HomeMy WebLinkAboutAPA1792FERC LICENSE APPLICATION
PROJECT NO. 7114-000
As accepted by FERC, July, 27 , 198 ~
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BEFORE THE
FEOE~.;;_ ENERGY REGULA TORY COMMISSION
APPLJCATiON FOF1 LICENSE FOR MAJOR PROJECT
SUSITNA HYDROELECTRIC PROJECT
VOLUME 1
UNiVEFlSITY OF ALASKA
ARCTIG ENV!RONMENTrU .. INFORMATION
AND DATJ,, CENl'l::R
707 A Si"ilil::IET
f-i.N>r..ttiO~E, ,~li:b 99'-S(Il
INITIAL STATEMENT
EXHIBIT A
EXHIBIT C
FEBRUARY 1983
EXHIBIT D
REVISED JULY 1983
ALASKA POWER AUTHORITY
INITIAL STATEMENT
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BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION:
APPLICATION FOR LICENSE FOR A
MAJOR UNCONSTRUCTED PROJECT OR MAJOR MODIFIED PROJECT
(1) The Alaska Power Authority applies to the Federal
Energy Regulatory Commission for a license for the Susitna
Hydroelectric Water Power Project, as described in the
attached exhibits.
(2) The lo6ation of the proposed project is:
State:
Borough:
Stream or Other Body of Water:
Alaska
Matanuska-Susitna
Susitna River
(3) The exact name, business address and telephone
number of the applicant is:
Alaska Power Authority
334 West 5th Avenue
Anchorage, Alaska 99501
(970) 276-0001
The exact names, business addresses and telephone
numbers of the persons authorized to act as agents for the
applicant in this application are:
Mr. Robert A. Mohn
Project Manager
Alaska Power Authority
334 West 5th Avenue
Anchorage, Alaska 99501
(907} 276-0001
and
D. Jane Drennan
Pillsbury, Madison & Sutro
Suite 900
1050 Seventeenth Street, N.W.
Washington, D.C. 20036
(202) 887-0300
(4) The applicant is a public corporation of the State
of Alaska in the Department of Commerce and Economic
Development but with separate and independent legal
existence.
(5) (i) The statutory or regulatory requirements of the
state in which the project would be located and that affect
the project as proposed with respect to bed and banks and to
the appropriation, diversion, and use of water for power
purposes, and with respect to the right to engage in the
business of developing, transmitting, and distributing power
and in any other business necessary to accomplish the
purposes of the license under the Federal Power Act, are:
(A) ALASKA STAT. §§44.83.010-44.83.425 (1977,
1982 Supp.} ("Alaska Power Authority")
(including §§44.83.300-44.83.360, entitled
"susitna River Hydroelectric Project") i
1982 Alaska Sess. Laws, Chapter 133, §21.
The above-cited sections of the Alaska Statutes
establish the Alaska Power Authority as a legal entity, the
purpose of which is "to promote, develop and advance the
general prosperity and economic welfare of the people of
Alaska by providing a means of constructing, acquiring,
financing and operating power projects," including
hydroelectric facilities. ALASKA STAT. §44.83.070 (1982
Supp.) The Alaska Power Authority has a number of specific
powers, including (1) the right to perform reconnaissance
studies, feasibility studies, and engineering and design
with respect to power projects, (2) the right to enter into
contracts, (3) the right to issue bonds, (4) the right to
exercise the power of eminent domain and (5) the right to
construct and operate power projects. See ALASKA STAT.
§44.83.080 (1982 Supp.).
Sections 44.83.300-44.83.360 deal specifically with the
Su~itna. River Hydroelectric Project, the purpose of which is
to'generate, transmit and distribute electric power in a
manner that will (1) minimize market area electrical power
costs, (2) minimize adverse environmental and social impacts
while enhancing environmental values to the extent possible
and (3) safeguard both life and property. ALASKA STAT.
§§44.83.300-44.83.310 (1977). 1982 Alaska Sess. Laws,
Chapter 133, §21 now permits the Alaska Power Authority to
contract for preliminary work on the Susitna Project
(including preparation of plans and studies, preparation and
submission of license applications, and other types of work
necessary before actual construction of the project can
begin) without seeking state legislative approval. See
ALASKA STAT. §44.83.325 (1982 Supp.) (Editor's note)-.-
However, the Alaska Power Authority is still required to
obtain approval by the state legislature of its preliminary
report on the Susitna Project in the manner specified in
ALASKA STAT. §44.83.325 (1977) before contracting for
preparation of the site or contracting for actual
construction of the project. In addition, state legislative
approval of the financing of the project is required. See
ALASKA STAT. §44.83.360 (1977).
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(B) ALASKA STAT. §§46.15.030-46.15.185 (1982)
("Appropriation and Use of Water"); ALASKA
ADMIN. CODE tit. 11, §§93.040-93.140 (Jan.
1980) ("Appropriation of Water").
These statutory provisions and regulations set forth
the manner by which a right to appropriate water in Alaska
may be acquired. They require that application for a permit
to appropriate be made to the Department of Natural
Resources. See ALASKA STAT. §46.15.040 (1982); ALASKA
ADMIN. CODE tit. 11, §93.040 (Jan. 1980). They also list
certain criteria which must be considered when evaluating
the application. See ALASKA STAT. §46.15.080 (1982); ALASKA
ADMIN. CODE tit. 1"1-;--§93.120 {Jan. 1980). In addition, the
cited statute and regulations specify under what conditions
one who has been granted a permit to appropriate shall be
granted a certificate of appropriation.
(C) ALASKA ADMIN. CODE tit. 11,
§§93.150-93.200.185 (Jan. 1980) ("Dam Safety
and Construction").
These regulations {also promulgated pursuant to ALASKA
STAT. §46.15.030-46.15.185 (1982), discussed in (B) above)
require a "certificate of approval" to be obtained from the
Department of Natural Resources prior to construction of
dams as large as those proposed for the Susitna Project.
Approval is based on information contained in drawings and
design data submitted with the application for the
certificate.
(D) ALASKA STAT. §16.05.870 (1982 Supp.)
("Protection of Fish and Game").
This section requires that any person or governmental
agency intending to "use, divert .•• or change the natural
flow or bed" of a river, lake or stream, such as the Susitna
River, which has been designated as important to the
spawning, rearing or migration of anadromous fish (1) notify
the Department of that intent and (2) await its approval of
the construction.
(E) ALASKA STAT. §§16.10.010-16.10.020 (1977)
("Interference With Salmon Spawning Streams
and Waters", "Grounds for Permit or
License").
These sections essentially require that any person who
will erect a dam which may affect salmon spawning streams or
waters first apply for and obtain a permit or license from
the Department of Environmental Conservation. One purpose
for which a permit or license may be granted is the
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development of power. As a condition for such a permit,
however, adequate fishways may be required.
(F) ALASKA STAT. §16.05.840 (1977) ("Fishway
Required").
The CoiTmissioner of the Department of Fish and Game may
require that a fishway be provided for a dam built across a
stream frequented by salmon or other fish. In the event
that a fishway is considered necessary, plans and
specjfications must be submitted for approval.
(G) ALASKA ADMIN. CODE tit. 18, §§15.130-15.180
(Jan. 1978) ("Certification").
Under Federal law, an applicant for a Federal license
to construct or operate a facility must obtain from the
State a certification of compliance with the Federal Water
Pollution Control Act. 33 U.S.C. §1341 (1977). The
certificate is governed by ALASKA ADMIN. CODE tit. 18,
§§15.130-15.180. The procedures governing that
certification process are set forth in these sections of the
Code.
(H) ALASKA STAT. §38.05.020-38.05.330 (1982
Supp.) ("Alaska Lands Act") .
These sections of the Alaska Statutes provide the
methods by which the Alaska Power Authority may obtain use
of state lands. The Department of Natural Resources may
lease, sell or otherwise dispose of state land to a state or
political subdivision for less than its appraised value if
such action is found by the Department to be fair and proper
and in the best interests of the public. ALASKA STAT.
§38.05.315 (1982 Supp.). The Department may issue permits,
rights-of-way or easements on state land for roads and
electric transmission and distribution lines. ALASKA STAT.
§38.05.330 (1982 Supp.). However, prior to disposing of
state land which is adjacent to a body of water or a
waterway, the Department must determine whether the body of
water or waterway is navigable or public water or neither.
If it is navigable or public water, the Department may
provide for easements or rights-of-way. ALASKA STAT.
§38.05.127 (1982 Supp.).
(I) ALASKA STAT. §§46.40.030-46.40.040;
§§46.40.090-46.40.100 (1982) ("Development of
Alaska Coastal Management Program").
These sections require that state agencies control the
resources within a coastal area in a manner consistent with
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the applicable d~strict coastal management plan. The
Susitna Project is located within a designated coastal
resource district.
(5) (ii) The steps which the applicant has taken, or
plans to take, to comply with each of the laws cited above
are:
(A) ALASKA STAT. §§44.83.010-44.83.425 (1977,
1982 Supp.).
The Alaska Power Authority plans to seek legislative
approval of its preliminary report on the Susitna Project.
(B) ALASKA STAT. §§46.15.030-46.15.185 (1982);
ALASKA ADMIN. CODE tit. 11, §§93.040-93.140
(Jan. 19 8D} .
An investigation of existing water rights has been
completed in connection with the permit required by the
cited statute and regulations. The results indicate that
the project would not have a materially adverse impact on
existing water rights. In addition, the Alaska Power
Authority has applied for a permit to appropriate water for
the Susitna Project.
(C) ALASKA ADMIN. CODE tit. 11, §§93.150-93.200
(Jan. 1980).
The required drawings and design data are contained in
Exhibits B, F, and G of this Initial Statement. The Alaska
Power Authority has applied for a certificate of approval.
(D) ALASKA STAT. §16.05.870 (1982 Supp.).
The Alaska Power Authority has notified the Department
of Fish and Game of its intent to construct the project on
the Susitna River.
(E) ALASKA STAT. §§16.10.010-16.10.020 (1977).
The Alaska Power Authority has apprised the appropriate
Departments of the Susitna Project and requested a ruling of
its permitting requirements pursuant to these sections.
(F) ALASKA STAT. §16.05.840 (1977).
The Alaska Power Authority has notified the Department
of Fish and Game of the Susitna Project.
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(G) ALASKA ADMIN. CODE tit. 18, §§15.130-15.180
(Jan. 1980).
The Alaska Power Authority has notified the Department
of Environmental Conservation that it will seek a
certificate of compliance with the Federal Water Pollution
Control Act. Under Alaska regulations, application for such
a certificate is made by serving on the Department a copy of
the Federal license application contemporaneously with
submission of the application to the Federal agency. ALASKA
ADMIN. CODE tit. 18, §15.180(c). The Alaska Power Authority
will comply with this requirement.
(H) ALASKA STAT. §§38.05.020-38.05.030 (1982
Supp.).
The Alaska Power Authority has requested a right-of-way
for transmission lines from the Department of Natural
Resources. Rights-of-way may be requested for an access
road and a railroad spur. If any state land acquired for
the Susitna Project is adjacent to public or navigable
waters, the Department of Natural Resources will determine
whether easements or rights-of-way shall be provided.
(I) ALASKA STAT. §§46.40.030-46.40.040~
§§46.40.040-46.40.100 (1982).
The Susitna Project will be reviewed for consistency
with the coastal management plan of the borough of
Matanuska. This revie\'l process is initiated when federal
permit-granting agencies forward copies of the Susitna
application to the Alaska Division of Policy Development and
Planning as part of the federal permit process.
IN WITNESS WHEREOF, the applicant, Alaska Power
Authority, has caused its name to be signed below by Eric P.
Yould, its Executive Director, and its seal to be affixed
hereto by Eric P. Youl d , its Executive Director , this
15th day of February 1982.
By
SEAL
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Eric P. Yould
Executive Direct r
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LEGISLATION
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§ 44.83.010 ALASKA STATUTES § 44.83.010
(3) "entire transmission system" means the gas-transmission
pipeline (together with all related facilities) to extend from the
Prudhoe Bay area on the North Slope of Alaska into the contiguous
United States, substantially as described in the President's report
entitled "Decision and Report to Congress on the Alaska Natural Gas
Transportation System", issued by the President on September 22,
1977, under provisions of the Alaska Natural Gas Transportation Act
ofl976, and includes planning, design and construction of the pipeline
and facilities;
(4) "project" means the gas transmission pipeline (together with all
related property and facilities) to extend from the Prudhoe Bay area on
the North Slope of Alaska to a connection with the Trans-Canada
Pipeline on the Alaska-Canada border, substantially as described in
the President's report entitled "Decision and Report to Congress on the
Alaska Natural Gas Transportation System", issued by the President
on September 22, 1977, under provisions of the Alaska Natural Gas
Transportation Act of 1976, and includes planning, design, and
construction of the pipeline and facilities;
(5) "project sponsor" means any partner of the Alaskan Northwest
Natural Gas Transportation Company or its successors;
(6) "Prudhoe Bay natural gas" means natural gas produced from the
Prudhoe Bay reservoir;
(7) "Prudhoe Bay oil" means oil produced from the Prudhoe Bay
reservoir;
(8) "Prudhoe Bay reservoir" means those areas defined in Article 5.1
of the "Prudhoe Bay Unit Agreement" of Aprill, 1977. (§ 2 ch 90 SLA
1918)
Chapter 83. Alaska Power Authority.
Article
1. Creation and Org3nizaLion (§I 44.83.010-44.83.0501
2. Purpose and Powers Itt 44.8.3.070-44.83.090)
3. Financial Provisions(§§ 44.83.100-44.83.160)
4. Power ProducLion Cost AuisLanee (!i§ 44.83.162-44.83.1641
5. Power Project Fund II 44.83.170)
6. General Provisions IU 44.83.177-44.83.2401
7. Susitna River Hydr~lectric Projeh !U 44.83.300-44.83.3601
Article 1. Creation and Organization.
Sectioft
10. Legislative finding and policy
20. Creation of au.lhority
30. Membership of Lhe authority
40. Officera and quorum
Section
45. Qualifications. powers, and dulies of
officera and directors.
50. !Repealed)
Sec. 44.83.0U). Legislative fmding a~nd policy •. (a) The
legislature finds. determines and declares that
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§ 44.83.020 STATE GovERNMENT § 44.83.030
(1) there exist numerous potential hydroelectric and fossil fue..l
gathering sites in the state;
(2) the establishment of power projects at these sites is necessary to
supply power at the lowest reasonable cost to the state's municipal
electric, rural electric, cooperative electric, and private electric
utilities, and regional electric authorities, and thereby to the
consumers of the state, as well as to supply existing or future industrial
needs;
(3) the achievement of the goals of lowest reasonable consumer
power costs and beneficial long-term economic gr.owth and of
establishing, operating and developing power projects in the state will
be accelerated and facilitated by the creation of an instrumentality of
the state with powers to construct, acquire, finance, and operate power
projects.
(b) It is declared to be the policy of the state, in the interests of
promoting the general welfare of all the people of the state, and public
purposes, to reduce consumer power costs and otherwise to encourage
the long-term economic growth of the state, including the development
of its natural resources, through the establishment of power projects by
creating the public corporation with powers, duties and functions as
provided in this chapter. (§ 1 ch 278 SLA 1976; am § 1 ch 156 SLA
1978)
Effect of amendment. -The 1978
amendmenl in aubseclion {a), aubstilulcd
·powu al the lowest reasonable cost" for
"lower toat power .. in paragraph {2) and
•towesl reasonable consumer power cosls
nnd beneficial"' fnr ''lower conwmH power
cost! ond" ;md "construct, acquire,
finance, and" for "incur debt for
constructing, and with powers to" in para·
graph (3).
Sec. 44.83.020. Creation of authority. There is created the Alaska
Power Authority. The authority is a public corporation of the state in
the Department of Commerce and Economic Development but with
separate and independent legal existence. (§ 1 ch 278 SLA 1976)
Sec. 44.83.030. Membership of the authority. (a) The authority
shall consist of the following directors:
(1) four director:; at large to be appointed by the governor and
confirmed by the legislature; ·
(2) the commissioner of commerce and economic dcvelorment.
(b) The commissioners of community and regional affairs, natural
resources, transportation and public facilities, and revenue shall have
the rights and privileges of directors except for the right lo vote and
may not be considered for purposes of quorum or voting. ( § 1 ch 278
SLA 1976; am § 2 ch 156 SLA 1978)
Effect of amendment. -The 1978
amendment rewrote thi~o section.
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144.83.040 ALASKA STATUTES § 44.83.070
Sec. 44.83.040. Officers and quorum. The director shall elect one
of the directors at large as chairman and other officers they deterrQ.jne
desirable. The powers of the authority are vested in the directors, and
three directors of the authority constitute a quorum. Action may be
taken and motions and resolutions adopted by the authority at a
meeting by the affirmative vote of at least three directors. The directors
of the authority serve without compensation, but they shall receive the
same travel pay and per diem as provided by law for board memb1:rs.
(§ 1 ch 278 SLA 1976; am ~ 3 ch 156 SLA 1978)
Effect of amendment. -The 1978 large" for "public members" in th• first
amendment substituted "directors ot sentence.
Sec. 44.83.045. Qualifications, powers, nnd duties of officers
and directors. (a) The directors at large must be residents and
qualified voters of Alaska and shall comply with the requirements of
AS 39.50 (conflict of interests). The directors at large shall serve
four-year terms. The four original directors at large have terms of one,
two, three, and four years, respectively.
(b) A vacancy in a directorship occurring other than by expiration of
a term shall be filled in the same 1Jlanne1· as the original appointment,
buL for the unexpired portion of the term only.
(c) The authority shall employ an executive director who may, with
the approval of the authority, employ additional stafT as necessary. In
addition to its sta!T of regular employees, the authority may contract
for and engage the services of legal and bond counsel, consultants,
experts, and financial and technical advisors the authority considers
necessary for the purpose of conducting studies, investigations,
hearings, or other proceedings. The b9cird of directors shall establish
the compensation of the executive director. The executive director of
the authority is subject to the provisions of AS 39.25. (§ 4 ch 156 SLA
1978)
Sec. 44.83.050. Stnff.
Repealed by § 23 ch 156 SLA 1978.
Editor'• note. -The repealed section
derived rrom § 1, ch. 278, SLA 1976.
Article 2. Purpose and Powers.
Sec lion
70. PuJ1>0ae of tne authority
80. Powen of the authority
Section
90. Power contracts and the Alaska Public
litilities Commission
Sec. 44.83.070. Purpose of the authority. The purpose of the
authority is to promote, develop and advance the general prosperity
and economic welfare of the people of Alaska by providing a means of
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§ 44.83.080 STATE GovERNMENT § 44.83.080
constructing, acquiring, financing and operating power production
facilities limited to fossil fuel, wind power, tidal, geothermal
hydroelectric, or solar energy production and waste energy
conservation facilities.(§ 1 ch 278 SLA 1976; am§ 5 ch 156 SLA 1978)
Effect ol amendment. -The 1978
amendment iubstituted the langua!le
beginning "power production facilities" for
"hydroelectric and fossil fuel ~<:cnerating
projects" at the end of the section.
Sec. 44.83.080. Powers of the authority. In furtherance of its
corporate purposes, the authority has the following powers in addition
to its other powers:
(l) to sue and be sued;
(2) to have a seal and alter it at pleasure;
(3) to make and alter bylaws for its organization and internal
management;
(4) to make rules and regulations governing the exercise of its
corporate powers;
(5) to acquire, whether by construction, purchase, gift or lease, and
to improve, equip, operate, and maintain power projects;
(6) to issue bonds to carry out any of its corporate purposes and
powers, including the acquisition or construction of a project to be
owned or leased, as lessor or lessee, by the authority, or by another
person, or the acquisition of any interest in a project or any right to
capacity of a project, the establishment or increase of reserves to secure
or to pay the bonds or interest on them, and the payment of all other
costs or expenses of the authority incident to and necessary or
convenient to carry out its corporate purposes and powers;
(7) to sell, lease as lessor or lessee, exchange, donate, convey or
encumber in any manner by mortgage or by creation of any other
security interest, real or personal property owned by it, or in which it
has an interest, when, in the judgment of the authority, the action is
in furtherance of its corporate purposes;
(8) to accept gifts, grants or loans from, and enter into contracts or
other transactions regarding them, with any person;
(9) to deposit or invest its funds, subject to agreements with
bondholders;
(10) to enter into contracts with the United Stales or any person and,
subject to the laws of the United States and subject to concurrence of
the legislature, with a foreign country or its agencies, for the financing,
construction, acquisition, operation and maintenance of all or any part
of a power project, either inside or outside the state, and for the sale or
transmission of pow~r from a project or any right to the capacity of it
or for the security of any bonds of the authority issued or to be issued
for the project;
(11) to enter into contracts with any person and with the United
States, and, subject to the laws of the United States and subject to the
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§ 44.83.080 ALASKA STATUTES § 44.83.080
concurrence of the legislature, with a foreign country or its agencies for
the purchase, sale, exchange, transmission, or use of power from a
project, or any right to the capacity of it;
(12) to apply to the appropriate agencies of the state, the United
States and to a foreign country and any other proper agency for the
permits, licenses, or approvals as may be necessary, and to construct,
maintain and operate power projects in accordance with the licenses or
permits, and to obtain, hold and use the licenses and permits in the same
manner as any other person or operating unit;
(13) to perform reconnaissance studies, feasibility studies, and
engineering and design with respect to power projects;
(14) to enter into contracts or agreement.<; with respect to the exer-
cise of any of its powers, and do all things necessary or convenient to
carry out its corporate purposes and exercise the powers granted in this
chapter;
(15) to exercise the power of eminent domain in accordance with AS
09.55.250-09.55.410;
(16) to recommend to the legislature
{A) the issuance of general obligation bonds of the state to finance
the construction of a power project if the authority first determines that
the project cannot be financed by revenue bonds of the authority at
reasonable rates of interest;
(B) the pledge of the credit of the state to guarantee repayment of all
or any portion of revenue bonds issued to assist in construction of power
projects;
(C) an appropriation from the general fund
(j) for debt service on bonds or other project purposes; or
(ii) to reduce the amount of debt financing for the project;
(D) an appropriation to the power project fund for a power project;
(£) an appropriation of a part of the income of the renewable
resources investment fund for a power project;
(F) development of a project under financing arrangements with
other entities using leveraged leases or other financing methods.(§. 1
ch 278 SLA 1976; am §§ 6-11 ch 156 SLA 1978; am§§ 16, 17 ch 83
SLA 1980)
Effect of amendments. -The 1978
amendment substituted "equip, operate,
and maintain" for "equip and operate" in
paragraph (51, inserted "or by nnother per·
son" in paragraph !61, substituted "a
projecl'' for "it" in two places in paragraph
(61, substituted "any person" for "a federal
agency or an agency or instrumentality of
the slate. municipality, private
organiz.alion or other source" in p;~ragraph
<81, inserted "financing" near the middle of
para~:raph ~ 101. delett>d "for the purchase,
!ale, uchange, lrllnsmission, or use of
power generated by a project. or any right
to the capacity of it" following "enter into
contracts" near the begi nninli: of para·
graph I Ill, added the lan!:uage l>cginning
"for the purchase, sale, exchange'' to the
end of paragrapn ~ 11•. and deleted
"hydroelcctrical and fossil fuel" following
"'with rP.spect to" and "generating" follow·
ing "power" in paragraph 1131.
The 19HO amendment inserted in the
middle of pMagraph ( 131, "fe:1sibitity
studirs, and ~n~o:ino~cring nnd design," and
11ddcd p:~ragrupn < 161.
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A~IENDMENTS
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§ 44.81.270 ALASKA STATUTEs SuPPLEMENT § 44.81.280
institution in contemplation of the extension of credit or the collection
of loans.
(4) Impersonal information based solely on transactions or experi-
ence with a member, such as amounts of loans, terms, and payment
records may be given by the bank for the. confidential use of a reliable
organization in contemplation of the extension of credit.
(5) Credit information concerning a member may be given when the
member consents to it in writing.
(6) In litigation between a member (or his successor in interest) and
the bank, any competent evidence may be-introduced with respect to
relevant statements made orally or in writing by or to the member or
his successor. (§ ·3 ch 109 SLA 1981)
Sec. 44.81.270. Audit of bank. The legislative auditor may cause
the bank to be audited in the manner and under the conditions pre-
scribed by AS 24.20.271 for audits performed by the legislative audit
division. The legislative audit division has free access to all books and
papers of the bank that relate to its business and books and papers kept
by a director, officer, or employee relating to or upon which a record of
its business is kept, and may summon witnesses and administer oaths
or affirmations in the examination of the directors, officers, or
employees of the bank or any other person in relation to its affairs,
transactions, and conditions, and may require and compel the produc-
tion of records, books, papers, contracts, or other documents by court
order if not voluntarily produced. (§ 8 ch 109 SLA 1981)
Sec. 44.81.280. Prohibition on disclosure .. The legislative audi-
tor and his employees may not disclose information acquired by them
in the course of an audit of the bank concerning the particulars of the
business or affairs of a borrower of the bank or another person, unless
the information is required to be disclosed by law or under a court
order. (§ 8 ch 109 SLA 1981)
Chapter 83. Alaska Power Authority.
Article
1. Creation and Organization (§§ 44.83.030 -44.83.045)
2. Purpose and Powers (§§ 44.83.070-44.83.090)
3. Financial Provisions (§§ 44.83.105, 44.83.110)
4. Power Production Cost Assistance (§§ 44.83.162 -44.83.164)
6. (kneral Provisions (§§ 44.83.177, 44.83.181, 44.83.183, 44.83.185, "14.83.186,
44.83.230).
8. Rural Electrification Revolving Loan Fund (§§ 44.83.361, 44.83.363)
9. Energy Program for Alaska (§§ 44.83.380 -44.83.425)
Article 1. Creation and Organization.
Section
30. Membership of the authority
40.' Offieers and quorum
Section
45. Qualifications, powers, and duties of
officers and directors
486
§ 44.83.030 STATE GoVERNMENT § 44.83.045
Sec. 44.83.030. Membership of the authority. The authority
shall consist of the following directors:
(1) three public directors to be appointed by the governor and
confirmed by the legislature; only one director may be appointed from
each judicial district described in AS 22.10.010;
(2) the director of the division of budget and management and three
commissioners of principal executive departments appointed by the
governor. (§ 1 ch 278 SLA 1976; am § 2 ch 156 SLA 1978; am § 2 ch
118 SLA 1981)
Effect of amendments. -The 1981
amendment deleted the subsection desig·
nation (a) and repealed subsection (b)
which read "The commissioners of commu-
nity and regional affairs, natural
resources, transportation and public
facilities, and revenue shall have the
rights and privileges of directors except far
the right to vote and may not be considered
for purposes of quorum or voting." The
amendment also substituted "three pub-
lic" for "four" preceding "directors,"
deleted Hat large" preceding "to be
appointed" and added "only one director
may be appointed from each judicial dis-
trict described in AS 22.10.010" in para-
graph (1) and substituted "the director of
the division of budget and management
and three commissioners of principal
executive departments appointed by the
governor" for "the commissionet of com-
merce and economic development" in para-
graph (2).
Editor's notes. -Section 15, ch. 118,
SLA 1981, provides: "APPLICABILITY
OF ACT TO DIRECTORS. (a) The terms of
office of all members of the Board of
Directors of the Alaska Power Authority
serving on the effective date of this section
terminate on the effective date of this sec-
tion [July 1, 1981].
"(b) The governor shall appoint three
public directors of the Alaska Power
Authority. When making his appoint-
ments under this subsection, the governor
shall appoint persons to serve in accor-
dance with AS 44.83.030(1) and shall spec-
ify the length of the term of office of each
member he appoints. Of the public mem-
bers first appointed by the governor under
this subsection,
"(1) one member shall serve a two-year
term;
"(2) one member shall serve a
three-year term;
"(3) one member shall serve a four-year
term."
Sec. 44.83.040. Officers and quorum. The directors shall elect
one of their number as chairman and may elect other officers they
determine desirable. The powers of the authority are vested in the
directors, and four directors of the authority constitute a quorum.
Action may be taken and motions and resolutions adopted by the
authority at a meeting by the affirmative vote of at least three
directors. The directors of the authority serve without compensation,
but they shall receive the same travel pay and per diem as provided by
law for board members.(§ 1 ch 278 SLA 1976; am§ 3 ch 156 SLA 1978;
am § 3 ch 118 SLA 1981)
Effect of amendments. -The 1981
amendment substituted "directors" for
"director," substituted "their number" for
"the directors at large" and added "may
elect" preceding "other officers" in the first
sentence and substituted "four" for "three"
preceding "directors" in the second sen-
tence.
Sec. 44.83.045. Qualifications, powers, and duties of officers
and directors. (a) The public directors shall be residents and qualified
487
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§ 44.83.070 ALASKA STATUTES SUPPLEMENT § 44.83.080
voters of Alaska and shall comply with the requirements of AS
39.50.010-39.50.200 (conflict of interests). The public directors shall
serve overlapping four-year terms. ·
(b) A vacancy in a directorship occurring other than by expiration of
a term shall be filled in the same manner as the original appointment,
but for the unexpired portion of the term only.
(c) The authority shall employ an executive director who may, with
the approval of the authority, employ additional staff as necessary. In
addition to its staff of regular employees, the authority may contract
for and engage the services of legal and bond counsel, consultants,
experts, and financial and technical advisors the authority considers
necessary for the purpose of conducting studies, investigations,
hearings, or other proceedings. The board of directors shall establish
the compensation of the executive director. The executive director of
the authority is subject to the provisions of AS 39.25.010-39.25.220.
(§ 4 ch 156 SLA 1978; am § 4 ch 118 SLA 1981)
Effect of amendments. -The 1981
amendment added "'public" preceding
"directors" and substituted "shall" for "at
large must" preceding "be residents" in the
first sentence, added "public" preceding
"directors," deleted "at large" following
"directors" and added "overlapping"
preceding "four-year terms" in the second
, sentence and deleted the former third sen-
tence which read "The four original
directors at large have terms of one, two,
three, and four years, respectively."
Article 2. Purpose and Powers.
Section
70. Purpose of the authority
80. Powers of the authority
Section
90. Power contracts and the Alaska Public
Utilities Commission
Sec. 44.83.070. Purpose of the authority. The purpose of the
authority is to promote, develop and advance the general prosperity
and economic welfare of the people of Alaska by providing a means of
constructing, acquiring, financing and operating
(l) power projects; and
(2) facilities that recover and use waste energy. (§ 1 ch 278 SLA
1976; am § 5 ch 156 SLA 1978; am § 1 ch 133 SLA 1982)
Effect of amendments. -The 1982
amendment, effective June 25, 1982, sub-
stituted paragraphs (1) and (2) for "power
production facilities limited to fossil fuel,
wind power, tidal, geothermal,
hydroelectric, or solar energy production
and waste energy conservation facilities."
Sec. 44.83.080. Powers ofth~ authority. In furtherance ofits cor-
porate purposes, the authority has the following powers in addition to
its other powers:
(1) to sue and be sued;
(2) to have a seal and alter it at pleasure;
(3) to make and alter bylaws for its organization and internal
management;
488
§ 44.83.080 STATE GoVERNMENT § 44.83.080
(4) to make rules and regulations governing the exereise of its corpo-
rate powers;
(5) to acquire, whether by construction, purchase, gift or lease, and
to improve, equip, operate, and maintain power projects;
(6) to issue bonds to carry out any of its corporate purposes and
powers, including the acquisition or construction of a project to be
owned or leased, as lessor or lessee, by the authority, or by another
person, or the acquisition of any interest in a project or any right to
capacity of a project, the establishment or increase of reserves to secure
or to pay the bonds or interest on them, and the payment of all other
costs or expenses of the authority incident to and necessary or
convenient to carry out its corporate purposes and powers;
(7) to sell, lease as lessor or lessee, exchange, donate, convey or
encumber in any manner by mortgage or by creation of any other
security interest, real or personal property owned by it, or in which it
has an interest, when, in the judgment of the authority, the action is
in furtherance of its corporate purposes;
(8) to accept gifts, grants or loans from, and enter into contracts or
other transactions regarding them, with any person;
(9) to deposit or invest its funds, subject to agreements with
bondholders;
(10) to enter into contracts with the United States or any person and,
subject to the laws of the United States and subject to concurrence of
the legislature, with a foreign country or its agencies, for the financing,
construction, acquisition, operation and maintenance of all or any part
of a power project, either inside or outside the state, and for the sale or
transmission of power from a project or any right to the capacity of it
or for the security of any bonds of the authority issued or to be issued
for the project;
(11) to enter into contracts with any person and with the United
States, and, subject to the laws of the United States and subject to the
concurrence of the legislature, with a foreign country or its agencies for
the purchase, sale, exchange, transmission, or use of power from a
project, or any right to the capacity of it;
(12) to apply to the appropriate agencies of the state, the United
States and to a foreign country and any other proper agency for the
permits, licenses, or approvals as may be necessary, and to construct,
maintain and operate power projects in accordance with the licenses or
permits, and to obtain, hold and use the licenses and permits in the
same manner as any other person or operating unit;
(13) to perform reconnaissance studies, feasibility studies, and engi-
neering and design-with respect to power projects;
(14) to enter into contracts or agreements with respect to the exer-
cise of any of its powers, and do all things necessary or convenient to
carry out its corporate purposes and exercise the powers granted in AS
44.83.010 -44.83.510;
489
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§ 44.83.090 ALAsKA STATUTES SuPPLEMENT § 44.83.090
(15) to exercise the power of eminent domain in accordance with AS
09.55.250-09.55.410;
(16) to recommend to the legislature
(A) the issuance of general obligation bonds of the state to finance
the construction of a power project if the authority first determines that
the project cannot be financed by revenue bonds of the authority at
reasonable rates of interest;
(B) the pledge of the credit of the state to-guarantee repayment of all
or any portion of revenue bonds issued to assist in construction of power
projects;
(C) an appropriation from the general fund.
(i) for debt service on bonds or other project purposes; or
(ii) to reduce the amount of debt financing for the project;
(D) an appropriation to the power project fund for a power project;
(E) an appropriation of a part of the income of the renewable
resources investment fund for a power project;
(F) development of a project under financing arrangements with
other entities using leveraged leases or other financing methods;
(G) an appropriation for a power project acquired or constructed
under the energy program for Alaska (AS 44.83.380-44.83.425). (§ 1
ch 278 SLA 1976; am §§ 6-11 ch 156 SLA 1978; am §§ 16, 17 ch 83
SLA 1980; am § 5 ch 118 SLA 1981)
Revisor's notes. -In paragraph (16)
(G), a reference to AS 44.83.400 -
44.83.510 was changed to AS 44.83.380-
44.83.425 to reflect numbering changes
made by the revisor of statutes pursuant to
AS 01.05.031 (b).
Effect of amendments. -The 1981
amendment added subparagraph (G) of
paragraph (16).
Sec. 44.83.090. Power contracts and the Alaska Public
Utilities Commission. (a) The authority shall, in addition to the other
methods which it may find advantageous, provide a method by which
municipal electric, rural electric, cooperative electric, or private elec-
tric utilities and regional electric authorities, or other persons autho-
rized by law to engage in the distribution of electricity may secure a
reasonable share of the power generated by a· project, or any interest
in a project, or for any right to the power and shall sell the power or
cause the power to be sold at the lowest reasonable prices which cover
the full cost of the electricity or services, including capital and
operating costs, debt coverage as considered appropriate by the author-
ity, and other charges that may be authorized by AS 44.83.010 -
44.83.510. Except for a contract or lease entered into under AS
44.83.380 -44.83.425, a contract or lease for the sale,· transmission
and distribution of power generated by a project or any right to the
capacity of it shall provide:
(1) for payment of all operating and maintenance expenses of a
project and costs of renewals, replacements and improvements of it;
490
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SUS I TNA HYDROELECTRIC PRO,.IECT
VOLUf1E 1
EXHIBIT A
PROJECT DESCRIPTION
-SUSITNA HYDROELECTRIC PROJECT
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VOLUME 1
EXHIBIT A
PROJECT DESCRIPTION
TABLE OF CONTENTS
1-PROJECT STRUCTURES-WATANA DEVELOPMENT ........................ .
1.1 -General Arrangement .....................................•.
1.2-Main Dam .......................................•..........
( a) T yp i c a 1 Cr o s s Sect i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(b) Crest Details and Freeboard ...........•..............
(c) Grouting and Pressure Relief System ........••........
(d) Instrumentation ....•. ; .............................. .
1 . 3 -Di version ................................................ .
(a) Tunnels ............................................. .
{b) Cofferdams ...............................•.......•...
(c) Tunnel Portals and Gate Structures .........•.........
(d)· Final Closure and Reservoir Filling ...............•..
1.4-Emergency Release Facilities ............................. .
1. 5 -elut 1 et F ac i 1 it i es ........................................ .
(a) Approach Channel and Intake ......................... .
(b) Intake Gates and Trashracks ........................ ..
(c) Shaft and Tunnel .................................... .
(d) Discharge Structure ................•......•..........
(e) Fixed-Cone Discharge Valves .......•..............•...
(f) Ring Follower Gates ................................ ..
(g) Discharge Area ..................................... ..
1. 6 - M a i n Sp i 11 way ........•.......................... , ........ .
(a) Approach Channel and Control Structure .....•.........
(b) Spi 11 way Gates and Stop logs ........................ ..
{c) Spillway Chute ..............•.........•..............
{ d) F 1 i p Bucket ............... , .......•.•......•........•
1.7 -Emergency Spillway ....................................... .
(a) Fuse Plug· and Apprc}ach Channel ....................... .
{b) Discharge Ch.annel •..•.....•....•....•................
l.B··-Power Intake .... '"' ....•........•.......................•.•...
fa) Intake Structure .................•.......•............•
(b) Approach Chan n e 1 ......................•...•••.•......
{c) Mechani-cal Arr·angement .........•..•..................
l. ·9 -Ffens.toc ks' ..........••...•.•.......... , .....• ., .................. .
(.a·) Steel Liner ••••.•.•...•.....•.....•.............•...•....
(b); €one rete L i ntng •...............••.......•........•....
(c) Grourti-ng a·nGJ. Pressure Rel i:ef System ...•............•.
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TABLE OF CONTENTS (Continued)
1.10 -Powerhouse .............................................. .
(a) Access Tunnels and Shafts .......................... .
(b) Powerhouse Cavern .................................. .
(c) Transformer Gallery ................................ .
(d) Surge Chamber ...................................... .
(e) Grouting and Pressure Relief System ................ .
(f) Cable Shafts ....................................... .
(g) Draft Tube Tunnels ................................. .
1 . 11 - T a i 1 race ................................................ .
1 . 12 -Ac c e s s P 1 an . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a) Access Objectives ................................. ..
(b) Access Plan Selection .............................. .
(c) Description of Access Plan ......................... .
(d) Right-of-Way ....................................... .
(e) Construction Schedule .............................. .
1.13 -Site Facilities ......................................... .
(a) General ............................................ .
(b) Temporary Camp and Village ......................... .
(c) Permanent Town ..................................... .
(d) Site Power and Utilities ........................... .
(e) Contractors• Area ................................. ..
1.14-Relict Channel .......................................... .
(a) Surface Flows ...................................... .
(b) Subsurface Flows ................................... .
(c) Permafrost ......................................... .
(d) Liquefaction ....................................... .
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2 -RESERVOIR DATA -WATANA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2-1
3-TURBINES AND GENERATORS-WATANA ............................... .
3. 1 -Unit Capacity ............................................ .
3.2 -Turbines ................................................. .
3.3 -Generators ............................................... .
(a) Type and Rating .................................... ..
{b) Unit Dimensions ..................................... .
(c) Generator Excitation System ......................... .
3. 4 -Governor System .......................................... .
4-TRANSMISSION FACILITIES FOR WATANA DEVELOPMENT ................. .
4.1-Transmission Requirements ................................ .
4.2 -Description of Facilities ................................ .
(a) Corridor ............................................ .
(b) Components .......................................... .
(c) Right-of-Way ........................................ .
(d) Transmission Lines .................................. .
(e) Switching and Substations ......................•.....
(f) Cable Crossing ...................................... .
(g) Dispatch Center -Energy Management Center
and Communications .......•...........................
4.3-Construction Staging ...................................... .
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TABLE OF CONTENTS (Continued)
5-APPURTENANT MECHANICAL AND ELECTRICAL EQUIPMENT-WATANA ....... .
5.1-Miscellaneous Mechanical Equipment ....................... .
(a) Powerhouse Cranes ................................... .
(b) Draft Tube Gates .................................... .
(c) Surge Chamber Gate Crane ............................ .
(d) Miscellaneous Cranes and Hoists ..................... .
(e) Elevators ................ · ........................... .
(f) Power Plant Mechanical Service Systems .............. .
(g) Surface Facilities Mechanical Service Systems ....... .
(h) Machine Shop Facilities ............................. .
5.2-Accessory Electrical Equipment ........................... .
(a) Transformers and HV Connections ..................... .
(b) Main Transformers .................................. ..
(c) Generator Isolated Phase Bus ........................ .
(d) Generator Circuit Breakers .......................... .
(e) 345 kV Oil-Filled Cable ............................. .
(f) Contra 1 Systems ..................................... .
(g) Station Service Auxiliary AC and DC Systems ......... .
(h) Grounding System .................................... .
(i) Lighting System ..................................... .
(j) Communications ...................................... .
5.3-Switchyard Structures and Equipment ...................... .
(a) Single Line Diagram ................................. .
(b) Switchyard Equipment ................•................
(c) Switchyard Structures and Layout .................... .
6 -LANDS OF THE UNITED STATES ..................................... .
7-PROJECT STRUCTURES-DEVIL CANYON DEVELOPMENT .................. .
7.1 -General Arrangement ...................................... .
7 . 2 -Arch Dam ................................................. .
(a) Foundations ......................................... .
(b) Arch Dam Geometry ................................... .
(c) Thrust Blocks ....................................... .
7.3-Saddle Dam ............................................... .
(a) Typical Cross Sect ion ............................... .
(b) Crest Details and Freeboard ......................... .
(c) Grouting and Pressure Relief System ................. .
(d) Instrumentation ..................................... .
7.4 -Diversion ................................................ .
(a) General ............................................. .
(b) Cofferdams .......................................... .
(c) Tunnel Portals and Gates ............................ .
(d) Final Closure and Reservoir Filling ................. .
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TABLE OF CONTENTS (Continued)
7 . 5 -0 ut 1 et F ac i 1 it i es ......................................... .
(a) Outlet ............................................... .
(b) Fixed-Cone Valves .................................... .
(c) Ring Follower Gates ........•..........................
(d) Trashracks ........................................... .
(e) Bulkhead Gates ....................................... .
7.6-Main Spillway ............................................. .
(a) Approach Channel and Control Structure ............... .
(b) Spillway Chute ....................................... .
(c) Fl i p Bucket .......................................... .
(d) Plunge Pool .......................................... .
7.7-Emergency Spillway ........................................ .
(a) Fuse Plug and Approach Channel ....................... .
(b) Discharge Channe 1 .................................... .
7.8-Devil Canyon Power Facilities ............................. .
(a) Intake Structure ..................................... .
(b) Intake Gates ......................................... .
(c) Intake Bulkhead Gates ................................ .
(d) Intake Gantry Crane .................................. .
7. 9 -Penstocks ................................................. .
(a) Steel Liner .......................................... .
(b) Concrete Liner ....................................... .
(c) Grouting and Pressure Relief System .................. .
7.10-Powerhouse and Related Structures ........................ .
