation on direct charges by public authori-
ties in Canada; the limitation is in Paragraph 11 of the
Agreement.
Annex V: Statements by the Provincial Governments
Public statements by the Governments of the three
western provinces are attached in which they agree to the
principles of the Transit Pipeline Treaty. Each also under-
takes to work out with the Canadian Government a Federal-
Provincial Agreement.
266
CHAPTER XII -SUMMARY OF COMMENTS RECEIVED
Throughout the period during which an Alaska natural
gas transportation system has been under consideration,
many comments concerning the decision have been sent to the
various Federal agencies involved in the decision process.
Comments have come from all parts of the American public,
including private citizens, businesses, labor unions, muni-
cipalities, legislators and Governprs. They ranged from
expressions of support for a specific proposal to sugges-
tions of alternative and often jnnovative methods·of
building a gas delivery system.
By far, the majority of comments were received within
the past few months in response to a Federal Register
notice on June 14, 1977, advising the public of Section 6(b)
of the Alaska Natural Gas Transportation Act of 1976 which
invites comments from Governors, municipalities, and other
interested parties. Letters soliciting comments were
written to the Governors of all the States, and meetings
were held on several occasions with a committee of State
Public Utility Commissioners.
The comments received in the period since the FPC's
Recommendation to the President have been of two basic
267
types --those supporting a specific proposal, and those
commenting on certain aspects of the FPC recommendations.
Almost all the letters received favored the delivery of
the North Slope gas to the lower-48 states. Very few
suggested that construction of a delivery system be signif-
icantly delayed or that no system be built.
Comments on Specific Projects
Arctic Gas
The supporters of Arctic Gas most often cited Arctic's
claims of lower cost of service and fuel use; ability to
connect Prudhoe Bay and Mackenzie Delta reserves with one
pipeline; and the opportunity to maintain Canadian gas
exports once the Mackenzie Delta reserves were connected.
The unfavorable comments generally concerned the
environmental impacts of crossing the Arctic National
Wildlife Range (ANWR); higher potential for delay and cost
overrun due to winter construction, use of snowroads, and
regulation by two countries. The unsettled status of the
Canadian native land claims was stressed as a factor which
would cause delays or preclude construction.
Before the July 4th Canadian NEB decision, the Arctic
Gas proposal received support from municipalities and
268
businesses in the Midwest and California; the Governors of
Arkansas, Kansas, Wisconsin, Minnesota, Massachusetts, Ohio,
Maryland, Illinois; and many private citizens from all parts
of the country. The Governors of California and Montana
also supported an overland route.
El Paso
Support for the El Paso proposal was primarily based on
the fact that El Paso would lie entirely within the United
States. According to its supporters, this fact would result
in greater domestic employment, higher tax payments, better
security of supply, and regulatory control by one country.
Another favorable point for El Paso cited was that it used
the existing Alyeska transportation corridor and facilities.
The principal negative comments concerned El Paso's
higher cost of service; the location of its LNG plant in
active seismic zones; difficulty of siting the regasification
plant in Southern California; and the possibility that it
would foreclose delivery of additional Canadian gas supplies.
Support for the El Paso proposal came from various
state AFL-CIO offices, maritime labor unions, some private
citizens, and the Governors of Alaska, New Mexico, Arizona,
Texas, Alabama, New York and Washington.
269
Alcan
Alcan's supporters often cited this proposal as an
example of the success of the National Environmental Policy
Act (NEPA) because the proposal developed as an alternative
which achieved the economies of scale of a pipeline while
avoiding the environmentally sensitive ANWR and Arctic
regions. Alcan also received support because it generally
follows existing transportation corridors. It seemed even
greater after the NEB selected the Alcan proposal and stated
that construction of a Trans-Canadian pipeline would facil-
itate maintenance of Canadian gas exports.
The negative comments on Alcan were that it had a less
developed hearing record; would incur more delays by being
subject to regulation by two countries; would lack adequate
pre-construction planning, would require settlement of
Canadian Native claims in southern Yukon; and would need
additional environmental studies. Concerns were raised
about the conditions imposed by the NEB, such as the
socioeconomic impact fund and the requirement to increase
capacity to carry Canadian gas in the system.
Support for the Alcan proposal has come from the major
environmental organizations and the Governors of Wyoming,
Nevada, Oregon, Colorado, and Utah.
270
Comments on Specific FPC Recommendations
Formula Wellhead Pricing
The producers and the State of Alaska strongly opposed
the FPC recommendation for "formula pricing" of the well-
head price. They contended that this approach forced the
producers to share the risk of the project --even if they
were not investors. This would serve to inhibit further
exploration for gas in northern Alaska. They also argued
this proposal would reduce the sponsor's incentive to manage
the project properly.
Minimum Throughput Requirements
The producers also opposed this recommendation because
contending that throughput should be established by the
behavioral characteristics of the reservoir and by the
State of Alaska.
Widespread Distribution of Gas
The members of the Arctic Gas Consortium strongly
opposed this recommendation. They argued that this require-
ment would be a disincentive for prospective members to
join the consortium; would be unfair and discriminatory
to companies who could purchase more than the maximum; and
would result in discriminatory treatment of Alaskan gas
compared with other fuel sources. Alcan, however, supported
the widespread distribution requirement.
271
Western Leg
The FPC recommendation to delay the decision on the
Western Leg was opposed by Arctic, Alcan and the' State of
California. It was argued that this recommendation is
inconsistent with the requirements of Alaska Natural Gas
Transportation Act. They also felt that new facilities will
be required to deliver Alaska gas to the West.
U, S, GOVERNMENT PRINTING OFFICE : 1977 0 -246-448