(a) Access Tunnels and Shafts ............................ .
(b) Powerhouse Cavern .................................... .
(c) Transformer Gallery .................................. .
(d) Surge Chamber ........................................ .
(e) Draft Tube Tunnels .................................. ..
7.11-Tailrace Tunnel ........................•..................
7.12 -Access Roads ............................................. .
(a) Description of Access Plan ........................... .
(b) Rail Extension ....................................... .
(c) Connecting Road ...................................... .
(d) Construction Schedule ................................ .
(e) Right-of-Way ......................................... .
7.13-Site Facilities .......................................... .
(a) Temporary Camp and Village .....•.....•..•.............
(b) Site Power and Utilities ........................... .
(c) Contractors• Area ....................................•
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9-TURBINES AND GENERATORS-DEVIL CANYON .......................... A-9-1
9.1 -Unit Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-9-1
9.2 -Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-9-1
9.3 -Generators ................................................ A-9-1
9.4-Governor System ........................................... A-9-2
10-TRANSMISSION LINES-DEVIL CANYON ............................. .
11-APPURTENANT EQUIPMENT-DEVIL CANYON .......................... .
11.1-Miscellaneous Mechanical Equipment ..................... .
{a) Powerhouse Cranes ................................. .
{b) Draft Tube Gates ................................. ..
(c) Draft Tube 'Gate Crane ............................. .
(d) Miscellaneous Cranes and Hoists ................... .
{e) Elevators ......................................... .
(f) Power Plant Mechanical Service Systems ............ .
{g) Surface Facilities Mechanical Service Systems ..... .
(h) Machine Shop Facilities ........................... .
11.2 -Accessory Electrical Equipment ......................... .
(a) General ........................................... .
(b) Transformers and HV Connections ................... .
(c) Main Transformers ................................. .
(d) Generator Isolated Phase Bus ..................... ..
{e) 345 kV Oil-Filled Cable ·~····· .................... .
(f) Control Systems .................................. ..
(g) Stat ion Service Auxiliary AC and DC Systems ....... .
{h) Other Accessory Electrical Systems ................ .
11.3 "" Switchyard Structures and Equipment ................... ..
(a) Single Line Diagram .............................. ..
{b) Switchyard Structures and Layout ••...........•.....
REFERENCES
LIST OF TABLES
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LIST OF TABLES
A.l Principal Project Parameters
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EXHIBIT A -PROJECT DESCRIPTION
The Susitna Hydroelectric Project will comprise two major developments
on the Susitna River some 180 m"iles north and east of Anchorage,
Alaska. The first phase of the project will be the Watana project
which will incorporate an earthfill dam together with associated diver-
sion, spillway, and power facilities. The second phase will include
the Devil Canyon concrete arch dam and associated facilities.
The description of the Watana project is presented in the following
Sections 1 through 5; the Devil Canyon project is described in Sections
7 through 11. Project lands for the entire project are discussed in
Section 6. Reference drawings will be found in Exhibit F.
1 -PROJECT STRUCTURES -WATANA DEVELOPMENT
1.1 -General Arrangement
The Watana Dam will create a reservoir approximately 48 miles long,
with a surface area of 38,000 acres, and a gross storage capacity of
9,500,000 acre-feet at Elevation 2185, the normal maximum operating
level.
The maximum water surface elevation during flood conditions will be
2201. The minimum operating level of the reservoir will be 2065, pro-
viding a live storage during normal operation of 3,700,000 acre-feet.
The dam wi 11 be an embankment structure with a central core. The nom-
inal crest elevation of the dam will be 2205, with a maximum height of
885 feet above the foundation and a crest length of 4,100 feet. The
embankment crest will initially be constructed to Elevation 2210 to
allow for potential seismic settlement. The total volume of the struc-
ture will be approximately 62,000,000 cubic yards. During construc-
tion, the river will be diverted through two concrete-lined diversion
tunnels, each 38 feet in diameter and 4100 feet long, on the north bank
of the river.
The power intake will be located on the north bank with an approach
channel excavated in rock. The intake will be a concrete structure
with multi-level gates capable of operation over the full 120-foot
drawdown range. From the intake structure, six concrete-1 ined pen-
stocks, each 17 feet in diameter, will lead to an underground power-
house complex housing six 170 MW generating units with Francis turbines
and semi-umbrella type generators.
Access to the powerhouse complex will be by means of an unlined access
tunnel and a road which will pass from the crest of the dam, down the
south bank of the river valley and across the embankment near the down-
stream toe. Turbine discharge will flow through six draft tube tunnels
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to a surge chamber downstream from the powerhouse. The surge chamber
will discharge to the river through two 34-foot diameter concrete-lined
tailrace tunnels. A separate transformer gallery just upstream from
the powerhouse cavern will house nine single-phase 15/345 kV transform-
ers (three transformers per group of two generators). The transformers
will be connected by three 345 kV single-phase, oil-filled cables
through two cable shafts to the switchyard at the surface.
Outlet facilities will also be located on the north bank to discharge
all flood flows of up to 24,000 cfs. With 7000 cfs passing through the
powerhouse, the combination of the powerhouse and the outlet facilities
will handle 31,000 cfs, during the estimated 50-year flood. The pass-
age of this flood assumes only two units of Watana operating and the
pool elevation going from 2185 to 2193 from flood surcharge. The up-
stream gate structure will be adjacent to the power intake and will
convey flows through a 28-foot diameter concrete-1 ined tunnel to six
fixed-cone discharge valves downstream of the dam. These valves will
be housed beneath the spillway flip bucket and will be used to dissi-
pate energy and eliminate undesirable nitrogen supersaturation in the
river downstream from the dam during spillway operations.
The main spillway will also be located on the north bank. This spill-
way will consist of an upstream ogee control structure with three ver-
tical fixed-wheel gates and an inclined concrete chute and flip bucket
designed to pass a maximum discharge of 120,000 cfs. This spillway,
together with the outlet facilities and the powerhouse, will be capable
of discharging the estimated 10,000-year flood (156,000 cfs). An emer-
gency spillway and fuse plug on the north bank will provide sufficient
additional capacity to permit discharge of the Probable Maximum Flood
(PMF} without overtopp·ing the dam. Emergency release facilities will
be located in one of the diversion tunnels after closure to allow low-
ering of the reservoir over a period of time to permit emergency in-
spection or repair of impoundment structures.
A local depression on the north rim of the reservoir upstream of the
dam will be closed by a low freeboard dike with a crest elevation of
2210. Provision will be made for monitoring potential seepage through
this area and placement of appropriate filter blankets at Tsusena Creek
downstream.
1.2 -Main Dam
The main dam at Watana will be located at mile 184 above the mouth of
the Susitna River, in a broad U-shaped valley approximately 2.5 miles
upstream of the Tsusena Creek confluence. The darn will be of compacted
earth and rockfill construction and will consist of a central imper-
vious core protected by fine and coarse filters upstream and down-
stream. The downstream outer shell will consist of rockfill and allu-
vial gravel underlain by a toe drain and filter, and the upstream outer
shell of clean alluvial gravel. A typical cross section is shown on
Plate F6 and is described below.
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(a) Typical Cross Section
The central core slopes will be 1H:4V with a top width of 15 feet.
The thickness of the core at any horizontal section will be
slightly more than 0.5 times the head of water at that section.
Minimum core-foundation contact will be 50 feet, requiring flaring
of the cross section at each end of the embankment.
The upstream and downstream filter zones will increase in thick'-
ness from 45 and 30 feet respectively near the crest of the dam to
a maximum in excess of 100 feet at the filter found at ion contact.
They are sized to provide protection against possible piping
through transverse cracks that could occur because of sett 1 ement
or resulting from internal displacement during a seismic event.
The shells of the dam will consist primarily of compacted alluvial
gravels. The saturated upstream shell will .consist of compacted
clean alluvial gravels processed to remove fines so that not more
than 10 percent of the materials are less than 3/8 inch in size to
minimize pore pressure generation and ensure rapid dissipation
should seismic shaking occur. The downstream shell will be un-
saturated and therefore will not be affected by pore pressure gen-
eration during a seismic event. This will be constructed with
compacted, unprocessed alluvial gravels and rockfill from the sur-
face or underground excavations.
Protection against wave and ice action on the upstream slope will
consist of a 10-foot layer of riprap comprising quarried rock up
to 36 inches in size.
The volume of material required to construct the Watana Dam is
presently estimated as follows:
Core material:
Fine filter material:
Coarse filter material:
Gravel and rockfill material:
{b) Crest Details and Freeboard
8,250,000 cubic yards
4,260,000 cubic yards
3,560,000 cubic yards
45,500,000 cubic yards
The typical crest detai 1 is shown in Plate F7. Because of the
r-narrowing at the dam crest, the filter zones are reduced in width
and the upstream and downstream coarse filters are eliminated. A
1 ayer of fi 1 ter fabric is incorporated to protect the core mate-
rial from damage by frost penetration and desiccation, and to act
as a coarse filter where required.
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The nominal crest elevation of the Watana Dam, after estimated
static and seismic settlement have taken place, will be 2205.
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Allowances will be made during construction of the dam to allow
for static settlement of the fill following completion, settlement
on saturation of the upstream shell, and possible settlement be-
cause of seismic shaking.
An allowance will be made for settlement due to seismic loading of
up to 0.5 percent of the height of the dam, or approximately 5
feet. The elevation at the center of the dam prior to any seismic
settlement will therefore be 2210. At each abutment the crest
elevation will be 2207, allowing for 2 feet of seismic settlement.
Under normal operating conditions the minimum freeboard relative
to the maximum operating pool elevation of 2185 will therefore be
20 feet, not including settlement allowances.
During construction of the dam, additional allowances will be made
for post-construction settlement of the dam under its own weight
and for the effects of saturation on the upstream gravel fill when
the reservoir is first filled. These allowances will be provided
in construction specifications and are consequently not shown on
the drawings at this time. For initial cost estimating purposes,
1 percent of the height of the dam has been allowed, or approx i-
mately 9 feet. The additional height constructed into the dam for
these settlements will be accomplished by steepening both slopes
above approximately Elevation 2090 on the upstream slope and 2110
on the downstream slope. These settlement allowances are conser-
vative when compared with observed sett 1 ements of similar struc-
tures. However, provision will be made during construction for
placement of additional fill at the crest should settlements
exceed these estimates.
The freeboard allowance of 20 feet is based on the worst con-
ceivable combination of flood, wave and runup water levels which
may occur after all settlement has taken place.
Ultimate security against overtopping of the main dam will be pro-
vided by the emergency spillway. Under normal operation this
spillway will be sealed by a fuse plug dam across the entrance
channel. This plug wi 11 be a gravel dam with a lowest crest el e-
vation of 2200 and with strict design of the core, upstream face,
and shell materials to ensure that it will erode rapidly if over-
topped, allowing flood flows to be discharged freely through the
emergency spillway. The maximum reservoir level during passage of
the PMF is estimated as 2201.5 prior to erosion of the plug. The
location and typical cross section through the fuse plug are shown
on P 1 ate Fl8 .
(c) Grouting and Pressure Relief System
A combination of consolidation grouting, cutoff curtain grouting
and installation of a downstream pressure relief (drainage) system
wi 11 be undertaken for the Watana Dam.
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(d)
The curtain grouting and drilling for the pressure relief system
will be largely carried out from galleries in the rock foundation
in the abutments and beneath the dam. Details of the grouting,
pressure relief and galleries are shown on Plate F8.
Instrumentation
Instrumentation will be installed to provide monitori.ng of perfor-
mance of the dam and foundation during construction as well as
during operation. Instruments for measuring internal vertical and
horizontal displacements, stresses and strains, and total and
fluid pressures, as well as surface monuments and markers, will be
installed. Estimates of quantities of instrumentation have been
allowed for conservatively on the basis of currently available
geotechnical data for the site. These include:
-Piezometers
Piezometers are used to measure static pressure of fluid in the
pore spaces of soil, rockfill and in the rock foundation.
-Internal Vertical Movement Devices
• Cross-arm settlement devices as developed by the USBR
Various versions of the taut-wire devices which have been
developed to measure internal settlement
Hydraulic-settlement devices of various kinds
-Internal Horizontal Movement Devices
. Taut-wire arrangements
Cross-arm devices
Inclinometers
Strain meters
-Uther Measuring Devices
Stress meters
Surface monuments and alignment markers
Seismographic records and seismoscopes
Flow meters to record discharge from drainage and pressure
relief system
1.3 -Diversion
(a) Tunnels
Diversiatl of the river flow during construction will be accom-
plished with two 38-foot di,ameter circular diversion t11nnels. The
tunnels wi 11 be concrete-lined and located on the north bank of
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the river. The tunnels are 4,050 feet and 4,140 feet in length.
The diversion tunnels are shown in plan and profile on Plate F9.
The tunne 1 s are designed to pass a flood with a ret urn frequency
of 1:50 years, equivalent to peak inflow of 87,000 cfs. Routing
effects are small, and thus at peak flow the tunnels will dis-
charge 80,500 cfs. The estimated maximum water surface elevation
upstream from the cofferdam for this discharge will be 1536.
The upper tunnel (Tunnel No. 1) wi 11 be converted to the permanent
low-level outlet after construction. A local enlarging of the
tunnel diameter to 45 feet will accornnodate the low-level outlet
gates and expansion chamber.
(b) Cofferdams
The upstream cofferdam wi 11 be a zoned embankment founded on the
closure dam (see Plate FlO). The closure dam will be constructed
to Elevation 1475 based on a low water elevation of 1470, and will
consist of coarse material on the upstream side grading to finer
material on the downstream side. Provision has been made for a
cutoff through the river bed alluvium to bedrock to control seep-
age during dam construction. The cement/bentonite slurry wall
cutoff and downstream pumping system is shown on Plate FlO.
Above Elevation 1475 the cofferdam will be a zoned embankment con-
sisting of a central core, fine and coarse upstream and downstream
filters, and rock and/or gravel supporting shell zones with rip-
rap on the upstream face to resist ice action. This cofferdam
wi 11 provide a 9-foot freeboard for wave runup and ice protec-
tion.
The downstream cofferdam will consist of only a closure dam con-
structed from approximate Elevation 1440 to 1472, and consisting
of coarse material on the downstream side grading to finer mater-
ial on the upstream side. Control of underseepage similar to that
for the upstream cofferdam will be required.
(c) Tunnel Portals and Gate Structures
A reinforced concrete gate structure wi 11 be lac ated at the up-
stream end of each tunnel, each housing two closure gates (see
Plate Fll) .
Each gate will be 38 feet high by 15 feet wide separated by a
center concrete pier. The gates will be of the fixed-roller ver-
tical lift type operated by a wire rope hoist. The gate hoist
will be located in an enclosed, heated housing. Provision will be
made for heating the gates and gate guides. The gate in Tunnel
No. 1 will be designed to operate with the reservoir at Elevation
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1536, a 46-foot operating head. The gate in Tunnel No. 2 will be
~""' designed to operate with the reservoir at Elevation 1536, a 116-
foot operating head. The gate structures for each tunnel will be
designed to withstand external (static) heads of 135 feet (No. 1)
and 520 feet (No. 2), respectively. The downstream portals will
be reinforced concrete structures with guides for stop logs ..
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(d) Final Closure and Reservoir Filling
As discussed above, the upper diversion tunnel (No. 1) wil.l be
converted to a low-l~vel outlet or emergency release facility
during construction.
It is estimated that one year will be required to construct and
install the permanent low-level outlet in the existing tunnel.
This will require that the lower tunnel (No. 2) pass all flows
during this period. The main dam will, at this time, be at an
elevation sufficient to allow a 100-year recurrence interval flood
(97,000 cfs) to pass through Tunnel No. 2. This flow will result
in a reservoir elevation of 1625. During the construction of the
low level outlet, the intake gates in the upper tunnel (No. 1)
will be closed. Prior to commencing operation of the low-level
out 1 et, coarse trashracks wi 11 be installed at the entrance to
Tunnel No. 1 intake structure.
Upon commencing operation of the low-level outlet, the lower tun-
nel (No. 2) will be closed with the intake gates, and construction
of the permanent plug and filling of the reservor will commence.
When the lower tunnel (No. 2) is closed the main dam crest will
have reached an elevation sufficient to start filling the reser-
voir and still have adequate storage available to store a 250-year
recurrence period flood.
During the filling operation, the low-level outlet will pass sum-
mer flows of up to 12,000 cfs and winter flows of up to 800 cfs.
In case of a large flood occurring during the filling operation,
the low-level outlet would be opened to its maximum capacity of
30,000 cfs until the reservoir pool was lowered to a safe level.
The filling of the reservoir is estimated to take four years to
complete to the full reservoir operating elevation of 2185. After
three years of filling, the reservoir will be at Elevation 2150
and will allow operation of the power plant to commence.
The filling sequence is based on the main dam elevation at any
time during construction and the capability of the reservoir stor-
age to absorb the inflow volume from a 250-year recurrence period
flood without overtopping the main dam.
A-1-7
1.4 -Emergency Release Facilities
The upper diversion Tunnel No. 1 will be converted to a permanent low-
level outlet, or emergency release facility. These facilities will be
used to pass the required minimum discharge during the reservoir fill-
ing period and will also be used for draining the reservoir in an emer-
gency.
During operation, energy will be dissipated by means of two gated con-
crete plugs separated by a 34.0-foot length of tunnel (see Plate Fl9).
Each plug will contain three water passages.
Bonnetted type high pressure slide gates will be installed in each of
the passages in the tunnel plugs. The gate arrangement will consist of
one emergency gate and one operating gate in the ·upstream plug and one
operating gate in the downstream plug. A 340-foot length of tunnel
between plugs will act as an energy dissipating expansion chamber.
The 7.5-foot by 11.5-foot gates will be designed to withstand a total
static head of about 740 feet; however, they will only be operated with
a maximum head of about 600 feet.
During operation, the operating gate opening in th€ upstream plug will
be equal to the opening of the corresponding gate in the downstream
plug. This should effectively balance the head across the gates. The
maximum operating head across a gate should not exceed 340 feet.
Each gate will have a hydraulic cylinder operator designed to raise or
lower it against a maximum head of 600 feet. Three hydraulic units
will be installed, one for the emergency gates, one for the upstream
operating gates and one for the downstream operating gates. Each gate
will have an opening/closing time of about 30 minutes. A grease injec-
tion system will be installed in each gate to reduce frictional forces
when the gates are operated.
The design of the gate will be such that the hydraulic cylinder as well
as the cylinder packing may be inspected and repaired without dewater-
ing the area around the gate. All gates may be locally or remotely
operated.
To prevent concrete erosion, the conduits in each of the tunnel plugs
will be steel-lined. An air vent will be installed at the downstream
side of the operating gate in the downstream plug. Energy dissipation
at the downstream tunnel exit will be accomplished by means of a con-
crete flip bucket in the exit channel (Plate F20).
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1.5-Outlet Facilities
The primary function of the outlet faci1ities will be to discharge
floods with recurrence frequencies of up to once in 50 years after they
have been routed through the Watana reservoir. The use of fixed-cone
discharge valves will ensure that downstream erosion will be minimal
and the dissolved nitrogen content in the discharges will be reduced
sufficiently to avoid harmful effects on Ure downstream fish popula-
tion. A secondary function will be to provide the capability to rapid-
ly draw down the reservoir during an extreme emergency situation.
The facilities will be located on the north bank and will consist of a
gate structure, pressure tunnel, and an energy dissipation and control
structure housing located beneath the spillway flip bucket. This
structure wi 11 accomnodate six fixed-cone valves which wi 11 discharge
into the river 105 feet below.
(a) Approach Channel and Intake
The approach channel to the outlet facilities will be shared with
the power intake. The channel will be 350 feet wide and excavated
,-to a maximum depth of approximately 150 feet in the bedrock with
an invert elevation of 2025. The gate structure will be founded
deep in the rock at the forebay end of the channel. The single
intake passage will have an invert elevation of 2027. It will be
divided upstream by a central concrete pier which will support
steel trashracks located on the face of the structure, spanning
the openings to the water passage. The racks will be split into
panels mounted one above the other and run in vertical steel
guides installed at the upstream face. The trashrack panels can
be raised and lowered for cleaning and maintenance by a mobile
gantry crane located at deck lever.
Two fixed-wheel gates wi 11 be located downstream of the racks be-
tween the pier and each of the sidewalls. These gates will be op-
erated by a mechanical hoist mounted above the deck of the struc-
ture. The fixed-wheel gates will not be used for flow control but
will function as c1osure gates to isolate the downstream tunnel
~"""· and allow dewatering for maintenance of the tunnel or ring gates
located in the discharge structure. Stop log guides will be pro-
vided upstream from the two fixed-wheel gates to permit dewatering
of the struct~.re and access to the gate guides for maintenance.
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(b) Intake Gates and Trashracks
The gates will be of the fixed-whee 1 vertical 1 ift type with down-
stream skin.plate and seals. The nominal gate size will be 14 feet
'Wide by 28 feet high. Each gate will be operated by a single drum
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wire rope hoist mounted in an enclosed tower structure at the top
of the intake. The height of the tower structure will permit
raising the gates to the intake deck for inspection and mainten-
ance.
The gates will be capable of being lowered either from a remote
control room or locally from the hoist area. Gate raising will be
from the hoist area only.
The trashracks wi 11 have a bar spacing of 6 inches and will be
designed for a maximum differential head of 40 feet. The maximum
net velocity through the racks will be 12 ft/sec. Provision will
be made for monitoring the head loss across the trashracks.
(c) Shaft and Tunnel
Discharges will be conveyed from the upstream gate structure by a
concrete-lined tunnel terminating in a steel liner and manifold.
The manifold will branch into six steel-lined tunnels which will
run through the main spillway flip bucket structure to the fixed-
cone valves mounted in line with the downstream face.
The water passage will be 28 feet in diameter as far as the steel
manifold. The upstream concrete-lined portion will run a short
distance horizontally from the back of the intake structure before
dipping at an angle of 55° to a lower level tunnel of similar
cross section. The lower tunnel will run at a 5 percent gradient
to a centerline elevation of 1560 approximately 450 feet upstream
of the flip bucket. At this point the depth of overlying rock is
insufficient to withstand the large hydrostatic pressure which
will occur within the tunnel. Downstream of this point the tunnel
will be steel-lined. The steel liner will be 28 feet in diameter
and embedded in mass concrete filling the space between the liner
and the surrounding rock. The area between the outside face of
the liner and the concrete will be contact grouted.
(d) Discharge Structure
The concrete discharge structure is shown on Plate Fl5. It will
form a part of the flip bucket for the main spillway and will
house the fixed-cone valves and individual upstream ring follower
gates. The valves will be set with a centerline elevation of 1560
and will discharge into the river approximately 105 feet below.
Openings for the valves wi 11 be formed in the concrete and the
valves will be recessed within these openings sufficiently to
allow enclosure for ease of maintenance and heating of the movable
valve sleeves. An access gallery upstream from the valves will
run the length of the discharge structure, and will terminate in
the access tunnel and access road on either side of the structure.
A-1-10
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Housing for the ring follower gates will be located upstream from
the fixed-cone valve chambers. The ring follower gates will serve
to isolate the discharge valves. Provision will be made for
relatively easy equipment maintenance and removal by means of a
25-ton service crane, transfer trolley and individual 25-ton mono-
rail t:10i sts.
(el Fixed-Cone Discharge Valves
(f)
Six 78-inch diameter fixed-cone discharge valves will be installed
at the downstream end of the outlet manifold, as shown on Plate
Fl5. The valves will be operated by two hydraulic cylinder oper-
ators. The valves may be operated either locally or remotely.
Ring Follower Gates
A ring follower gate will be installed upstream from each valve
and will be used:
-To permit inspection and maintenance of the fixed-cone valves;
-To relieve the hydrostatic pressure on the fixed-cone valves
when they are in the closed position; and
-To close against flowing water in the event of malfunction or
failure of the valves.
The ring follower gates will have a nominal diameter of 90 inches
and will be designed to withstand a total static head of 630
feet.
The ring follower gates will be designed to be lowered under flow-
ing water conditions and raised under balanced head conditions. A
grease injection system will be installed in each gate to reduce
frictional forces when the gates are operated. The gates will be
operated by hydraulic cylinders from either a local or remote
location.
(g) Discharge Area
Immediately downstream from the discharge structure, the rock will
be excavated at a slope of 2H:3V to a lower elevation of 1510.
This face will be heavily reinforced by rock bolts and protected
by a concrete slab anchored to the face. The lower level will
consist of unlined rock extending to the river.
1.6 -Main Spillway
The main spillway will provide discharge capability for floods exceed-
ing the capacity of the outlet facilities. The combined total capacity
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of the main sp·illway and outlet facilities will be sufficient to pass
routed floods with a frequency of occurrence of up to once in 10,000
years.
The main spillway, shown on Plate Fl2, will be located on the north
bank of the river and will consist of an approach channel, a gated agee
control structure, a concrete-lined chute, and a flip bucket.
The spillway is designed to discharge flows of up to 120,000 cfs with a
corresponding reservoir elevation of 2193.5. The total head dissipated
by the spillway is approximately 730 feet.
(a) Approach Channel and Control Structure
The approach channel will be excavated to a maximum depth of
approximately 100 feet into rock. It will be located on the south
side of the power intake and, in order to minimize its length, it
will be partially integrated with the power approach channel up-
stream of the intake structure.
The concrete contra l structure will be located at the end of the
approach channel, adjacent to the north dam abutment in line with
the dam crest. Flows will be controlled by three 49-foot high by
36-foot wide vertical lift gates, as shown on Plate Fl3. The
structure will be constructed in individual monoliths separated by
construction joints. The main access route to the dam will pass
across the roadway deck and along the dam crest.
Hydraulic model tests will be undertaken during the detailed de-
sign stage to confirm the precise geometry of the control struc-
ture.
The sides of the approach channel will be excavated to 1H:4V
slopes. Only localized rock bolting and shotcrete support are
required. The control structure will be founded deep in sound
rock and consolidation grouting is not anticipated. However,
minor shear or fracture zones passing through the foundation may
require dental excavation, concrete backfill and/or consolidation
grouting. The slope of the contact surface between the dam core
and the spillway control structure will be constructed at 1H:3V to
ensure sufficient contact stress and therefore prevent leakage.
The main dam grout curtain and drainage system will pass beneath
the structure. Access to the grouting tunnels will be via a ver-
tical shaft within the control structure side wall and a gallery
running through the agee weir.
(b) Spillway Gates and Stoplags
The three spillway gates will be of the fixed-wheel vertical lift
type operated by double drum wire rope hoists located in an en-
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closed tower structure. The gate size is 36 feet wide by 49 feet
high, including freeboard allowance. The gates will have upstream
skinplates and will be totally enclosed to permit heating in the
event that winter operation is necessary. Provision will also be
made for heating the gate guides.
The height of the tower and bridge structure will permit raising
of the gates above the top of the spillway pier for gate inspec-
tion and maintenance.
An emergency engine will be provided to enable the gates to be
raised in the event of loss of power to the spillway gate hoist
motors.
Stoplog guides will be installed upstream of each of the three
spillway gates. One set of stoplogs will be provided to permit
servicing of the gate guides.
Spill way Chute
The control structure will discharge down an inclined chute that
tapers slightly until a width of 80 feet is reached. A constant
width of 80 feet is maintained over the remainder of its length.
Convergence of the chute walls will be gradual to minimize any
shock wave development.
The chute section will be rectangular in cross section, excavated
in rock, and lined with concrete anchored to the rock. An exten-
sive underdrainage system will be provided to ensure stability of
the structure. The dam grout curtain and drainage system wi 11
also extend under the spillway control structure utilizing a gal-
lery through the mass concrete rollway. A system of box drains
will be constructed in the rock under the concrete slab in a her-
ringbone pattern at 20 feet spacing for the entire length of the
spillway. To avoid blockage of the system by freezing of the sur-
face drains, a drainage gallery will be excavated to a depth of 30
feet over the entire length of the spillway. Drain holes from the
surface drains will intersect the gallery. Drainage holes drilled
into the high rock cuts will also ensure increased stability of
excavations.
A series of four aeration galleries will be provided at intervals
down the chute to prevent cavitation damage of the concrete.
Details of these aeration devices are shown in Plate F14.
Flip Bucket
The function of the f1 i p bucket will be to direct the spill way
flow clear of the concrete structures and well downstream into the
river below. A mass concrete block will form the flip bucket for
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the main spillway. Detailed geometry of the bucket, as well as
dynamic pressures on the floor and walls of the structure, will be
confirmed by model studies.
1.7 -Emergency Spillway
The emergency spillway will be located on the north side of the river
upstream from the main spillway and power intake structure (see Plate
Fl8). The emergency spillway will consist of a long straight chute
excavated in rock and leading in the direction of Tsusena Creek. An
erodible fuse plug, consisting of an impervious core and fine gravel
materials, will be constructed at the upstream end. The plug will be
designed to wash away when overtopped, releasing flows of up to 120,000
cfs in excess of the combined main spillway and outlet facility capac-
ities, thus preventing overtopping of the main dam under PMF condi-
tions.
(a) Fuse Plug and Approach Channel
The approach channel to the fuse plug will be excavated in rock
and will have a width of 310 feet and invert elevatlon of 2170.
The main access road to the dam and powerhouse will cross the
channel by means of a bridge. The fuse plug will close the ap-
proach channel, and will have a maximum height of 31.5 feet with a
crest elevation of 2201.5. The plug will have a core up to 10
feet wide, steeply inclined in the upstream direction, with fine
filter zones upstream and downstream. It will be supported on a
downstream erodible shell of crushed stone or gravel up to 1.5
inches in diameter. The crest of the plug will be 10 feet wide
and will be traversed by a 1.5-foot deep pilot channel. The prin-
ciple of the plug is based on erosion progressing rapidly downward
and laterally from the pilot channel as soon as water levels rise
above the channel invert.
(b) Discharge Channel
The rock channel downstream from the fuse plug will narrow to 200
feet and continue in a straight line over a distance of 5000 feet
at gradients of 1.5 percent to 5 percent in the direction of
Tsusena Creek. The flow will discharge into a small valley on the
west side of and separate from the area of the relict channel. It
is estimated that flows down the channel would continue for a
period of 20 days under PMF conditions. Some erosion in the
channel would occur, but the integrity of the main dam would not
be impaired. The reservoir would be drawn down to Elevation 2170.
Reconstruction of the fuse plug would be required prior to refill-
ing of the reservoir.
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1.8 -Power Intake
(a) Intake Structure
The power intake will be a concrete structure located deep in the
rock on the north bank. Access to the structure wi 11 be by road
from the south side of the emergency spillway bridge.
In order to draw from the reservoir surface over a drawdown range
of 120 feet, four openings will be provided in the upstream con-
crete wall of the structure for each of the six independent power
·intakes. The upper opening will always be open, but the lower
three openings can -be closed off by sliding steel shutters oper-
ated in a common guide. All openings will be protected by up-
stream trashracks. A heated boom wi 11 operate in guides upstream
from the racks following the water surface, keeping the racks ice
free.
A lower control gate will be provided in each intake unit. A
single set of upstream bulkhead gates will be provided for routine
maintenance of the six intake gates. In an emergency, stoplogs
can be installed on the trashrack guides to permit work on the
trashracks or shutter guides.
The overall base width of the intake will be 300 feet, providing a
minimum spacing of penstock tunnel excavations of 2.5 times the
excavated diameter.
The upper level of the concrete structure will be set at Elevation
2201. The level of the lowest intake is governed by the vortex
criterion for flow into the penstock from the minimum reservoir
level elevation of 2065. The foundation of the structure will be
approximately 180 feet below existing ground level and is expected
to be in sound rock.
Mechanical equipment will be housed in a steel-frame building on
the upper level of the concrete structure. ·The general arrange-
ment of the power intake is shown on Plate F24.
(b) Approach Channel
The overall width of the approach channel is governed by the com-
bined width of the power intake and the outlet facilities gate
structure, and will be approximately 350 feet. The length of the
channel will be 1000 feet.
A-1-15
The maximum flow in the intake approach channel wi 11 occur when
six machines are operating and the outlet facilities are discharg-
ing at maximum design capacity. With the reservoir drawn down to
Elevation 2065, the velocity in the approach channel will be
3.5 ft/sec, which will not cause any erosion problems. Velocities
of 10 ft/sec may occur where the intake approach channel inter-
sects the approach channel to the main spillway.
(c) Mechanical Arrangement
(i) Ice Boom
A heated boom will be installed in guides immediately up-
stream from the trashracks for each of the six power in-
takes. The boom will be operated by a movable hoist and
will automatically follow the reservoir level. The boom
will serve to minimize ice accumulation in the trashrack
and intake shutter area, and prevent thermal ice-loading on
the trashracks.
( i i) Trashracks
Each of the six power intakes will have four sets of trash-
racks, one set in front of each intake opening. Each set
of trashracks will be in two sections to facilitate hand-
1 ing by the intake service crane. Each set of trashracks
will cover an opening 30 feet wide by 26 feet high. The
trashracks will have a bar spacing of 6 inches and will be
designed for a maximum differential head of 20 feet.
(iii) Intake Shutters
Each of the six power intakes will have three intake shut-
ters which will serve to prevent flow through the openings
behind which the shutters will be installed. As the reser-
voir level drops, the sliding shutters will be removed as
necessary using the intake service crane.
Each of the shutters will be designed for a differential
head of 15 feet. The lowest shutter at each power intake
will incorporate a flap gate which, with a 15-foot differ-
ential head across the shutter, will allow maximum turbine
flow through the gate. This will prevent failure of the
shutters in the event of accidental blocking of all intake
openings.
The shutter guides will be heated to facilitate removal in
sub-freezing weather. In addltion, a bubbler system will
be provided in the intake behind the shutters to keep the
intake structure water surface free of ice.
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( i v) Intake Service Crane
A single overhead traveling-bridge type intake service
crane will be provided in the intake service building. The
crane will be used for:
-Servicing the ice bulkhead and ice bulkhead hoist
-Handling and ~leaning the trashracks
-Handling the intake shutters
-Handling the intake bulkhead gates and
-Servicing the intake gate and hoist
The overhead crane will have a double point lift and fal-
l owers for handling the trashrack shutters and bulkhead
gates. The crane will be radio-cantrall ed with a pendant
or cab control for backup.
(v) Intake Bulkhead Gates
(vi)
One set of intake bulkhead gates will be provided for clos-
ing any one of the six intake openings upstream from the
intake gates. The bulkhead gates will be used to permit
inspection and maintenance of the intake gate and intake
gate guides. The gates will be designed to withstand full
differential pressure.
Intake Gates
The intake gates will close a clear opening of 13 feet 5
inches by 17 feet. They will be of the vertical fixed-
wheel lift type with upstream seals and skinplate.
Each gate wi 11 be operated· by a hydraulic cylinder type
hoist. The length of a cylinder will allow withdrawal of
the. gate from the water flow. The intake service crane
will be used to raise the gate above deck level for main-
tenance. The gates wi 11 normally be closed under balanced
flow conditions to permit dewatering of the penstock and
turbine water passages for inspection and maintenance of
the turbines. The gates will also be designed to close in
an emergency with full turbine flow conditions in the event
of loss of control of the turbine.
1. 9 -Penstocks
The general arrangement of the penstocks is shown on Plates F21 and
F23.
Six penstocks will be provided to convey water from the power intake to
the powerhouse, one penstock for each generating unit. Each penstock
will be a concrete-lined rock tunnel 17 feet in internal diameter. The
mininum lining thickness will be 12 inches, which will be increased as
A-1-17
appropriate to withstand design internal pressures. The 1 ateral spac-
ing between penstocks will be 50 feet on centers at the intake and this
will increase to 60 feet on centers at the powerhouse. The difference
in lateral spacing will be taken out at the upper horizontal bend. The
inclined sections of the concrete-lined penstocks will be at 55° to the
horizontal.
The design static head on each penstock is 763 feet at centerline dis-
tributor level (Elevation 1422). An allowance of 35 percent has been
made for pressure rise in the penstock caused by hydraulic transients.
(a) Steel Liner
The rock immediately adjacent to the powerhouse cavern will be in-
capable of resisting the internal hydraulic ~orces within the pen-
stocks. Consequently, the first 50 feet of each penstock upstream
of the powerhouse will be reinforced by a steel liner designed to
resist the maximum design head, without support from the sur-
rounding rock. Beyond this section the steel liner will be ex-
tended a further 150 feet, and support from the surrounding rock
will be assumed, up to a maximum of 50 percent of the design pres-
sure.
The steel 1 iner wi 11 be surrounded by a concrete infi 11 with a
minimum thickness of 24 inches. The internal diameter of the
steel lining will be 15 feet. A steel transition will be provided
between the liner and the 17-foot diameter concrete-lined pen-
stock.
(b) Concrete Lining
The penstocks will be fully lined with concrete from the intake to
the steel-lined section, the thickness of lining varying with the
external hydrostatic head. The internal diameter of the concrete-
lined penstock will be 17 feet. The minimum lining thickness will
be 12 inches.
(c) Grouting and Pressure Relief System
A comprehensive pressure relief system will protect the under-
ground caverns against seepage from the high pressure penstock.
The system will comprise small diameter boreholes set out to in-
tercept the jointing in the rock. A grouting and drainage gallery
will be located upstream from the transformer gallery.
1.10-Powerhouse
The underground powerhouse camp 1 ex wi11 be constructed beneath the
north abutment of the dam. This will require the excavation in rock of
three major caverns, the powerhouse, transformer gallery, and surge
chamber, with interconnecting rock tunnels for the draft tubes and
isolated phase bus ducts.
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Unlined rock tunnels, with concrete inverts where appropriate, will be
provided for vehicular access to the three main rock caverns .and the
penstock construction adit. Vertical shafts will be provided for
personne 1 access to the underground powerhouse, for cab 1 e ducts from
the transformer gallery, for surge chamber venting, and for the heating
and ventilation system.
The general layout of the powerhouse complex is shown in plan and sec-
tion in Plates F25 and F26, and in isometric projection in Plate F24.
The transformer gallery will be located on the upstream side of the
powerhouse cavern; the surge chamber will be located on the downstream
side.
The draft. tube gate gallery and crane wi 11 be located in the surge
chamber cavern, above the maximum anticipated surge level. Provision
wi 11 a 1 so be made in the surge chamber for ta i 1 race tunne 1 intake stop-
logs, which will be handled by the same crane.
(a)
(b)
Access Tunnels and Shafts
Vehicular access to the underground facilities at Watana will be
provided by a single unlined rock tunnel from the north bank area
adjacent to the diversion tunnel portal. The access tunnel will
cross over the diversion tunnels and then descend at a uniform
gradient to the south end of the powerhouse cavern at generator
floor level, Elevation 1463. Separate branch tunnels from the
main tunnel will provide access to the transformer gallery at
Elevation 1507, the penstock construction adit at Elevation 1420,
and the surge chamber at Elevation 1500. The maximum gradient
will be 6. 9 percent on the construct ion access tunnel and on the
permanent access tunnels.
The cross section of the access tunnel has a modified horseshoe
shape, 35 feet wide by 28 feet high. The access tunnel branch to
the surge chamber and draft tube gallery will have a reduced sec-
tion consistent with the anticipated size of vehicle and loading
required.
The main access shaft will be at the north end of the powerhouse
cavern, providing personnel access from the surface control build-
ing by elevator. Access tunnels will be provided from this shaft
for pedestrian access to the transformer gallery and the draft
tube gate ga 11 ery. Elevator access will also be provided to the
fire protection head tank, located approximately 250 feet above
powerhouse level. The main access shaft will be 20 feet in inter-
nal diameter with a concrete lining of 9 to 18 inches.
Powerhouse Cavern
The main powerhouse cavern is designed to accommodate six verti-
cal-shaft Francis turbines, in line, with direct coupling to syn-
chronous generators. Each unit has a design output capabi 1 ity of
A-1-19
170 MW. The length of the cavern will allow for a unit spacing of
60 feet, with a 110-foot long service bay at the south end for
routine maintenance and for construction erection. Vehicular
access will be by tunnel to the generator floor at the south end
of the cavern; pedestrian access will be by elevator from the
surface control building to the north end of the cavern. Multiple
stairway access points will be available from the main floor to
each gallery level. Access to the transformer gallery from the
powerhouse will be by tunnel from the main access shaft, or by
stairway through each of the isolated phase bus shafts. A service
elevator will be provided for access to the various powerhouse
floors.
Hatches will be provided through all main floors for install at ion
and maintenance of heavy equipment using the powerhouse cranes.
(c) Transformer Gallery
The transformers will be located underground in a separate gal-
lery, 120 feet upstream from the main powerhouse cavern, with
three connecting tunnels for the isolated phase bus. There will
be nine single-phase transformers rated at 15/345 kV, 145 MVA, in-
stalled in groups of three transformers for two generating units.
Generator circuit breakers will be installed in the powerhouse on
the lower generator floor level.
The transformer gallery is 45 feet wide, 40 feet high, and 414
feet long; the bus tunnels are 16 feet wide and 16 feet high.
High voltage cables will be taken to the surface by two cable
shafts, each with an internal diameter of 7.5 feet. Provision has
been made for installation of an inspection hoist in each shaft.
A spare eransformer will be located in the transformer gallery,
and a spare HV circuit will also be provided for improved relia-
bility. The station service auxiliary transformers (2 MVA) and
the surface auxiliary transformer (7.5/10 MVA) will be located in
the bus tunnels. Generator excitation transformers will be locat-
ed in the powerhouse on the main floor.
Vehicle access to the transformer gallery will be the main power-
house access tunnel at the south end. Pedestrian access wilT be
from the main access shaft or through each of the three isolated
phase bus tunnels.
(d) Surge Chamber
A surge chamber wi 11 be provided 120 feet downstream from the
powerhouse cavern to control pressure fluctuations in the turbine
draft tubes and tailrace tunnels under transient load conditions,
and to provide storage of water for the machine start-up sequence.
A-1-20
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The chamber will be common to all six draft tubes, and under nor-
mal operation will discharg·e equally to the two tailrace tunnels.
The overall surge chamber size is 350 feet long, 50 feet wide, and
145 feet high (including the draft tube gate gallery}.
The draft tube gate gallery and crane wi 11 be locat·ed in the same
cavern, ab.ove the maximum anticipated surge lev.el. The crane has
also been designed to allow installation of tailrace tunnel intake
stop logs for emergency closure of eith·er tailrace tunnel.
-The chamber will generally be an ·unlined rock excavation, with
1 oca 1 i zed rock support as necessary for stability of the roof arch
and wa 11 s. The gate guides for the draft tube gates and tailrace
stop logs wi 11 be of embedded in reinforced concrete anchored to
the rock by rock bolts. -
Access to the draft tube gate gallery will be iby an adit from the
!""" main access tunnel. This access will b.e widened locally for stor-
age of tailrace tunnel intake stoplogs.
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(e) Grouting and Pressure Relief System
(f)
(g)
Control of seepage in the powerhouse area will be achieved by a
grout curtain upstream from the transformer gallery and an ar-
rangement of drainage holes downstream from this curtain. In
addition, drain ho 1 es will be drilled from the caverns extending
to a depth greater than the rock anchors. Seepage water wi 11 be
call ected by surface drainage channels and directed into the
powerhouse drainage system.
Cable Shafts
Cable shafts will be 8. 5 feet in excavated diameter. Although not
required for rock stabi 1 ity, a 6-inch thick concrete lining has
been specified for convenience of installing hoist, stairway and
cable supports.
Draft Tube Tunnels
The draft tube tunnels wiTl be shaped to provide a transition to a
uniform horseshoe section with a 19-foot diameter and a concrete
lining at least 2.5 feet thick. The initial rock support will be
concentrated at the junctions with the powerhouse and surge cham-
ber where the two free faces giv•e greatest potential for block in-
slabi 1 ity.
1.11 -T a i 1 race
Two tailrace pressure tunnels will be provided at Watana to carry water
from the surge chamber t.o the river. The tunnels will have a modified
horseshoe cross section with a major 'internal d·imension of 34 feet.
The tunnels will be fully concrete-lined throughout, with a m1mmum
concrete thickness of 12 inches and a length of 1800 feet. The tai 1-
race tunnels will be arranged to discharge into the river between the
main dam and the main spillway.
The upstream sections of the tailrace tunnels will be bearing 249° and
will parallel the main access tunnel. The southern tunnel will join
the lower diversion tunnel and utilize the diversion portal for the
tailrace outlet. The northern tunnel will change direction at the
downstream end to bear 238° and the portal will be situated between the
diversion tunnel portals and the spillway flip bucket. The tunnels
will be concrete-lined for hydraulic considerations.
The downstream portal of the northern tunnel wi 11 be located between
the spillway fltp bucket and diversion tunnel portal. A rock berm will
be left in place to the south of the portal to separate the outlet and
diversion tunnel channels.
The tailrace portals will be reinforced concrete structures designed to
reduce the outlet flow velocity, and hence the velocity head loss at
the exit to the river.
1.12 -Access Plan
(a) Access Objectives
The primary objective of access is to provide a transportation
system that will support construction activities and allow for the
orderly development and maintenance of site facilities.
(b) Access Plan Selection
Detailed access studies resulted in the development of eighteen
alternative access plans within three distinct corridors. The
three corridors were identified as:
A corridor running west to east from the Parks Highway to the
damsites on the north side of the Susitna River;
A corridor running west to east from the Parks Highway to the
damsites on the south side of the Susitna River; and
A corridor running north to south from the Denali Highway to
the Watana damsite.
Criteria were established to evaluate the responsiveness of the
plans to project objectives and the desires of the resource agen-
cies and affected communities. The selected access plan (Plan 18,
otherwise referred to as Denali-North) represents the most favor-
able solution to meeting both project related goals and minimizing
impacts to the environment and the surrounding communities. Where
adverse environmental impacts are unavoidable or project objec-
A-1-22
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tives compromised, mitigation and management measures have been
formulated to reduce these impacts to a minimum. These mitigation
measures are outlined in detail within Exhibit E of the license
app 1 i cation.
Description of Access Plan
Access to the Watana damsite will connect with the existing Alaska
Railroad at Cantwell where a railhead and storage facility occupy-
ing 40 acres will be constructed. This facility will act as the
transfer point from rail to road transport and as a storage area
for a two-week backup supply of materials and equipment. From the
railhead facility the road will follow an existing route to the
junction of the George Parks and Denali Highways (a distance of
two miles), then proceed in an easterly direction for a distance
of 21.3 miles along the Denali Highway. A new road, 41.6 miles in
·length, will be constructed from this point due south to the
Watana camp site. On completion of the dam, access to Native
lands on the south side of the Susitna River will be provided from
the Watana camp site with the road crossing along the top of the
dam. This will involve the construction of an additional 2.6
miles of road bringing the total length of new road to 44.2
miles.
Plate F32 shows the proposed access plan route. Plate F33 shows
details, for both the Watana and Devil Canyon developments, of
typical road and railroad cross sections, railhead facilities, and
the high-level bridge at Devil Canyon.
Assessment of projected traffic volumes and loadings during con-
struction resulted in the selection of the following design param-
eters for the access roads.
Surfacing
Width of Running Surface
Shoulder Width
Design Speed
Maximum Grade
Maximum Curvature
Design Loading
-during construction
-after construction
Unpaved (Treated Gravel Surface)
24 feet
5 feet
55 mph
6% 50
sok axle, 2ook total
HS -20
These design parameters were ~hosen for the efficient, economical,
and safe movement of supp 1 i es and are in accordance with current
highway design standards. Adhering to these grades and curvatures
the entire length of the road would result in excessively deep
cuts and extensive fills in some areas, and could create serious
technical and environmental problems. From an engineering stand-
point, it is advisable to avoid deep cuts because of the potential
slope stability problems, especially in permafrost zones. Also,
deep cuts and large fills are detrimental to the environment for
they act as a barrier to the migration of big game and disrupt the
A-1-23
visual harmony of the wilderness setting. Therefore, in areas
where adhering to the aforementioned grades and curvatures in-
volves extensive cutting and filling, the design standards have
been reduced to allow steeper grades and shorter radius turns.
This flexibility of design standards has provided greater latitude
to 11 fit" the road within the topography and thereby enhance the
visual quality of the surrounding 1 andscape. For reasons of
driver safety, the design standards will in no instance be less
than those applicable to a 40 mph design speed.
In the community of Cantwell the road wi 11 be paved from the
marshalling yard to 4 miles east of the junction of the George
Parks and Denali Highways. This will eliminate any problem with
dust and flying stones in the residential district. In addition,
the following measures will be taken.
Speed restrictions will be imposed along the above segment;
A bike path will be provided along the same segment to safe-
guard children in transit to and from a school which is situ-
ated close to the road; and
Improvements will be made to the intersection of the George
Parks and Denali Highways including pavement markings and traf-
fic signals.
(d) Right-of-Way
The 21.3 miles of existing road along the Denali Highway will be
upgraded to the aforementioned standards. However, the present
alignment is such that any realignment required should be possible
within the existing easement.
The majority of the new road will follow terrain and soil types
which allow construction using side borrow techniques, resulting
in a mini mum of disturbance to areas away from the alignment. A
berm type cross section will be formed, with the crown of the road
being approximately 2 to 3 feet above the elevation of adjacent
ground. To reduce the visual impact, the side slopes will be
flattened and covered with excavated peat material. A 200-foot
right-of-way will be sufficient for this type of construction.
Although sidehill cuts must be minimized to avoid the effects of
thawing permafrost and winter icing on the section of road running
parallel to Deadman Creek, in isolated spots of extensive sidehill
cutting it may be necessary to exceed the 200-foot width.
(e) Construction Schedule
The overall schedule for the Watana development relies heavily on
the ability to move supplies, materials and equipment to the site
as soon as possible after the start of project construction. The
selected plan involves the least mileage of new road construction
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and follows relatively level, open terrain in comparison with the
alternative routes in the two other corridors. Consequently,
construction of this route has the highest probability of meeting
schedule and hence affords the least risk of project delay. It
has been estimated that it will take approximately 6 months to
secure initial access with an additional year for completion and
the upgrading of the Dena 1 i Highway section.
1.13-Site Facilities
(a} General
(b)
The construction of the Watana development will require various
facilities to support the construction activities throughout the
entire construction period. Following construction, the operation
of the Watana hydroelectric development will require certain perm-
anent staff and f ac il it i es to support the permanent operation and
maintenance program.
The most significant item among the site facilities will be a com-
bination camp and village that will be constructed and maintained
at the project site. The camp/village will be a largely self-
sufficient community housing 3300 people during construction of
the project. After construction is complete, it is planned to
dismantle and demobilize most of the facility and to reclaim the
area. The dismantled buildings and other items from the camp will
be used as much as possible during construction of the Devil
Canyon developmenL Other site facilities include contractors 1
work areas, site power, services, and communications. Items such
as power and communications will be required for construction
operations independent of camp operations. The same will be true
regarding a hospital or first aid room.
Permanent f ac i 1 it i es required wi 11 inc 1 ude a permanent town or
small community for approximately 130 staff members and their
families. Other permanent facilities will include a maintenance
building for use during subsequent operation of the power plant.
A conceptual plan for the permanent town is shown on P1ate F36.
Temporary Camp and Village
The proposed location of the camp and village will be on the north
bank of the Sus jtna River between Deadman and TS'userM Creek,
approximately 2. 5 miles northeast of the Watan:a Darn. The north
side of the Susitna fhver was chos-en: because the main acceS-s will
be from the north and south-facing slopes can be used for siting
the structures. The 1ocat ion is shown in Plate f34 ~
The camp will consist of fJOrtable weodframe do-rmitories for hache-
i,ors wtth modular mess halls~ re'creational b11i ~dings, bank, post
ofHce, fire stationy warehouses, hos_pttal, offices, ~t-c. The
camp wi"ll be a Single -stat~s camp for appro'ximately 'JDOG workers.
A-1-25
The village, accommodating approximately 300 families, will be
grouped around a service core containing a school, gymnasium,
stores, and recreation area.
The village and camp areas will be separated by approximately 1. 5
miles to provide a buffer zone between areas. The hospital will
serve both the main camp and village.
The camp 1 ocat ion wi 11 separate 1 i v·ing areas from the work areas
by a mile or more and keep travel time to work to less than 15
minutes for most personnel.
The camp/vi 11 age wi 11 be constructed in stages to accommodate the
peak work force. The facilities have been designed for the peak
work force plus 10 percent for turnover. The turnover wi 11 in-
clude allowances for overlap of workers and vacations. The con-
ceptual 1 ayouts for the camp and village are presented on Plates
F36 and F37.
(i) Site Preparation
Both the camp and the vi 11 age areas wi 11 be cleared and in
select areas filter fabric will be installed and granular
material placed over it for building foundations. At the
village site, selected areas will be left with trees and
natural· vegetation intact. Topsoil stripped from the
adjacent dam borrow site will be utilized to reclaim camp
and village sites.
Both the main camp and the village site have been selected
to provide well-drained land with natural slopes of 2 to 3
percent.
( i i) Facilities
Construction camp buildings will consist largely of
trailer-type factory-built modules assembled at site to
provide the various facilities required. The modules will
be fabricated complete with heating, lighting and plumbing
services, interior finishes, furnishings, and equipment.
Larger structures such as the central utilities building,
warehouses and hospital will be pre-engineered, steel-
framed structures with metal cladding.
(c) Permanent Town
The permanent town will be located at the north end of the tempo-
rary village (see Plate F34) and be arranged around a small lake
for aesthetic purposes.
The permanent town will consist of permanently constructed build-
ings. The various buildings in the permanent town are as
follows:
A-1-26
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-Single family dwellings;
-Multifamily dwellings;
-Hospital;
-Schoo 1;
-Fire station;
- A town center wi 11 be constructed and wi 11 contain the
following:
a recreation center
a gymnasium and swimming pool
. a shopping center
The concept of building the permanent town at the beginning of the
construction period and using it as part of the temporary village
was considered. This concept was not adopted, since its intended
occupancy and use is a minimum of 10 years away, and the require-
ments and preferences of the potential long-term occupants cannot
be predicted with any degree of accuracy.
Site Power and Utilities
( i) Power
Electrical power required to maintain the camp/ village and
construction activities will be provided by diesel gener-
ators. Generating capacity will be provided for peak load
with sufficient backup for essential services should the
main generating station be out of service.
The peak demand during the peak camp population year is
estimated at 10 MW for the camp/vi 11 age and 6 MW for con-
struction requirements. The distribution system in the
camp/village and construction area will be 4.16 kV.
Power for the permanent town will be supplied from the
station service system after the power plant is in opera-
tion.
(ii) Water
The water supply system will provide for potable water and
fire protection for the camp/village and selected contrac-
tors • work areas. The estimated peak population to be
served will be 4000 (3000 in the camp and 1000 in the
vi 11 age) .
The principal source of water will be Tsusena Creek, with a
backup system of wells drawing on ground water. The water
will be treated in accordance with the Environmental Pro-
tection Agency•s (EPA) primary and secondary requirements.
A-1-27
A system of pumps and storage reservoirs wi 11 pro vi de the
necessary system capacity. The distribution system will be
contained within utilidors constructed using plywood box
sections integral with the permawalks. The distribution
and location of major components of the water supply system
are presented in P 1 ate F34. Details of the uti 1 i dors are
presented in Plate F38.
(iii) Wastewater
A wastewater collection and treatment system will serve the
camp/village. One treatment plant will serve the campi-
village. Gravity flow lines with lift stations will be
used to co 11 ect the wastewater from all of the camp and
village facilities. The "in-camp" and 11 in-village 11 cal-
l ect ion systems will be run through the uti 1 i dors so that
the collection system will be protected from freezing.
The chemical toilets located around the construction site
will be serviced by sewage trucks, which will discharge
directly into the sewage treatment plant. The sewage
treatment system will be a biological system with lagoons
designed to meet Alaskan and EPA standards. The sewage
plant will discharge its treated effluent through a force
main to Deadman Creek. All treated sludge will be disposed
in a solid waste sanitary landfill.
The location of the treatment plant is shown in Plate F37.
The location was selected to avoid unnecessary odors in the
camp as the winds are from the southeast only 4 percent of
the time, which is considered minimal.
(e) Contractors 1 Area
The on-site contractors will require office, shop, and general
work areas. Partial space required by the contractors for fabri-
cation shops, maintenance shops, storage or warehouses, and work
areas will be located between the main camp and the main access
road.
1.14 -Relict Channel
A relict channel exists on the north bank of the reservoir approxi-
mately 2600 feet upstream from the dam. This channel runs from the
Susitna River gorge to Tsusena Creek, a distance of about 1.5 miles.
The surface elevation of the lowest saddle is approximately 2205, and
depths of up to 454 feet of glacial deposits have been identified.
This cllannel represents a potential source of leakage from 'the 1~atana
reservoir. Along the buried channel thalweg, the highest or cantral-
l ing bedrock surface is some 450 feet below reservoir level, while
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along the shortest leakage path between the reservoir and Tsusena Creek
the highest rock surface is some 250 feet below reservoir level. The
maximum average hydraulic gradient along any flow path in the buried
channel from the edge of pool to Tsusena Creek is approximately 9 per-
cent, while the average gradient is believed to be less than 6 percent.
There is no indication of any existing water-level connection between
the Susitna River and Tsusena Creek. Tsusena Creek at the relict chan-
nel outlet area is at least 120 feet above the natural river level.
There are several surface lakes within the channel area, and some arte-
sian water is present in places. Zones of permafrost have also been
identified throughout the channel area.
To preserve the integrity of the rim of the Watana reservoir and to
control losses due to potential seepage, a number of remedial measures
will be undertaken. These measures are designed to deal with potential
problems which may arise due to settlement of the reservoir rim, sub-
surface flows, permafrost and liquefaction during earthquakes.
(a) Surface Flows
To eliminate the potential problems associated with settlement and
breaching of a saddle dam allowing surface flows through the bur-
ied channel area, the maximum operating level of the reservoir has
been set at 2185 feet, leaving a natural saddle width of at least
1500 feet of ground above pool level at this elevation. A free-
board dike with a crest elevation of 2210 wi 11 be constructed to
pro vi de protection against extreme reservoir water 1 evel s under
PMF conditions. The shortest distance between the toe of the dike
and the edge of the reservoir pool (Elevation 2185) is at least
450 feet, and under a PMF flood the stat k water level will just
reach the toe of the dike before the emergency fuse plug washes
out. The freeboard dike will consist of compacted granular mate-
rial placed on a prepared foundation from which all surface soils
and organic materials will be removed.
(b) S~bsurface Flows
The potential for progressive p1p1ng and erosion in the area of
~ discharge into the Tsusena Creek will be controlled by the place-
ment of properly graded granular materials to form a filter blan-
ket over any zones of emergence. Further field investigations
.-. will be carried out to fully define critical areas, and only such
areas will be treated. Continuous monitoring of the outlet area
will be undertaken for a lengthy period after reservoir filling to
ensure that a state of equil i bri urn is established with respect to
permafrost and seepage gradients in the buried channel area.
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If the permeabi 1 ity of the base .all-uvium is found to be excessive,
a provision will also be made to carry out grouting of the up-
stream alluvium at a natural narrow reach to reduce the total
leakage.
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(c) Permafrost
Thawing of permafrost will occur and may have an impact on subsur-
face flows and ground settlement. Although no specific remedial
work is foreseen at this time, flows, groundwater elevation, and
ground surface elevation in the buried channel area will be care-
fully and continuously monitored by means of appropriate instru-
mentation systems and any necessary maintenance work carried out
to maintain freeboard and control seepage discharge.
(d) Liquefaction
To guarantee the integrity of the reservoir rim through the chan-
nel area requires that either:
-There be no potential for a liquefaction slide into the reser-
voir, or
If there is such potential, there be a sufficient volume of
stable material at the critical section so that, even if the
upstream materials were to slide into the reservoir, the failure
zone could not cut back to the reservoir rim.
Any requirement of remedial treatment will depend on the location
and extent of critical zones and could range from stabilization by
compaction (vibroflotation), grouting techniques (either cement,
colloidal or chemical grouting), or, in the limit, removal of
material and replacement with compacted nonsusceptible fill.
Available geotechnical information ·indicates that there is no
widespread potentially liquefiable material in the upper 200-250
feet of glacial deposits in the relict channel. Further geotech-
nical studies will be required to fully define the extent and
characteristics of the materials in the relict channel. Provi-
sions will be made in design for treatment to cover the worst
conditions identified. These measures include:
-Densification
Layers within about 100 feet of the surface could be compacted
by vibroflotation techniques to eliminate the risk of liquefac-
tion and provide a stable zone by increasing the relative den-
sity of the in situ material.
-Stabilization
Critical layers at any depth could be grouted, either with ce-
ment for fine gravels and coarse sands or by chemical grouting
for fine sands and silts.
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-Removal
This could range from the replacement of critical material near
the valley slopes with high-quality, processed material, which
would stabilize the toe of a potential sl~de and so prevent the
initiation of failure that might otherwise cut back and cause
major failures, to the excavation, blending, and replacement of
large volumes of material to provide a stable zone.
The most positive solution to a worst case scenario is the re-
placement of the critical zone with material that would not lique-
fy. This would involve, in effect, the rearrangement of the in-
place materials to create an underground dam section constructed
of selected materials founded on the dense till layer beneath the
critical alluvium. Such an operation will require the excavation
of a trench up to 135 feet deep with a surface width up to 1000
feet. Selected materials would be compacted to form a central
stable zone, while surplus and unsuitable materials would be
placed on both sides of this central 11 dam 11 to complete backfilling
to ground surface. The central zone would be designed to remain
stable in the event that all upstream material did slide into the
reservoir. Such a structure would be about 5000 feet long, with a
total cut volume of about 13 million cubic yards, of which 4-1/2
million cubic yards could be used in the compacted center zone.
The cost of such work is estimated to be about $100 million.
Although this is considered an unlikely scenario, contingency
allowances will be adequate to cover this cost.
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2 -RESERVOIR DATA -WATANA
The Watana reservoir, at normal operating level of 2185 feet (mean sea
level), will be approximately 48 miles long with a maximum width in the
order of 5 miles. The total water surface area at normal operating
level is 38,000 acres. The minimum reservoir level will be 2065 feet
during normal operation, resulting in a maximum drawdown of 120 feet.
The reservoir will have a total capacity of 9.5 million acre-feet, of
which 3.7 million acre-feet will be live storage.
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3 -TURBINES AND GENERATORS -WATANA
3.1 -Unit Capacity
The Watana powerhouse will have six generating units with a design
capability of 170 MW corresponding to the minimum December reservoir
level (Elevation 2114) and a corresponding gross head of 652 feet on
the station.
The head on the plant will vary from 610 feet to approximately 735
feet.
The rated head for the turbine has been established at 680 feet, which
is the weighted average operating head on the station. The rated tur-
bine output will be 250,000 hp (186.5 MW) at ful1 gate.
The generator rating has been selected as 190 MVA with a 90 percent
power factor. The generators wi 11 be capable of a continuous 15 per-
cent overload allowing a unit output of 196 MW. At maximum reservoir
water level, the turbines will be operated below maximum output to
avoid overloading of the generators.
3.2 -Turbines
The turbines will be of the vertical-shaft Francis type with steel
spiral casing and a concrete elbow-type draft tube. The draft tube
will comprise a single water passage without a center pier.
The rated output of the turbine net wi 11 be 250,000 hp at 680 feet
rated net head. Maximum and minimum heads on the units will be 725
feet and 600 feet, respectively. lhe full gate output of the turbines
will be about 275,000 hp at 725 feet net head and 209,000 hp at 600
feet net head. Overgating of the turbines may be possible, providing
approximately 5 percent additional power; however, at high heads the
turbine output will be restricted to avoid overloading the generators.
The best efficiency point of the turbines will be established at the
time of preparation of bid documents for the generating equipment and
will be based on a detailed analysis of the anticipated operating range
of the turbines. For preliminary design purposes, the best efficiency
(best-gate) output of the units has been assumed as 85 percent of the
full gate turbine output.
The full-gate and best-gate efficiencies of the turbines will be about
91 percent and 94 percent, respectively, at rated head. The efficiency
will be about 0.5 percent lower at maximum head and 1 percent lower at
minimum head.
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3.3 -Generators
(a) Type and Rating
The six generators in the Watana powerhouse will be of the verti-
cal-shaft, overhung type directly connected to the vertical
Francis turbines. The arrangement of the units is shown in Plates
F25 and F26, and the single line diagram is shown in Plate F30.
There wi 11 be two generators per transformer bank, with each
transformer bank comprising three single-phase transformers. The
generators will be connected to the transformers by isolated phase
bus through generator circuit breakers directly connected to the
isolated phase bus ducts.
Each generator will be provided with a high initial response
static excitation system. The units will be controlled from the
Watana surface control room, with local control facility also pro-
vided at the powerhouse floor. The units will be designed for
black start operation.
The generators will be rated as follows:
Rated Capacity
Rated Power
Rated Voltage
Synchronous Speed
Inertia Constant
Transient Reactance
Short Circuit Ratio
Efficiency at Full Load
190 MVA, 0.9 power factor
170 MW
15 kV, 3 phase, 60 Hertz
225 rpm
3.5 MW-sec/MVA
28 percent (maximum)
1.1 (minimum)
98 percent (minimum)
The generators will be of the air-cooled type, with water-to-air
heat exchangers located on the stator periphery. The ratings
given above are for a temperature rise of the stator and rotor
windings not exceeding 60°C with cooling air at 40°C.
The generators will be capable of delivering 115 percent of rated
power cant i nuous ly (195. 5 MW) at a voltage of +5 percent without
exceeding 80°C temperature rise in accordance with ANSI Standard
C50.10.
The generators wi 11 be capable of continuous operation as synch-
ronous condensers when the turbine is dewatered, with an under-
excited reactive power rating of 140 MVAR and an overexcited rat-
ing of 110 MVAR. Each generator will be capable of energizing the
transmission system without risk of self-excitation.
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(b) Unit DimensiDns
Approximate dimensions and weights of the principal parts
of the generator ar~ given below:
Stator pit diameter
Rotor diameter
Rotor length (without shaft)
Rotor weight
Total weight
36 feet
22 feet
7 feet
385 tons
740 tons
It should be noted that these are approximate figures and
they will vary between manufacturers.
(c) Genera tor Excitation System
The generator will be provided with a high initial response
type static excitation system supplied with rectified exci-
tation power from transformers connected directly to the
generator terminals. The excitation system will be capable
of supplying 200 percent of rated excitation field (ceiling
voltage) with a generator terminal voltage of 70 percent.
The power rectifiers will have a one-third spare capacity
to maintain generation even during failure of a complete
rectifier module.
The excitation system will be equipped with a fully static
voltage regulating system maintaining output from 30 per-
cent to 115 percent, within +0.5 percent accuracy of the
voltage setting. Manual control will be possible at the
excitation board located on the powerhouse floor, although
the unit will normally be under remote control.
3.4 -Governor System
The governor system which controls the generating unit will include a
governor actuator and a governor pumping unit. A single system will be
provided for each unit. The governor actuator will be the electric
hydraulic type and will be connected to the computeri.zed station con-
trol system.
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4 -TRANSMISSION FACILITIES FOR WATANA DEVELOPMENT
4.1 -Transmission Requirements
The purpose of the project transmission facilities will be to deliver
power from the Susitna River basin 9enerating plants to the major load
centers at Anchorage and Fairbanks in an economical and reliable man-
ner. The facilities will consist of overhead transmission lines,
under-water cables, switchyards, substations, a load dispatch center,
and a communications system. The development of the full potential of
the river basin will be phased over a number of years and the trans-
mission facilities will be arranged so that reliable operations will be
insured at all phases of the development. The design will provide for
delivery of power to one substation in Fairbanks, one substation at
Willow, and two substations in Anchorage. As the power generated by
the Watana hydroelectric station will be used to serve all the sub-
stations noted above, the transmission facilities associated with
Watana will extend over the full length of the corridor. Later when
Devil Canyon is developed, the facilities will be supplemented with
additional components along some parts of the corridor.
4.2 -Description of Facilities
(a) Corridor
The corridor that the transmission lines will follow as they leave
the generating plants is generally westward, following the Susitna
River valley to Gold Creek near the Alaska Railroad route. At
this point, the corridor divides to provide for lines running
north to Fairbanks and south to Anchorage; in both cases, the
corridor generally follows the Railbelt. However the lines to
Anchorage will leave the Railbelt just outside Willow. At this
point, the corridor continues in a southerly direction to reach
the north shore of Kn i k Arm. The corridor enters military re-
served territory and is constrained to pass near the northern and
eastern perimeter of Fort Richard son through the reservati on, and
finally loops south and west to the site of the existing Universi-
ty substation located some four miles southeast of the center of
Anchorage.
The length of the corridor sections and the number of lines con-
tained within them are shown in the following table;
NUMBER OF 345 KV CIRCUITS
LENGTH
(Mi) Watana Canyon Developed
1. Watana to Gold Creek 37 2 2
2. Devil Canyon to Gold Creek 8 2 2
3. Gold Creek to Knik Arm (West) 123 2 1 3
4. Knik Arm Crossing 3 2 1 3
5. Knik Arm to Anchorage 19 2 2
6. Gold Creek to Fairbanks 185 2 2
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The physical location of the corridor is shown in a regional con-
text, together with the single line diagram of the system, on
Plate No. F74, Exhibit F.
(b) Components
At the Watana development a switchyard will be provided on the
11 breaker-and-a-half" layout arrangement which will provide high
reliability. This switchyard will allow the output of the devel-
opment to be divided between the two outgoing lines, or concen-
trated on one line or the other in the event of an outage of one
line. (Refer to Plate F31, Exhibit F)
From Watana, two single-circuit 345 kV lines will leave the
switchyard and run westward to the Gold Creek switching station.
From the Watana substation, both lines will continue· in a
northwest direction, a distance of approximately two mn es
crossing Tsuesen a Creek, then will turn west and share the same
general corridor as the proposed access road all the way to the
Devil Canyon damsite. From Devil Canyon, the lines will head in a
southwest direction, crossing the Susitna River at river mile
149.8, then will turn westward and follow the proposed railroad
extension a distance of approximately six miles to the Gold Creek
switching station. The Gold Creek switching station will be
located in a wooded area on the south bank terraces of the Susitna
River at approximately river mile 142.
The Gold Creek switching station layout will be based on the
breaker-and-a-half arrangement for a reliable and secure
operation. At this station switching will be provided so that the
output of the Watana development can be dispatched partly north
along the two lines to Fairbanks and partly to Anchorage along the
two lines that run south. Power dispatched in either of these
directions will be able to be switched to one line of the pair in
the event of an outage on the other. Switching also will all ow
either of the incoming lines from Watana to feed either Fairbanks
or Anchorge, providing complete flexibility. Access to the Gold
Creek switching station site will be by an 8-mile long all-weather
road from the railroad at Gold Creek. (Refer to Plate F76,
Exhibit F)
The two 345 kV single-circuit lines to Fairbanks from Gold Creek
will share the same right-of-way north, generally following the
Railbe1t past Chulitna, Cantwell, Denali Park and Healy, sited to
the east of the railroad. About 1 mile north of Healy the lines
will cross to the west side of the Nenana River and the railroad,
continuing northwards for about 14 miles between the Parks Road on
the west and the railroad on the east. At this point the lines
wi 11 recross to the east side of the Nenana River and the rai 1-
road, continuing north to cross the Tanana River about 8 miles
east of the town of Nenana, and then will continue northeastward
to a point six miles west of Fairbanks at Ester substation, the
northern terminal of the 345 kV system.
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At Ester substation prov1s1on will be made to step down the volt-
age to 138 kV for delivery to the Golden Valley Electric Associa-
tion through up to three 150 MVA transformer banks. Switching
will be provided at 345 kV to enable the load to be fed from both
or either of the incoming lines, using a breaker-and-a-half
arrangement for rel i abi 1 ity. The Ester switchyard will also be
provided with switchable 75 MVAR shunt reactors on each of the 345
kV lines for use during line energizing; switching will allow the
reactor to be removed from the line if necessary during emergency
heavy line loading if one line suffers an outage. For purposes of
control of the system status VAR compensation w"ill be required -on
the 138 kV buses at Ester consisting of units with +200/-100 MVAR
continuous, and +300/-100 IVIVAR short time rat·i11gs. The ratings of
the VAR control equipment wi 11 be confirmed and, if necessary,
refined during final design. Access to the Ester Substation w"lll
be provided by an all-weather gravel road 1 inked to the nearby
Fairbanks Highway. (Refer to Plate F75, Exhibit F)
The description of the line components from Gold Creek switching
station south to Anchorage follows.
Two single-circuit 345 kV lines will exit from the Gold Creek
switching station in a southwesterly direction following the east
bank of the Susitna River past the village of Gold Creek. At this
point while the river and the Alaska Railroad continue southwest,
the line route will head south departing up to 10 miles to the
east from the Railbelt. Approximately 50 miles south of Gold
Creek the lines will rejoin the Railbelt near the Kashwitna River.
From here the lines will run 6 miles parallel to the Railbelt on
the east of the road to reach the Willow switching station sited
about 2 mi 1 es north of w·i 11 ow.
The Willow switching station will serve a dual function; firstly,
it will provide a facility to feed load in the locality at 138 kV
through up to three 75 MVA, three-phase transformers. Secondly
the station will provide complete line switching through a
breaker-and-a-half arra.ngement for rel i abi 1 ity. This switching
will facilitate line energizing by limiting overvoltages. It will
also allow flexibilty to isolate a line section that might suffer
an outage and to route load t·hrough the remaining 1 i nes. The
Willow site access wi 11 be provided with an all -weather gravel
road about 1 mile long across Will ow Creek to the Will ow Creek
Road. (Refer to Plate F77, Exhibit F)
Also located at Willow will be the Energy Management Center where
the control of the entire operation of the power generation and
transmission facilities will be centralized. Remote control will
be provided through communications vi a a microwave system. Exist-
ing microwave communications from Anchorage to Willow and from
Fairbanks to Healy wi 11 be augmented and extended to provide a
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continuous link between Fairbanks and Anchorage with a spur into
the power developments at Devil Canyon and Watana.
Two single-circuit 345 kV lines leaving Willow switching station
wi 11 run due west for about 4 nri 1 es, then turn south and cross
Willow Creek. The lines will continue in a generally southward
direction to cross the Little Susitna River about 25 miles from
Willow Creek. At this point the lines will bear in a south-
easterly direction for about 15 miles to arrive at the west side
of Knik Arm about five and a half miles north of Pt. MacKenzie,
adjacent to the site of an existing 230 kV 1 ine.
Knik Arm will be crossed by submarine cable buried in the inlet
bed. Two circuits will be provided, each consisting of three
individual single-phase 345 kV submarine cables. On each shore a
cable termination station will contain disconnects, arrestors and
ground connection devices required for operation of the cable
facility. Another feature of the terminals will be an arrangement
of an upper level bus which will allow for temporary connections
to bring into contingency service a spare phase cable, to replace
any cable which might suffer accidental damage. In the bed of the
inlet, the circuits will be physically separated into three back-
filled trenches; two will contain three single-phase cables making
up the two main circuits, the third will contain the spare phase.
Each trench will be separated from the other by approximately 1/4
mile with a similar distance being maintained from the existing
230 kV crossing. The separation in the navigation area will be
achieved by curving the trenches in plan on the foreshore of the
inlet. This arrangement of separating the circuits will provide
an added measure of protection against multiple circuit damage due
to navigation in the inlet. Access to the east and west terminals
will be by gravel road built along the transmission line right-of-
way to the nearest public access about 3 miles distant on the east
side and 12 miles on the west.
On the east side of Knik Arm the line route will pass through the
military reservation forming Fort Richardson. The route will
follow a path parallel to the existing 230 kV line. Beyond the
Knik Arm substation it will consist of two 345 kV circuits. Be-
cause of the restricted width available for right-of-way there is
a requirement to use compact line design techniques. Double-
circuit steel pole structures will be designed with extra conser-
vative safety factors to increase reliability against loss of both
circuits due to structural failure. Separation of the circuit
onto two separate single pole structures using post type insula-
tors to prevent conductor swing will be adopted where right-of-way
width permits. From the east shore of Knik Arm the route will run
east to the intersection of Glen and Davis Highways, where it will
turn south following the Glen Highway on the east side, and then
pass east of Homesite Park and west to the vicinity of the exist-
ing University substation on Tudor Road.
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The Knik Arm substation will be located in the general vicinity of
the Glen and Davis Highway intersection near where the existing
230 kV and 115 kV 1 ines share the same right-of-way. This facili-
ty will allow for a breaker-and-a-half layout with complete flex-
ibility in switching at 345 kV between the incoming and outgoing
pairs of lines to cope with possible outage situations. Each of
the incoming lines from Willow will have a switchable 30 MVAR
shunt reactor to assist with voltage control during energizing of
the line. Also the facility will provide one 75 MVA, three-phase
transformer to feed into the 115 kV existing system that passes
nearby. (Refer to Plate F78, Exhibit F)
The University substation site will represent the southernmost
terminal of the 345 kV transmission facility. The substation
will serve as the major distribution point for power from Watana
into the Anchorage area. Provision will be made for transforma-
tion to 230 kV and 115 kV to suit the existing distributions in
the area. At the 230 kV 1 evel up to three 250 MVA banks of
single-phase transformers will be accommodated, and at 115 kV one
250 MVA bank of single-phase transformers. For transient stabi 1-
ity, static VAR compensation will be provided on outgoing lines to
Anchorage consisting of units with ratings on the 230 kV system of
+150/-100 MVAR continuous and +200/-75 MVAR short time; on the 115
kV system rated at +200/-75 MVAR continuous, and +300/-75 MVAR
short time. The ratings of the VAR control equipment will be con-
firmed and, if necessary, refined in final design. Access to the
University substation will be by gravel road directly off Tudor
Road. (Refer to Plate F79, Exhibit F)
It should be noted that the Alaska Power Authority is proceeding
with an 11 Intertie 11 project to build approximately 170 miles of one
of the 345 kV 1 ines between Healy and Willow on the Fairbanks to
Anchorage corridor (Commonwealth Associates 1982). This line will
be built to operate eventually at 345 kV but will be energized
initially at 138 kV, until it is integrated into the Watana trans-
mission system.
Right-of-Way
The right-of-way for the transmission corridor will consist of a
linear strip the width of which depends on the number of lines it
contains. North of the cable crossing of Knik Arm the right-of-
way wi 11 include that area necessary for the additions to the
facilities planned in conjunction with the Devil Canyon develop-
ment. Where the total development will consist of two lines, the
right-of-way width will be 300 feet; for three lines it will be-
come 400 feet. Between Go 1 d Creek and Dev i 1 Canyon, where ult i-
mate1y four lines will be required, the width will be 510 feet.
In the Knik Arm crossing area the right-of-way will be widened to
accommodate the fact that each circuit of the total development
will be separated from the adjacent circuits by a distance of
about 1/4 mile, as wi 11 be the spare phase. The width of the bed
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affected by the crossing wn 1 be approximately one mi 1 e. East of
Knik Arm the right-of-way width will be restricted in the military
reservation. In this section the right-of-way will be 300 feet
from the centerline of the 220 kV 1 ine.
The right-of-way areas to be occupied by the switching and sub-
stations are listed below. They are stated in acres because,
until final design is completed, overall dimensions may be varied,
although the area should remain within the limits indicated.
Area of
Right-of-Way
(acres)
Go 1 d Creek Switchyard . . . . . . . . . . . . . . . . . . . . 16
Fairbanks (Ester) Substation . . . . . . . . . . . . . 25
Willow Substation .... .. .... .. .. .. .. .. .. .. 25
Knik Arm Substation .. .. .. .. .. .. . .. . ... ... 15
Anchorage (University) Substation ........ 45
Rights-of-way for permanent access to switchyard and substations
will be required linking back to a public road or in some cases
rail access. These rights-of-way will be 100 feet wide.
(d) Transmission Lines
Access to the transmission line corridor will be via trails from
existing access routes at intermittent points along the corridor.
The exact location of these trails will be established in the
final design phase. Within the transmission corridor itself an
access strip 25 feet wide will run along the entire length of the
corridor, except at areas such as major river crossings and deep
ravines where an access strip would not be uti 1 i zed for the move-
ment of equipment and materials. This access strip and the trails
leading to the corridor will be constructed to the minimum stand-
ard suitable for four wheel drive vehicles.
The conductor capacity for the lines will be in the range of 1950
MCM; this can be provided in several ways. Typical of these is a
phase bundle consisting: of two 954 MCM 11 Rail" (45/7) Aluminum
Conductor Steel Reinforced (ACSR) or a single 2156 MCM 11 Bluebird 11
(84/17) ACSR conductor, both of which provide comparable levels of
corona and radio noise within normally accepted limits. The
single 11 Bluebird'' conductor attracts less load under wind or ice
loadings and avoids the need to provide the space damper devices
required for a bundled phase. The single conductor is stiffer and
heavier to handle during stringing operations, although this will
tend to be balanced out due to the extra work involved in handling
the twin bundle. Selection of the optimum conductor arrangement
will be made in final design. The conductor will be specified to
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have a dull finish treatment to reduce its visibility at a
distance. The conductor capacity between Knik Arm and University
will be 2700 MCM per phase to handle the output of Dev i 1 Canyon
without an additional circuit in this section of the route.
Two overhead ground wires will be provided the full length of the
line. These will consist of 3/8-inch diameter galvanized steel
stands. The arrangement will be based on a shielding angle of 15
degrees over the outer phases; this will provide protection a-
gainst lightning strikes to the line. More refined studies of the
lightning performance of the line will be made during final design
to confirm the arrangement outlined above.
Highly effective vibration control devices will be required on
both the conductors and the ground wire. Due to the very exposed
nature of much of the line route, the rating and spacing of the
devices will be specified with special care. Stockbridge-type
dampers on single wires and spacer dampers with an elastometer
damping element are expected to be most suitable.
Conductor suspension and dead-end assemblies will be detailed
according to 11 Corona free" design and prototype tested to check
that corona and radio interference are below nuisance levels when
operating at elevations of up to 3500 feet. Insulators will be
standard parcel a in or glass disc type suspension units. A chain
of 18 units is expected to be sufficient to provide acceptable
flashover performance of the line. The configuration will be 11 M"
type with vertical strings on the outside phases and a 11 V11 string
supporting the center phase.
The transmission structures and foundations that serve to support
the conductors and ground wires will be designed for a region
where foundation movement due to permafrost and annual freeze-thaw
cycling is common. Of the structural solutions that have proved
successful in similar conditions, all utilize an arrangement of
guy cables to support the structure. All depend upon the basic
flexibility inherent in guyed structures to resist effects of
foundation movement. For tangent and small angle applications the
guyed type of structure such as the guyed 11 V11 ~ guyed uyu ~ guyed
delta and the guyed portal are the most common economical arrange-
ments. The guyed 11 X" design has been selected for use on the 345
kV Intertie (1) and is therefore a prime candidate for considera-
tion on the Watana lines. Experience gained during the Intertie
project will be used in the final structure design. (Refer to
Plate F80, Exhibit F)
Structures for 1 arger angle and dead end app 1 icat ions wi 11 be in
the form of individual guyed masts, one for each phase. Individ-
ual guyed masts will also be used for lengths of line that are
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judged to be in unusually hazardous locations due to exposure to
special wind load effects, or slow slide effects if the terrain is
extremely rugged. All structures will utilize a "weathering 11
steel which matures over several years to a dark brown color which
is considered to have a more aesthetically pleasing appearance
than galvanized steel or aluminum. (Refer to Plate F80, Exhibit
F)
Foundations for structures will utilize driven steel piles in
unstable soil conditions. In better soils steel grillage founda-
tions will be used and set sufficiently deep to avoid the effects
of the freeze-thaw cycle. Rock footings will employ grouted rock
anchors with a minimum use of concrete to facilitate winter con-
struction. Foundations for cantilever pole type structures will
be large diameter cast-in-place concrete augered piles. Several
types of guy anchor will be available for use.; they include the
screw-in helix type, the grouted bar earth anchor, driven piles
and grouted rock anchors. Selection of the most economical solu-
tion in any given situation will depend on the site specific con-
straints including soil type, access problems and expected guy
load. Foundation sites will be graded after installation to con-
tour the disturbed surface to suit the existing grades. Tower
grounding provisions will depend upon the results of soil electri-
cal resistivity measurements both prior to and during construc-
tion. Continuous counterpoise may be required in sections where
rock is at or close to the surface; it also may be required in
other areas of high soil resistance. The counterpoise will take
the form of two galvanized steel wires remaining at a shallow bury
parallel to and under the lines. These will be connected to each
tower and cross connected between lines in the right-of-way.
Elsewhere, grounding will be installed in the form of ground rods
driven into the soil adjacent to the towers.
(e) Switching and Substations
The physical location of the stations and the system single line
diagram is shown on Plate F74 of Exhibit F. The single line
diagram and layout of the individual stations are contained on
Plates F75 through F79 of Exhibit F.
The construction access to all sites will be over the route of the
permanent access provided for each location. Any grading of the
sites will be carried out on a balanced cut-and-fill basis
wherever possible. Equipment will be supported on reinforced
concrete pad-and-column type footings with sufficient depth -of-
bury to avoid the active freeze-thaw layer. Backfill immediately
around footings w.ill be granular to avoid frost heave effects.
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Light equipment may be placed on spread footings if movements are
not a significant factor in operational performance.
The station equipment requirements are determined by the breaker-
and-a-half arrangement adopted for reasons of reliability and
security of operation. One and one-half breakers wi 11 be needed
for every element (line or transformer circuit). The transformer
capacities are determined by the load requirements at each sub-
station. Control and metering provisions will cater to the plan
for remote operation of all the facilities in normal circum-
stances. Protective relaying schemes for the 345 kV system wi 11
be in accordance with conventional practices, using the general
philosophy of dual relaying and the local backup principle.
The station layouts are based on conventional outdoor design with
a two-level bus which will result in a relatively low profile to
the station. This will assist in limiting the visual impact of
the stations and make the most of any available neutral buffers.
Although they will be remotely controlled, all stations will be
provided with a control building; in larger stations an additional
relay building will be provided. A storage building will also be
provided for maintenance purposes. Each station will have auxil-
iary power at 480 V; the norma 1 480 V ac power wi 11 be supp 1 i ed
from the tertiaries on the autotransformers or the local utility.
The Willow station will include the Energy Management Center and
the headquarters of the system maintenance group.
(f) Cable Crossing
The cable crossing will consist of two 345 kV circuits each com-
prising three individual 2,000 MCM single-phase submarine cables;
in addition a spare phase cable will be provided. Each circuit
will be buried in the inlet bottom, the three cables of the cir-
cuit shar·ing the same trench. Beyond the foreshore area it is
anticipated that cables can be buried by a combination of dredging
and ploughing as the bed materials are reported to be soft. At
each shore, gravel deposits are expected to be encountered so that
conventional excavate-and-fill methods are more probable with work
being performed from barges in the tidal zone.
The centerline of each circuit will be routed on the foreshore so
as to obtain a physical separation of approximately 1/4 mile be-
tween circuits and the spare phase; a similar spacing will be
maintained from the existing 220 kV circuit which runs adjacent to
the crossing site.
On each side of the inlet a terminal yard will be provided to
contain the disconnects, arrestors, and grounding for the cables
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as well as the cable terminals. The yards will have bus arrange-
ments which will permit the spare phase to be brought into service
by installation of temporary bus connections.
(g) Dispatch Centers -Energy Management Centers and Communications
The operation of the transmission facility and the dispatch of
power to the load centers will be contra ll ed from a centra 1 dis-
patch and Energy Management System (EMS) center. It has been pro-
posed that the center be located at Willow since a suitable site
could be developed at the Willow switching station site. The
location of the center could alternatively be at one of the other
key points along the line route. University substation could be
considered in final design studies if close proximity to an exist-
ing major center of population is thought to be a major advantage
in siting. The center will operate in conjunction with northern
and southern area control systems in Fairbanks and Anchorage which
would control generation in those two areas. The generation at
the Susitna hydroelectric sites would be controlled at the Watana
power faci 1 ity. The Energy Management Center would orchestrate
the overall operation of the system by request to the three local
generation control centers for action and direct operation of the
Gold Creek switching station and the four 345 kV switching and
substations along the transmission system.
The system communications requirements will be provided by means
of a microwave system. The system wi 11 be an enlargement of the
facility being provided for the operation of the Intertie between
Healy and Willow. Communications into the hydroelectric plants
will be by a microwave extension from the Gold Creek switching
stat ion.
4.3 -Construction Staging
The initial development of Watana will require staged development of
transmission facilities to Fairbanks and Anchorage. The first stage
includes the following:
Substations
Watana
Gold Creek
Wi 11 OW
Kn i k Arm
University (Anchorage)
Ester (Fairbanks)
Number of
Line Section Circuits
Watana to Intertie
switchyard near Gold Creek 2
Switchyard to Willow 2
Willow to Knik Arm 2
Knik Arm Crossing 2
Knik Arm to University 2
Devil Canyon to Fairbanks 2
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The transmission will consist of two circuits from Watana to the load
centers. The conductor for the sections from Wat ana to Kn i k Arm and
Watana to Fairbanks will consist of bundled 2 x 954 kcmil, ACSR. The
section between Knik Arm and University wlll employ bundled 2 x 1351
kcmil, ACSR. The submarine cable crossing will consist of two cir-
cuits. The cable will be single conductor, 345 kV self-contain~d oil-
filled. For project ~urposes, the cable size will be 500 rrrn • A
size of up to 1500 mm may be installed if duty requirements are in-
creased. For reliability, a spare cable will be included on a standby
basis.
The Matanuska Electric Association will be serviced from the Willow and
Knik Arm substations via step-down transformers to suit the local volt-
age. Chugach Electric Association, Anchorage Municipal Light and
Power, and Golden Valley Electric Association will be ,serviced through
the University substation in Anchorage and Ester substation at
Fairbanks.
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5 -APPURTENANT MECHANICAL AND ELECTRICAL EQUIPMENT -WATANA
5.1-Miscellaneous Mechanical Equipment
(a) Powerhouse Cranes
(b)
Two overhead traveling-bridge type powerhouse cranes wi 11 be in-
stalled in the powerhouse. The cranes will be used for:
-Installation of turbines, generators, and other powerhouse
equipment; and
-Subsequent dismantling and reassembly of equipment during main-
tenance overhauls.
Each crane will have a main and auxiliary hoist. The combined
capacity of the main hoist for both cranes will be sufficient for
the heaviest equipment lift, which will be the generator rotor,
plus an equalizing beam. A crane capacity of 205 tons has been
established. The auxiliary hoist capacity will be about 25 tons.
Draft Tube Gates
Draft tube gates will be provided to permit dewatering of the tur-
bine water passages for inspection and maintenance of the tur-
bines. The draft tube gate openings (one opening per unit) will
be located in the surge chamber. The gates wi 11 be of the bulk-
head type, installed under balanced head conditions using the
surge chamber crane. Four sets of gates have been assumed for the
six units. Each gate will be 20 feet wide by 10 feet high.
(c) Surge Chamber Gate Crane
A crane will be installed in the surge chamber for install at ion
and removal of the draft tube gates as well as the tailrace tunnel
intake stop logs. The crane wi 11 either be a monorail ·(or twin
monorail) crane, a top running crane, or a gantry crane. The
.-crane will have a capacity of 30 tons and a two point lift.
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(d) Miscellaneous Cranes and Hoists
In addition to the powerhouse cranes and surge chamber gate crane,
the following cranes and hoists will be provided in the power
plant:
A 5-ton monorail hoist in the transformer gallery for trans-
former maintenance;
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-A 4-ton monorail hoist in the circuit breaker gallery for hand-
ling the main circuit breakers;
Small overhead jib or A-frame type hoists in the machine shop
for handling material; and
-A-frame or monorail hoists for handling miscellaneous small
equipment in the powerhouse.
(e) Elevators
Access and service elevators will be provided for the power plant
as follows:
-An access elevator from control buildings.to powerhouse;
- A service elevator in the powerhouse service bay; and
-Inspection hoists in the cable shafts.
{f) Power Plant Mechanical Service Systems
The mechanical service systems for the power plant can be grouped
into six major categories:
(i) Station Water Systems
The station water systems will include the water intake,
cooling water systems, turbine seal water systems, and
domestic water systems. The water intakes will supply
water for the various station water systems in addition to
fire protection water.
(ii) Fire Protection System
The power plant fire protection system will consist of fire
hose stations located throughout the powerhouse, trans-
former gallery, and bus tunnels; sprinkler systems for the
generators, transformers, and the oil rooms; and portable
fire extinguishers located in strategic areas of the power-
house and transformer gallery.
(iii) Compressed Air Systems
Compressed air will be required in the powerhouse for the
following:
-Service air;
-Instrument air;
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-Generator brakes;
-Draft tube water level depression;
-Air blast circuit breakers; and
-Governor accumulator tanks.
For the preliminary design, two compressed air systems have
·been assumed: a 100-ps i g air system for service air, brake
air, and air for draft tube water level depression; and a
.1,000-psig high-pressure air system for governor air and
circuit breaker air. For detailed plant design, a separate
governor air system and circuit-breaker air system may be
provided.
(iv) Oil Storage and Handling
Facilities will be provided for replacing oil in the trans-
formers and for topping-off or replacing oil in the turbine
and generator bearings and the governor pumping system.
For preliminary design purposes, two oil rooms have been
included, one in the transformer gallery and one in the
-powerhouse service bay.
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(v) Drainage and Dewatering Systems
The drainage and dewatering systems will consist of:
-A unit dewatering and filling system
- A clear water discharge system
- A sanitar.y drainage system.
The unit dewatering and fi 11 i ng systems will consist of two
sumps each with two dewatering pumps and associated piping
and valves from each of the units. To prevent station
flooding, the sump will be designed to withstand maximum
tailwater pressure. A valved draft tube drain line will
connect to a dewatering header running along the dewatering
gallery. The spiral case will be drained by a valved line
connecting the spiral case to the draft tube. It will be
necessary to insure that the spiral case drain valve is not
open when the spiral case is pressurized to headwater
level. The dewatering pump discharge line will discharge
water into the surge chamber. The general procedure for
dewatering a unit will be to close the intake gate, drain
the penstock to tailwater level through the unit, then open
the draft tube and spiral case drains to dewater the unit.
Unless the drainage gallery is below the bottom of the
draft tube elbow, it will not be possible to completely
dewater the draft tube through the dewatering header. If
necessary, the remainder of the draft tube can be dewatered
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using a submersible pump lowered through the draft tube
access door. Unit filling to tailwater level w-ill be
accomplished from the surge chamber through the dewatering
pump discharge line (with a bypass around the pumps) and
then through the draft tube and spiral case drain lines.
Alternatively, the unit can be filled to tailwater level
through the draft tube drain line from an adjacent unit.
Filling the unit to headwater pressure will be accomplished
by 11 Cracking 11 the intake gate and raising it about 2 to 4
inches.
(vi) Heating, Ventilation, and Cooling
The heating, ventilation, and cooling system for the under-
ground power plant will be designed primarily to ma·!ntain
suitable temperatures for equipment operation and to pro-
vide a safe and comfortable atmosphere for operating and
maintenance personnel.
The power plant will be located in mass rock which has a
constant year-round temperature of about 40°F. Considering
heat given off from the generators and other equipment, the
primary requirement will be for air cooling. Initially,
some heating will be required to offset the heat loss to
the rock, but after the first few years of operation an
equilibrium will be reached with a powerhouse rock surface
temperature of about 60 to 70°F.
(g) Surface Facilities Mechanical Service Systems
The mechanical services at the control building on the surface
will include:
A heating, ventilation, and air conditioning system for the con-
trol room;
-Domestic water and washroom facilities; and
- A halon fire protection system for the control room.
Domestic water will be supplied from the powerhouse domestic water
system, with pumps located in the powerhouse and piping up through
the access shaft. Sanitary drainage from the control building
will drain to the sewage treatment plant in the powerhouse through
piping in the access tunnel.
The standby generator building will have the following services:
- A heating and ventilation system;
A-5-4
-A fuel oil system with buried fuel oil storage tanks outside the
building, and transfer pumps and a day tank within the building;
and
- A fire protection system of the carbon dioxide or halon type.
(h) Machine Shop Facilities
A machine shop and tool room will be located in the powerhouse
service bay area with sufficient equipment to take care of all
normal maintenance work at the plant, as well as machine shop work
for the larger components at Devil Canyon.
5.2 -Accessory Electrical Equipment
The accessory electrical equipment described in this section includes
the following:
Main generator step-up 15/345 kV transformers
Isolated phase bus connecting the generator and transformers
Generator circuit breakers
. 345 kV oil-filled cables from the transformer terminals to the
switchyard
Cont~ol systems of the entire hydro plant complex
Station service auxiliary ac and de systems.
Other equipment and systems described include grounding, lighting sys-
tem, and communications.
The main equipment and connections in the power plant are shown in the
single 1 ine diagram, Plate F30. The arrangement of equipment in the
powerhouse, transformer gallery, and cable shafts is shown on Plates
F25 through F27.
(a) Transformers and HV Connect ions
Nine single-phase transformers and one spare transformer wi 11 be
located in the transformer gallery. Each bank of three single-
phase transformers wi 11 be connected to two generators through
generator circuit breakers by isolated phase bus located in indi-
vidual bus tunnels. The HV terminals of the transformer will be
~ , connected to the 345 kV switchyard by 345 kV single-phase, oil-
filled cable installed in 700-foot long vertical shafts. There
will be two sets of three single-phase 345 kV oil-filled cables
installed in each cable shaft. One set will be maintained as a
spare three-phase cable circuit in the second cable shaft. These
cable shafts will also contain the control and power cables be-
tween the powerhouse and the surface control room, as well as
emergency power cables from the diesel generators at the surface
to the underground facilities.
A-5-5
{b) Main Transformers
The nine single-phase transformers (three transformers per group
of two generators) and one spare transformer will be of the two-
winding, oil-immersed, forced-oil water-cooled (FOW) type, with
rating and electric characteristics as follows:
Rated capacity
High voltage winding
Basic insulation level (BIL)
of H.V. winding
Low voltage winding
Transformer impedance
145 MVA
345 I 13 kV, Grounded Y
1300 kV
15 kV, Delta
15 percent
The temperature rise above ambient ( 40"C) wi 11 be 55° C for the
windings for continuous operation at the rated kVA.
Fire walls will separate each single-phase transformer. Each
transformer will be provided with fog-spray water fire protection
equipment, automatically operated from heat detectors located on
the transformer.
(c) Generator Isolated Phase Bus
The isolated phase bus main connections will be located between
the generator, generator circuit breaker, and the transformer.
Tap-off connections will be made to the surge protection and
potential transformer cubicle, excitation transformers, and
station service transformers. Bus duct ratings are as follows:
Rated current, amps
Short circuit current
momentary, amps
Short circuit current~
symmetrical, amps
Basic insulation level, kV {BIL)
Generator
Connection
9,000
240,000
150,000
150
Transformer
Connection
18,000
240,000
150,000
150
The bus conductors will be desigRed for a temperature rise uf 65"C
above 40"C ambient.
{d) Generator Circuit Breakers
The generator circuit breakers will be enclosed air circuit break-
ers suitable for mounting in line with the generator 1solated.
phase bus i:1ucts. They are rated as follows:
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Rated Current
Voltage
Breaking capacity,
symmetrical, amps
9,000 Amps
23 kV c1ass, 3-phase, 60 Hertz
150,000
The short circuit rating is tentative and will depend on detailed
analysis in the design stage.
(e) 345 kV Oil-Filled Cable
The recommended 345 kV connection is a 345 kV oil-filled cable
system between the high voltage terminals of the transformer and
the surface switchyard. Cables from two transformers will be
installed in a single vertical cable shaft.
The cable will be rated for a continuous maximum current of 800
amps at 345 kV +5 percent. The maximum conductor temperature at
the maximum ratTng will be 70°C over a maximum ambient of 35°C.
This rating will correspond to 115 percent of the generator over-
load rating. The normal operating rating of the cable will be 87
percent, with a corresponding lower conductor temperature which
will improve the overall performance and lower cable aging over
the project operating life. Depending on the ambient air tempera-
ture, a further overload emergency rating of about 10 to 20 per-
cent will be available during winter conditions.
The cables will be of single-core construction with oil flow
through a central oil duct within the copper conductor. The oi 1
duct provided within the cables will permit low viscosity oil to
flow automatically into or out of hermetically sealed reservoirs
or 11 pressure tanks" directly connected to the cable during a
heating/cooling cycle. Cables will have an aluminum sheath and
PVC oversheath. No cable jointing will be required for the 700-
to 800-foot cable installation.
(f) Control Systems
( i ) General
A Susitna Area Control Center will be located at Watana to
control both the Watana and the Devil Canyon power plants~
The control center will be 1 inked through the supervisory
system to the Central Dispatch Contro 1 Center at Wi 11 ow as
described in Exhibit B, Section 3.6.
The supervisory control of the entire Alaska Railbelt sys-
tem will be accomplished at the Central Dispatch Center at
Willow. A high level of control automation with the aid of
digital computers will . be sought, but not complete com-
puterized control of the Watana and Devil Canyon power
plants. Independent operator controlled local-manual and
A-5-7
local-auto operations will still be possible at Watana and
Devil Canyon power plants for testing/commissioning or dur-
ing emergencies. The control system will be designed to
perform the following functions at both power plants:
-Start/stop' and loading of units by operator;
-Load-frequency control of units;
-Reservoir/water flow control;
-Continuous monitoring and data logging;
-Alarm annunciation; and
Man-machine communication through visual display units
(VDU) and console.
In addition, the computer system wi 11 be capab 1 e of re-
trieval of technical data, design criteria, equipment char-
acteristics and operating limitations, schematic diagrams,
and operating/ maintenance records of the unit.
The Susitna Area Control Center will be capable of com-
pletely independent control of the Central Dispatch Center
in case of system emergencies. Similarly it will be pos-
sible to operate the Susitna units in an emergency from the
Central Dispatch Center, although this should be an un-
likely operation considering the size, complexity, and im-
pact of the Susitna generating plants on the system.
The Watana and Devil Canyon plants will be capable of
"black start" operation ·in the event of a complete blackout
or co 11 apse of the power system. The contra 1 systems of
the two plants and the Susitna Area Control Center complex
will be supplied by a non-interruptible power supply.
(ii) Unit Control System
The unit control system will permit the operator to initi-
ate an entire sequence of actions by pushing one button at
the control console, provided all preliminary plant condi-
tions have been first checked by the operator, and system
security and unit commitment have been cleared through the
central dispatch control supervisor. Unit control will be
designed to:
-Start a unit and synchronize it with the system
-Load the unit
-Stop a unit
Operate a unit as spinning reserve (runner in air with
water blown down in turbine and draft tube)
-Operate as a synchronous condenser (runner in air as
above).
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(iii) Computer-Aided Control System
The computer-aided control system at the Susitna Area Con-
trol Center at Watana will provide for the following:
-Data acquisition and monitoring of units (MW, MVAR,
speed, gate position, temperatures, etc.);
-Data acquisition and monitoring of reservoir headwater
and tailwater levels;
-Data acquisition and monitoring of electrical system
voltage and frequency;
-Load-frequency control;
-Unit start/stop control;
-Unit loading;
-Plant operation alarm and trip conditions (audible and
visual alarm on control board, full alarm details on VDU
on demand);
-General visual plant operation status on VDU and on large
wall mimic diagram;
-Data logging, plant operation records;
-Plant abnormal operation or disturbance automatic record-
ing; and
-Water management (reservoir control).
(iv) Local Control and Relay Boards
( v)
Local boards will be provided at the powerhouse floor
equipped with local controls, alarms, and indications for
all unit control functions. These boards will be located
near each unit and will be utilized mainly during testing,
commissioning, and maintenance of the turbines and genera-
tors. They will also be utilized as needed during emergen-
cies if there is a total failure of the remote or computer-
aided control systems.
Load-Frequency Control
The load-frequency system will provide remote control of
the output of the generator at Watana and Devil Canyon from
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the central dispatch control center through the supervisory
and computer-aided control system at Watana. The basic
method of 1 oad-frequency contro 1 wi 11 use the plant error
(differential) signals from the load dispatch center and
wi 11 all ocate these errors to the power plant generators
automatically through speed-level motors. Provision will
be made in the control system for the more advanced scheme
of a closed-loop control system with digital control of
generator power.
The contro 1 system wi 11 be designed to take into account
the digital nature of the controller-timed pulses as well
as the inherent time delays caused by the speed-level motor
runup and turbine-generator time constants.
(g) Station Service Auxiliary AC and DC Systems
(i) Auxiliary AC System
The station service system w"ill be designed to achieve a
reliable and economic distribution system for the power
plant and switchyard ·in order to satisfy the following
requirements:
Station service power at 480 volts will be obtained from
two 2,000 kVA auxiliary transformers connected directly
to the generator circuit breaker outgoing leads of Units
1 and 3;
-Surface auxiliary power at 34.5 kV will be supplied by
two separate 7. 5/10 MVA transformers connected to the
generator leads of Units 1 and 3;
-Station service power will be maintained even when all
units are shut down and the generator circuit breakers
are open;
-100 percent standby transformer capacity will be avai 1-
able;
- A spare aux i 1 i ary transformer wi 11 be maintained, con-
nected to Unit 5; and
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11 Black start 11 capability will be provided for the power
plant in the event of total failure of the auxiliary
supply system, and 500 kW emergency diesel generators
will be automatically started to supply the power plant
and switchyard with auxiliary power to the essential
services to enable start-up of the generators.
The main ac auxiliary switchboard will be provided with two
bus sections separated by bus-tie circuit breakers. Under
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normal operating conditions, t-h~ station-service load is
divided and connected to each of the two-end incoming
transformers. In the event of failur~ of_one end supply,
the tie breakers will close automatically. If both end
supplies fail, the emergency diesel generator will be auto-
matically connected to the station service bus.
Each unit will be provided with a unit auxiliary board sup-
p 1 i ed by separate feeders from the two bus section feeder
from the two bus section of the main switchboard inter-
locked to prevent parallel operation. Separate ac switch-
boards will furnish the auxiliary power to essential and
general services in the power plant.
The unit auxiliary board will supply the auxiliaries neces-
sary for starting, running, and stopping the generating
unit. These supplies will include those to the governor
and oi 1 pressure system, bearing oi 1 pumps, coo 1 i ng pumps
and fans, generator circuit breaker, excitation system, and
miscellaneous pumps and devices connected with unit opera-
tion.
The 34.5 kV supply to the surface facilities will be dis-
tributed from a 34.5 kV switchboard located in the surface
control and administration building. Power supplies to the
switchyard, power intake, and spillway as well as the
1 i ght i ng systems for the access roads and tunne 1 s will be
obtained from the 34.5 kV switchboard.
The two 2000 kVA, 15,000/480 volt stations service trans-
formers and the spare transformer will be of the 3-phase,
dry-type, sealed gas-filled design. The two 7.5/10 MVA,
15/34.5 kV transformers will be of the 3-phase oil-immersed
OA/FA type.
Emergency diesel generators, each rated 500 kW, will sep-
arately supply the 480 volt and 34.5 kV auxiliary ·switch-
boards during emergencies. Both diesel generators will be-
located in the surface control building.
An uni nterrupti b 1 e high security power supply will be pro-
vided for the computer control system.
DC Auxiliary Station Service System
The de auxiliary system will supply the protective relay-
ing, supervisory, alarm, control, tripping and indication
circuit in the power plant. The generator excitation sys-
tem wi 11 be started with 11 fl as hi ng 11 power from the de bat-
tery. The de auxiliary system will also supply the emer-
gency lighting system at critical plant locations.
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6 -LANDS OF THE UNITED STATES
The Susitna Hydroelectric Project will include numerous parcels of
federal land within the project boundary as defined in Exhibit G of
this application. The following is a tabulation of those lands with
ownership and acreage. Included under the federal lands are those with
non-federal owners but which are subject to Section 24 of the Federal
Power Act.
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DAMSITES, QUARRYSITES AND RESERVOIR AREAS
(Federal Ownership)
SEWARD MERIDIAN, ALASKA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE
T31N,R1W
Section 1 BLM** 66 640.0
Section 2 BLM** 66 640.0
T32N,R1W
Section 35 BLI~** G6 320.0
Section 36 CIRI G6 0
T31N,R1E
Section 1 CIRI G7 0
Section 2 CIRI G7 0
Section 3 CIRI G7 0
Section 4 CIRI 66&G7 0
Section 5 CIRI 66 0
Section 6 BLM** 66 607.4
Section 7 BLM** 66 152.1
Section 8 BLM** · G6 160.0
Section9 BLM** G6 60.0
Section 10 BLM** G7 00.6
Sect ion 11 BLM** G7 00.5
T321~,R1E
Section 31 CIRI G6 0
Section 32 CIRI 66 0
Section 33 CIRI G6&G7 0
Section 34 BLM** G7 22.9
T31N,R2E
Section 1 CIRI G8 0
Section 4 BLM** 67&G8 137.4
Section 5 BLM** G7 200.2
Section 6 BLM** G7 275.0
Section 7 BLM** G7 57.9
Section 8 BLM** G7 00.7
Section 12 CIRI G8 0
Section 13 BLM** G8&G9 207.5
Section 24 BLM** G9 07.4
A-6-2
SEC.24 FPA
ACREAGE*
0
0
0
28.5
235.5
340.7
367.5
188.2
19.4
88.7
0
0
0.7
00.6
00.5
264.4
370.0
251.8
22.9
189.3
137.4
200.2
27'5.0
57.9
00.7
197.1
207.5
07.4
DAMSITES, QUARRYSITES AND RESERVOIR AREAS (Cont 1 d)
SEC.24 FPA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE ACREAGE* --
T32N, R2E
Section 22 BLM** GB 00.2 00.2
Section 27 BLM** G8 51.2 51.2
Section 31 BUt G7 01.1 01.1
Section 32 CIRI G7 0 48.0
Section 33 CIRI G7&G8 0 222.3
Section 34 CIRI G8 0 176.5
Section 35 CIRI G8 0 161.8
Section 36 CIRI G8 0 120.9
T31N,R3E
Section 13 BLM** G10 43.4 43.4
Section 14 BLM** G10 97.8 97.8
Section 15 BLM** G10 108.8 108.8 ,-
Section 16 BLM** G10 17.2 17.2
Section 17 BLM** G9&G10 59.9 59.9
Section 18 BLM** G9 148.0 148.0
Section 19 CIRI G9 0 157.9
Section 20 CIRI G9&G10 0 149.3
Section 21 CIRI GlO 0 226.2
Section 22 CIRI G10 0 196.0
Section 23 BLM** G10 201.3 201.3
Section 24 CIRI G10 0 323.4
T3~N,R4E
Section 2 CIRI G12 0 51.7
Section 3 CIRI G11&G12 0 268.6
Section 9 BLM** Gll 38.3 38.3
Section 10 BLM** Gll 300.0 300.0
Section 15 BLM** Gll 95.6 95.6
Section 16 CIRI Gll 0 318.5
Section 18 BLM G10 00.2 00.2
Section 19 CIRI G10 0 374.4
Section 20 BLM** G10&Gll 445.7 445.7
Section 21 CIRI Gll 0 319.5
Section 29 BLM** Gll 02.7 02.7
T32N, R4E
Section 25 CIRI G12 0 32.6
Section 26 BLM G12 225.0 03.5
Section 34 BLM** G12 130.0 33.1
Section 35 CIRI G12 0 388.0
Section 36 CIRI G12 0 262.9
A-6-3
;;~
DAMSITES, QUARRYSITES AND RESERVOIR AREAS (Cont'd)
SEC.24 FPA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE ACREAGE*
T31N,R5E
-Section 3 BLM** Gl3&G15 420.0 0
Section 4 BLM** G13 480.0 0
Section 5 BLM** G13 360.0 0
T32N,R5E
Section 13 BLM G16 60.6 0
Section 14 BLM G16 260.0 0
Section 15 BLM G14&G16 400.0 0
Section 16 BLM G14 330.0 0
Section 17 BLM G14 30.0 0
Section 19 BLM G13&G14 160.0 0
Section 20 BLM G13&G14 560.0 0 -Section 21 BLM G13&614 640.0 0
Section 22 BLM 613 ,G14&G15 640.0 0
Section 23 BLM G15&G16 631.1 00.7
Section 24 BLM 615&G16 75.2 0
Section 25 BLM** 615 560.3 72.5
Section 26 CIRI G15 0 327.2
Section 27 CIRI G13&G15 0 238.3
Section 28 CIRI Gl3 0 47.3
Section 29 BLM 613 640.0 0
Section 30 CIRI G13 0 38.1 -Section 31 CIRI Gl3 0 127.7
Section 32 CIRI G13 0 196.5
Section 33 CIRI G13 0 204.3
Section 34 BLM** G13&G15 598.4 104.8
Section 35 BLM** 615 303.5 84.4
Section 26 BLM** G15 329.3 180.1
,..... T31N,R6E
Section 1 BLM** G17 233.8 00.2
Section 2 BLM** 617 01.9 0 -
T32N,R6E
~ Section 2 BLM G18 09.3 0
Section 3 BLM G18 01.0 0
Section 10 BLM G18 201.1 0
!"""' Section 11 BLM G18 70.6 0
Section 13 BLM G18 482.3 0 Section 14 BLM G18 243.2 0
Section 15 BLM G18 507.2 0
ff""
.....
A-6-4
DAMSITES, QUARRYSITES AND RESERVOIR AREAS (Cont'd)
SEC.24 FPA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE ACREAGE*
T32N,R6E (Cont'd)
Section 16 BLM G18 00.7 0
Section 21 BLM G15,G16&G18 162.5 0
Section 22 BLM G17&G18 640.0 74.8
Section 23 BLM G17&G18 640.0 03.2
Section 24 BLM G17&G18 640.0 214.9
Section 25 BLM** Gll 640.0 556.5
Sect ion 26 BLM** G17 640.0 573.9
Section 27 BLM** G17 640.0 496.8
Section 28 BLI~** G15&G17 630.2 407.0
Section 29 BLM** G15 496.0 212.3 r--I
Section 30 BLM G15 382.2 73.0
Section 31 BLM** G15 333.6 204.0
Section 32 BLM** G15 256.1 92.6
Section 33 BLM** G15&G16 184.9 01.3
Section 34 BLM** G17 257.8 0
Section 35 BLM** G17 396.5 14.4
Section 36 BLM** G17 633.3 219.8 p---,,
T31N,R7E
Section 1 BLM G19 338.0 61.3
Section 2 BLM G19 634.4 481.2
Section 3 BLM G19 629.8 523.1
Section 4 BLM*** G17&G1{) 495.8 304.4
Section 5 BLM** G17 332.4 111.7
Section 6 BLM** G17 302.3 01.1
Section 10 BLM G19 88.1 00.4
Section 11 BLM*** G19 311.4 146.3
Section 12 BLM*** G19 621.8 462.1
Section 13 BLM G19 141.4 41.5
Section 14 BLM G19 01.1 0
T32N,R7E
Section 3 BLM G20 246.4 0
Section 4 BLM G18&G20 160.7 17.1
Section 7 BLM G18 166.5 0
Section 8 BLM G18 331.0 91.9
Section 9 BLM G18&G20 517.5 96.7
Section 10 BLM G20 31.9 0
Section 16 BLM G18 141.8 0
Section 17 BLM G18 637.5 175.5
Section 18 BLM G18 563.9 151.2
Section 19 BLI~ G17&G18 601.8 290.0
A-6-5
DAMSITES, QUARRYSITES AND RESERVOIR AREAS (Cont•d)
~
SEC.24 FPA .-TOWNSHIP/Section OWNER PLATE U.S. ACREAGE ACREAGE*
T32N,R7E (Cont•d)
~ Section 20 BLM G17&G18 640.0 0
Section 21 BLM G17, G18&G20 391.6 0
Section 22 BLM G19&G20 60.7 0
Section 27 BLM G19 174.4 0
Section 28 BLM G17&G19 624.1 0
Section 29 BLM Gl7 640.0 0
Section 30 BLM** G17 603.7 226.9
Section 31 BLM** G17 605.5 483.9
Section 32 BLM*** G17 640.0 497.2
Section 33 BLM*** G17&G19 640.0 344.2
Section 34 BLM G19 423.5 97.3
Section 35 BLM G19 53.5 0
Section 36 BLM G19 11.0 0
T33N,R7E
"""'
Section 27 BLM G21 80.2 0
Section 28 BLM G21 40.0 0
Section 33 BLM G20&G21 74.0 0
Section 34 BLM G20&G21 182.9 0
T30N ,R8E
Section 4 BLM G23 08.2 0
f31N,R8E
fP" Section 1 BLM G24 56.9 0 '
Section 7 BLM G19 386.4 251.9
Section 8 BLM G19&G24 535.0 311.6
Section 9 BLM G24 576.7 381.6
Section 10 BLM G24 372.9 225.8
Section 11 BLM G24 138.5 44.3
Section 12 BLM G24 287.9 53.1
Section 13 BLM G23&G24 598.6 381.8
Section 14 BLM G23&G24 612.2 431.8
Section 15 BLM G23&G24 640.0 476.8 r-Section 16 BLM G24&G23 280.3 128.6 I Section 17 BLM G19,G22&G24 334.7 211.0
Section 18 BLM G19 353.1 193.5
Section 21 BLM G23 182.3 35.3
Section 22 BLM G23 248.9 52.4
Section 23 BLM G23 09.1 ' 0 -Section 24 BLM G23 55.1 0
' Section 27 BLM G23 06.1 0
Section 28 BLM G23 245.8 01.2
Section 33 BLM G23 138.4 0
A-6-6
DAMSITES, QUARRYSITES AND RESERVOIR AREAS {Cont'd)
SEC.24 FPA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE ACREAGE*
T30N,R9E
Section 1 BLM G26 143.0 33.5
Section 12 BLM G26 105.3 03.8
Section 13 BLM G26 05.8 0
T31N, R9E
Section 6 BLM G24 49.2 0
Section 7 BLM G24 00.7 0
Section 17 BLM G24&G25 178.0 97.7
Section 18 BLM G23&G24 450.2 376.9
Section 19 BLM G23 175.3 24.3
Section 20 BLM G23&G24 432.8 306.7
Section 21 BLM G25 499.3 357.1
Section 22 BLM G25 267.1 159.1
Section 23 BLM G25 185.4 73.2
Section 25 BLM G25 280.1 112.9
Section 26 BLM G25 316.2 172.0
Section 27 BLM G25 309.3 148.1 (.""':"-·-,
Section 28 BLM G25 107.8 17.9
Section 36 BLM G25&G26 408.1 136.7
T30N,R10E
Section 6 BLM G26 216.0 122.2
Section 7 BLM G26&G27 389.3 193.5
Section 8 BLM G27 313.7 180.5
Section 9 BLM G27 170.8 13.9
Section 10 BLM G27 96.4 13.6
Section 11 BLM G27 312.9 312.9
Section 12 BLM G27 254.6 254.6
Section 13 BLM G27 120.2 120.2
Section 14 BLM G27 105.1 102.8
Section 15 BL~l G27 251.1 117.1
Section 17 BLM G27 77.9 14.2
T31N,R10E
Section 31 BLM G26&G27 143.2 74.4
T29N,R11E
Section 1 BLM G29 45.2 45.2
Section 2 BLM G29 199.2 199.2
Section 3 BLM G29 222.6 222.6
Section 4 BLM G29 68.2 68.2
A-6-7
,...
DAMSITES, QUARRYSITES AND RESERVOIR AREAS (Cont'd)
~'J!I\ll!'!
SEC.24 FPA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE ACREAGE*
T29N,R11E (Cont'd) -Section 5 BLM G29 176.6 101.5
Section 6 BLM G29 135.3 12.3
Section 9 BLM G29 00.4 00.4 -Section 10 BLM G29 204.5 103.1
T30N,Rl1E
Section 7 BLM G27&28 293.8 165.1
Section 8 BLM G28 01.8 0.18
Sect ion 17 BLM G28 241.0 167.1 -Sect ion 18 BLM G27&G28 280.4 195.7
Section 20 BLM G28 445.9 206.7
Section 21 BLM G28 00.9 0.0
""" Section 25 BLM G29 21.2 21.2
Section 28 BLM G28&G29 177.9 141.6
Section 29 BLM G28&29 480.0 163.4
Section 32 BLM G29 482.7 293.1 -Section 33 BLM G29 437.3 385.4
Sect ion 34 BLM G29 640.0 270.8
Section 35 BLM G29 471.8 269.0 ,_ Section 36 BLM G29 35.6 35.6
TOTAL 61,628.0+ 28,344.8+
-* Areas shown are true areas at elevation
** Selected by Cook Inlet Region Incorporated
*** Partially selected by Cook Inlet Region Incorporated
A-6-8
ELECTRICAL TRANSMISSION LINE CORRIDOR RIGHT-OF-WAY ACREAGES
(Federal Ownership)
SEWARD MERIDIAN, ALASKA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE* --
Tl3N,R2W
Section 4 u.s. Army G30 10.21
Section 5 u.s. Army G30 35.51
Section 7 u.s. Army . G30 37.20
Section 8 u.s. Army G30 06.36
Section 18 u.s. Army G30 30.q8
Section 19 u.s. Army G30 30.66
Section 30 u.s. Army G30 30.31
Section 31 u.s. Army G30 04.46
Tl4N, R2W
Section 19 u.s. Army G30 33.66
Section 20 u.s. Army G30 31.36
Section 21 u.s. Army G30 38.29
Section 22 u.s. Army G30 03.06
Section 28 u.s. Army G30 31.12
Section 33 u.s. Army G30 36.52
Tl4N,3W
Section 9 u.s. Army G30 19.56
Section 10 u.s. Army G30 33.29
Sect ion 11 u.s. Army G30 05.31
Section 13 u.s. Army G30 14.15
Section 14 u.s. Army G30 44.50
Section 24 u.s. Army G30 24.64
T31N,1W
Section 3 BLM** G39 62.74
Section 4 BLM** G39 54.77
Section 5 BLM** G39 62.74
Section 6 BLM** G39 61.36
T32N,R1E
Section 13 BLM** G39 11.77
Section 23 BLM** G39 34.22
Section 24 BLM** G39 33.23
Section 26 BLM** G39 07.35
Section 27 ~LM** G39 38.03
Section 28 BLM** G39 38.03
Section 29 BLM** G39 37.95
Section 30 BLM** G39 02.70
A-6-9
,.,.;·---,,
. ro---,
r:-l
-
ELECTRICAL TRANSMISSION LINE CORRIDOR
RIGHT-OF-WAY ACREAGES (Cont•d)
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE*
T32N,R2E
Section 3 BLM** G39 41.90
Section 4 BLM** G39 20.02
Section 8 BLM** G39 36.99
Section 9 BLW* G39 24.88
Section 17 BLM** G39 07.91
Section 18 BLM** G39 42.13
T33N,R2E
Section 25 BLM** G40 34.20
Section 34 BLM** G40 09 0 28
Section 35 BLM** G40 44.90 -Sect ion 36 BLM** G40 07.81
T32N,R3E
Section 2 BLM** G40 19.69
Section 3 BLI\1** G40 37.52 -Section 11 BLM** G40 22.42
Section 12 BLI\1** G40 40.01
T32N ,R4E
Section 7 BLM** G40 34.69
Section 8 BLM** G40 15.67
Section 13 BLM** G40 37.10
Section 14 BLM** G40 37.10
Section 15 BLM** G40 35.22
Section 16 BLM** G40 37.10
.ffll8\ Section 17 BLM** G40 21.43
T32N, R5E -Section 18 BLM** G40 16.45
Section 19 BLM** G40 20.47
Section 20 BLM** G40 07.68
SEWARD MERIDIAN SUB-TOTAL 1,598.31~
"""'
A-6-10
ELECTRICAL TRANSMISSION LINE CORRIDOR
RIGHT-OF-WAY ACREAGES (Cont 1 d) (c-'
FAIRBANKS MERIDIAN, ALASKA
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE* --
Tl2S,R7W
Section 7 FED R.R. G46 43.77
Section 17 FED R.R. G46 15.71
Section 18 FED R.R. G46 14.52
T7S,R8W
Section 24 USAF G48 23.27
Section 25 USAF G48 51.86
Section 26 USAF G48 51.86
T7S, R7W
Section 5 USAF G48 48.93
Section 6 USAF G48 02.76
Section 7 USAF G48 51.36
Section 8 USAF G48 00.50
Section 18 USAF G48 51.86
Section 19 USAF G48 28.59
T6S,R7W
Section 4 BLM G49 49.43
Section 9 BLM G49 48.70
Section 16 BLM G49 48.25
Section 17 BLM G49 00.45
Section 20 BLM G49 34.86
Section 21 BLM G49 13.81
Section 29 BLM G49 49.63
Section 32 BLM G49 51.78
FAIRBANKS 1\llERIDIAN SUB-TOTAL 681.90+
TOTAL 2,280.21~
ACREAGE SHOWN IS TRUE AREA AT ELEVATION
A-6-11
·-ACCESS CORRIDOR RIGHT-OF-WAY ACREAGES
(Federal Ownership)
f-..-
ACCESS CORRIDOR RIGHT-OF-WAY ACREAGES (Cont 1 d)
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE*
T22S,R4W
Section 3 BLM G54 24.39
Section 10 BLM G54 24.53
Section 15 BLM G54 26.96
Section 16 BLM G54 08.55
~·-,
FAIRBANKS MERIDIAN SUB-TOTAL 686.25+
SEWARD MERIDIAN, ALASKA
T31N,R1W
Section 3** BLM** G59 26.20
Section 4** BLM** G59 27.92
Section 5** BLM** G59 12.92
Section 6** BLM**· G59 21.80
T32N,R1E
Section 23 BLM** G58 14.19
Section 24 BLM** G58 27.63
Section 26 BLM** G58 12.91
Section 27 BLM** G58 29.85
Section 28 BLM** G58 24.33
Section 29 BLM** G58 13.52
T32N,R2E
Section 2 BLM** G57 15.01
Section 3 BLM** G57 28.29
Section 4 BLM** G57 06.29
Section 8 Bltvl** G58 07.92
Section 9 BLM** G57&G58 31.71
Section 17 BLM** G58 21.70
Section 18 BLM** G58 13.94
Section 19 BLM** G58 13.94
T33N, R2E
Section 35 BLM** G57 19.42
Section 36 BLM** G57 26.34 ~'
A-6-13
fl"" ACCESS CORRIDOR RIGHT-OF-WAY ACREAGES (Cont'd)
TOWNSHIP/Section OWNER PLATE U.S. ACREAGE*
T32N,R3E
Section 2 BLM** G57 01.15
Section 3 BLM** G57 37.09
Section 11 BLM** G57 28.62 -SeCtion 12 BLM** G57 20.09
Section 13 BLM** G57 07.22
T32N,4E
Section 11 BLM** G56 22.96
Section 12 BLM** G56 16.60
Section 13 BLM** G56 21.23
Section 14 BLM** G56 10.80
Section 15 BLM** G56 26.86
Section 16 BLM** G57 24.72
P"' Section 17 BLM** G57 24.75
Section 18 BLM** G57 24.45
-T32N,R5E
Section 3 BLM** G56 47.60 -Section 4 BUo1** G56 26.86
Section 5 BLM** G56 28.06
Section 8 BLM** G56 26.46
Section 10 BLM G56 25.32 r Section 15 BLM G56 09.51
I Section 17 BLM** G56 09.62
Section 18 BLM** G56 23.69
SEWARD MERIDIAN SUB-TOTAL 863. 59+
-TOTAL 1,549.84+
* Areas shown are true areas at elevation
** Selected by Cook Inlet Region Incorporated
A-6-14
-
....
!
-
-
-
7 -PROJECT STRUCTURES -DEVIL CANYON DEVELOPMENT
This section describes the various components of the Devi 1 Canyon de-
velopment, including diversion facilities, emergency release facili-
ties, main dam, primary outlet facilities, reservoir, main and emergen-
cy spillways, saddle dam, power intake, penstocks, and the powerhouse
complex~ including turbines, generators, mechanical and electrical
equipment, switchyard structures, and equipment and project lands. A
summary of project parameters is presented in Table A.1.
A description of permanent and temporary access and support facilities
is also included.
7.1 -General Arrangement
The Devil Canyon reservoir and surrounding area are shown on Plate F39.
The site layout in relation to main access facilities and camp facili-
ties is shown on Plate F70. A more detailed arrangement of the various
site structures is presented in Plate F40.
The Devil Canyon Dam will form a reservoir approximately 26 miles long
with a surface area of 7,800 acres and a gross storage capacity of
1,100,000 acre-feet at Elevation 1455, the normal maximum operating
level. The operating level of the Devil Canyon reservoir is controlled
by the tailwater level of the upstream Watana development. The maximum
water surface ,elevation during flood conditions will be 1466. The
minimum operating level of the reservoir will be 1405, providing a live
storage during normal operation of 350,000 acre-feet.
The dam will be a thin arch concrete structure with a crest elevation
of 1463 (not including a three-foot parapet) and maximum height of 646
feet. The dam will be supported by ~ass concrete thrust blocks on each
abutment. On the south bank, the lower bedrock surface will require
the construction of a substantial thrust block. Adjacent to this
thrust block, an earth-and rockfill saddle dam will provide closure to
the south bank. The saddle dam will be a central core type generally
similar in cross section to the Watana Dam. The dam will have a nom-
inal crest elevation of 1469 with an additional 3 feet of overbuild for
potential seismic settlement. The maximum height above foundation
level of the dam is approximately 245 feet.
During construction, the river will be diverted by means of a single
30-foot diameter concrete-lined diversion tunnel on the south bank of
the riveL
A power intake on the north bank will consist of an approach channel
excavated in rock leading to a reinforced concrete gate structure.
From the intake structure four 20-foot diameter concrete-lined penstock
tunnels will lead to an underground powerhouse complex housing four 150
MW units with Francis turbines and semi-umbrella type generators.
A-7-1
Access to the powerhouse camp 1 ex wi 11 be by means of an un 1 i ned access
tunnel approximately 3200 feet long as well as by a 950-foot deep ver-
tical access shaft. The turbines w·ill discharge to the river by means
of a single 38-foot diameter tailrace tunnel leading from a surge cham-
ber downstream from the powerhouse cavern. A separate transformer gal-
lery just upstream from the powerhouse cavern will house twelve single-
phase 15/345 kV transformers. The transformers will be connected by
345 kV single-phase, oil-filled cable through a cable shaft to the
switchyard at the surface.
Outlet facilities consisting of seven individual outlet conduits will
be located in the lower part of the main dam. These will be designed to
discharge all flood flows of up to 38,500 cfs, the estimated 50-year
flood with Watana in place. This assumes that only one of the generat-
ing units will be operating. Each outlet conduit will have a fixed--
cone valve similar to those provided at Watana to dissipate energy and
minimize undesirable nitrogen supersaturation in the flows downstream.
The main spillway will also be located on the north bank. As at
Watana, this spillway will consist of an upstream agee control struc-
ture with three vertical fixed-wheel gates and an inclined concrete
chute and flip bucket designed to pass a maximum discharge of 123,000
cfs. This spillway, together with the outlet facilities, will thus be
capab 1 e of discharging the estimated 10,000-year flood. An emergency
spillway and fuse plug on tne south bank will provide sufficient addi-
tional capacity to permit discharge of the PMF without overtopping the
dam.
7.2 -Arch Dam
The Devil Canyon Dam will be located at the Devil Canyon gorge, river-
mile 152, approximately 32 river-miles downstream from Watana. The
arch dam will be located at the upstream entrance of the canyon.
The dam will be a thin arch concrete structure 646 feet high, with a
crest length-to-height ratio of approximately two, and designed to
withstand dynamic loadings from intense seismic shaking. The proposed
height of the dam is well within precedent.
(a) Foundations
Bedrock is well exposed along the canyon walls, and the arch dam
will be founded on sound bedrock. Approximately 20 to 40 feet of
weathered and/or loose rock will be removed beneath the dam foun-
dation. A 11 bedrock i rregu 1 ar it i es will be smoothed out beneath
the foundation to eliminate high stress concentrations within the
concrete. During excavation the rock will also be trimmed as far
as is practical to increase the symmetry of the centerline profile
and provide a comparatively uniform bearing stress distribution
across the dam. Areas of deteriorated dikes and the local areas
of poorer quality rock will be excavated and supplemented with
dental concrete.
A-7-2
-
(b)
,. ....
The foundation will be consolidation grouted over its entire area,
and a double grout curtain up to 300 feet deep will run beneath
the dam and its adjacent structures as shown in Plate F47. Grout-
ing will be done from a system of galleries which will run through
the dam and into the rock. Within the rock these galleries will
also serve as collectors for drainage holes which will be drilled
just downstream of the grout curtain and intercept any seepage
passing through the curtain.
Arch Dam Geometry
The canyon is V-shaped below Elevation 1350. Sound bedrock does
not exist above this level on the south abutment and an artificial
abutment wi 11 be provided up to crest El ev at ion 1463 in the form
of a massive concrete thrust block designed to take the thrust
from the upper arches of the dam. A corresponding block will be
formed on ·the north abutment to provide as symmetrical a profile
as possible bordering the dam and to give a symmetrical stress
distribution across the faces of the horizontal arches.
Two slight ridges will be formed by the rock at both abutments.
The arch dam will abut the upstream side of these such that the
plane of the contact of the horizontal arches is generally normal
to the faces of the dam. An exception will be in the lower
portion of the dam where the rock in the upstream corners will be
retained in order to decrease the amount of excavation.
The dam will bear directly on the rock foundation over the entire
length of the contact surface. The bedrock at the foundation will
be excavated to remove all weathered material and further trimmed
to provide a smooth line to the foundation, thus avoiding abrupt
changes in the dam profile and consequent stress concentrations ..
The dam will be a double curvature structure with a cupola shape
of the crown cantilever defined by vertical curves of approxi-
mately 1352-foot and 893-foot radii. The horizontal arches are
based on a two-center configuration with the arches prescribed by
varying radii moving along two pairs of centerlines. The shorter
radii of the intrados face cause a broadening of the arches at the
abutment, thus reducing the contact stresses. The dam reference
plane is approximately central to the floor of the canyon and the
two-center configuration assigns longer radii to the arches on the
wider north side of the valley, thus providing comparable contact
areas and central angles on both sides of the arches at the con-
crete/rock interface. The longer radii will also allow the thrust
from the arches to be directed more into the abutment rather than
para 11 el to the river. The net effect of this two-center 1 ayout
wi 11 be to improve the symmetry of the arch stresses across the
dam.
A-7-3
The crown cantilever will be 643 feet high. It will be 20 feet
thick at the crest and 90 feet at the base, a base width-to-height
ratio of 0.140. The radii of the dam axis at crest level will be
699 feet and 777 feet for the south and north sides of the dam,
respectively. The central angles vary between 53° at Elevation
1300 and 10° at the base for the south side of the arch, and 57°
to 10° for the north side. The dam crest length is 1260 feet and
the ratio of crest length to height for the dam is 1.96 (thrust
blocks not included). The volume of concrete in the dam is
approximately 1.3 x 106 cubic yards.
(c) Thrust Blocks
The thrust blocks are shown on Plate F46. The massive concrete
block on the south abutment is 113 feet high and 200 feet long.
It wi 11 be formed to take the thrust from the upper part of the
dam above the existing sound rock level. It will also serve as a
trans it ion between the concrete dam and the adjacent rockfill
saddle dam. The inclined end face of the block will abut and seal
against the impervious saddle dam core and be enveloped by the
supporting rock shell.
The 113-foot high, 125-foot long thrust block formed high on the
north abutment at the end of the dam, adjacent to the spillway
control structure, will transmit thrust from the dam through the
intake control structure and into the rock.
7.3-Saddle Dam
The saddle dam at Devil Canyon, which is of similar configuration as
the main Watana Dam, will be of earth and rockfill construction and
will consist of a central compacted core protected by fine and coarse
fi 1 ters upstream and downstream. The downstream outer shell wi 11 con-
sist of two zones: a lower zone of clean processed rockfill material,
and an upper zone of unprocessed rockfill material. The upstream outer
shell will consist of cleaned and graded rockfill material. A typical
cross section is shown on Plate F49 and described below.
(a) Typical Cross Section
The central core slopes are 1H:4V with a top width of 15 feet.
The thickness of the core at any section will be slightly more
than 0.5 times the head of water at that section. Minimum core-
foundation contact will be 50 feet, requiring flaring of the cross
section at the abutments.
The upstream and downstream filter zones will increase in thick-
ness from 45 and 30 feet, respectively, near the crest of the dam
to a maximum of approximately 60 feet at the filter-foundation
contact. They are sized to provide protection against possible
piping through transverse cracks that could occur because of set-
tlement or resulting from internal displacement during a seismic
event.
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Protection against wave and ice action on the upstream slope will
consist of a 10-foot layer of riprap comprising quarried rock up
to 36 inches in size.
The estimated volumes of material needed to construct the saddle
dam are:
-core material
-fine filter material
-coarse filter material
-rockfill material
310,000 cubic yards
230,000 cubic yards
180,000 cubic yards
1,200,000 cubic yards
The saturated sections of both shells will be constructed of com-
pacted clean rockfill processed to remove fin.e material in order
to minimize pore pressure generation and ensure rapid dissipation
during and after a seismic event. The lower section of the down-
stream shell, due to a unique combination of bedrock and topo-
graphic elevations, may become saturated by natural runoff or dam
seepage. During design the cost of a major drainage system to
prevent this occurrence will be weighed against the added cost of
processing the materials for the lower portion of the fill. Since
pore pressures cannot develop in the unsaturated upper section of
the downstream shell, the material in that zone will be unproc-
essed rockfill from surface or underground excavations.
(b) Crest Details and Freeboard
A 3-foot high parapet will be constructed on the crest of the arch
dam to provide a freeboard of 11 feet.
The highest reservoir level will be Elevation 1466 under PMF con-
ditions. At this elevation, the fuse plug in the emergency spill-
way will be breached and the reservoir level will fall to the
emergency spillway sill elevation of 1434. The normal maximum
pool elevation will be 1455.
The typical crest detail for the saddle darn is shown in Plate F50.
Because of the narrowing of the darn crest, the filter zones are
reduced in width and the upstream and downstream coarse filters
are eliminated. A layer of filter fabric is incorporated to
protect the core material from damage by frost penetration and
dessication, and to act as a coarse filter where required.
A minimum saddle darn freeboard of three feet will be provided for
the PMF; hence, the nominal crest of the saddle dam will be Eleva-
tion 1469. In addition, an a 11 owance of one, percent of the height
of the dam will be made for potential settlement of the rockfill
shells under seismic loading. An allowance of one foot has been
made for settlement adjacent to the abutments; hence, the con-
structed crest elevations of the saddle dam will be 1470 at the
abutments, rising in proportion to the total height of the dam to
Elevation 1472 at the maximum section. Under normal operating
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conditions, the freeboard will range from 15 feet at the abutments
to 17 feet at the center of the dam. Further allowances will be
made to compensate for static settlement of the dam after comple-
tion due to its own weight and the effect of saturation of the up-
stream shell, which will tend to produce additional breakdown of
the rockfill at point contacts. Therefore, one percent of the dam
height will be allowed for such settlement, giving a maximum crest
elevation on completion of the construction of 1475 at the maximum
height, and 1471 at the abutments.
The allowances for post-construction settlement and seismic slump-
ing will be achieved by steepening both slopes of the dam above
Elevation 1400. These allowances are considered conservative.
(c) Grouting and Pressure Relief System
The rock foundation will be improved by consolidation grouting
over the core contact area and by a grouted cutoff along the cen-
terline of the core. The cutoff at any location will extend to a
depth of a least 0.7 of the water head at that location, as shown
on Plate F47.
A grouting and drainage tunnel will be excavated in bedrock be-
neath the dam along the centerline of the core and will connect
with a simi 1 ar tunnel beneath the adjacent concrete arch dam and
thrust block. Pressure relief and drainage holes will be drilled
from this tunnel, and seepage from the drainage system will be
discharged through the arch dam drainage system to ultimately exit
downstream below tailwater level.
(d) Instrument at ion
Instrumentation will be installed within all parts of the dam to
provide monitoring during construction as well as during opera-
tion. Instruments for measuring internal vertical and horizontal
displacements, stresses and strains, and total and fluid pres-
sures, as well as surface monuments and markers similar to those
proposed for the Watana Dam, will be installed,
7.4-Diversion
(a) General
Diversion of the river flow during construction will be through a
single 30-foot diameter' concrete-1 ined diversion tunnel on the
south bank. The tunnel will have a horseshoe-shaped cross section
and be 1,490 feet in length. The diversion tunnel plan and pro-
file are shown on Plate F51.
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(b)
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(c)
The tunnel is designed to pass a flood with a return frequency of
1:25 years routed through the Watana reservoir. The peak flow
that the tunnel wi 11 discharge will be 39,000 cfs. The maximum
water surface elevation upstream of the cofferdam will be Eleva-
tion 944.
Cofferdams
The upstream cofferdam will consist of a zoned embankment founded
on a closure dam (see Plate F52). The closure dam will be con-
structed to Elevation 915 based on a low water elevation of 910
and will consist of coarse material on the upstream side grading
to finer material on the downstream side. When the closure dam is
completed, a grout curtain or slurry wall cutoff will be con-
structed to minimize seepage into the main dam excavation. Final
details of this cut-off will be determined following further inv-
estigations to define the type and properties of river alluvium.
The abutment areas w·ill be excavated to sound rock prior to place-
ment of any cofferdam material.
The cofferdam, from Elevation 915 to 947, will be a zoned embank-
ment consisting of a central core, fine and coarse upstream and
downstream filters, and rock and/or gravel shells with riprap on
the upstream face. The downstream cofferdam will be a similar
closure dam constructed from Elevation 860 to 898, with a cutoff
to bedrock.
The upstream cofferdam crest elevation wi 11 have a 3-foot free-
board allowance for sett 1 ement and wave run up. Under the proposed
schedule, the Watana development will be operational when this
cofferdam is constructed. Therma 1 studies conducted show that
discharge from the Watana reservoir will be at 34°F when passing
through De vi 1 Canyon. Therefore, an ice cover wi 11 not form up-
stream of the cofferdam, and no freeboard allowance for ice wi 11
be necessary.
Tunnel Portals and Gates
A gated concrete intake structure will be located at the upstream
end of the tunnel (see Plate F53). The portal and gate will be
designed for an external pressure (static) head of 250 feet.
Two 30-foot high by 15-foot wide water passages wi 11 be formed in
the intake structure, separated by a central concrete pier. Gate
guides wi 11 be provided within the passages for the operation of
30-foot high by 15-foot wide fixed-whee 1 c losure/contro 1 gates.
Each gate will be operated by a wire rope hoist in an enclosed
housing, and wi 11 be designed to operate with a 75-foot operating
head (Elevation 945).
A-7-7
Stoplog guides will be installed in the diversion tunnel to permit
dewatering of the diversion tunnel for plugging operations. The
stoplogs will be in sections to facilitate relatively easy hand-
ling, with a mobile crane using a follower beam.
(d) Final Closure and Reservoir Filling
Upon completion of the Devil Canyon Dam to a height sufficient to
allow ponding to a level above the outlet facilities, the intake
gates will be partially closed, allowing for a discharge of mini-
mum environmental flows while raising the upstream water level.
Once the level rises above the lower level of discharge valves,
the diversion gates will be permanently closed and discharge will
be through the 90-inch diameter fixed-cone valves in the dam. The
diversion tunnel will be plugged with concrete and curtain grout-
ing performed around the plug. Construction will take approxi-
mately 1 year. During this time the reservoir will not be allowed
to rise above Elevation 1135.
7.5-Outlet Facilities
The primary function of the outlet facilities is to provide for dis-
charge through the main dam, in conjunction with the power facilities,
of routed floods with up to 1:50 years recurrence period at the Devil
Canyon reservoir. This will require a total discharge capacity of
38,500 cfs through the valves. The use of fixed-cone valves will en-
sure that downstream erosion will be minimal and nitrogen supersatura-
tion of the releases will be reduced to acceptable levels, as in the
case of the Watana development. A further funct.ion of these releases
is to pro vi de an emergency drawdown for the reservoir,· should mai nten-
ance be necessary on the main dam or low level submerged structures,
and also to act as a diversion facility during the latter part of the
construction period.
The outlet facilities will be located in the lower portion of the main
dam, as shown on Plate F48, and will consist of seven fixed-cone dis-
charge valves set in the lower part of the arch dam.
(a) Outlet
The fixed-cone type disch~rge valves will be located at two eleva-
tions: the upper group, consisting of four 102-inch diameter
valves, will be set at Elevation 1050, and the lower group of
three 90-inch diameter valves will be set at Elevation 930. The
valves will be installed nearly radially (normal to the dam cen-
terline) with the points of impact of the issuing jets staggered
as shown in Plate F48.
Th~ fixed-cone valves will be installed on individual conduits
passing through the dam, set close to the downstream face, and
protected by upstream ring follower gates located in separate
A-7--a
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(b)
chambers within the dam. Provisions will be made for maintenance
and removal of the valves and gates. The gates and valves wi 11 be
1 inked by a 20-foot high gallery running across the dam and into
the left abutment, where access will be provided by means of a
vertical shaft exiting through the thrust block. Although second-
ary access will be provided via a similar shaft from the north
abutment, primary access and install at ion are both from the south
side.
The valve and gate assemblies will be protected by individual
trashracks installed on the upstream face. The racks wi 11 be re-
movable along guides running on the upstream dam face. A travel-
ling gantry crane will be used for raising the racks. Guides will
be installed-for the installation of bulkhead gates, if required,
at the upstream face. The bulkhead gates will be handled by the
travelling gantry crane.
Fixed-Cone Valves
The 102-inch diameter valves operating at a gross head of 405 feet
and the 90-inch diameter valves operating at a head of 525 feet
are within current precedent considering the valve size and the
static head on the valve. The valves will be located in individ-
ually heated rooms and will be provided with electric jacket heat-
ers installed around the cylindrical sleeve of each valve. The
valves will be capable of year-round operation, although winter
operation is not contemplated. Normally, when the valves are
closed, the upstream ring follower gates will also be closed to
minimize leakage and freezing of water through the valve seats.
The valves will be operated remotely by two hydraulic operators.
Operation of the valves will be from either Watana or by local
operation.
(c) Ring Follower Gates
(d)
Ring follower gates will be installed upstream of each valve.
The ring follower gates will have nominal diameters of 102 and 90
inches and will be of welded or cast steel construction. The
gates will be designed to withstand the total static head under
full reservoir.
The design and arrangement of tbe ring follower gates will be as
for Watana.
Trashracks
A steel trashrack will be instal1ed at the upstream entra-nce to
each water passage to prev-ent debris from being drawn into the
A-7-9
discharge valves.
mately 6 inches.
across the racks.
(e) Bulkhead Gates
The bar spacing on the racks will be approxi-
Provision will be made for monitoring head loss
The bulkhead gates will be installed only under balanced head con-
ditions using the gantry crane. The gates will be 13 feet and 11
feet square for the upper and lower valves, respectively.
Each gate will be designed to withstand full differential head un-
der maximum reservoir water level. One gate for each valve size
has been assumed. The gates will be stored at the dam crest
1 eve 1 .
A temporary cover will be placed in the bulkhead gate check at
trashrack level to prevent debris from getting behind the trash-
racks.
The bulkhead gates and trashracks will be handled by an electric
travelling gantry type crane located on the main dam crest at Ele-
vation 1463. The crane and lifting arrangement will have provi-
sion for lowering a gate around the curved face of the dam.
7.6-Main Spillway
The main spillway at Devil Canyon will be located on the north side of
the canyon (see Plate F54). The upstream control structure will be
adjacent to the arch dam thrust block and will discharge down an
inclined concrete-1 i ned chute constructed on the steep face of the
canyon wall. The chute will terminate in a flip bucket which will
direct flows downstream and into the river.
The spillway will be designed to pass the 1:10,000 year Watana routed
flood in conjunction with the outlet facilities. The spillway will
have a design capacity of 123,000 cfs discharged over a total head drop
of 550 feet. No surcharge wi 11 occur above the normal maximum reser-
voir operating level of 1455 feet during passage of this flood.
(a) Approach Channel and Control Structure
The approach channel will be excavated to a depth of approximately
100 feet in the rock with a width of just over 130 feet and an
invert elevation of 1375.
The control structure, as shown in Plate F55, will be a three-bay
concrete structure set at the end of the channel. Each bay wi 11
incorporate a 56-foot high by 30-foot wide gate on an agee-crested
weir and, in conjunction with the other gates, will control the
flows passing through the spillway. The gates will be fixed-wheel
gates operated by individual rope hoists.
A-7-10
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(b) -
(c)
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A gallery will be provided within the mass concrete weir from
which grouting can be carried out and drain holes can be drilled
as a continuation of the grout curtain and drainage beneath the
main dam. The main access route will cross the control structure
deck upstream of the gate tower and bridge structure.
Spillway Chute
The spillway chute will be excavated in the steep north face of
the canyon for a distance of approximately 900 feet, terminating
at Elevation 1000. The chute will taper uniformly over its length
from 122 feet -at the upstream end to 80 feet downstream. The
chute wi 11 be concrete-1 ined with invert and wall slabs anchored
to the rock.
The velocity at the lower end of the chute will be approximately
150ft/sec. In order to prevent cavitation of the chute surfaces,
air will be introduced into the discharges. As at Watana, air
will be drawn in along the chute via an underlying aeration gal-
lery and offshoot ducts extending to the downstream side of a
raised step running transverse to the chute.
An extensive underdrainage system will be provided, similar to
that described for Watana, to ensure adequate underdrainage of the
spillway chute and stability of the structure. This system is
designed to prevent excessive uplift pressures due to reservoir
seepage under the control structure and from groundwater and
seepage through construction joints from the high velocity flows
within the spillway itself.
The dam grout curtain and drajnage system will be extended under
the spillway control structure utilizing a gallery through the
rollway. A system of box drains will be installed for the entire
length of the spillway under the concrete slab. To avoid blockage
of the system by freezing of the surface drains, a 30-foot deep
drainage gallery will also be constructed along the entire length
of the spillway. Drain holes from the surface drains will inter-
sect the gallery. To ensure adequate foundation quality for
anchorage, consolidation grouting will be undertaken to a depth of
20 feet. Drainage holes drilled into the base of the high rock
cuts will ensure increased stability of the excavation.
Flip Bucket
The spillway chute will terminate in a mass concrete flip bucket
founded on sound rock at Elevation 970, approximately 100 feet
above the river. Detailed geometry of the curve of the flow sur-
face of the bucket will be confirmed by means of hydraulic model
tests. A grouting/drainage gallery will be provided within the
bucket. The jet issuing from the bucket will be directed down-
stream and parallel to the river alignment.
A-7-11
(d) Plunge Pool
The impact area of the issuing spillway discharge will be limited
to the area of the river surface downstream to prevent excessive
erosion of the canyon walls. This will be done by appropriate
shaping of the flow surface of the flip bucket on the basis of
model studies. Over this impact area the alluvial material in the
riverbed wi 11 be excavated down to sound rock to provide a p 1 unge
pool in which most of the inherent energy of the discharges wi 11
be dissipated, although some energy will already have been dissi-
pated by friction in the chute and in dispersion and friction
through the air.
7.7 -Emergency Spillway
The emergency spillway will be located on the south side of the river
south of the rockfill saddle dam. It will be excavated within the rock
underlying the south side of the saddle and will continue downstream
for approximately 2,000 feet.
An erodible fuse plug, consisting of impervious material and fine
gravels, will be constructed at the upstream end of the spillway. It
will be designed to wash out when overtopped by the reservoir, releas-
ing flows of up to 150,000 cfs in excess of the combined main spillway
and outlet capacities, thus preventing overtopping of the main or sad-
dle dams during the passage of the PMF.
(a) Fuse Plug and Approach Channel
The approach channel to the fuse plug will be excavated in the
rock and will have a width of 220 feet and an invert elevation of
1434. The channel wi 11 be crossed by the main access road to the
dam on a bridge consisting of concrete piers, precast beams, and
an in situ concrete bridge deck. The fuse plug will fill the
approach channel and will have a maximum height of 31.5 feet with
a crest elevation of 1465.5. The plug will be located on top of a
fl atcrested concrete weir placed on an air-excavated rock founda-
tion. The plug will be traversed by a pilot channel with an in-
vert elevation of 1464.
(b) Discharge Channel
The channel will narrow downstream, lead·ing into a steep valley
tributary above the Susitna River. This channel will rapidly
erode under high flows but will serve the purpose of training the
initial flows in the direction of the valley and away from the
permanent project facilities. The erosion of the channel would
happen on 1 y during an event of very rare frequency. The materia 1
which would erode is alluvial material which would be deposited
downstream. Should the Susitna basin experience flood of this
magnitude, the volume of material eroded would be small relative
to other changes which would take place in the river.
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7.8-Devil Canyon Power Facilities
(a)
(b)
(c)
Intake Structure
The intake structure will be located on the north side of the can-
yon as shown on Plates F59 and F62. Four sets of intake openings
will be provided. The intake openings and power tunnels will be
grouped in pairs so that each turbine may be supplied by water
passing through two sets of intake openings. Each set of intake
openings will consist of an upper and lower opening. The
reservoir level will vary between Elevations 1455 (October through
July) and 1405 (August and September). During the period October
through July, the water will normally be withdrawn from the top
opening in each set. As the reservoir is drawn down in August and
September, the lower opening will be used. Each opening will be
provided with a set of trashracks and a provision for placing
sliding steel closure shutters upstream from the intake opening.
In an emergency, stoplogs will be installed on the upstream wall
of the power intake structure for work on the trashracks or
shutters.
The intake will be located at the end of a 200-foot long unlined
approach channel. The overburden in this area is estimated to be
approximately 10 feet deep. The excavation for the intake struc-
ture wi 11 require four tunnel portals on 60-foot centers. Rock
pillars 32 feet wide and 38 feet deep will separate the portals.
Intake Gates
Each of the four powerhouse intake tunnels will have a single
fixed-wheel intake gate 20 feet wide by 25 feet high. The gates
will have an upstream skinplate and seal and will be operated by
hydraulic or wire rope hoists located in heated enclosures immedi-
ately below deck level. The gates, which will normally close
under balanced head conditions to permit dewatering of the pen-
stock and turbine water passages for turbine inspection and main-
tenance, wil.l also be capable of closing under their own ~veight
with full flow conditions and maximum reservoir water level in the
event of runaway of the turbines. A heated air vent will be pro-
vided at the intake deck to satisfy air demand requirements when
the intake gate is closed with flowing water condition~.
Intake Bulkhead Gates
A bulkhead gate consisting of two sections will be provided for
closing the intake openings. The gate will be used to permit
inspection and maintenance of the intake gate and intake gate
guides. The gates will be raised and lowered under balanced head
conditions only.
A-7-13
(d) Intake Gantry Crane
A 50-ton capacity electrical traveling gantry crane will be pro-
vided on the intake deck at Elevation 1466 for handling the trash-
racks, and intake bulkhead gates and for servicing the intake gate
equipment.
7.9 -Penstocks
The power plant will have four penstocks, one for each unit. The maxi-
mum static head on each penstock will be 638 feet, as measured from
normal maximum operating level (Elevation 1455) to centerline distribu-
tor level (Elevation 817). An allowance of 35 percent has been made
for pressure rise in the penstock under transient conditions, giving a
maximum head of 861 feet. Maximum extreme head (including transient
loadings) corresponding to maximum reservoir flood level will be 876
feet.
The penstock tunnels are fully concrete-1 i ned except for a 250-foot
section upstream of the powerhouse which is steel-lined. The inclined
sections of the concrete-lined penstocks will be at 55° to the horizon-
tal.
(a) Steel Liner
The steel-lined penstock will be 15 feet in diameter. The first
50 feet of steel liner immediately upstream of the powerhouse will
be designed to resist the full internal pressure. The remainder
of the steel 1 i ner, extending another 200 feet upstream, wi 11 be
designed to partially resist the internal pressure together with
the rock. Beyond the steel liner, the hydraulic loads will be
supported solely by the rock tunnel with a concrete liner.
The steel liner is surrounded by a concrete infill with a minimum
thickness of 24 inches. A tapered steel transition will be pro-
vided at the junction between the steel liner and the concrete
liner to increase the internal diameter from 15 feet to 20 feet.
(b) Concrete Liner
The thickness of the concrete 1 in i ng wi 11 vary with the design
head, with the minimum thickness of lining being 12 inches. The
internal diameter of the concrete liner will bL 20 feet.
(c) Grouting and Pressure Relief System
A comprehensive pressure relief system will be installed to pro-
tect the underground caverns against seepage from the high pres-
sure penstocks and reservoirs. The system will consist of small
diameter boreholes set out in an array to intercept the jointing
in the rock. Grouting around the penstocks will also be under-
taken.
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7.10-Powerhouse and Related Structures
The underground powerhouse comp 1 ex wi 11 be constructed in the north
side of the canyon. This will require the excavation of three major
caverns (powerhouse, transformer gallery and surge chamber), with in-
. terconnecting rock tunnels for the draft tubes and isolated phase bus
ducts.
An unlined rock tunnel will be constructed for vehicular access to the
three main rock caverns. A second unlined rock tunnel will provide
access from the powerhouse to the foot of the arch dam.
Vertical shafts will be required for personnel access by elevator to
the underground powerhouse, for oi 1-fi 11 ed cab 1 e from the transformer
gallery, and for surge chamber venting.
The draft tube gate ga 11 ery and cavern wi 11 be located in the surge
chamber cavern, above maximum design surge level.
The general layout of the powerhouse complex is shown on Plates F63,
F64 and F65. The transformer gallery will be located upstream of the
powerhouse. cavern and the surge chamber .wi 11 be located downstream of
the powerhouse cavern. The spacing between the underground caverns
wi 11 be fixed so as to be at 1 east 1. 5 times the main span of the
larger excavation.
(a) Access Tunnels and Shafts
The 3,000-foot long main access tunnel will connect the powerhouse
cavern at Elevation 858 with the canyon access road on the north
bank. A secondary access tunnel will run from the main powerhouse
access tunne 1 to the foot of the arch dam for routine maintenance
of the fixed-cone valves. Branch tunnels from the secondary
access tunne 1 wi 11 pro vi de construction access to the 1 ower sec-
tion of the penstocks at Elevation 820. Separate branch tunnels
from the main access tunnel will give vehicle access to the trans-
former gallery at Elevation 896 and the draft tube gate gallery at
Elevation 908. The maximum gradient on the permanent access tun-
nel will be 8 percent; the maximum gradient on the secondary ac-
cess tunnel will be 9 percent.
The cross section of the access tunnels, which will be dictated by
requirements for the construction plant, will be a modified horse-
shoe shape 35 feet wide by 28 feet high.
The main access shaft wi 11 be located at the north end of the
powerhouse cavern, providing personnel access by elevator from the
surface. Horizontal tunnels will be provided from this shaft for
pedestrian access to the transformer gallery and the draft tube
gate gallery. At a higher level, access will also be available to
the fire protection head tank.
A-7-15
Access to the upstream grouting gallery will be from the trans-
former gallery main access tunnel at a maximum gradient of 13.5
percent.
(b) Powerhouse Cavern
The main powerhouse cavern is designed to accommodate four verti-
cal-shaft Francis turbines~ in line, with direct coupling to over-
hung generators. Each unit will have a design capability of 150
MW.
The unit spacing will be 60 feet with an additional 110-foot ser-
vice bay at the south end of the powerhouse for routine mainte-
nance and construction erection. The control room will be located
at the north end of the main powerhouse floor. The width of the
cavern will be sufficient for the physical size of the generator
plus galleries for piping, air-conditioning ducts~ electrical
cables, and isolated phase bus. The overall size of the power-
house cavern will be 74 feet wide, 360 feet long, and 126 feet
high.
Multiple stairway access points will be available from the
powerhouse main floor to each gallery level. Access to the
transformer gallery from the powerhouse will be by a tunnel from
the access shaft or by a stairway through each of the four bus
tunnels. Access wi 11 also be available to the draft tube gate
gallery by a tunnel from the main access shaft.
A service elevator will be provided for access from the service
bay area on the main floor to the machine shop, and the dewatering
and dra·inage galleries on the lower floors. Hatches will be pro-
vided through all main floors for installation and routine main-
tenance of pumps, valves a-nd other heavy equipment using the main
powerhouse crane.
(c) Transformer Gallery
The transformers will be located underground in a separate unlined
rock cavern, 120 feet upstream of the powert10use cavern, with four
interconnecting tun-nels for the isolated phase bus. There will be
12 sing1e-~hase transformers with one group of three transformers
for each generating unit. Each transformer is rated at 15/345, 70
MVA. For increased reliability, one spare transformer and one
spare HV circuit will be provided. The station service transfor-
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(d)
(e)
mers and the surface fac i 1 it i es transformers wi 11 be located in
the bus tunnels. Generator excitation transformers will be locat-
ed on the main powerhouse floor. The overall size of the' trans-
former gallery will be 43 feet wide, 40 feet high, and 446 feet
long; the bus tunnels will be 14 feet wide and 14 feet high.
High voltage cables will be taken to the surface in two 7.5-foot
internal diameter cable shafts, and provision will be made for an
inspection hoist in each shaft.
Vehicle access to the transformer gallery will be from the south
end via the main powerhouse access tunnel. Personnel access will
be from the main access shaft or through each of the four isolated
phase bus tunnels.
Surge Chamber
A simple surge chamber will be constructe& 120 feet downstream of
the powerhouse to control pressure fluctuations in the turbine
draft tubes and tailrace tunnel under transient load conditions,
and on machine start-up. The chamber will be common to all four
draft tubes. The overall size of the chamber wi 11 be 75 feet
wide, 240 feet long, and 190 feet high.
The draft tube gate gallery and crane will be located in the same
cavern, above the maximum anticipated surge level. Access to the
draft tube gate gallery will be by a rock tunnel from the main
access tunnel. The tunnel wi 11 be widened locally for storage of
the draft tube gates.
The chamber will be an unlined rock excavation with localized rock
support as necessary for stability of the roof arch and walls.
The guide b 1 ocks for the , draft tube gates wi 11 be of reinforced
concrete anchored to the rock excavation by rock bolts.
Draft Tube Tunnels
The orientation of the draft tube tunnels will be 300°. The tun-
nels will be 19 feet in diameter and steel-and concrete-lined,
with the concrete having a thickness of about 2 feet.
7.11 -Tailrace Tunnel
The tailrace pressure tunnel will convey power plant discharge from the
surge chamber to the river. The tunne 1 will have a modified horseshoe
cross section with an internal dimension of 38 feet, and will be
concrete-lined throughout with a minimum thickness of 12 inches. The
length of the tunnel is 6800 feet.
The tailrace portal site will be located at a prominent steep rock face
on the north bank of the river. The portal outlet is rectangular in
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section, which reduces both the maximum outlet velocity (8ft/sec)
as well as the velocity head losses. Vertical stoplog guides will
be provided for closure of the tunnel for tunnel inspection and/or
maintenance.
7.12 -Access Plan
(a) Description of Access Plan
Access to the Devil Canyon development will consist primarily of a
railroad extension from the existing Alaska Railroad at Gold Creek
to a railhead and storage faci 1 ity adjacent to the Devil Canyon
camp area. From here materials and supplies will be distributed
using a system of site roads.
To provide flexibility of access the railroad extension will be
augmented by a road between the Devil Canyon and Watana damsites.
The availability of both road and rai 1 access will reduce the
schedule and cost risks associated with limited access.
This road connection is also required for travel between Watana
and Devil Canyon by the post-construction operation and mainten-
ance personnel who will be stationed at Watana.
(b) Rail Extension
Except for a 2-mil e sect ion where the route traverses steep ter-
rain alongside the Susitna River, the railroad will climb steadily
for 12.2 miles from Gold Creek to the railhead facility near the
Devil Canyon camp.
Nearly all of the route traverses potentially frozen Basal till on
side slopes varying from flat to moderately steep. Several
streams are crossed, requiring the construction of large culverts.
However, where the rai 1 road crosses Jack Long Creek small bridges
will be built to minimize impacts to the aquatic habitat. In view
of the construction conditions it is estimated that it w·ill take
eighteen months to two years to complete the extension. Therefore
construction should start_ two years prior to commencement of the
main works at Devil Canyon.
The railroad extension will be designed in accordance with the
parameters set out below:
Maximum grade
Maximum curvature
Design loading
2.5% 100
E-72
These parameters are consistent with those presently being used by
the Alaska Railroad.
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(c) Connecting Road
(d)
From the railhead facility at Devil Canyon a connecting road will
be built to a high-level suspension bridge approximately one mile
downstream of the damsite. The route then proceeds in a north-
easterly direction, crosses Devil· Creek and swings around past
Swimming Bear Lake at an elevation of 3500 feet before continuing
in a southeasterly direction through a wide pass. After crossing
Tsusena Creek, the road continues south to the Watana damsite.
The overall length of the road is 37.0 miles.
In general the alignment crosses good soil types with bedrock at
or near the surface. Erosion and thaw settlement problems should
not be a problem since the terrain has gentle to rooderate slopes
which will allow roadbed construction without deep cuts.
The connecting road wi 11 be bui 1t to the same standards and in
accordance with the design parameters used for the Watana access
road. However, as will be the case for the Watana damsite access
road, the design standards will be reduced to as low as 40 mph in
areas where it is necessary to minimize the extent of cutting and
filling. The affected areas are the approaches to some of the
stream crossings, the most significant being those of the high-
level bridge crossing the Susitna River downstream of Devil
Canyon.
Construction Schedule
The 1790-foot long high-level suspension bridge crossing the
Susitna River is the controlling item in the construction sched-
ule, requiring three years for completion. Therefore, it will be
necessary to begin construction three years prior to the start of
the main works at the Devil Canyon damsite.
(e) Right-of-Way
The road and railroad routes mainly traverse terrain with gentle
to moderate side slopes, where a right-of-way width of 200 feet
. will be sufficient. Only in areas of major sidehill cutting and
deep excavation will it be necessary to go beyond 200 feet.
7.13 -Site Facilities
The construction of the Devil Canyon development will require various
facilities to support the construction activities throughout the entire
construction period. Following construction, the planned operation and
maintenance of the development will be centered at the Watana develop-
ment; therefore, a minimum of facilities at the site will be required
to maintain the power facility.
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As described for Watana, a camp and construction village will be
constructed and maintained at the project site. The carnp/vill age
will provide housing and living facilities for 1,800 people during
construction. Other site facilities will include contractors 1
work areas, site power, services, and communications. Items such
as power and communications and hospital services will also be re-
quired for construction operations independent of camp operations.
Buildings used for the Watana development will be used where
possible in the Devil Canyon development. Current planning calls
for dismantling and reclaiming the site after construction.
Electric power will be provided from the Watana development. The
salvaged building modules used from the Watana camp/village will
be retrofitted from fuel oil heating to electric heat.
(a) Temporary Camp and Village
The proposed location of the camp/village is on the south bank of
the Sus itna River between the dams ite and Portage Creek, approx i-
mately 2.5 miles southwest of the Devil Canyon Dam (see Plate
F70). The south side of the Sus itna was chosen because the main
access road in this area will be from the south. South-facing
slopes will be used for the camp/village location.
The camp will consist of portable woodframe dormitories with
modular mess halls, recreational buildings, bank, post office,
fire station, warehouses, hospital, offices, etc. The camp will
be a single status camp for approximately 1,650 workers.
The village, designed for approximately 150 families, will be
grouped around a service core containing a school, gymnasium,
stores, and recreation area.
The two areas will be separated by approximately 1/2 mile to pro-
vide a buffer zone. The hospital will serve both the main camp
and the village.
This camp location will be separated from the work areas by ap-
proximately one mile. Travel time to the work area will generally
be less than 15 minutes.
The camp/vi 11 age will be constructed in stages to accommodate the
peak work force. The facilities will be designed for the peak
work force p 1 us 10 percent for 11 turnover 11 • The 11 turnover 11 will
include provisions for overlap of workers and vacations. The
conceptual 1 ayouts for the camp/vi 11 age are presented in Plates
F72 and F73.
A-7-20
Construction camp buildings will consist largely of trailer-type
factory-built modules assembled at site to provide the various
facilities required. The modules will be fabricated with heating,
lighting, and plumbing facilities, interior finishes, furnishings,
and equipment. Trailer roodules will be supported on timber crib-
bing or blocking approximately two feet above grade.
Larger structures such as the central utilities building, gym, and
warehouses will be pre-engineered steel-framed structures with
met a 1 c 1 add i n g.
The various buildings in the camp are identified on Plate F72.
(b) Site Power and Utilities
( i) Power
( i i )
A 345 kV transmission line from Watana and a substation
will be in service during the construction activities. Two
transformers will be installed at the substation to reduce
the line voltage to the desired voltage levels.
Power will be sold to the contractors by the Power Author-
ity. The peak demand during construction is estimated at
20 MW for the camp/village and 4 MW for construction re-
quirements. The distribution system for the camp/village
will be 4.16 kV.
Water
The water supply system will serve the entire camp/village
and selected contractors• work areas. The water supply
system will provide for potable water and fire protection.
The estimated peak population to be served will be 2,150
(1,650 in the camp and 500 in the village).
The principal source of water will be the Susitna River.
The water will be treated in accordance with the Environ-
mental Protection Agency (EPA) primary and secondary re-
quirements.
(iii) Wastewater
One wastewater colT ection and treatment system win serve
the camp/village. Gravity flow Hnes with lift stations
will be used to collect the wastewater from all of the camp
and village facilities. The "in-camp" and "in-village"
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co 11 ect ion systems will be run through the permawa 1 k s and
utilidors so that the collection system will always be
protected from the elements.
At the village, an aerated collection basin will be in-
st a 11 ed to co 11 ect the sewage. The sewage will be pumped
from this collection basin through a force main to the
sewage treatment plant.
Chemical toilets located around the site will be serviced
by sewage trucks which will discharge directly into the sewage
treatment plant.
The sewage treatment system will be a biological system
with 1 agoons. The system wi 11 be designed to meet Alaskan
State water law secondary treatment standards. The lagoons
and system will be modular to allow for growth and contrac-
tion of the camp/village.
The location of the treatment plant is shown on Plate F70.
The location was selected to avoid unnecessary odors in
the camp.
The sewage plant will discharge its treated effluent to the
Susitna River. All treated sludge will be disposed of in a
solid waste sanitary landfill.
(c) Contractors• Area
Constractors on the site wi 11 require offices, workshops, ware-
houses, storage areas, and fabrication shops. These will be lo-
cated on the south side of the Susitna River near the owner/
manager•s office. Additional space required by contractors will
be in the area between the access road and the camp.
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8 -DEVIL CANYON RESERVOIR
The Devil Canyon reservoir, at a normal operating level of 1455 feet,
will ba approximately 26 miles long with a maximum width of approxi-
mately 1/2 mile. The total surface area at normal operating level will
be 7800 acres. lrTmedi ately upstream of the dam, the maximum water
depth will be approximately 580 feet. The minimum reservoir level will
be 1405 feet during normal operation, resulting in a maximum drawdown
of 50 feet. The reservoir will have a total capacity of 1,100,000
acre-feet of which 350,000 acre-feet will be live storage.
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9 -TURBINES AND GENERATORS -DEVIL CANYON
9.1 -Unit Capacity
The Devil Canyon powerhouse will have four generating units with a de-
sign capability of 150 MW based on the minimum December reservoir level
(Elevation 1405) and a corresponding gross head of 555 feet. The head
on the plant will vary from 555 feet to 605 feet.
The rated average operating head for the turbine will be 575 feet.
Allowing for generator losses, this will result in a rated turbine
o~tput of 225,000 hp (168 MW) at full gate.
The generator rating will be 180 MVA with a 90 percent power factor.
The generators wi 11 be capab 1 e of continuous operation at 115 percent
rated power. Because of the high capacity factor for the Devil Canyon
station, the generators will therefore be sized on the basis of maximum
turbine output at maximum head, allowing for a possible 5 percent addi-
tion in power from the turbine. This maximum turbine output {250,000
hp) will be within the continuous overload rating of the generator.
9.2 -Turbines
The turbines will be of the vertical-shaft Francis type with steel
spiral casing and a concrete e"lbow-type draft tube. The draft tube
will have a single water passage (no center pier).
Maximum and minimum heads on the unit will be 603 feet and 541 feet,
respectively. The full-gate output of the turbines will be about
205,000 hp at maximum net head and 180,000 hp at minimum net head.
Overgating of the turbines may be possible, providing approximately 5
percent additional power. For preliminary design purposes, the best
efficiency {best-gate) output of the units has been assumed at 85
percent of the full-gate turbine output.
The full-gate and best-gate efficiencies of the turbines will be about
91 percent and 94 percent, respectively, at rated head. The efficiency
will be about 0.2 percent lower at maximum head and 0.5 percent lower
at minimum head
9.3 -Generators
The four generators in the De vi 1 Canyon powerhouse will be of the
vert i ca 1-shaft, overhung semi -umbre 11 a type directly connected to the
vertical Francis turbines.
The generators will be similar in construction and design to the Watana
generators. The general features described in Section 3.2 for the
A-9-1
stator, rotor, excitation system, and other details also will apply for
the Devil Canyon generators.
The rating and characteristics of the generators will be as follows:
Rated Capacity:
Rated Power:
Rated Voltage:·
Synchronous Speed:
Inertia Constant:
Short Circuit Ratio:
Efficiency at Full Load:
9.4 -Governor System
167 MVA, 0.9 power factor with
overload rating of 115 percent.
162 MW
15 kV, 3 phase, 60 Hertz
225 rpm
3.5 MW-Sec/MVA
1. 1 ( m i n i mum)
98 percent (minimum)
A governor system with electric hydraulic governor actuators will be
provided for each of the Devil Canyon units. The system will be the
same as for Watana (See Section 3.4).
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10 -TRANSMISSION LINES -DEVIL CANYON
As part of the Devil Canyon development, the transmission systems will
be supplemented as described in the following paragraphs.
Two single-circuit 345 kV transmission lines will be built between the
De vi 1 Canyon switchyard at the power development and the Go 1 d Creek
switching station. From the Devil Canyon substation the lines will
head directly west for a distance of approximately one mile where they
will intersect the Watana to Gold Creek transmission corridor. From
this point to the Gold Creek switching station the lines will share the
same corridor as the Watana lines.
At Gold Creek, three 345 kV breakers will be added in an additional bay
within the switching station to receive the incoming lines and to ac-
commodate a new line to Anchorage.
Between Gold Creek and Knik Arm switching stations, a third 345 kV
single-circuit line will be built parallel to the two Watana lines.
The crossing of Knik Arm will be by cable with a similar arrangement to
the original two circuits. At Willow switching station, four 345 kV
breakers will be added, one in an existing bay, the rest in a new bay.
These handle the new line a~d allow the installation of a third 75 MVA
transformer for local supply, if required. Similarly, at Knik Arm
switching station, a breaker will be installed in an existing bay to
receive the incoming Watana line. Between the Knik Arm and University
stations, the lines built for Watana were sized to accommodate the
De vi 1 Canyon need in order to 1 imit right-of-way requirements. At
University an additional transformer bank at each of 230 kV and 115 kV
levels will be provided; this will involve the addition of two breakers
in existing bays. At the Ester substation in Fairbanks, an additional
150 MVA transformer bank will be installed to serve the local load;
this will require one new breaker in an existing bay.
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11 -APPURTENANT EQUIPMENT -DEVIL CANYON
11.1 -Miscellaneous Mechanical Equipment
(a)
(b)
(c)
(d)
Powerhouse Cranes
Two overhead type powerhouse cranes will be provided at Devil Can-
yon as at Watana. The crane capacity will be approximately 200
tons.
Draft Tube Gates
Draft tube gates will be provided to permit dewatering of the
turbine water passages for inspection and maintenance of the
turbines. The arrangement of the draft tube gates wi 11 be the
same as for Watana, except that only two sets of gates wi 11 be
provided, each set with two 21-foot wide by 10.5-foot high sec-
tions.
Draft Tube Gate Crane
A crane will be installed in the surge chamber for installation
and removal of the draft tube gates. The crane will be either a
monorail (or twin monorail) or a gantry crane with an approximate
capacity of 30 tons. The crane wi 11 be pendant-operated and have
a two point lift. A follower will be used with the crane for
handling the gates. The crane runway will be located along the
upstream side of the surge chamber and will extend over the intake
for the compensation flow pumps as well as a gate unloading area
at one end of the surge chamber.
Miscellaneous Cranes and Hoists
In addition to the powerhouse cranes and draft tube gate cranes,
the following cranes and hoists will be provided in the power
plant: ·
- A 5-ton monorail hoist in the transformer gallery for transfor-
mer maintenance;
-Small overhead, jib, or A-frame type hoists in the machine shop
for handling material; and
A-frame or monorail hoists in other powerhouse areas for hand-
ling small equipment.
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(e) Elevators
Access and service elevators will be provided for the power plant,
as follows:
-Access elevator from the control building to the powerhouse;
-Service elevator in the powerhouse service bay; and
-Inspection hoists in cable shafts.
(f) Power Plant Mechanical Service Systems
The power plant mechanical service systems for Devil Canyon will
be essentially the same as discussed in Section S.l(f) for Watana,
except for the following:
-There will be no main generator breakers in the power plant;
therefore, circuit breaker air will not be required. The high-
pressure air system wi 11 be used on 1 y for governor as we 11 as
instrument air. The operating pressure will be 600 to 1000 psig
depending on the governor system operating pressure.
-An air-conditioning system will be installed in the powerhouse
control room.
Heating and ventilating will be required for the entrance build-
ing to the access shaft in the south abutment.
-For preliminary design purposes, only one drainage and one de-
watering sump have been provided in the powerhouse. The de-
watering system will also be used to dewater the intake and dis-
charge lines for the cvmpensation flow pumps.
(g) Surface Facilities Mechanical Service Systems
The entrance building above the power plant will have only a heat-
ing and ventilation system. The mechanical services in the stand-
by power building will include a heating and ventilation system, a
fuel oil system, and a fire protection system, as at Watana.
(h) Machine Shop Facilities
A machine shop and tool room will be located in the powerhouse
service bay area to take care of maintenance work at the plant.
The facilities will not be as extensive as at Watana. Some of the
larger components will be transported to Watana for necessary
machinery work.
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11.2 -Accessory Electrical Equipment
(a) General
(b)
(c)
The accessory electrical equipment described belo~ includes the
following:
-Main generator step-up 15/345 kV transformers;
-Isolated phase bus connecting the generator and transformers;
-345 kV oil-filled cables from the transformer terminals to the
switchyard;
-Control systems; and
-Station service auxiliary ac and de systems.
Other equipment and systems described include grounding, lighting
system and communications.
The main equipment and connections in the power plant are shown in
the single line diagram (Plate F68). The arrangement of equipment
in the powerhouse, transformer gallery, and cable shafts is shown
in Plates F63 to F65.
Transformers and HV Connections
Twelve single-phase transformers and one spare transformer will be
located in the transformer gallery. Each bank of the three
single-phase transformers will be connected to one generator by
isolated phase bus located in bus tunnels. The HV terminals of
the transformer will be connected to the 345 kV switchyard by 345
kV single-phase, oil-filled cables installed in 800-foot long ver-
tical shafts. There will be two sets of three single-phase 345 kV
oil-filled cables installed in each cable shaft. One additional
set will be maintained as a spare three-phase cable circuit in the
second cable shaft. These cable shafts will also contain the con-
trol and power cables between the powerhouse and the surface con-
trol room, as well as emergency power cables from the diesel gen-
·erators at the surface to the underground facilities.
Main Transformers
The transformers will be of the single~phase, two-winding, oil-
immersed, forced-oil water-cooled (FOW) type. A total of twelve
single-phase transformers and one spare transformer will be pro-
vided, with rating and characteristics as follows:
Rated capacity:
High Voltage Winding:
Basic Insulation Level
(BIL) of HV Winding:
Low Voltage Winding:
Transformer Impedance:
A-11-3
70 MVA
345/ ./ 3 kV, grounded Y
1300 kV
15 kV, Delta
15 percent
(d) Generator Isolated Phase Bus
Isolated phase bus connections will be located between the genera-
tor and the main transformer. The bus will be of the self-cooled,
welded aluminum tubular type with design and construction details
generally sirni 1 ar to the bus at the Watana power plant. The rat-
ing of the main bus will be as follows:
Rated current:
Short circuit current momentary:
Short circuit current
symmetrical:
Basic Insulation Level (BIL):
(e) 345 kV Oil-Filled Cable
9000 amps
240,000 amps
150,000 amps
150 kV
The cables will be rated for a continuous maximum current of 400
amps at 345 kV +5 percent. The cables will be of single-core con-
struction with oi 1 flowing through a centra 1 oi 1 duct within the
copper conductor. The cables will be installed in the 800-foot
cable shafts from the transformer gallery to the surface. No
cable jointing will be necessary for this installation length.
(f) Control Systems
The Devil Canyon power plant will be designed to be operated as an
unattended plant. The plant will be normally controlled through
supervisory control from the Susitna Area Control Center at
Watana. The plant will, however, be provided with a control room
with sufficient control, indication, and annunciation equipment to
enable the plant to be operated during emergencies by one operator
in the control room. In addition, for the purpose of testing and
commissioning and maintenance of the plant, local control boards
will be mounted on the powerhouse floor near each unit.
Automatic load-frequency control of the four units at Devil Canyon
will be accomplished through the central computer-aided control
system located at the Watana Area Control Center.
The power plant w·ill be provided with "black start" capability
similar to that provided at Watana to enable the start of one unit
without any power in the powerhouse or at the switchyard, except
that provided by one emergency diesel generator. After the start-
up of one unit, auxiliary station service power will be
established in the power plant and the switchyard; the remaining
generators can then be started one after the other to bring the
plant into full output within the hour.
As at the Watana power plant, the control system will be designed
to permit local-manual or local-automatic starting, voltage ad-
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justing, synchronizing, and loading of the unit from the
powerhouse control room at Devil Canyon.
The protective relaying system is shown in the main single line
diagram (Plate F68) and is generally similar to that provided for
the Watana power plant.
(g) Station Service Auxiliary AC and DC Systems
( i)
{ i i)
AC Auxiliary System
The auxiliary system will be similar to that in the Watana
power plant except that the switchyard and surface facili-
ties power will be obtained from a 4.16 kV system supplied
by two 5/7.5 MVA, OA/FA, oil-immersed transformers connec-
ted to generators Nos. 1 and 4, respectively. The 4.16 kV
double-ended switchgear will oe located in the powerhouse.
It will have a normally-open tie breaker which will prevent
parallel operation of the two sections. The tie breaker
will close on failure of one or the other of the incoming
supplies. The 1400 hp compensation flow pumps will be
supplied with power directly from the 4.16 kV system. Two
4.16 cables installed in the cable shafts will supply power
to the surface facilities.
The 480 V station service system will consist of a main
480 V switchgear, separate auxiliary boards for each unit,
essential auxiliaries board, and a general auxiliaries
board. The main 480 V switchgear will be supplied by two
2000 kVA, 15,000/480 V grounded wye sealed gas dry-type
transformers. A third_ 2000 kVA transformer wi 11 be main-
tained as a spare.
Two emergency diesel generators, each rated 500 kW, will be
connected to the 480 V powerhouse main switchgear and 4.16
kV surface switchboard, respectively. Both diesel genera-
tors will be located at the surface.
An uninterruptible high-security power supply will be pro-
vided for the supervisory computer-aided plant control sys-
tems.
DC Auxiliary Station Service System
The de auxiliary system wi 11 be similar to that provided at
the Wat ana plant ~nd wi l 1 consist of two 125 V de lead-acid
batteries. -Each battery system will be supplied by a
do-uble--rect-ifier charging system. A 48 V de battery system
will be provided for supplying the supervisory and communi-
cat ions systems.
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(h) Other Accessory Electrical Systems
The other accessory electrical systems including the grounding
system, lighting system, and powerhouse communications system will
be similar in general design and construction aspects to the sys-
tem described in Section 5.2 for the Watana power plant.
11.3 -Switchyard Structures and Equipment
(a) Single Line Diagram
A breaker-and-a-half single line arrangement will be used at the
switchyard. This arrangement was selected for reliability and
security of the power system. Plate F69 shows the details of the
switchyard single line diagram.
{b) Switchyard Structures and Layout
The switchyard layout will be based on a conventional outdoor type
design. The design adopted for this project will provide a two-
level bus arrangement. This design is commonly known as a low
station profile.
The two-level bus arrangement is desirable because it is less
prone to extensive damage in case of an earthquake. Due to the
lower heights, it is also easier to maintain.
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REFERENCES
Commonwealth Associates Inc. January 1982. Anchorage-Fairbanks
Transmission Intertie Route Selection Report. Prepared for the
Alaska Power Authority.
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TABLE A. 1: PRINCIPAL PROJECT PARAMETERS
Item
Hydrology
-Average River Flow Ccfsl
-Peak Flood Inflows (cfsl
• PMF
• 1 0,000-year
• 50-year
• 25-year
-Peak Flood Flows through
the Dam (cfs)
PMF
1 0,000-year
50-year
Reservoir Characteristics
-Normal Maximum Operating Level (ftl
-Maximum Level, PMF (ftl
-Minimum Operating Level (ftl
-Area at NMOL (acres)
-Length (miles)
-Total Storage (acre-feet)
-Live Storage (acre-feet)
Project Outputs
-Plant Design Capability (MWJ
-Annual Generation (GWhl
• Firm
• Average
Dams
-Type
-Crest Elevation (ft)
-Crest Length (ftl
-Height Above Foundation (ft)
-Crest Width (ft)
-Upstream S~ope (H:V)
-Downstream Slope (H:V)
Diversion
-Cofferdams
• Type
• Upstream Crest Elevation (ft)
• Downstream Crest Elevation (ft)
• Maximum U/S Water Leve I (ftl
-Tunnels
• Number/Type
• Diameter (ft)
• Capacity (cfs)
Watana
7,990
326,000
156,000
87,000
76,000
293,000
150,000
31,000
2,185
2,201
2,065
38,000
48
9. 5 X 1 Q~
3.7x10
1,020
2,620
3,460
Earth/Rockfil I,
Centra I Core
2,210
4,100
885
35 z. 4: 1
2: 1
Rockf iII,
Central Core
1,545
1,472
1,536
2 -Circular,
concrete-I i ned
38
80,500
Dev i I Canyon
9,080
345,000 with Watana
362,000 without Watana
165,000 with Watana
161,000 without Watana
39,000 with Watana
98,000 without Watana
37,800 with Watana
85~000 without Watana
345,000 with Watana
165,000 with Watana
39,000 with Watana
I ,455
1,466
1,405
7,800
26 6
1. 1 X J Q 6 0. 35 X 10
600
2,718
3,450
Concrete Arch
( Earth/Rock.f i I I
Saddle)
1,463 (1472)
'· 650 (950) 646 (245)
20 (35)
(2.4:1)
(2: 1)
Rock.f i I I,
Central Core
947
898
944
I -Horseshoe,
concrete-I i ned
30
39,000
TABLE A.1 (Cont 1 d)
Item
Outlet Facll ities
-Central Structures
-Diameter ( i n l
-Water Passage Diameter (ft)
-Capacity (cfs)
Main Spillways
-Capacity (cfs)
-Control Structure
• Type
• Crest Elevation (ft)
• Gates (H x W, ft)
-Chute Width (ft)
-Energy Dissipation
Emergency Spi I lways
-Capacity (cfs)
-Control Structure
• Type
• Crest Elevation (ft)
-Chute Width (ft)
P9wer Intakes
-Control Structures
-Gates (H x W, ft)
-Crest Elevation (ftl
-Maximum Drawdown (ft)
-Capacity, per unit (cfs)
Penstocks
-Number
-Type
-Diameter (ft)
• Concrete-I ined
• Steel-1 ined
Powerhouses
-Type
-Cavern Size (L x W x H, ft)
-Turbine/Generator
-Speed (rpm)
-Design Unit Capability
• Net head (ft)
• Flow (cfsl
• Output CMW)
-Rated Unit Capabll lty
• Net Head (ft)
• Full-Gate Flow (cfs)
• Full-Gate Output CMW)
• Best-Gate Output <MWl
Watana
6-fixed cone valves
78
28
24,000
120,000
gated ogee
2,148
3-49 X 36
144/80
Flip bucket
120,000
Open channel/
fuse pI ug
2200/2201.5
310/200
Multi-level, gated
4-20 X 30
2,030
120
3,870
6
Inc! !ned/horizontal
17
15
Underground
455 X 74 X 126
6 Vertical Francis/
Synchr.
225
652
3,490
170
680
3,550
183
156
Dev i I Canyon
7-fixed cone valves
4-102, 3-90
a. 5/7. 5
38,500
123,000
gated ogee
1,404
3-56 X 30
122/80
Flip bucket
150,000
Open channel/
fuse plug
1464/1465. 5
220
Multi-level, gated
2-20 X 30
1,365
50
3,670
4
Inclined/horizontal
20
15
Underground
360 X 74 X 126
4 Vertical Fr-ancis/
Synchr.
225
542
3,680
150
590
3, 790
164
140
TABLE A. 1 (Cont 1 d)
Item
-Transformers
• Location
• Cavern Size (L x W x H, ft)
• Number/Type -• Vo I tage (kV)
• Rating (MVA)
Tailrace Tunnels
-Number/Type
-Diameter (ft)
-Surge Chamber Size (L x W x H, ft)
-Capacity (cts)
-
-
-
Watana
Upstream ga I I ery
314 X 45 X 40
9 -single phase
15/345
145
2 -Horseshoe,
concrete-IT ned
34
350 X 50 X 150
22,000
Dev i I Canyon
Upstream ga I I ery
446 X 43 X 40
12 -single phase
15/345
70
1 -Horseshoe
concrete-I I ned
38
240 X 75 X 190
15,500
SUSITNA HYDROELECTRIC PROJECT
VOLUME 1
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
-
-
SUSITNA HYDROELECTRIC PROJECT
VOLUME 1
EXHIBIT C
PROPOSED CONSTRUCTION SCHEDULE
TABLE OF CONTENTS
1 -WATANA SCHEDULE ........................................... .
1. 1 -Access .............................................. .
1 . 2 -Site F ac i 1 it i es ..................................... .
1.3 -Diversion ........................................... .
1. 4 -Main Dam ............................................ .
1.5 -Spillways and Intakes .............................. ..
1.6-Powerhouse and Other Underground Works .............. .
1.7-Transmission Lines/Switchyards ...................... .
1.8-General ............................................. .
C-1-1
C-1-2
C-1-2
C-1-2
C-1-2
C-1-3
C-1-3
C-1-3
C-1-3
2 -DEVIL CANYON SCHEDULE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2-1
2.1 -Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2-1
2.2 -Site Facilities ...................................... C-2-1
2.3 -Diversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2-1
2.4 -Arch Dam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2-1
2.5-Spillways and Intake ................................. C-2-2
2.6-Powerhouse and Other Underground Works ............... C-2-2
2.7-Transmission Lines/Switchyards ....................... C-2-2
2.8 -General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2-2
3 -HISTORY OF EXISTING PROJECT C-3-1
LIST OF FIGURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i
LIST OF FIGURES
C.l Watana Construction Schedule
C.2 Devil Canyon Construction Schedule
-
-
i -
-
(""'
I
!
r
r
r
EXHIBIT C -PROPOSED CONSTRUCTION SCHEDULE
This section describes the development schedules prepared for both
Watana and Devil Canyon to meet the on-line power requirements of 1994
and 2002, respectively. These schedules span the period from 1983
until 2004. Schedules for the development of both Watana and Devil
Canyon are shown on Figures C.1 and C.Z. The main elements of the
project have been shown on these schedules, as well as some key inter-
relationships. For purposes of planning, it has been assumed that a
license will be awarded by December 31, 1984.
At both sites the period for construction of the main dam is critical.
Other activities are fitted to the main dam work. A study of the front
end requirements at Watana concluded that initial access work should
commence immediately after receipt of license and be completed in the
shortest possible time to permit a sufficiently rapid buildup of man-
power and equipment to meet construction requirements.
1 -WATANA SCHEDULE
Corrrnencement of construct ion:
Initial access road
Site facilities
Diversion
Completion of construction:
-April 1985
-April 1985
-July 1985
Four of six units ready -January 1994
Six units ready -July 1994
Commencement of commercial operations:
Four of six units
Six units
-January 1994
-July 1994
The Watana schedules were developed to meet two overall project
constraints:
-FERC license would be issued by December 31, 1984; and
-Four units would be on-line by the beginning of 1994.
The critical path of activities to meet the overall constraints was
determined to be through site access, site fac-ilities, diversion and
main dam construction. In general, construction activities leading up
to diversion in 1987 are on an accelerated schedule whereas the re-
maining activities are on a normal schedule. These are highlighted as
follows:
C-1-1
1.1 -Access
Initial road access to the site is required by October 1, 1985.
Certain equipment will be transported overland during the pre-
ceding winter months so that an airfield can be constructed by
July 1985. This effort to complete initial access is required to
mobilize labor, equipment, and materials in 1985 for the con-
struction of site facilities and diversion works.
1.2 -Site Facilities
Site facilities must be developed in a very short time to support
the main construction activities. A camp to house approximately
1000 men must be constructed during the first eighteen months.
Site construction roads and contractors' work areas have to be
started. An aggregate processing plant and concrete batching
plant must be operational to start diversion tunnel concrete work
by April 1986. On-site power generating equipment must be in-
stalled in 1985 to supply power for camp and construction activ-
ities.
1.3 -Diversion
Construction of diversion and dewatering facilities, the first
major activity, should start by mid-1985. Excavation of the
portals and tunnels requires a concentrated effort to allow com-
pletion of the lower tunnel for river diversion by October 1986.
The upper tunnel is needed to handle the spring runoff by May
1987. The upstream cofferdam must be placed to divert river
flows in October 1986 and raised sufficiently to avoid over-
topping by the following spring.
1.4-Main Dam
The progress of work in the main dam is critical throughout the
period 1986 through 1992. Mobilization of equipment and start of
site work'must begin in 1986. Excavation of the right abutment
as well as river alluvium under the dam core begins in 1986.
During 1987 and 1988, dewatering, excavation and foundation
treatment must be completed in the riverbed area and a substan-
tial start made on placing fill. The construction schedule is
based on the following program:
C-1-2
r -,
-
-
Quantity
Year (yd 3 X 10 6)
198'1
1988 6
1989 12
1990 13
1991 13
1992 12
1993 3
Accumulated
Quantity
(yd 3 X 10 6 )
9
21
34
47
59
62
Fill
Elevation
October 15
(feet)
1660
1810
1950
2130
2210
Reservoir
Elevation
(feet)
1460
1865
2050
2185
The program for fill placing has been based on an average six-
month season. It has been developed to provide high utilization
of construction equipment required to handle and process fill
materials.
1.5 -Spillways and Intakes
These structures have been scheduled for completion one season in
advance of the requirement to handle flows. In general, excava-
tion for these structures does not have to begin until most of the
excavation work has been completed for the main dam.
1.6 -Powerhouse and Other Underground Works
The first four units are scheduled to be on line by the beginning
of 1994 and the remaining two units in early 1994. Excavation of
the access tunne 1 into the powerhouse comp 1 ex has been scheduled
to start in late 1987. Stage I concrete begins in 1989 with start
of installation of major mechanical and electrical work in 1991.
In general, the underground works have been scheduled to level
resource demands as much as possible.
1.7 -Transmission Lines/Switchyards
Construction of the transmission 1 ines and switchyards has been
scheduled to begin in 1989 and to be completed before commission-
ing of the first unit.
1.8 -General
The Watana schedule requires that extensive planning, bid selec-
tion and commitments be made before the end of 1984 to permit work
to progress on schedule during 1985 and 1986. The rapid develop-
ment of site activities requires commitments, particularly in the
areas of access and site facilities in order that construction
operations have the needed support.
C-1-3
The schedule has also been developed to take advantage of possible
early reservoir filling to the minimum operating level by October
1992. Should this occur, power £auld possibly be generated by the
end of 1992.
C-1-4
( .. ,·--,
-
-
-
-
-
-
2 -DEVIL CANYON SCHEDULE
Commencement of construction:
Main Access -April 1992
Site Facilities -June 1994
Diversion -June 1995
Completion of construction:
Four units -October 2002
Commencement of commercial operations:
Four units -October 2002
The Devil Canyon schedule was developed to meet the on-line power re-
quirement of all four units in 2002. The critical path of activities
was determined to follow through site facilities, diversion and main
dam construction.
2.1 -Access
It has been assumed that site access built to Watana will exist
at the start of construction. A road will be constructed con-
necting the Devil Canyon site to the Watana access road including
a high level bridge over the Susitna River downstream of the
Devil Canyon Dam. At the same time, a railroad spur will be con-
structed to permit railroad access to the south bank of the
Susitna near Devil Canyon. These activities will be completed by
mid-1994.
2.2 -Site Facilities
Camp facilities should be started in 1994.
that buildings can be salvaged from Watana.
could also be started at this time.
2.3 -Diversion
It has been assumed
Site roads and power
Excavation and concreting of the single diversion tunnel should
begin in 1995. River closure and cofferdam construction will
take place to permit start of dam construction in 1996.
2.4 -Arch Dam
The construction of the arch dam wi 11 be the most crit i ca 1 con-
struction activity from start of excttvation in 1996 until topping
out in 2001. The concrete program has been based on an
C-2-1
average 8-month placing season for 4-1/2 years. The work has
been scheduled so that a fairly constant effort may be maintained
during this period to make best use of equipment and manpower.
2.5 -Spillways and Intake
The spillway and intake are scheduled for completion by the end
of 2000 to permit reservoir filling the next year.
2.6 -Powerhouse and Other Underground Works
Excavation of access into the powerhouse cavern is scheduled to
begin in 1996. Stage I concrete begins in 1998 with start of
installation of major mechanical and electrical work in 2000.
2.7 -Transmission Lines/Switchyards
The additional transmission facilities needed for Devil Canyon
have been scheduled for completion by the time the final unit is
ready for commissioning in late 2001.
2.8 -General
The development of site facilities at Devil Canyon begins slowly
in 1994 with a rapid acceleration in 1995 through 1997. Within a
short period of time, construction begins on most major civil
structures. This rapid development is dependent on the provision
of support site facilities which should be completed in advance
of the main construction work.
C-2-2
-
-
-
'~
-
-
3 -HISTORY OF EXISTING PROJECT
An intertie is planned to permit the economic interchange of up to
70 megawatts of power between major load centers at Anchorage and
Fairbanks. Connecting to existing transmission systems at Willow in
the south and Healy in the north, the intertie will be built to the
same standards as those proposed for the Susitna project transmission
system. It wi 11 be energized initially at 138 kV. Subsequent to con-
struction of the Watana project, the intertie will be incorporated into
the Susitna transmission system and will operate at 345 kV.
Construction of the intertie is scheduled to begin in March 1983. Com-
pletion and initial operation is planned for September 1984, well in
advance of the anticipated date for receipt of a FERC license on
December 31, 1984.
C-3-1
DESCRIPTION 1983 1984 1985 1986 1987 1988 1989 1990 199 1 1992 1993 1994
01 FERC LICENSE , 01
02 INITIAL ACCESS "111.1.11#.. 02
03 03
04 MAIN ACCESS .,I~ FIIIIIIIIIIAI 04
05 05
06 SITE FACI UTI ES rlllllllll. ~111111111111. ~111111111111. ~11111111-06
07 ror po ~TE 01n • Nn. 1 g~':,; \'o~~NNEL LOWER TUNI 0,, Dill"
07
08 DIVERSION TUNNELS 11111111111111111111 JU 111111 nn oo m;;;:m;;;;;;r .. ••••••••• ~···· 08
09 * ,., b~ * T I 09
10 COFFERDAMS 111111111111111111111~111111111 111111 11111111J I I 10
II lAIITM~NTS ..!. Dl l.~D D~n J. START GR
START ~E ~0 ~ 10 I ~ 0 ~1 la o ~ 10 II
VEL
12 MAIN DAM ill llllll~lllll , ,,,,,,,,,ll.,;~ •••• ,flhn)ilil·i,,,,,,,.,, ·~~·~~····~~"~'lhnn)illlt'ltil'lii '" ,,, """ "" ..J """""""""' ·"" """" "" "" '" "" """"" "" "" "" """" ""-' 12
13 I 13
14 RELICT CHANNEL
I 11 1111111111111111111111 '"""""""""'-----.. ,,,,,,,,,, 14 I
15 I 15
16 MAIN SPILLWAY 11111111111111111111111111111 1111 11111111111111111111111111111 111111111111111111111111111111111 111111111 •••••••••••• 16
17 I FU"E P'""
17
18 EMERGENCY SPILLWAY 111111111111111111111111 111 11111111111111111111 """"' 18
19 I 19
20 OUTLET FACILITIES 111111111111111111111 1111111111111111111111111111111111111111111 .... ·········~····· 20
21 I 21
22 POWER INTAKE Mlllllllllllllll IIIIIIIIIUIIIII 111111111111~··· ••••••••••••••• 22
23 I 23
24 PENSTOCKS f111111 11 111111111111111111111 1111111111111111111111111111111111111111111 24
25 >:" I 25 .A& ESS I VlULT STAGE STAGE 2
I 26 POWERHOUSE llllllllllllllllllllljllllllllllllllllllll IIIIIIIII IHIIIIIIIII 26
I
27 l I TRANSFORME Its 27
28 TRANSFORMER GALLERY I CA BLE SHAFTS I GALLERY /SHAFTS I ·····~··· 28 11111111111111111111111 1111111 111111111111
29 I I • I 29
--
11111111111111111111111111111111111111 111 1 i 30 TAILRACE I SURGE CHAMBER 111111111 30 111111111111
31 • I I 31
32 TURBINE /GENERATORS •••••••••••••••••• ~··············T··· •••••••••••••••••• ····I 32
33 • I I I 33
PH CRANES
34 MECH. I ELECT. SYSTEMS ••••••••• ••••••••• .............. ,, .. •••••••••••••••••••• ····~ 34
35 EXCAVATE FILL FOUNDATIONS <:TDII "'IPIIIENT ~ I 35
36 SWITCH YARD I CONTROL BLDG. 1111111111111111111111 llllllllllt""""""""""" IIIII II ••••••••••••I I 36
37 I ; : 37
ACCE"" t'OIF boN<> en •Tonue TOWE $/STRINGING
38 TRANSMISSION LINES J'IIIIIIJ''''''''' 1111111111 111111111'·'·11 ............ '1 I 38 I
39 .J, Fk ~ ~,n...l ~5 ~ 50 I 39
'
40 IMPOUNDMENT ~--· ~------·
,. _____
I 40
41 J,1-...,..1 W2 W3 4 ~5 W6 ON-LINE 41
42 TEST AND COMMISSION ~ ... ~ •••••••• l •••• ..~ .... •••••••••• 42
43 43
44 44
LEGEND
r111.1~ ACCESS /FACILITIES
11111111111111111 EXCAVATION /FOUNDATION TREATMENT
'"" "" ""' FILL -CONCRETE ••••••• MECHANICAL /ELECTRICAL --· IMPOUNDMENT
WATANA
CONSTRUCTION SCHEDULE
FIGURE C. I
DESCRIPTION 1992 1993 1994 1995 1996 1997 1998 1999 2 0 00 2001 2002 2003
01 01
02 MAIN ACCESS P'.l'.l'.l'.l'.l'.#'.l'.l'l. ----------------------~ ...................... ~ 02
03 0 3
04 SITE FACILITIES #IIIII I:. ~111111111111,. l-'1111'11111111,. 1-'111111111~ 04
05 05
DIVERSIOI'i PLUG
06 DIVERSION TUNNELS 111111 1111111111 111111 'IIIII II I & I 06
07 'if cLOSE T I 0 7
08 COFFERDAMS ·''"!.,_,,,., .. ,,,,, I I 08
09 ' RNFRRFn : : 09
10 MAIN DAM lllllllll lnnm;rrnN~fl~~~~ 1111111111111111111111111111111111111111 10
II I I II
12 SADDLE DAM ·'''''''''' :-.,.,,,,,,,,, I 12 111111111111111111 111111111111111
13 : I 13
14 OUTLET FACILITIES 11·1·1·1 ·1·1· 11·1·1·1·1•1 I 14
15 I 15
16 MAIN SPILLWAY 111111111111111111111111111111 1111 11111111111111111111111111111 111111111 •1•1•nu•1•1•11 I 16
17
FUSE P UG : 17
18 EMERGENCY SPILLWAY 11111111111111111111111 1111111 11111111111 1111111111111111111111 -'-'''' I 18
19 I 19
20 POWER INTAKE 111111111111111111111 111111111 ' 111111 ·1·1-1111·1·1·11 I 20
21
... I 21 I
22 PENSTOCKS 111111111111111111111 IIIII I I 22
23 A CCESS VA~ T STAGE 1
I 23
STAGE 2
24 POWERHOUSE 111111111111111111111111111111111 111111111111111111111 24
25 I 'I" I TRANSFORM s 25
26 TRANSFORMER GALLERY I CABLE SHAFTS lllllllllli,.ll'iimnlllllllllllll·l~llllll I ···1·1·1· 26
27 I I I 27
28 TAILRACE/SURGE CHAMBER 1111111111 111111111111111111111111111111111111111111 1111111111111111111111111111111 1 I I 28
29 I , I 29
30 TURBINES/ GENERATORS ~1-,1·1·1·1 ·1·1·1·1· ·1·1·1·······~···1 l•l•l••••j 30
31 ' I I I 31 PH CRANES
32 MECH./ ELECT. SYSTEMS 1·1 ·1·1··· 11·1·1·1·1 ~1·1·1·1·1····~1·1· ····~····, 32
33 I I I 33 EXCAVATION /FIL FOUNDATIONS STRUCTURES /EQUIPMENT
34 SWITCHYARD I CONTROL BLDG . 111111111111111"-'-'''''' 1·1·1·1·1·1~ I 34
35 , I I 35
FOUNDATIONS TOWERS/STRINGING
36 TRANSMISSION LINES 111111111111111111 1111111111111111 ........... , I 36
37 w I I 37
38 IMPOUNDMENT ----r-· ----+-· 38
39 ,/,1--, 1 "2 ~3 "4 PN-LINE 39
40 TEST S COMMISSION ••• II ··~·~·~·~•~···7 40
41 41
42 42
43 43
44 44
LEGEND
,Ill I~ ACCESS /FACILITIES
11111111111111111 EXCAVATION/FOUNDATION TREATMENT
.. ''"'''"'' FILL -CONCRETE
11·1·1·1 MECHANICAL/ELECTRICAL ---IMPOUNDMENT
DEVI L CANYON
CONSTRUCTION SCHEDULE
FIGURE C.2
SUSITNA HYDROELECTRIC PROJECT
VOLUME 1
EXHIBIT D
-
PROJECT COSTS AND FINANCING
-
-
-
-
-
"'""
SUSITNA HYDROELECTRIC PROJECT
VOLUME 1
EXHIBIT D
PROJECT COSTS AND FINANCING
TABLE OF CONTENTS
1-ESTIMATES OF COST •..................•...•....•........... D-1-1
1.1-Construction Costs ...................•.....•.....•• D-1-1
(a) Code of Accounts .•..•.•....•....•............• D-1-1
(b) Approach to Cost Estimating ..........•.....•.. D-1-2
(c) Cost Data ....................................... D-1-3
(d) Seasonal Influences on Productivity .....•..... 0-1-4
(e) Construction Methods .....•.........•.•........ 0-1-5
(f) Quantity Takeoffs ······················~······ D-1-5
(g) Indirect Construction Costs ........•........•. D-1-5
1.2-Mitigation Costs ....•.............................. D-1-7
1.3 -Engineer·ing and Administration Costs ............•.. D-1-8
{a) Engineering and Project Management Costs .. ~ ..• D-1-8
(b) Construction Management Costs .....•......•.... D-1-9
{c) Procurement Costs ....................•........ D-1-10
(d) Owner 1 s Costs . . . . . . . . . . . • . . . . . . . . . . . . . . . . . . . . . D-1-10
1.4 -Operation, Maintenance and Replacement Costs ....... D-1-10
1.5-Allowance for Funds Used During Construction ....•.. D-1-11
1.6 -Escalation .......................................... D-1-12
1.7-Cash Flow and Manpower Loading Requirements ........ D-1-12
1.8 -Contingency ........................................ D-1-13
1.9-Previously Constructed Project Facilities .......... D-1-13
1.10-EBASCO Check Estimate .............................. D-1-13
2 -ESTIMATED ANNUAL PROJECT COSTS ........................... D-2-1
3-MARKET VALUE OF PROJECT POWER ..........•...........•..... D-3-1
3.1 -The Rail belt Power System .......................... D-3-1
3.2-Regional Electric Power Demand and Supply .......... D-3-1
3.3-Market and Price for Watana Output in 1994 .....•... D-3-1
3.4 ~Market and Price for Watana Output 1995-2001 ..... :. 0-3-2
3.5 -Market and Price for Watana and Devil Canyon
OutprJt in 2003 ...................................... D-3-3
3.6-Potential Impact of State Appropriations ........... D-3-3
4-EVALUATION OF ALTERNATIVE ENERGY PLANS ....•.............. D-4-1
4.1 -General ...•...........................•....•....... D-4-1
4.2 -Existing System Characteristics .................... 0-4-2
(a) System Description ............................ 0-4-2
(b) Retirement Schedule ........................... 0-4-2
(c) Schedule of Additions ......................... 0-4-3
TABLE OF CONTENTS (Continued)
4.3 -Fairbanks -Anchorage Intertie ................... ..
4.4 -Hydroelectric Alternatives ....................... ..
(a) Selection Process ............................ .
(b) Selected Sites ............................... .
(c) lake Chakachamna .............................•
4.5-Thermal Options-Development Selection •...........
(a) Assessment of Thermal Alternatives ........... .
( b ) Co a 1 -F i red Steam ............................ ..
(c) Combined Cycle .............................•..
(d) Gas-Turbine ······························'ll···· (e) Diesel Power Generation ..................... ..
(f) Plan Formulation and Evaluation ............. ..
4.6-Without Susitna Plan ............................•..
(a) System as of January 1993 .................... .
(b) System Additions ............................. .
(c) System as of 2010 ............................ .
4.7 Economic Evaluation .............................. ..
(a) Economic Principles and Parameters ........... .
(b) Analysis of Net Economic Benefits .....•.......
4.8-Sensitivity to World Oil Price Forecasts ........... .
4.9-Other Sensitivity Assessments ...................... .
4.10-Battelle Railbelt Alternatives Study ............... .
5-CONSEQUENCES OF LICENSE DENIAL ........................ .
5.1-Cost of license Denial ............................. .
5.2-Future Use of Damsites if License is Denied ........ .
6-FINANCING e••······•e•········~························""' 6.1 -Forecast Financial Parameters ..................... .
6.2-Inflationary Financing Deficit .................... .
6.3 -Legislative Status of Alaska Power Authority
and Susitna Project ............................... .
6 • 4 - F i nan c i n g P 1 an ..•......•••...• ~ o •• ., ••••••••••••••••
LIST OF TABLES
LIST OF FIGURES
REFERENCES
APPENDIX D-1 FUELS PRICING STUDIES
Page
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D-5-1
D-6-1
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D-6-2
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LIST OF TABLES
D.1
D.2
D.3
0.4
0.5
D.6
0.7
D.8
D.9
0.10
D.ll
0.12
0.13
D.14
D.15
D.16
0.17
0.18
D.19
0.20
D.21
D.22
0.23
D.24
D.25
D.26
D.27
Summary of Cost Estimate
Estimate Summary -Watana
Estimate Summary -Devil Canyon
Mitigation Measures -Summary of Costs Incorporated
In Construction Cost Estimates
Summary of Operation and Maintenance Costs
Variables for AFDC Computations
Watana and Devil Canyon Cumulative and Annual Cash Flow
Anchorage Fairbanks Intertie Project Cost Estimate
Summary of EBASCO Check Estimate
No State Contribution Scenario
Susitna Cost of Power
Forecast Financial Parameters
Total Generating Capacity Within t~e Railbelt System
Generating Units Within the Railbelt -1982
Schedule of Planned Utility Additions (1982-1988)
Operating and Economic Parameters for Selected
Hydroelectric Plants
Results of Economic Analyses of Alternative Generation
Scenarios
Summary of Thermal Generating Resource Plant
P arameters/1982$
Bid Line Item Costs for Beluga Area Station
Bid Line Item Costs for Nenana Area Station
Bid Line Item Costs for a Natural Gas-Fired
Combined-Cycle 200-MW Station
Economic Analysis
Forecasts of Electric Power Demand
Electric Power Demand Sensitivity Analysis
Discount Rate Sensitivity Analysis
Capital Cost Sensitivity Analysis
Fuel Price Sensitivity Analysis
i
LIST OF TABLES (Continued)
0.28 Summary of Sensitivity Analysis Indexes of Net
Economic Benefits
0.29 Battelle Alternatives Study for the Railbelt Candidate
Electric Energy Generating Technologies
0.30 Battelle Alternatives Study, Summary of Cost and
Performance Characteristics of Selected Alternatives
0.31 Financing Requirements-$ Million for $1.8 Billion State
Appropriation
0.32 $1.8 Billion (1982 Dollars) State Appropriation Scenario
7% Inflation and 10% Interest
ii
IJIM!il.
LIST OF FIGURES
D.1
D.2
D.3
D.4
D.5
D.6
D.7
D.8
D.9
D.10
Watana Development Cumulative and Annual Cash Flow
January 1982 Dollars
Devil Canyon Development Cumulative and Annual Cash Flow
January 1982 Dollars
Susitna Hydroelectric Project Cumulative and Annual Cash
Flow Entire Project, January 1982 Dollars
Energy Demand and Deliveries From Susitna
System Costs Avoided by Developing Susitna
Formulation of Plans Incorporating Non-Susitna Hydro
Generation
Selected Alternative Hydroelectric Sites
Formulation of Plans Incorporating All-Thermal
Generation
Alternative Generation Scenario Reference Case Load
Forecast
Energy Cost Comparison -100% Debt Financing
0 and 7% Inflation
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EXHIBIT D -PROJECT COSTS AND FINANCING
This exhibit presents the estimated project cost for the Susitna
Hydroelectric Project, the market value of project power and a
financing plan for the project. Alternative sources of power which
were studied are also presented.
1 -ESTIMATES OF COST
This section presents estimates of capital and operating costs for the
Susitna Hydroelectric Project, comprising the Watana and Devil Canyon
developments and associated transmission and access facilities. The
costs of design features and facilities incorporated into the project
to mitigate environmental impacts during construction and operation are
identified. Cash flow schedules, outlining capital requirements during
planning, construction, and start up are presented. The approach to
the derivation of the capital and operating costs estimates is
described.
The total cost of the Watana and Devil Canyon projects is summarized in
Table 0.1. A more detailed breakdown of cost for each development is
presented in Tables D.2 and D.3.
1.1 -Construction Costs
This section describes the process used for derivation of construction
costs and discusses the· Code of Accounts established, the basis for the
estimates and the various assumptions made in arr1v1ng at the
estimates. For general consistency with planning studies, all
construction costs developed for the project are in January 1982
dollars.
(a)
Group
Code of Accounts
Estimates of construction costs were developed using the FERC
format as outlined in the Federal Code of Regulations, Title 18
(GPO 1982).
The estimates have been subdivided into the following main cost
groupings:
Description
Production Plant Costs for structures, equipment, and
facilities necessary to produce
power.
D-1-1
Transmission Plant
General Plant
Indirect Costs
Overhead Construction Costs
Costs for structures, equipment, and
facilities necessary to transmit
power from the sites to load
centers.
Costs for equipment and facilities
required for the operation and
maintenance of the production and
transmission plant.
Costs that are common to a number of
construction activities. For this
estimate only camps have been
identified in this group. The
estimate for camps includes electric
power costs. Other indirect costs
have been included in the costs
under production, transmission, and
general plant costs.
Costs for engineering and
administration.
Further subdivision within these groupings was made on the basis of the
various types of work involved, as typically shown in the following
example:
Group: Production Plant
-Account 332: Reservoir, Darn, and Waterways
-Main Structure 332.3: Main Dam
-Element 332.31: Main Dam Structure
-Work Item 332.311: Excavation
-Type of Work: Rock
The detailed schedule of costs using this breakdown is presented in
Volume 6 of the Susitna Hydroelectric Project Feasibility Report (Acres
1982a).
(b) Approach to Cost Estimating
The estimating process used generally included the following
steps:
-Collection and assembly of detailed cost data for labor,
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(c)
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material, and equipment as well as information on productivity,
climatic conditions, and other related items;
-Review of engineering drawings and technical information with
regard to construction methodology and feasibility;
-Production of detailed quantity takeoffs from drawings in
accordance with the previously developed Code of Accounts and item
listing;
-Determination of direct unit costs for each major type of work by
development of labor, material, and equipment requirements;
development of other costs by use of estimating guides, quotations
from vendors, and other information as appropriate;
-Devel'opment of construction indirect costs by review of labor,
material, equipment, supporting facilities, and overheads; and
-Development of construction camp size and support requirements
from the labor demand generated by the construction direct and
indirect costs.
Cost Data
Cost information was obtai ned from standard estimating sources,
from sources in Alaska, from quotes by major equipment suppliers
and vendors, and from representative recent hydroe 1 ectri c
projects. Labor and equipment costs for 1982 were developed from
a number of sources (State of Alaska 1982; Caterpillar Tractor Co.
1981) and from an analysis of costs for recent projects performed
in the Alaska environment.
It has been assumed that most contractors wi 11 work an average of
two 10-hour shifts per day, six days per week. Due to the severe
compression of construction activities in 1985-86, it has been
assumed that most work in this period will be on two 12-hour
shifts, seven days per week.
The 10-hour work shift assumption provides for high utilization of
construction equipment and reasonable levels of overtime earnings
to attract workers. The two-shift basis generally achieves the
most economical balance between labor and camp costs.
Construction equipment costs were obtained from vendors on an FOB
Anchorage basis with an appropriate allowance included for
transportation to site. A representative list of construction
D-1-3
equipment required for the project was assembled as a basis for
the estimate. It has been assumed that most equipment would be
fully depreciated over the life of the project. For some
activities such as construction of the Watana main dam, an
allowance for major overhaul was included rather than fleet
replacement. Equipment operating costs were estimated from
industry source data, with appropriate modifications for the
remote nature and extreme climatic environment of the site.
Alaskan labor rates were used for equipment maintenance and
repair. Fuel and oil prices have been based upon FOB site
prices.
Information for permanent mechanical and electrical equipment was
obtained from vendors and manufacturers who provided guideline
costs on major power plant equipment.
The costs of materials required for site construction were
estimated on the basis of suppliers 1 quotations with allowances
for shipping to site.
(d) Seasonal Influences on Productivity
A review of climatic conditions together with an analysis of
experience in Alaska and in northern Canada on large construction
projects was undertaken to determine the average duration for
various key activities. It has been projected that most above-
ground activities will either stop or be curtailed during December
and January because of the extreme cold weather and the associated
lower productivity. For the main dam construction activities, the
following seasons have been used:
-Watana dam fi 11 -6-month season
-Devil Canyon arch dam-8-month season.
Other above-ground activities are assumed to extend up to 11
months depending on the type of work and the criticality of the
schedule. Underground activities are generally not affected by
climate and should continue throughout the year.
Studies by others (Roberts 1976) have indicated a 60 percent or
greater decrease in efficiency in construction operations under
adverse winter conditions. Therefore, it is expected that most
contractors would atternpt to schedule outside work over a period
of between six to ten months.
Studies performed as part of this work program indicate that the
general construction activity at the Susitna damsite during the
months of April through September would be comparable with that in
the northern sections of the western United States. Rainfall in
the general region of the site is moderate between mid-April and
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(e)
mid-October, ranging from a low of 0.75 inches precipitation in
April to a high of 5.33 inches in August. Temperatures in this
period range from 33°F to 66°F for a twenty-year average. In the
five-month period from November through March, the temperature
ranges from 9.4°F to 20.3°F, with snowfall of 10 inches per
month. ·
Construction Methods
The construction methods assumed for development of the estimate
and construction schedule are generally considered normal to the
industry, in line with the available level of technical
information. A conservative approach has been taken. in those
areas where more detailed information will be developed during
subsequent investigation and engineering programs. For example,
normal drilling, blasting, and mucking methods have been assumed
for all underground excavation. Convent i anal equipment has also
been considered for major fill and concrete work.
{f) Quantity Takeoffs
(g)
Detailed quantity takeoffs were produced from the engineering
drawings using methods normal to the industry. The quantities
developed are listed in the detailed summary estimates in the
Susitna Hydroelectric Feasibility Report (Acres 1982a, Vol. 6).
Indirect Construction Costs
Indirect construction costs were estimated in detail for the
civil construction activities. A more general evaluation was used
for the mechanical and electrical work.
Indirect costs included the following:
-Mobilization
Technical and supervisory personnel above the level of trades
foremen
All vehicle costs for supervisory personnel
-Fixed offices, mobile offices, workshops, storage facilities,
and laydown areas, including all services
-General transportation for workmen on site and off site
D-1-5
-Yard cranes and f1 oats
-Utilities including electrical power, heat, water, and
compressed air
-Small tools
-Safety program and equipment
-Financing
-Bonds and securities
-Insurance
-Taxes
-Permits
-Head office overhead
-Contingency allowance
-Profit.
In developing contractor's indirect costs, the following assumptions
have been made:
-Mobilization costs have generally been spread over construction
items;
-No escalation allowances have been made, and therefore any risks
associated with escalation are not included. These have been
addressed ·in both the economic and financial studies;
-Financing of progress payments has been estimated for 45 days, the
average time between expenditure and reimbursement;
-Holdback would be limited to a nominal amount;
Project all-risk insurance has been estimated
indirect cost for this estimate, but it is
insurance would be carried by the owner; and
as a contractor's
expected that this
Contract packaging would provide for the supply of major materials to
contractors at site at cost. These include fuel , electric power,
cement, and reinforcing steel.
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1.2 -Mitigation Costs
The project arrangement includes a number of features designed to
mitigate potential impacts on the natural environment and on residents
and communities in the vicinity of the project. In addition, a number
of measures are planned during the construction of the project to
reduce simi 1 ar impacts caused by construction act i vites. These measures
and facilities represent additional costs to the project than would
otherwise be required for safe and efficient operation of a
hydroelectric development. These mitigation costs have been estimated
at $153 m-illion and have been summarized in Table D.4. In addition,
the cost of full reservoir clearing at both sites has been estimated at
$85 m"lllion. Although full clearing is considered good engineering
practice, it is not essential to the operation of the power facilities.
These costs include direct and indirect costs, engineering,
administration, and contingencies.
A number of mitigation costs are associated with facilities,
improvements or other programs not direct 1 y related to the project or
located outside the project boundaries. These would include the
following items:
-Caribou barriers
-Raptor nesting platforms
-Fish channels
-Fish hatcheries
-Stream improvements
-Salt licks
Habitat management for moose
-Fish stocking program in reservoirs
A detailed discussion of the mitigation programs required for the
project is included in Exhibit E along with tables listing detailed
costs. The costs of these programs including contingency have been
estimated as follows and listed under project indirects in the capital
cost estimate.
Watana
Devil Canyon
Total Project
$32 million (Approximately)
5 million (Approximately)
$17 mi 11 ion
A number of studies and programs will be required to monitor the
impacts of the project on the environment and to develop and record
various data during project construction and operation. These
include:
-Archaeological studies
-Fisheries and wildlife studies
D-1-7
Right-of-way studies; and
-Socioeconomic planning studies.
The costs for the above work have been included under project overheads
and have been estimated at approximately $20 million.
1.3 Engineering and Administration Costs
Engineering has been subdivided into the following accounts for the
purposes of the cost estimates:
-Account 71
. Engineering and Project Management
Construction Management
Procurement
-Account 76
Owner • s Costs
The total cost of engineering and administrative activities has been
estimated at 12.5 percent of the total construction costs, including
contingencies. A detailed breakdown of these costs is dependent on the
organizational structure established to undertake design and management
of the project, as well as more definitive data relating to the scope
and nature of the various project components. However, the main
elements of cost included are as follows:
(a) Engineering and Project Management Costs
These costs include ~lowances for:
-Feasibility studies, including
investigations and logistics support;
site surveys
Preparation of the license application to the FERC;
and
-Technical and administrative input for other federal, state
and local permit and license applications;
Overall coordination and administration of engineering, con
struction management, and procurement activities;
-Overall planning, coordination, and monitoring activities
related to cost and schedule of the project;
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(b)
-Coordination with and reporting to the Power Authority regarding
all aspects of the project;
-Preliminary and detailed design;
-Technical input to procurement of construction services,
support services, and equipment;
-Monitoring of construction to ensure conformance to design
requirements;
-Preparation of start up and acceptance test procedures; and
-Preparation of project operating and maintenance manuals.
Construction Management Costs
Construction management costs have been assumed to include:
-Initial planning and scheduling and establishment of project
procedures and organization;
-Coordination of on site contractors and construction management
activities;
-Administration of on site contractors to ensure harmony of
trades, compliance with applicable regulations, and maintenance
of adequate site security and safety requirements;
-Development, coordination, and monitoring of construction
schedules;
-Construction cost control;
-Material, equipment and drawing control;
-Inspection of construction and survey control;
Measurement for payment;
-Start up and acceptance tests for equipment and systems;
-Compilation of as-constructed records; and
-Final acceptance.
0-1-9
(c) Procurement Costs
Procurement costs have been assumed to include:
-Establishment of project procurement procedures;
-Preparation of non-technical procurement documents;
Solicitation and review of bids for construction services,
support services, permanent equipment, and other items required
to complete the project;
-Cost administration and control for procurement contracts; and
-Quality assurance services during fabrication or manufacture of
equipment and other purchased items.
(d) Owner's Costs
Owner's costs have been assumed to include the following:
-Administration and coordination of project management and
engineering organizations;
Coordination with other state, local, and federal agencies and
groups having jurisdiction or interest in the project;
-Coordination with interested public groups and individuals;
-Reporting to legislature and the public on the progress of the
project; and
-Legal costs.
1.4 -Operation, Maintenance and Replacement Costs
The facilities and procedures for operation and maintenance of the
project are described in the Susitna Feasibility Report (Acres l982a,
Vol. 1). Assumptions for the size and extent of these facilities have
been made on the basis of experience at large hydroelectric
developments in northern climates. The annual costs for operation and
maintenance for the Watana development have been estimated at $10.4
million. When Devil Canyon is brought on line these costs increase to
$15.2 million per annum. Interim replacement costs have been estimated
at .3 percent per annum of the capital cost.
The breakdown in Table 0.5 is provided in support of the allowance used
in the finance/economic analysis of the Susitna Hydroelectric Project.
It is based on an operating plan involving full staffing of power plant
0-1-10
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and permanent town site support personnel. A total of 105 will be
employed for Watana with another 25 to be added when Devil Canyon comes
on line. This manpower level will provide manned supervisory staff on
a 24-hour, three-shift basis, with maintenance crews to handle all but
major overhauls. A nominal allowance has been made for major
maintenance work which would utilize contracted labor. It is unlikely
that major overhauls will be necessary in the first ten years of
project operation. In earlier years, this allowance is a prudent
provision for unexpected start up costs over and above those covered by
warranty.
Allowance for contracted services also covers helicopter operations and
access road snow clearing and maintenance.
Allowances have also been made for environmental mitigation as well as
a contingency for unforeseen costs.
Estimates for Susitna have been based on original estimates and actual
experience at Churchill Falls. It should be realized that alternative
operating plans are possible which would eliminate the need for
permanent town site facilities and rely on more remote supervisory
systems and/or operations/maintenance crews transported to the plant on
a rotating shift basis. Cost implications of these alternatives have
not yet been ex ami ned.
1.5 -Allowance for Funds Used During Construction (AFDC)
At current levels of interest rates, AFDC will amount to a
significant element of financing cost for the lengthy periods required
for construction of the Watana and Devil Canyon projects. However, in
economic evaluations of the Susitna project the low real rates of
interest assumed would have a much reduced impact on assumed project
development costs. Furthermore, direct state involvement in financing
of the Susitna project wi 11 also have a significant impact on the
amount, if any, of AFDC. Provisions for AFDC at appropriate rates of
interest are made in the economic and financial analyses included in
this Exhibit.
Interest and escalation were calculated as a percent of the total
capital costs of the project at the start of construction. The method
used for calculating the effects of interest and escalation during
construction is documented in Phung 1978.
An S-shaped symmetric cash flow was adopted where:
D-1-11
1 + f
co
1
1rf+ 2 -J2 L B ln ( 1 +f)
where ~
1 + fco =Total cost upon commercial service expressed as a
multiplier of construction cost.
1 + f = 1 + y
1 + X
x ~ effective interest rate
y =escalation rate
B = construction period
The value of the variables used in the computations are summarized in
Table 0.6. The Watana and Devil Canyon constructions periods were
taken from Exhibit Cas 8.5 years and 7.5 years, respectively.
The resultant total project cost was then calculated for each
interest/escalation scenario used in OGP-6 economic and financial
studies. Interest and escalation were calculated as a percent of
annual capital expenditure for the financial analysis as shown in
Table D .1.
1.6-Escalation
All construction costs presented in this Exhibit are at January 1982
levels and consequently include no allowance for future cost
escalation. Thus, these costs would not be representative of actual
construction and procurement bid prices. This is because provision
must be made in such bids for continuing escalation of costs, and the
extent and variation of escalation which might take place over the
lengthy construction periods involved. Economic and financial
evaluations take full account of such escalation at appropriate rates
as discussed in the previous paragraph.
1.7 -Cash Flow and Manpower Loading Requirements
The cash flow requirements for construction of Watana and Devil
Canyon are an essential input to economic and financial planning
studies. The bases for the cash flow are the construction cost
estimates in January 1982 dollars and the construction schedules
presented in Exhibit C, with no provision being made as such for
escalation. The cash flow estimates were computed on an annual basis
and do not include adjustments for advanced payments for mobilization
or for holdbacks on construction contracts. The results are presented
in Table 0.7 and Figures D.l through 0.3. The manpower loading
requirements were developed from cash flow projections. These curves
were used as the basis for camp loading and associated socioeconomic
impact studies.
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1.8 -Contingency
An overall contingency allowance of approximately 15 percent of
construction costs has been included in the cost estimates.
Contingencies have been assessed for each account and range from 10 to
20 percent. The contingency is estimated to include cost increases
which may occur in the detailed engineering phase of· the project after
more comprehensive site investigations and final designs have been
completed and after the requirements of various concerned agencies have
been satisfied. The contingency estimate also includes allowances for
inherent uncertainties in costs of labor, equipment and materials, and
for unforeseen conditions which may be encountered during construction.
Escalation in costs due to inflation is not included. No allowance has
been included for costs associated with significant delays in project
implementation. These items have been accounted for in economic and
financial planning studies.
1.9 -Previously Constructed Project Facilities
An electrical intertie between the major load centers of Fairbanks
and Anchorage is currently under construction. The line will connect
existing transmission systems at Willow in the south and Healy in the
north. The intertie is being built to the same standards as those
proposed for the Susitna project transmission lines. The line will be
energized initially at 138 kV in 1984 and will operate at 345 kV after
the Watana phase of the Susitna project is complete.
The current estimate for the completed intertie is $130.8 million.
This cost is not included in the Susitna project cost estimates. A
breakout of the cost estimate is shown in Table 0.8.
1.10 -EBASCO Check Estimate
An independent check estimate was undertaken by EBASCO Services
Incorporated (EBASCO 1982). The estimate was based on engineering
drawings, technical information and quantities prepared by Acres
American in the feasibility study. Major quantity items were checked.
The EBASCO check estimated capital cost was approximately 7 percent
above the Acres estimate.
A summary of EBASco•s check estimate has been included in Table 0.9 of
this exhibit.
D-1-13
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2 -ESITMATED ANNUAL PROJECT COSTS
The cost of the project has been estimated by two methods. In the
first, the cost of energy was determined by preparing a financial
forecast for the project assuming 100 percent debt financing. Table 10
Sheet 1 to 4 shows the projected year-by-year energy trends of the
project and a summary of revenue (RL516), operating costs (170),
interest, and cash sources and uses. These costs are in nominal
dollars assuming 7 percent inflation and 10 percent cost of capital.
Costs are based on power sales at cost assuming 100 percent debt
financing at 10 percent interest. This results in a nominal cost of
power of 298 mills in 1994 (first full year of Watana) and 350 mills in
2003 (first full year of Watana and Devil Canyon) as shown on line 520
of the table . The real cost of power, adjusted for inflation of 7
percent per annum, would be 128 mills in 1994 and 82 mills in 2003 and
would then fall progressively for the remaining life of the project.
The annual cost of energy from the project for the period 1993 to 2021
in nominal dollars and real dollars is shown on Sheets 5 and 6,
respectively, of Table 10.
The cost of power (capacity) from the project is shown on Table D-11.
This cost is determined in accordance with FERC procedures and is the
sum of the annual plant investment cost and the annual fixed operating
cost. As can be seen from Table D.ll, the total annual capacity cost
in 1982 dollars is $225/kW.
No taxes have been assessed to the project's annual costs. Although
these taxes would be expressed as a percentage of project plant in
service in this type of annual cost estimate, the taxes would be based
on revenues. As a corporation of the State, the Alaska Power Authority
is a not-for-profit entity. As such the Authority would not be subject
to a revenue tax.
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3 -MARKET VALUE OF PROJECT POWER
This section presents an assessment of rates at which energy and
capacity of the Susitna development could be priced, together with a
proposed basis for contracting for the supply of Susitna energy. Both
the marketing approach and financing plan are the subjects of ongoing
review and development. The Susitna project is scheduled to begin
generating power for the Railbelt in 1993. At that time the project
will meet growing electrical demand, replace retiring units and
displace capacity having more expensive running rates.
3.1 -The Railbelt Power System
The Railbelt region covers the Anchorage-Cook Inlet area and the
Fairbanks-Tanana Valley area. A complete discussion of the Railbelt
System is presented in Exhibit B.
Susitna ·capacity and energy will be partially delivered to the Region
via the linkage of the Anchorage and Fairbanks systems by an intertie
to be completed in the mid-1980s. The intertie will allow a capacity
transfer of up to 70 MW in either direction. The interconnection is
designed for initial operation at 138 kV with subsequent uprating to
345 kV allowing the line to be integrated into the Susitna transmission
facilities.
3.2 -Regional Electric Power Demand and Supply
The Reference Case forecast of electric power demand is presented in
Exhibit B. The results of studies presented in Exhibit B and Section 4
of the Exhibit call for Watana to come into operation in 1993 and to
deliver a full year's energy generation in 1994. Devil Canyon will
come into operation in 2002 and deliver a full year's energy in 2003.
Energy demand in the Railbelt region and the deliveries from Susitna
are shown in Figure 0.4.
3.3 -Market and Price for Watan~ Output in 1994
It is anticipated that Watana energy will be supplied at a single
wholesale rate to Railbelt utilities at a level to permit the maximum
use of the Susitna Project, thus achieving its full economic benefit.
This requires, in effect, that Susitna energy be priced so that it is
attractive even to utilities with the lowest cost alternative source of
energy. In evaluating the terms of power sales contracts, utilities
can be expected to consider the advantages afforded by Susitna's
long-term price stability, as well as the price offered in the initial
years. That wholesale price at which consumers would be neither better
nor worse off in 1994 under the with-Susitna plan or the best
alternative plan has been selected for evaluation. The actual
wholesale price charged for Susitna energy may vary from this price
D-3-1
depending on the course of power sales contract negotiations and on the
further development of the marketing approach.
This estimated 1994 price is based on calculations using the financial
parameters in Table 0.12, Reference Case fuel prices discussed in
Section 4.5, and a prevailing 7 percent rate of inflation per annum.
The most cost effective without-Susitna plan from which the estimated
1994 price is derived is specified in Seeton 4.6. The associated plant
capital and operating costs are shown in Table 0.18.
In order to determine the cost of the alternative thermal capacity and
energy which would replace Susitna generation, the cost of thermal
generation under the with Susitna plan was subtracted from the cost of
thermal generation under the without Susitna plan. This avoided
thermal cost which would be replaced by Susitna generation is
shown on Figure 5. The costs shown are expressed in mills per
kilowatt-hour which is the total avoided thermal cost divided by the
Susitna energy output in a given year. In 1994 this cost is estimated
at 136 mills/kWh in nominal dollars.
The financing considerations under which it would be appropriate for
Watana energy to be sold at approximately 136 mills per kWh price are
considered in Section 6 of this Exhibit.
The Power Authority wi 11 seek to contract with Rail belt utilities for
the purchase of Sus itna capacity and energy on a basis appropriate to
support financing of the project. Pricing policies for Susitna output
will be constrained both by cost and by the price of energy from the
best alternative option.
3.4 -Market and Price for Watana Output 1995-2001
After its first full year of operation in the system in 1994, 2957
GWh of the total 3105 GWh of Watana output is initially marketable.
The excess energy occurs in the surrrner. The market for the project
strengthens over the years to 2001 since energy demand will increase by
16 percent over this period as projected in the Reference Case fore-
cast. Figure 0.5 shows the avoided cost of energy for the period 1995
to 2001.
The addition of the Susitna project will add a large generating
resource in the system in 1993, displacing a significant amount of the
existing generating resources in the system. The project will provide
about 70 percent of total energy demand. The displaced units will be
used as reserve capacity and to meet growing load until the Devil
Canyon project comes on line. This effect is illustrated on Figure
0.4.
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3. 5 -Market and Price for Watana and Devil Canyon Output in 2003
After the Devil Canyon project comes on line, the Susitna project will
provide about 90 percent of the energy demand. The avoided therma 1
costs in 2003 is 230 mills per kWh (2003 dollars, 7 percent annual
escalation) as shown on Figure D.S. The excess Susitna power occurs in
the summer while additiona1 energy from other resources is required in
the winter. The generating resources displaced are units nearing
retirement and will be used as reserve capacity.
3.6-Potential Impact of State Appropriations
In the preceding paragraphs, the price facing Railbelt utilities in
the absence of Susitna has been identified. Sale of Susitna energy at
this price wi11 depend upon the magnitude of any proposed state
appropriation and upon the willingness of Railbelt utilities to pay an
appropriate rate in light of the project•s long-term benefits.
Based on the assessment of the market for power and energy output from
the Susitna Hydroelectric Project, it has been concluded that, with the
appropriate level of state appropriation a viable basis exists for the
Susitna Power to be absorbed by the Railbelt utilities.
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4 -EVALUATION OF ALTERNATIVE ENERGY PLANS
4.1 -General
This section describes the process of assembling the information
necessary to carry out the systemwide generation pl arming studies for
assessment of the economic feasibility of the Susitna project.
Included is a discussion of the existing system characteristics, the
planned Anchorage-Fairbanks intertie, and details of various generating
options including hydroelectric and thermal. Performance and cost
information required for the generation planning studies is presented
for the hydroelectric and thermal generation options considered.
-The approach taken in economically evaluating the Susitna project
involved the development of long-term generation plans for the Railbelt
electrical supply system with and without the proposed project. In
order to compare the with-and-without plans, the cost of the plans were
compared on a present worth basis. A generation planning model which
simulated the operation of the system annually was used to project the
annual generation costs.
During the pre-license phase of the Susitna project planning, two
studies proceeded in parallel which addressed the alternatives in
generating power in the Alaska Railbelt. These studies are the Susitna
Hydroelectric Project Feasibility Study sponsored by the Alaska Power
Authority and the Railbelt Electric Power Alternatives Study sponsored
by the Office of the Governor, State of Alaska.
The objective of the Susitna Feasibility Study was to determine the
feasibility of the proposed project. The economic evaluations
performed during the study found the project to be feasible as
documented in this exhibit. The Railbelt study focused on the
feasibility of all possible generating and conservation alternatives.
Although the studies were independent, several key factors were
consistent. Both studies used the approach of comparing costs by using
generation planning simulation models. Thus, selected alternatives
were put into a plan context and their economic performance compared by
comparing costs of the plans.
The following presentation focuses primarily on the Susitna Feasibility
Study process and findings. A separate section provides findings of
the Battelle study.
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4.2 -Existing System Characteristics
(a) System Description
The two major load centers of the Railbelt region are the
Anchorage-Cook Inlet area and the Fairbanks-Tanana Valley area
which at present operate independently. The existing transmission
system between Anchorage and Will ow consists of a network of 115
kV and 138 kV lines with interconnection to Palmer. Fairbanks is
primarily served by a 138 kV line from the 28 MW coal-fired plant
at Healy. Communities between Willow and Healy are served by
local distribution.
Table D.l3 summarizes the total generating capacity within the
Railbelt system in 1982, based on information provided by Railbelt
utilities and other sources. Table D.14 presents the resulting
detailed listing of units currently operating in the Railbelt,
information on their performance characteristics, and their
on-1 ine and projected retirement dates for generation planning
purposes. The total Railbelt installed capacity of 1122.8 1"1W
consists of two hydroelectric plants totaling 46 MW plus 1076.8 MW
of thermal generation units fired by oil, gas, or coal, as
summarized in Table 0.14.
(b) Retirement Schedule
In order to establish a retirement policy for the existing
generating units, several sources were consulted, including the
Power Authority's draft feasibility study guidelines, FERC
guidelines (FERC 1979), the Battelle Railbelt Alternatives Study
(Battelle 1982), and historical records. Utilities, particularly
those in the Fairbanks area, were also consulted. Based on these
sources, the following retirement periods of operation were
adopted for use in this analysis:
-Large Coal-Fired Steam Turbines(> 100 MW):
Small Coal-Fired Steam Turbines(< 100 MW):
-Oil-Fired Gas Turbines:
-Natural Gas-Fired Gas Turbines:
-Diesels:
-Combined Cycle Units:
-Conventional Hydro:
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30 years
35 years
20 years
30 years
30 years
30 years
50 years
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(c)
Table 0.14 lists the service dates for each-of the current
generating units which would be retired based on the above
retirement policy.
Schedule of Additions
Two new projects are assumed to be added to the Rai 1 belt system
prior to 1990, as shown in Table 0.15. The Alaska Power Authority
is conducting a feasibility study of the Bradley Lake
Hydroelectric Project on the Kenai Peninsula. If the project is
determined to be feasible the APA will take steps to build the
project. For analysis purposes, the project is assumed to provide
90 MW of generating capacity and 347 GWh of annual energy, and to
be in service by 1988.
Feasibility study of the Grant Lake Project has been completed by
APA recently. This project is planned to serve the City of
Seward, and to provide 7 MW of generating capacity and 33 GWh of
annual energy. For the purpose of analysis, this project is
assumed to be in service by 1988 also.
In addition, Fairbanks Municipal Utility Systems is considering
the addition of a 25-30 MW cogeneration unit to replace Chena
Units 1, 2 and 3; however, these plans are not definite.
4.3 -Fairbanks -Anchorage Intertie
Engineering studies have been undertaken, equipment has been
purchased and construction contracts have been let for construction of
an intertie between the Anchorage and Fairbanks systems. This
connection will involve a 345 kV transmission line between Willow and
Healy scheduled for completion in 1984. The line will initially be
operated at 138 kV with capability of expansion as the loads grow in
the load centers.
Costs of additional transmission facilities were added to the scenarios
as necessary for each unit added. In the 11 With Susitna,. scenarios, the
costs of adding circuits to the intertie corridor were added to the
Susitna project cost. For the non-Susitna units, transmission costs
were added as fo 11 ows:
No costs were added for combined-cycle or gas-turbine units, since
they were assumed to have sufficient siting flexib-ility to be placed
near the major transmission works;
-A multiple coal-fired unit development in the Beluga fields was
estimated to have a transmission system with security equal to that
planned for Susitna, costing $220 million. This system would take
power from the bus back to the existing load center; and
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A single coal-fired unit development in the Nenana area using coal
mined in the Healy fields would require a transmission system costing
$117 million dollars.
With the addition of a unit in the Fairbanks area in the 1990's, no
additions to the 345 kV line were considered necessary. Thus, no other
transmission changes were made to the non-Susitna plans.
4.4 -Hydroelectric Alternatives
Numerous studies of hydroelectric potential in Alaska have been under-
taken. These date as far back as 1947 and were performed by various
agencies including the then Federal Power Commission, the Corps of
Engineers, the U.S. Bureau of Reel amation, the U.S. Geological Survey,
and the State of Alaska. A significant amount of the identified poten-
tial is located in the Railbelt region, including several sites in the
Susitna River Basin.
(a) Selection Process
The application of the five-step methodology (Figure D.6) for
selection of non-Susitna plans which incorporate hydroelectric
developments is summarized in this section. The analysis was
completed in early 1981 and is based on January 1981 cost figures;
all other parameters are contained in the Development Selection
Report (Acres 198lb). Step 1 of this process essentially
established the overall objective of the exercise as the selection
of an optimum Rai"lbelt generation plan which incorporated the
proposed non-Susitna hydroelectric developments for comparison
with other plans.
Under Step 2 of the selection process, all feasible candidate
sites were identified for inclusion in the subsequent screening
exercise. A total of 91 potential sites were obtained from
inventories of potential sites published in the COE National
Hydropower Study and the Power Admi ni strati on report 11 Hydroel ec-
tric Alternatives for the Alaska Ra·ilbelt.11
The screening of sites under Step 3 required a total of four
successive iterations to reduce the number of alternatives to a
manageable short list. The overall objective of this process was
defined as the selection of approximately ten sites for considera-
tion in plan formulation, essentially on the basis of published
data on the sites and appropriately defined criteria. Figure 0.7
shows 49 of the sites which remained after the two initial screen-
ings.
In Step 4 of the plan selection process, the ten sites short
listed under Step 3 were further refined as a basis for formula-
tion of Railbelt generation plans. Engineering sketch-type lay-
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(b)
outs were produced for each of the sites, and quantities and
capital costs were evaluated. These costs, listed in Table 0.16,
incorporate a 20 percent allowance for contingencies and 10
percent for engineering and owner•s administration. A total of
five plans were formulated incorporating various combinations of
these sites as input into the Step 5 evaluations.
Power and energy values for each of the developments were reeval-
uated in Step 5 utilizing monthly streamflow and a computer reser-
voir simulation model. The results of these calculations are
summarized in Table 0.16 .
The essential objective of Step 5 was the derivation of the opti-
mum plan for the future Railbelt generation incorporating non-
Susitna hydro generation as well as required thermal generation.
Selected Sites
The se 1 ected potentia 1 non-Sus itn a basin hydro deve 1 opments were
ranked in terms of their economic cost of energy. They were then
introduced into the all-thermal generating scenario during the
generation planning analyses, in groups of two or three. The most
economic schemes were introduced first and were followed by the
less economic schemes. The methods of analysis are the same as
those discussed in Section 4.5 (f).
The results of these analyses, completed in early 1981, are sum-
marized in Table 0.17 and illustrate that a minimum total system
cost can be achieved by the ·introduction of the Chakachamna,
Keetna, and Snow projects. Note that further studies of the
Chakachamna project were initiated in mid-1981 by Bechtel for the
Alaska Power Authority.
(c) Lake Chakachamna
Bechtel Civil and Minerals studied the feasibility of developing
the power potential of Lake Chakachamna (Bechtel Civil and
. Minerals 1981). The lake is on the west side of Cook Inlet 85
miles west of Anchorage. Its water surface 1 i es at about Eleva-
tion 1140.
Two basic alternatives have been identified to harness the hydrau-
lic head for the generation of electrical energy. One is via the
valley of the Chakachatn a River. This river runs out of the
easterly end of the lake and descends to about Elevation 400 where
the river leaves the confines of the valley and spills out onto a
broad alluvial flood plain. A maximum hydrostatic head of about
740 feet could be developed via this ~ternative.
D-4-5
The other alternative calls for development by diversion of the
lake outflow to the valley of the McArthur River which lies to the
southeast of the lake outlet. A maximum hydrostatic head of about
960 feet could be harnessed by this diversion.
(i) Project Layout
The Bechtel study evaluated the merits of developing the
power potential by diversion of water southeasterly to the
McArthur River via a tunnel about 10 miles long, or easterly
down the Chakachatna valley either by a tunnel about 12
miles long or by a dam and tunnel development. Few sites,
adverse foundation conditions, the need for a large capacity
spillway and the nearby presence of an active volcano made
it evident that the feasibility of constructing a dam in the
Chakachatna valley would be problematical. The main thrust
of the initial study was therefore directed toward the tun-
nel ~ternatives.
Two alignments were studied for the McArthur tunnel. The
first considered the shortest distance that gave no oppor-
tunity for an additional point of access during construction
via an intermediate adit. The second alignment was about a
mile longer, but gave an additional point of access, thus
reducing the lengths of headings and also the time required
for construction of the tunnel. Cost comparisons neverthe-
1 ess favored the shorter 10-mi l e, 25-foot diameter tunnel.
The second alignment running more or less parallel to the
Chakachatna River in the right (southerly) wall of the
valley afforded two opportunities for intermediate access
ad its. These, plus the upstream and downstream portals
would allow construction to proceed simultaneously in six
headings and reduce the construction time by 18 months from
that required for the McArthur tunnel.
If all the controlled water were used for power generation,
the McArthur powerhouse could support 400 MW installed
capacity and produce average annual firm energy of 1753 GWh.
Making a provisional reservation of approximately 19 percent
of the average annual inflow to the lake for instream flow
requirements in the Chakachatn a River reduced the economic
tunnel diameter to 23 feet. The installed capacity in the
powerhouse would then be reduced to 330 MW and the average
annual firm energy to 1446 MW.
For the Chakachatna powerhouse, diversion of all the con-
trolled water for power generation would support an in-
stalled capacity of 300 MW with an average annual firm
energy generation of 1314 GWh. Provisional reservation of
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approximately 0.8 percent of the average annual inflow to
the lake for instream flow requirements in the Chakachatna
River was regarded as having negligible effect on the
installed capacity and average annual firm energy because
that reduction is within the accuracy of the Bechtel study.
(ii) Technical Evaluation and Discussion
Several alternative methods of developing the project have
been identified and reviewed. Based on the analyses per-
formed, the more viable alternatives have been identified by
Bechtel for further study.
-Chakachatna Dam Alternative
The construction of a dam in the Chakachatna River canyon
approximately 6 miles downstream from the lake outlet does
not appear to be a reasonable alternative. While the site
is topographically suitable, the foundation conditions in
the river valley and left abutment are poor. Furthermore,
its environmental impact specifically on the fisheries
resource will be significant (although provision of fish
passage facilities could mitigate this impact to a certain
extent).
-McArthur Tunnel Alternatives A and B
Diversion of flow from Chakachamna Lake to the McArthur
valley to develop a head of approximately 900 feet has
been identified as the most advantageous with respect to
energy production and cost.
The geologic conditions for the various project facilities
including intake, power tunnel, and powerhouse appear to
be favorab 1 e based on a 1981 field reconnaissance. No
insurmountable engineering problems appear to exist in
development of the project.
Alternative A, in which essentially all stored water would
be diverted form Chakachamna Lake for power production
purposes, could deliver 1664 GWh of firm energy per year
to Anchorage and provide 400 MW of peaking capacity.
However, since the flow of the Chakachatna River below the
lake outlet would be adversely affected, the existing
anadromous fishery resource which uses the river to gain
entry to the lake and its tributaries for spawning would
be lost. In addition, the fish which spawn in the lower
Chakachatna River would also be impacted due to the much
reduced river flow. For this reason, Alternative B has
been developed, with essentially the same project arrange-
0-4-7
ment except that approximately 19 percent of the average
annual flow into Chakachamna Lake would be released into
the Chakachatna River below the lake outlet to maintain
the fishery resource. Because of the smaller flow
available for power production, the installed capacity of
the project would be reduced to 330 MW and the firm energy
delivered to Anchorage would be 1374 GWh per year.
Obviously, the long-term environmental impacts of the
project in this Alternative B are significantly reduced
compared to Alternative A, since the river flow is
maintined, albeit at a reduced amount. Estimated project
costs for Alternatives A and 8 are $1.5 billion and $1.45
billion, respectively.
-Chakachatna Tunnel Alternatives C and D
An alternative to the development of this hydroelectric
resource by diversion of flows from Chakachamna Lake to the
McArthur River· is constructing a tunnel through the right
wall of the Chakachatna valley and locating the powerhouse
near the downstream end of the valley. The general layout
of the project would be similar to that of Alternatives A
and B for a slightly longer power tunnel.
The geologic conditions for the various project features
including intake, power tunnel, and powerhouse appear to be
favorable and very similar to those of Alternatives A and
B. Similarly, no insurmountable engineering problems
appear to exist in development of the project.
Alternative C, in which essentially all stored water is
diverted from Chakachamna Lake for power production, could
deliver 1248 GWh of firm energy per year to Anchorage and
provide 300 MW of peaking capability. While the river flow
in the Chakachatna River bel ow the powerhouse at the end of
the canyon wi 11 not be substantia 11 y affected, the fact
that no releases are provided into the river at the lake
outlet will cause a substantial impact on the anadromous
fish which normally enter the lake and pass through it to
the upstream tributaries. Alternative D was therefore
proposed in which a release of 30 cfs is maintained at the
lake outlet to facilitate fish passage through the canyon
section into the lake. In either of Alternatives C or D
the environmental impact would be limited to the
Chakachatna River as opposed to Alternatives A and B in
which both the Chakachatna and McArthur Rivers would be
affected. Si nee the instream flow release for Alternative
D is less than 1 percent of the total available flow, the
power production of Alternative D can be regarded as being
the same as the Alternative C (300 MW peaking capability,
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1248 GWh of firm energy delivered to Anchorage) .
. Estimated project costs for Alternatives C and D are $1.6
billion and $1.65 billion, respectively.
4.5 -Thermal Options -Development Selection
As discussed earlier in this section, the major portion of generating
capability in the Railbelt is currently thermal, principally natural
gas with some coal-and oil-fired installations. There is no doubt
that the future electric energy demand in the Railbelt could be satis-
fied by an all-thermal generation mix. In the following paragraphs, an
outline is presented of the analysis undertaken in the feasibility
study to determine an appropriate all-thermal generation scenario for
comparison with the Susitna hydroelectric scenario.
(a) Assessment of Thermal Alternatives
The overall objective established for this selection process was
the selection of an optimum all-thermal Railbelt generation plan
for comparison with other plans (Figure D.8).
Primary consideration was given to gas-, coal-, and oil-fired
generation sources which are the most readily developable alterna-
tives in the Railbelt from the standpoint of technical and eco-
nomic feasibility. The broader perspectives of other alternative
resources such as peat, refuse, geothermal, wind and so 1 ar and the
relevant environmental, social, and other issues involved were
addressed in the Battelle alternatives study (Battelle 1982).
As such, a screening process was therefore considered unnecessary
in this study, and emphasis was placed on selection of unit sizes
appropriate for inclusion in the generation planning exercise .
. For analysis purposes the following types of thermal power
generation units were considered:
-Coal-fired steam
-Gas-fired combined-cycle
-Gas-fired gas turbine
-Diesel.
The following paragraphs present the thermal options used in
developing the present without-Susitna plan.
(b) Coal-Fired Steam
A coal-fired steam plant is one in which steam is generated by a
D-4-9
coal-fired boiler and used to drive a steam-turbine generator.
Cooling of these units is accomplished by steam condensation in
cooling towers or by direct water cooling.
Aside from the military power plant at Fort Wainwright and the
self-supplied generation at the University of Alaska, there are
currently two coal-fired steam plants in operation in the Rail-
belt. These plants are small compared with most new plants
installed to meet base load in the lower 48 states and new plants
being considered for the railbelt thermal generation
alternatives.
( i) Capital Costs
A detailed cost study was done by EBASCO Services Incorpor-
ated as part of Battelle's alternatives study (Battelle
1982, Vol. XII). The report found that it was feasible to
establish a plant at either the undeveloped Beluga field or
near Nenana, using Healy field coal. The study produced
costs and operating characteristics for both plants. All
new coal units were estimated to have an average heat rate
of 10,000 Btu/kWh and involve an average construction
period of five to six years. Capital costs and operating
parameters are defined for coal and other thermal
generating plants in Table 0.18. Cost estimates by major
account are presented in Tables 0.19 and 0.20.
It was found that, rather than develop solely at one field
in the non-Susitna case, development would be likely to
take place in both fields. Thus, two units would be
developed near Nenana to service the Fairbanks load center,
with the remaining units placed in the Beluga fields.
To satisfy the national New Performance Standards, the cap-
ital costs incorporate provision for installation of flue
gas desulfurization for sulphur control, highly efficient
combustion technology for control of nitrogen acids, and
baghouses for particulate removal.
(ii) Fuel Costs
Coal in the Railbelt in quantities sufficient for electric
power generation is available from the Nenana Field near
Healy and the Beluga Field near Anchorage. The analysis
presented in Appendix D-1 developed the base cost of coal
_from these sources, transportation costs, if required, and
real price escalation rates.
For the purposes of the economic analysis, it was assumed
that up to two 200-MW coal-fired steam units would be
located at Nenana, rather than at mine-mouth, due to the
mine 1 S proximity to Denali National Park. A mine-mouth
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price of $1.40/MMBtu in 1983 dollars was estimated for
Nenana coal-based on current contracts with Golden Valley
Electric Association and Fairbanks Municipal Ut-ility
Systems adjusted for changes in production levels and new
1 and reel aimation regulations. Transportation costs to
Nenana are estimated to be $0.32/MMBtu in 1983 dollars.
Therefore, the total cost of the coal delivered in Nenana
would be $1.72/MMBtu. The coal has an average heat content
of about 7800 Btu/"lb.
Agreements between coal suppliers and electric utilities
for the sale/purchase of coal are usually long term
contracts which include a base price for the coal and a
method of escalation to provide prices in future ·years.
The base price provides for recovery of the capital
investment, profit, and operating and maintenance costs at
the level in existence when the contract is executed. The
intent of the escalation mechanism is to recover actual
increases in labor and material costs from operation and
maintenance of the mine. Typically the escalation
mechanism consists of an index or combination of indexes
such as the producer price index, various commodity and
labor indexes, the consumer price index applied to
operating and maintenance expenses, and or regulation
related indices. The original capital investment is not
escalated, so the base price of coal to the utility tends
to increase with general inflation.
Several escalation rates have been estimated for utility
coal in Alaska and in the lower 48 states, and they range
from 2.0-2.7%/year (real). Several more generic rates have
also been developed by Sherman H. Clark and Associates and
by Data Resources Inc. (DRI). Because the forecasts of DRI
and Sherman H. Clark are oased upon supply-demand factors,
they were applied to the base contract price of coal. The
2.6% real rate of increase used by DRI and Sherman H. Clark
is applied to the mine-mouth price of Nenana Field coal as
this mine is used principally to supply domestic markets.
It should be noted, however, that this is the price before
transport. Transportation costs over time are assumed to
increase at 0.9%/yr. The overall real composite rate of
escalation including transportation for coal consumed in a
generating plant located at Nenana is 2.3%/yr.
Other than the two 200-MW units installed at Nenana, all
other coal-fired units will be mine-mouth units installed
at Beluga. The base price of coal has been determined
under the assumption of an export market and was calculated
as the net back cost in Alaska based on the value of coal
in Japan as described in Appendix D-1. This cost is $1.86/
MMBtu at 1983 price levels for coal with a heat content of
about 7500 Btu/lb.
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An escalation rate of 1.6%/yr. of the price of Beluga coal
is based on escalation rates developed by DRI and Sherman
H. Clark for coal exported to Pacific Rim countries.
Both Nenana and Beluga coal prices have been assumed to
escalate to the date a given generating unit enters
operation. At that time, the coal price for that unit is
assumed to remain constant in real terms until the unit is
replaced. Using this approach the average coal price
escalation rate for the Reference Case all thermal
generation alternative is about 1%/yr.
The coal escalation rates discussed above were used for
the reference case and the DRI sensitivity case. Zero real
price escalation of coal was assumed for the DOR-mean and
-2 percent sensitivity cases.
(iii) Other Performance Characteristics
Annual operation and maintenance and representative forced
outage rates are shown in Table 0.18.
(c) Combined Cycle
Combined cycle plants achieve higher efficiencies than
conventional gas turbines. There are two combined cycle
plants in Alaska at present. One is the 139-MW G. M.
Sullivan plant of Anchorage-Municipal Light and Power (AMLP). The
other is the Beluga No. 8 unit owned by Chugach Electric
Association (CEA). It is a 42-I~W steam turbine, which was added
to the system in late 1982, and utilizes heat from currently
operating gas turbine units, Beluga Nos. 6 and 7.
( i) Capital Costs
A new combined cycle plant unit size of 200-MW capacity was
considered to be representative of future additions to
generating capability in the Anchorage area. This is based
on economic sizing for plants in the lower 48 states and
projected load increases in the Rail belt. A heat rate of
8000/Btu/kWh was adopted based on the alternative study
completed by Battelle.
The capital cost was estimated using the Battelle study
basis (Battele 1982, Vol. XXXI) and is listed in Table
0.18. A bid line item cost is shown on Table 21.
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( i i ) Fuel Costs
The avai 1 abi 1 i ty, use, and price of natura 1 gas are
presented in Appendix D-1. Known recoverab 1 e reserves of
natural gas in Alaska are located in the Cook Inlet area
near Anchorage and on A 1 ask a 1 s North S 1 ope at Prudhoe Bay.
Gas is presently being produced from the Cook Inlet area.
Some of the gas is committed under firm contract but
considerable quantities of gas remain uncommitted and could
be used for power generation. There are substantial
recoverable reserves on the North Slope that could be used
for power generation, but until a pipeline or electrical
transmission 1 i ne is constructed, the gas cannot be
utilized. Undiscovered gas resources are believed to exist
in the Cook In 1 et area and a 1 so in the Gulf of A 1 ask a where
no gas has been found to date.
Natural gas is produced and used in Alaska for heating,
electrical generation, liquified natural gas (LNG) export,
manufacture of ammonia/urea, reinjection in the recovery of
oil, and for field operations. Most of the production and
use (other than reinjection) currently takes p 1 ace in the
Cook Inlet area. Cook Inlet gas that has been injected (or
actually reinjected) is not consumed and is still available
for heating, electrical generation, or other uses. Gas used
in field operations is the gas consumed at the wells and
gathering areas to assist in the lifting and production of
oi 1 and gas.
LNG sales are for export· to Japan and the manufactured
ammonia/urea is exported to the lower forty-eight states.
Both uses of gas have been fairly constant in the past and
are expected to remain so in future years. Natural gas is
used for electrical generation by Chugach Electric
Association and Anchorage Municipal Light and Power. The
use of gas by both of these utilities has been increasing
to meet increases in electrical load and to replace
oil-fired generation. The military bases in the Anchorage
area, Elmendorf AFB and Fort Richardson, use gas to
generate electricity and to provide steam for heating. The
military gas use has been fairly constant in the past and
is expected to remain so in the future. The gas utility
sales are made principally by Enstar and are for space and
water heating and other uses by residential, commerical, and
industrial customers.
The future consumption of Cook Inlet gas depends on the gas
needs of the major users and their ability to contract for
needed supp 1 i es. S i nee there is a 1 imited quantity of
proven gas and estimated· undiscovered reserves in the Cook
Inlet area, reserves will be exhausted at some time in the
D-4-13
future. To estimate the quantity of Cook Inlet gas
available for electrical generation, the requirements and
prioritites of the major users are discussed in Appendix
0-1. Natural gas consumption for electric generation
represents only a small portion of the total Cook Inlet gas
consumption. It is projected that, by the year 2005, only
about 8 percent of the total cumulative consumption of
natural gas would have been for electric generation based
on the all thermal generation alternative for the Reference
Case.
If other gas consumption by retail sales, and ammonia and
gas conversion, continues at the projected rates, the
proven reserves plus the mean of the undiscovered reserves
estimates wi 11 be exhausted by 2010. The proven reserves
by themselves will be exhausted by 2000. This is true for
any of the world oil price forecast scenarios studied.
There is no single market price of gas in Alaska since a
well developed market does not exist. In addition, the
price of gas is affected by regulation vi a the Natural Gas
Policy Act of 1978 (NGPA) which specifies maximum wellhead
prices that producers can charge for various categories of
gas (some categories wi 11 be deregulated in 1985). There
are now some existing contracts for the sale/purchase of
Cook Inlet gas which specify wellhead prices, but since
there are no existing contracts for the sale of North Slope
gas, the North Slope wellhead price can only be estimated
based on an estimated final sales price and the estimated
costs to deliver the gas to market.
The wellhead price agreed on in the Enstar contracts is
$2.32/Mcf with an additional charge of $0.35/~lcf beginning
in 1986. Estimated severance taxes of $0.15/l'v1cf and a
fixed pipeline charge of about $0.30/Mcf for pipeline
delivery from Beluga to Anchorage are additional costs. The
pipeline charge of $0.30/Mcf will, of course, not be
incurred if the gas is used at Beluga to generate
electricity. Future prices (Jan. 1, 1984 and on) are to be
determined by escalating the wellhead price plus the demand
charge based on the price of #2 fuel oil in the year of
escalation versus the price on Janaury 1, 1983. If it were
assumed that the generating units were located at the
source of gas, the Jan. 1, 1983 price would be $2.47/Mcf,
as discussed in Appendix D-1.
Real escalation of the gas price is assumed to be dependent
on the escalation of world oil prices because the current
Enstar contract specifically provides for escalation of gas
prices based on the price of No.2 fuel oil on the Kenai
peninsula which is closely related to world oil prices.
Real escalation rates for the reference case are as
follows:
D-4-14
Period
1984
1985
1986-1988
1989-2010
2011-2020
2021-2030
2031-2051
Real
Escalation
Rate
%
-4.6
-4.7
0
3.0
2.5
1.5
1.0
Real escalation rates for the sensitivity oil price
forecasts are presented in Appendix 0-1.
(iii) Other Performance Characteristics
Annual operation and maintenance costs, along with a
pH. representative forced outage rates, are given in Table
0.18.
-
:~
{d) Gas-Turbine
Gas turbines are by far the main source of thermal power generating
resources in the Railbelt area at present. There are 720 MW of
installed gas turbines operating on natural gas in the Anchorage area
and approximately 210 MW of oil-fired gas turbines supplying the
Fairbanks area (see Table 0.14). Their low initial cost, simplicity of
construction and operation, and relatively short implementation lead
time have made them attractive as a Railbelt generating alternative.
The low-cost of gas in the Anchorage area has made this type of
generating facility cost-effective for the Anchorage load center.
( i) Capital Costs
( i i )
( i i i )
A unit size of 75 ·Mw was considered to be representative of
modern gas turbine plant addition in the Railbelt region.
Gas turbine plants can be built over a two year construc-
t·ion period and new plants have an average heat rate of
approximately 12,200 Btu/kWh. The capital costs were again
taken from the Battelle alternatives study.
Fuel Costs
Gas turbine units can be operated on oil as well as natural
gas. The market No. 2 oil is $6.23/MMBtu (1983) as dis-
cussed in Appendix 0-1. The real annual growth rates in
oil costs are also discussed in Appendix 0-1.
Other Performance Characteristics
Annu a 1 operation and maintenance costs and forced outage
rates are shown in Table 0.18.
D-4-15
(e) Diesel Power Generation
Most diesel plants in the Rai.lbelt today are on standby
status or are operated only for peak load service. Nearly
all the continuous duty units were retired in the past several
years because of high fuel prices. About 65 MW of diesel plant
capacity is currently available.
(i) Capital Costs
The high cost of diesel fuel and low capital cost make new
diesel plants most effective for emergency use or in remote
areas where small loads exist. A unit size of 10 MW was
selected as appropriate for this type of facility, large by
diesel engine standards. Units of up to 20 MW are under
construction in other areas. Potentially, capital cost
savings of 10-20 percent could be realized by going to the
larger units. However, these larger units operate at very
low speeds and may not have the reliability required if
used as a major alternative for Railbelt electrical power.
The capital cost was derived from the same source as given
in Table 0.18 (Battelle 1982, Vol. IV).
( i i) Fuel Costs
Diesel fuel costs and growth rates are the same as oil
costs for gas turbines.
(iii) Other Performance Characteristics
Annual operation and maintenance costs and the forced
outage rate are given in Table 0.18.
{f) Plan Formation and Evaluation
The four unit types and sizes discussed above were used to
formulate plans for meeting future Railbelt power generation
requirements. The purpose of this study was to formulate
appropriate plans for meeting the projected Railbelt demand on the
basis of economic preferences.
Economic evaluation of any Susitna basin development plan requires
that the impact of the plan on the cost of energy to the Rai 1 belt
area consumer be assessed on a systemwide basis. Since the
consumer is supplied by a large number of different generating
sources, it is necessary to determine the total Railbelt system
cost in each case to compare the various Susitna basin development
options.
The primary tool used for electric system an~ysis is the
mathematical model developed by the General Electric Company. The
model is commonly known as OGP 6 or Optimized Generation Planning
Model, Version 6. The general concept of the OGP program and its
rel at ionshi p with other computer models used in the power market
forecast is described in Exhibit B, Section 5.3. That section
D-4-16
-
deals specifically with the use of variables and assumptions in
all the models to assure that they are consistent throughout the
planning process. As explained in Section 4.6, the OGP 6 model
was used for the period 1993-2020. The load forecasts produced by
the RED model were extended from 2010 to 2020 using the average
annual growth for the period 2000 to 2010. The following
information is paraphrased from GE 1 iterature on the program.
(General Electric, 1983)
The OGP6 program was developed over ten years to combine the three
main elements of generation expansion planning (system reli-
ability, operating and investment costs) and automate generation
addition decision analysis. OGP6 will automatically develop
optimum generation expansion patterns in terms of economics, reli-
ability and operation.
The OGP6 program requires an extensive system of specific data to
perform its planning_ function. In developing an optimal plan, the
program considers tHe existing and committed units (planned and
under construction) available to the system and the characteris-
tics of these units including age, heat rate, size and outage
rates as the base generation plan. The program then considers the
given load forecast and operation criteria to determine the need
for additional system capacity based on given reliability cri-
teria. This determines 11 how much,. capacity to add and 11 When 11 it
should be installed. If a need exists during any monthly itera-
tion, the program will consider additions from a list of alterna-
tives and select the available unit best fitting the system needs.
Unit selection is made by computing production costs for the
system for each alternative included and comparing the results.
The unit resulting in the lowest system production costs is
selected and added to the system. Finally, an investment cost
analysis of the capital costs is completed to answer the question
of 11 What kind 11 of generation to add to the system.
The model is then further used to compare a4ternative plans for
meeting variable electrical demands, based on system reliability
and production costs for the study period.
The use of the output from the generation planning model is in
Section 4.6(a).
D-4-17
4.6 Without Susitna Plan
In order to analyze the economics of developing the Susitna Project, it
was necessary to analyze the costs of meeting the projected Alaska
Railbelt load forecast with and without the project. Thus, a plan
using the identified components was developed.
Using the generation planning model, a base case ''without Susitna" plan
was structured based on the Reference Case power market forecast. The
input to the model included:
-The reference case load forecast (Exhibit B Section 5.4.3);
-Fuel cost as specified above;
-Coal-fired steam and gas-fired combined-cycle and combustion turbine
units as future additions to the system;
-Costs and characteristics of future additions as specified above;
The existing system as specified and scheduled commitments listed in
Tables 0.14 and 0.15.
-Fuel escalation as specified above;
Economic parameters of 3 percent interest and 0 percent general in-
flation;
-Generation system reliability set to a loss of load probability of
one day in ten years. This is a probabilistic measure of the
inability of the generating system to meet projected load. One day
in ten years is a value generally accepted in the industry for.
planning generation systems.
It was found that the critical period for capacity addition to the
system. would be in the winter of 1992-1993. Until that time, the
existing system, given the additions of the planned intertie and the
planned units, appears to be sufficient to meet Railbelt demands.
Given this information, the period of plan development using the model
was set as 1993-2020.
In early years (1993-1996), the economically preferred units are those
which generate base load power. After 400MW of this type of power in
the form of coal units are added, the preference switches to gas
turbine units which are used to meet seasonal (winter) peak months and
daily peaking needs. During the later years, the generating system
needs capacity to meet target reliability rather than to generate power
continually and adds a mix of coal-fired steam, combined cycle, and gas
turbine units.
D-4-18
The following was established as the non-Susitna Railbelt base plan
(see Figure 0.9):
(a) System as of January 1993
Coal-fired steam: 59 MW
Natural gas GT: 452 MW
Oil GT: 137 MW
Diesel: 21 MW
Natural gas cc: 317 MW """ Hydropower: 143 MW
Total (including committed conditions): 1129 MW -
(b) System Additions
Gas-Fired Gas-Fired
Gas Turbine Combined Cycle Coal Fired Unit
Year (MW) (MW) ~MW)
I""" 1993 1 X 200 (Beluga)
1994 1 X 70
1995 1 X 70
1996 1 X 200 (Beluga)
1997 1 X 70
1998 1 X 70
F" 1999
2000
2001
2002 1 X 70
2003 1 X 70
2004
2005 1 x 200 (Nenana)
~"""' 2006 1 X 70
2007
2008 1 X 70
2009
~"' 2010 1 X 200 (Nenana)
2011 1 X 70
2012 1 X 200 (Beluga)
~ 2013 1 X 200
2014
2015
..... 2016
2017
2018
2019 1 X 70
Total 840 200 loOO
r
D-4-19
(c) System as of 2020
Coal-fired steam:
Natural gas GT:
Oi 1 GT:
Diesel:
Natural gas CC:
Hydropower:
1000 MW
840 MW
0 MW
0 MW
200 MW
143 MW
Total (accounting for retirements and additions) 2183 MW
There is one particularly important assumption underlying the plan.
The costs associated with the Beluga development are based on the
opening of that coal field for commercial development. That
development is not a certainty now and is somewhat beyond the control
of the state, si nee the rights are in the hands of private interests.
Even if the seam is mined for export, there will be environmental
problems to overcome. The greatest problem will be the availability of
cooling water for the units. The problem could be solved in the
11 Worst 11 case by using the sea water from Cook Inlet as cooling water;
however, this solution would add significantly to project costs.
The thermal plan described above has been selected as representative of
the generation scenario that would be pursued in the absence of
Susitna.
4.7-Economic Evaluation
This section provides a discussion of the key economic parameters used
in the study and develops the net economic benefits stemming from the
Susitna Hydroelectric Project. Section 4.7 (a) deals with those
economic principles relevant to the analysis of net economic benefits
and develops inflation and discount rates.
Section 4. 7 (b) presents the net economic benefits of the proposed
hydroelectric power investments compared with this thermal ~ternative.
These are measured in terms of present-value differences between
benefits and costs. Recognizing that even the most careful estimates
will be surrounded by a degree of uncertainty, particularly in regard
to world oi 1 prices, the benefit-cost assessments were subjected to
sensitivity analyses as described in Section 4.8 (oil prices) and
Section 4.9 (other variables),
D-4-20
-
..... ;
'
""" I
I
-
(a) Economic Principles and Parameters
( i ) Economic Principles -Concept of Net Economic Benefits
A necessary condition for maximizing the increase in state
income and economic growth is the se 1 ect ion of pub 1 i c or
private investments with the highest present valued net
benefits to the state. In the context of Alaskan electric
power investments, the net benefits are defined as the dif-
ference between the costs of optimal Susitna-inclusive and
Susitna-exclusive (all thermal) generation plans.
The energy costs of power generation are initially measured
in terms of opportunity values or shadow prices which may
differ from accounting or market prices currently prevail-
ing in the state. The concept and use of opportunity val-
ues is fundamental to the optimal allocation of finite pub-
lic resources. Energy investment decisions should not be
made solely on the basis of accounting prices in the state
if the international value of traded energy commodities
such as coal and gas diverge from local market prices. The
opportunity value represents the value of the resource if
disposed of in the most economically attractive alternative
manner. In the case of oil, gas, and coal, it would rep-
resent the sale of the Alaskan commodities on the world
market, compared to their consumption in state. The world
price must be adjusted through a net-back exercise which
accounts for the costs of getting the resource to world
markets.
The choice of a time horizon is also crucial. If a short-
term planning period is selected, the investment rankings
and choices will differ markedly from those obtained
through a long-term perspective. In other words, the
benefit-cost analysis would point to different generation
expansion plans depending on the selected planning period.
A short-run optimization of state income would, at best,
allow only a moderate growth in fixed capital investment;
at worst, it would lead to underinvestment in not only the
energy sector but also in other infrastructure fac i1 it i es
such as roads, airports, hospitals, schools, and communica-
tions.
It therefore follows that the Susitna project, like other
Alaskan investments, should be appraised on the basis of
long-run optimization, where the long run is defined as the
expected economic life of the facility. For hydroelectric
projects, this service life is typically 50 years or more.
The costs of a Susitna-inclusive generation plan have
therefore been compared with the costs of the next-best
D-4-21
alternative wh4ch is the all-thermal generation plan and
assessed over
2051, using
seen ari os and
energy.
a planning period extending from 1982 to
internally consistent sets of economic
appropriate opportunity values of Alaskan
Throughout the analysis, all costs and prices are expressed
in real (inflation-adjusted) terms using January 1982 dol-
lars except for fuel which is expressed in January 1983
dollars. Hence, the results of the economic calculations
are not sensitive to modified assumptions concerning the
rates of general price inflation. In contrast, the
financial and market analyses conducted in nominal
(inflation-inclusive) terms will be influenced by the rate
of general price inflation from 1982 to 2021.
(ii) Price Inflation and Discount Rates
-General Price Inflation
Despite the fact that price levels are generally higher
in Alaska than in the lower 48 states, there is little
difference in the comparative rates of price changes;
i.e., price inflation. Between 1970 and 1978, for ex-
ample, the U.S. and Anchorage consumer price indexes rose
at annual rates. of 6.9 and 7.1 percent, respectively.
From 1977 to 1978, the differential was even smaller; the
consumer prices increased by 8.8 percent and 8. 7 percent
in the U.S. and Anchorage, respectively (U.S. Department
of Labor).
Forecasts of Alaskan prices extend only to 1986 (Alaska
Department of Commerce and Economic Development 1980).
These indicate an average rate of increase of 8. 7 percent
from 1980 to 1986. For the longer period between 1986
and 2051, it is assumed that Alaskan prices will escalate
at ·the overall U.S. rate, or at 5 to 7 percent compounded
annually. The average annual rate of price inflation is
therefore about 7 percent between 1982 and 2051. Si nee
this is consistent with long-term forecasts of the CPI
advanced by leading economic consulting organizations,
(Data Resources 1980; Wharton Econometric Forecasting
Associates 1981) 7 percent has been adopted as the study
value. This analysis could have been done with the GNP
deflator in lieu of the CPI. Results would be essential-
ly the same.
Discount Rates
Discount rates are required to compare and aggregate cash
flows occurring in different time periods of the planning
D-4-22
1-:-:;--
-
-
-
horizon. In essence, the discount rate is a weighting
factor reflecting that a dollar received tomorrow is
worth less than a dollar received today. This holds even
in an inflation-free economy as long as the productivity
of capital is positive. In other words, the value of a
dollar received in the future must be deflated to reflect
its earning power foregone by not receiving it today.
The use of discount rates extends to both real dollar
(economic) and escalated dollar (financial) evaluations,
with corresponding inflation-adjusted (real) and infl a-
t ion-inclusive (nominal) values.
Real Discount and Interest Rates
Several approaches have been suggested for estimating
the real discount rate applicable to public projects
(or to private projects from the public perspective).
Three common alternatives include:
the social opportunity cost (SOC) rate;
the social time preference (STP) rate; and
the government 1 s real borrowing rate or the real
cost of debt capital (Baumel 1968; Mi shan 1975;
Prest and Turvey 1965).
The SOC rate measures the real social return (before
taxes and subsidies) that capital funds could earn in
alternative investments. If, for example, the marginal
capital investment in Alaska has an estimated social
yield of X percent, the Susitna Hydroelectric Project
should be appraised using the X percent measure of
11 foregone returns 11 or opportunity costs. A shortcoming
of this concept is the difficulty inherent in determin-
ing the nature and yields of the foregone investments.
The STP rate measures society 1 s preferences for allo-
cating resources between investment and consumption.
This approach is also fraught with practical measure-
ment difficulties since a wide range of STP rates may
be inferred from market interest rates and socially-'
desirable rates of investment.
A subset of STP rates used in project ev al uat ions is
the owner 1 s real cost of borrowing; that is, the real
cost of debt capital. This industrial or government
borrowing rate may be readily measured and provides a
starting point for determining project-specific dis-
count rates. For example, long-term industrial bond
D-4-23
rates have averaged about 2 to 3 percent in the U.S. in
real (inf1ation-adjusted) terms (Data Resources 1980;
U. S. Department of Commerce). Forecasts of real in-
terest rates show average values of about 3 percent and
2 percent in the periods of 1985 to 1990 and 1990 to
2000, respectively. The U.S. Nuclear Regulatory
Commission has also analyzed the choice of discount
rates for investment appraisal in the electric utility
i nd ustr y and has recommended a 3 percent real rate
(Roberts 1980). Therefore, a real rate of 3 percent has
been adopted as the base case discount and interest
rate for the period 1982 to 2051.
Nominal Discount and Interest Rates
The nominal discount and interest rates are derived
from the real values and the anticipated rate of gen-
eral price inflation. Given a 3 percent real discount
rate and a 7 percent rate of price inflation, the nomi-
nal discount rate is determined as 10.2 percent or
about 10 percent*.
Capital Cost Escalation
Based on present trends in construction costs, no real
capital cost escalation has been assumed for either the
hydro or the thermal units.
(b) Analysis of Net Economic Benefits
(i) Modeling Approach
Using the economic parameters discussed in the previous
section and data relating to the electrical energy
generation alternatives available for the Railbelt, an
analysis was made comparing the costs of electrical
energy production with and without the Susitna project.
The method of comparing the "with 11 and "without"
Susitna alternative generation scenarios is based on
the long-term present worth (PW) of total system costs.
The planning model determines the total production
costs of alternative plans on a year-by-year basis.
These total costs for the period of modeling include
all costs of fuel and operation and maintenance (O&M)
for all generating units included as part of the
system, and the annualized investment costs of any
generating and system transmission plants added during
the period of 1993 to 2020. Fuel price real cost
escalation was included in the analysis at the rates
specified above for the Reference Case.
* (1 +the nominal rate) = (1 +the real rate) x (1 +the inflation
rate) = 1. 03 x 1.07, or 1.102
D-4-24
-
.....
-
-
( i i )
-
Factors which contribute to the ultimate consumer cost of
power but which are not included as input to this model are
investment costs for all generation plants in service prior
to 1993 investment, cost of the transmission and
distr'ibution facilities already in service, and
administrative costs of utilities. These costs are common
to all scenarios-and therefore have been omitted from the
study.
In order to aggregate and compare costs on a significantly
long-term basis, annual costs have been aggregated for the
period 1993 to 2051. Costs have been computed as the sum
of two components and converted to a 1982 PW. The first
component is the 1982 PW of cost output from the first 28
years of model simulation from 1993 to 2020. The second
component is the estimated PW of long-term system costs
from 2021 to 2051 .
For an assumed set of economic parameters on a particular
generation alternative, the first element of the PW value
represents the amount of cash (not including those costs
noted above) needed in 1982 to meet electrical production
needs in the Railbelt for the period 1993 to 2020. The
second element of the aggregated PW value is the long-term
(2021 to 2051) PW estimate of production costs. In consid-
ering the value to the system of the addition of a hydro-
electric power plant which has a useful life of approxi-
mately 50 years, the ·shorter study period would be inade-
quate. A hydroelectric plant added in 1993 or 2002 would
accrue benefits for only 28 or 19 years, respectively,
using an investment horizon that extends to 2020. However,
to model the system for an additional 31 years, it would be
necessary to develop future load forecasts and generation
alternatives which are beyond the extent of normal
projections. For this reason, it has been assumed that the
production costs for the final study year (2020) would
s_imply recur for an additional 31 years, however they would
be adjusted to take into account real fuel price
escalation, and the PW of these was added to the 28-year PW
(1993 to 2020) to establish the long-term cost differences
between alternative methods of power generation.
Reference Case Analysis
-Pattern of Investments 11 With 11 and 11 Without 11 Susitna
The Reference Case comparison of the 11 With 11 and 11 Without 11
Susitna plans is based on an assessment of the PW
production costs for the period 1993 to 2051, the
Reference Case values for the energy demand and load
forecast, fuel prices, fuel price escalation rates, and
capital costs.
D-4-25
The with Susitna case calls for Watana to come on line in 1993 to
meet system capacity requirements. Although the initial
installation at Watana will be 1020 MW only about 520 MW will be
dependable during the period Watana operates on base before Devil
Canyon comes on line in 2002, as discussed in Exhibit B, Sections
3. 7 and 4. 3.
The second stage of Susitna, the Devil Canyon project, is scheduled
to come on line in 2002 with an installed capacity of 600 MW. The
combined operation of Watana on peak and Devil Canyon on base will
have a dependable capacity of 1270 MW in 2020 under flow regime C
as discussed in Exhibit B, Section 4.
In addition to the Susitna projects, the with-Susitna plan calls
for the addition of a 70-MW gas turbine unit in each of the
following years, 2001, 2012, 2014, 2015, 2016, 2017, and2019.
Also a 200-MW gas-fired combined cycle unit would be installed in
2020. The without Susitna plan is discussed in Section 4.5.
-Reference Case Net Economic Benefits
The economic comparison of these plans is shown in Table
D.22. During the 1993 to 2020 study period, the 1982 PW
cost for the Susitna plan is $3.4 billion. The annual production
cost in 2020 is $0.3 billion. The PW of this level cost, which
remains virtually constant except for fuel cost escalation for a
period extending to the end of the life of the Devil Canyon plant
(2051), is $2.1 billion. The resulting total present worth of the
with-Susitna plan is $5.5 billion in 1982 dollars.
The non-Susitna plan (Section 4.5) which was modeled has
a 1982 PW cost of $3.9 billion for the 1993 to 2020 period with a
2020 annual cost of $0.5 billion. The total long-term cost has a
PW of $7.3 billion. Therefore, the net economic benefit of
adopting the Susitna plan is $1.8 billion. In other words, the
D-4-26
-
present value cost difference between the Susitna plan
and the expansion plan based on thermal plant addition is
$1.8 billion in 1982 dollars.
It is noted that the magnitude of net economic benefits
($1.8 billion) is not particularly sensitive to
alternative assumptions concerning the overall rate of
price inflation as measured by the Consumer Price Index.
The analysis has been carried out in real (inflation-
adjusted) terms. Therefore, the present valued cost
savings will remain close to $1.8 billion regardless of
CPI movements, as long as the real (inflation-adjusted)
discount and interest rates are maintained at 3 percent.
The Susitna project 1 s internal rate of return (IRR),
i.e., the real (inflation-adjusted) discount rate at
which the with-Susitna plan has zero net economic bene-
fits, or the discount rate at which the costs of the
with-Susitna and the alternative plans have equal costs,
has also been determined. The IRR is about 5.0 percent
in real terms, and 10.6 percent in nominal (inflation-
inclusive) terms. Therefore, the investment in Susitna
would significantly exceed the 5 percent nominal rate of
return 11 test 11 proposed by the State of Alaska in cases
where state appropriations may be involved.*
*See Alaska legislation A5 44.83.670
D-4-27
The generation planning analysis has implicitly assumed
that all environmental costs for both the Susitna and
the non-Susitna plans have been casted however there
are factors relating to the non-Susitna plans which may
increase the net economic benefits to the project. To
the extent that the thermal generation expansion plan
may carry greater environmental costs than the Susitna
plan, the economic cost savings from the Susitna
project may be understated. Due to the greater level
of study of the Susitna project, costs for mitigation
plans were included. This may not be the case with the
coal alternative which may underestimate environmental
costs. These differences or added costs cannot be
quantified at this stage of study on the coal
alternative.
The generation planning analysis also did not assume
any restrictions on the supply of natural gas. As
stated in Section 4.5(c) Cook Inlet proven reserves
wi 11 be exhausted by the year 2000, and proven reserves
plus the mean of the undiscovered reserves estimates
wi 11 be exhausted by 2010. Under the Reference Case
without Susitna expansion plan, gas consumption in 2020
would be about 8000 Mcf and total gas consumption for
the period from 2020 to 2051 after proven plus
undiscovered reserves are exhausted waul d be 210,000
Mcf or about 3. 8 percent of the 1982 est imte of proven
plus undiscovered reserves. Since this value is
rel at i vel y small, errors in the estimate of the
reserves and in the consumption rates for other gas
uses could easily affect the date by which gas would be
exhausted for electrical generation. Also over the
planning horizon to 2051 North Slope gas will probably
become available to the Railbelt market, albeit at a
higher price than Cook Inlet gas.
Since the generation planning analysis did not assume
any supply restrictions of natural gas nor any price
increase for substitute gas becoming available, the
analysis could underestimate the benefits available to
the Sus itn a project.
D-4-28
-
4.8 -Sensitivity to World Oil Price Forecasts
Assumptions regarding future world oil prices impact the
forecasts of electric power demand for the railbelt area. This
relationship is discussed in detail in Exhibit B, Section 5.4.
Table 0.23 contains a summary of the load forecasts considered.
A sensitivity analysis was performed to identify the effect of
world oil price forecasts lower and higher than the reference
case. Sensitivity analyses were performed for the ORI, DOR-mean
and -2 percent load forecasts. The fuel price escalation rates
which correspond to these forecasts are discussed in Appendix
D-1. Table 0.24 depicts the results of the sensitivity analysis.
As can been seen from Table 0.24, the DOR mean case, with
negative net benefits or a net cost of $85 million is
approximately a break-even case in which the costs of the with
Susitna plan are about equal to the costs of the without Susitna
plan. Under the -2 percent case, the without Susitna plan is
clearly more q.ttractive, having a present worth about $1.9
billion less than the with Susitna plan. The DRI plan generates
net benefits of $1.82 billion or about the same those of the
Reference Case.
In performing the above analysis, it was assumed that the initial
operating dates of Watana and Devil Canyon would be the same as
under the reference case, or 1993 and 2002 respectively. A study
of the expansion programs for the sensitivity case showed that
new capacity, that could be provided by Watana, would be required
in 1993 in ~l cases and that Devil Canyon could be delayed by up
to 5 years under the -2 percent case. However, sensitivity
analyses showed that delaying Devil Canyon would not
significantly affect the results of the economic analysis.
D-4-29
4.9 -Other Sensitivity Assessments
Rather than relying on a single point comparison to assess the
net benefit of the Susitna project, a sensitivity analysis was
carried out to identify the impact of a change in assumptions on
the results. The analysis was directed at the following
variables other than those related to the world price of oil.
Variable, Reference Table
Discount Rate (%), Table 0.25
Watana Cap. Costs ($x106), Table
Base fuel price ($/MMBtu), Table
Coal -Nenana
-Beluga
Natural Gas
Real Fuel Escalation
'
D-4-30
Reference Case
Value
3.0
0.26 3597
0.27
1.72
1.86
2.47
Escalation
to 2051
Sensitivity
Values
2, 5
2917, 4316
1. 38, 2.06
1.49, 2.23
1. 98, 2. 96
Escalation
to 2020 only
-
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.-
Tables D.25 to D.27 depict the results of the sensitivity analysis for
the variables except for real fuel· escalation. Net benefits for the
-Reference Case would be reduced to about $1.0 billion from $1.8 billion
if no real fuel price escalation is applied. Table D.28 summarizes the
net economic benefits of the Susitna project associated with each
sensitivity test. The net benefits have been compared using indexes
relative to the Reference Case value ($1.827 billion) which is set to
100.
As can be seen from Table D.28 the economic analysis is most sensitive
to the forecast of world oil prices and the corresponding power market
forecast and related fuel price escalation rates. As stated in Section
4.8 under certain forecasts the with Susitna plan is marginal or
unattractive when compared to the without Susitna plan.
The analysis is about equally sensitive to the other three variables
mentioned above, discount rate, Watana capital cost, and fuel price as
can be seen on Table D.28. Over the range of values given these
variables, the with Susitna plan maintains positive net benefits over
the without Susitna plan.
In addition to the above sensitivity analyses, the sensitivity of the
analysis to a delay in the construction of the Devil Canyon project and
to a change in the loss of load probability was evaluated. Changes in
these assumptions had no significant affect on the results of the
economic analysis.
4.10 -Battelle Railbelt Alternatives Study
The Office of the Governor, State of Alaska, Division of Policy
Development and Planning, and the Governor's Policy Review Committee
contracted with Battelle Pacific Northwest Laboratories. to investigate
potential strategies for future electric power development in the
Railbelt region of Alaska. This section presents a summary of final
results of the Railbelt Electric Power Alternatives Study.
The overall approach taken on this study involved five major tasks or
activities that led to the results of the project, a comparative eval-
uation of electric energy plans for the Railbelt. The five tasks con-
ducted as part of the study evaluated the following aspects of elec-
trical power planning:
- f u e 1 sup p 1 y and pr i c e an a 1 ys i s
-electrical demand forecasts
-generation and conservation alternatives evaluation
-development of electric energy themes or 11 futures 11 available to the
Rail belt
-systems integration/evaluation of electric energy plans.
Note that while each of the tasks contributed data and information to
the final results of the project, they also developed important results
that are of interest independently of the final results of this pro-
ject. Output from the first three tasks contributed directly as input
to analysis of the Susitna project presented in this Exhibit and in
D-4-31
Exhibit B. The results of the fourth task is presented in this
subsection.
The first task evaluated the price and availability of fuels that
either directly could be used as fuels for electrical generation or
indirectly could compete with electricity in end-use applications sue
as space or water heating.
The second task, electrical demand forecasts, was required for two
reasons. The amount of electricity demanded determines both the size
of generating units that can be included in the system and the number
of generating units or the total generating capacity required. The
forecast used from this study in the Susitna feasibility study is
presented in Exhibit B.
The third task's purpose was to identify electric power generation and
conservation alternatives potentially applicable to the Railbelt region
and to examine their feasib-rlity, considering several factors. These
factors include cost of power, environmental and socioeconomic effects,
and public acceptance. Alternatives appearing to be best suited for
future application to the region were then subjected to additional
in-depth study and were incorporated into one or more of the electric
energy plans.
The fourth task, the development of electric energy themes or plans,
presents possible electric energy "futures" for the Railbelt. These
plans were developed both to encompass the full range of viable alter-
natives available to the region and to provide a direct comparison of
those futures currently receiving the greatest interest within the
Railbelt. A plan is defined by a set of electrical generation and
conservation alternatives sufficient to meet the peak demand and annual
energy requirements over the time horizon of the study. The time
horizon of the study is the 1981-2050 time period. The set of alterna-
tives used in each plan was drawn from the alternatives selected for
further study in the analysis of alternatives task.
As the name implies, the purpose of the fifth task, the system
integration/comparative analysis task, was to integrate the results of
the other tasks and to produce a comparative evaluation of the electric
energy plans. This comparative evaluation basically is a description
of the implications and impacts of each electric energy plan. The
major criteria used to evaluate and compare the plans are cost of
power, environmental and socioeconomic impacts, as· well as the
susceptibility of the plan to future uncertainty in assumptions and
parameter estimates.
This summary focuses on the third task: alternatives evaluation.
(a) Alternatives Evaluation
The companion Battelle study reviewed a much wider range of
generating alternatives than the Susitna feasibility study. The
following text summarizes the process followed and results of
selecting techno1ogies for developing energy plans.
D-4-32
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. Selecting generating alternatives for the Rail belt electric energy
plans proceeded in three stages. First, a broad set of candidate
technologies was identified, constrained only by the availability
of the technology for commercial service prior to the year 2000.
After a study was prepared on the candidate technologies, they
were evaluated based on several technical, economic, environmental
and institutional considerations. Using the results of that
study, a subset of more promising technologies was subsequently
identified. Finally, prototypical generating facilities (specific
sites in the case of hydropower) were identified for further
development of the data required to support the analysis of
electric energy plans.
A wide variety of energy resources capable of being applied to the
generation of electricity is found in the Railbelt. Resources
currently used include coal, natural gas, petroleum-derived li-
quids and hydropower. Energy resources currently not being used
but which could be developed for producing electric power within
the planning period of this study include peat, wind power, solar
energy, municipal refuse-derived fuels, and wood waste. Light
water reactor fuel is manufactured in the lower 48 states and
could be readily supplied to the Railbelt, if desired. Candidate
electric generating technologies using these resources and most
1 ikely to be avail able for commercial order prior to the year 2000
are listed in Table 0.29. The 37 generation technologies and com-
binations of fuel conversion-generation technologies shown in the
table comprised the candidate set of technologies selected for
add it i anal study. Further discussion of the se 1 ect ion process and
technologies rejected from consideration at this stage are pro-
vided in the Battelle Electric Power Alternatives Study (Battelle
1982, Vol. IV).
Selection of generation alternatives was based on the followinng
considerations:
-the availability and cost of energy resources;
the likely effects of minimum plant size and operational charac-
teristics on system operation;
the economic performance of the various technologies as re-
flected in estimated busbar power costs;
-pub 1 i c acceptance, both as reflected in the framework of e 1 ec-
tric energy plans within which the selection was conducted and
as impacting specific technologies; and
-ongoing Railbelt electric power planning activities.
From this analysis, described more fully in the Battelle Electric
Power Alternatives Study (Battelle 1982, Vol. IV), 13· generating
D-4-33
technologies were selected for possible 4nclusion in the Railbelt
electr4c power plans. For each nonhydro technology, a
prototypical plant was defined to facilitate further development
of the needed information. For the hydro technologies, promising
sites were selected for further study. These prototypical plants
and sites constitute the generating alternatives selected for
consideration in the Railbelt electric energy plans. In the
following paragraphs, each of the 13 preferred technologies is
briefly described, along with some of the principal reasons for
its selection. Also described are the prototypical plants and
hydro sites selected for further study.
(i) Coal-Fired Steam-Electric Plants
Coal-fired steam-electric generation was selected for con-
sideration in Railbelt electric energy plans because it is
a commercially mature and economical technology that poten-
tially is capable of supplying all of the Railbelt 1 S base-
load electric power needs for the indefinite future. An
abundance of coal in the Railbelt should be mineable at
costs allowing electricity production to be economically
competitive with all but the most favorable alternatives
throughout the planning period. Coal may be available
from both the Beluga and Nenana fields. However, the
Beluga fields are not yet opened and their opening is as
yet uncertain. Should the fields not be mined for commer-
cial use, the coal may not be competitive for Railbelt
electrical power. Should the fields not open, the existing
Nenana coal fields would need to supply an increased ton-
nage at higher prices.
The extremely low sulfur content of Railbelt coal and the
availability of commercially tested oxides of sulfur
(SOx) and particulate control devices will facilitate
control of these emissions to levels mandated by the Clean
Air Act. Principal concerns of this technology are envi-
ronmental impacts of coal mining, possible ambient air-
quality effects of residual SOx, oxides of nitrogen
(NOx) and particulate emissions, long-term atmospheric
buildup of C02 (common to all combustion-based tech~olo
gies) and the long-term susceptibility of busbar power
costs to inflation.
Two prototypical facilities were chosen for in-depth study:
in the Beluga area, a 200-MW plant that uses coal mined
from the Chutna Field, and at Nenana a plant of similar
capacity that uses coal delivered from the Nenana field at
Healy by Alaska Railroad.
(ii) Coal Gasifier-Combined-Cycle Plants
These plants consist of coal gasifiers producing a synthe-
tic gas that is burned in combustion turbines that drive
D-4-34
-
electric generators. Heat-recovery boilers use turbine
exhaust heat to raise steam to drive a steam turbine-
generator.
These plants, when commercially available, should allow
continued use of Alaskan coal resources at costs comparable
to conventional coal steam-electric plants, while providing
environmental and operational advantages compared to con-
ventional plants. Environmental advantages include less
waste-heat rejection and water consumption per unit of out-
put due to higher plant efficiency. Better control of
NOx, SOx and particulate emission is also afforded.
From an operational standpoint, these plants offer a poten-
tial for load-following duty. (However, much of the
existing Railbelt capacity most likely will be available
for intermediate and peak loading during the planning
period.) Because of superior plant efficiencies, coal
gasifer -combined-cycle plants should be somewhat less
susceptible to inflation fuel cost than conventional
steam-electri'c plants. Principal concerns relative to
these plants include land disturbance resulting from mining
of coal, C02 production, and uncertainties in plant per-
formance and capital cost due to the current state of tech-
nology development.
A prototypic9.l plant was selected for in-depth analysis
(Battelle 1982, VOl. XVII). This 200 MW plant is located
in the Beluga area and uses coal mined from the Chuitna
Field. The plant would use oxygen-blown gasifiers of Shell
design, producing a medium-Btu synthesis gas for combustion
turbine firing. The plant would be capable of
1 oad-following operation. ,
(iii) Natural Gas Combustion Turbines
Although of relatively low efficiency, natural gas
combustion turbines serve well as peaking units in a system
dominated by steam-electric plants. The short construction
1 ead times char acteri st i c of these units also offer
opportunities to meet unexpected or temporary increases in
demand. Except for production of C02, and potential
local noise prob,lems, these units produce minimal
environmental impact. The principal economoc conern is the
sensitivity of these plants to esalating fuel costs.
Because the costs and performance of combustion turbines
are relatively well understood, no prototype was selected
for in-depth study.
D-4-35
(iv) Natural-Gas -Combined-Cycle Plants
Natural gas -combined-cycle plants were selected for
consideration because of the current availability of low-
cost natural gas in the Cook Inlet area and the likely
future availability of North Slope supplies in the Railbelt
(although at prices higher than those currently experi-
enced). Combined-cycle plants are the most economical and
environmentally benign method currently available to gener-
ate electric base-load or mid-range peaking power using
natural gas. The principal economic concern is the sensi-
tivity of busbar power costs to the possible substantial
rise in natural gas costs. The principal environmental
concern is C02 production and possible local noise prob-
1 ems.
A nominal 200 MW prototypical plant was selected for fur-
ther study. The plant is located in the Beluga area and
uses Cook Inlet natural gas (Battelle 1982, Vol. XIII).
(v) Natural Gas Fuel-Cell Stations
These plants would consist of a fuel conditioner to convert
natural gas to hydrogen and C02~ phosphoric acid fuel
cells to produce de power by electrolytic oxidation of
hydrogen~ and a power conditioner to convert the de power
output of the fuel cells to ac power. Fuel-cell stations
most likely would be relatively small and sited near load
centers.
Natural gas fuel-cell stations were considered in the
Railbelt electric energy plans primarily because of the
apparent peaking duty advantages they may offer over
combustion turbines for systems relying upon coal or
natural-gas fired base and intermediate load units. Plant
efficiencies most likely will be far superior to combustion
turbines and relatively unaffected by partial power
operation. Capital investment costs most likely will be
comparable to that of combustion turbines. These costs and
performance characteristics should lead to significant
reduction in busbar power costs, and greater protection
from escalation of natural gas prices compared to
combustion turbines. Construction lead time should be
comparable to those of combustion turbines. Because
environmental effects most likely will be limited to C02
production~ load-center siting will be possible and
transmission losses and costs consequently will be reduced.
Since the fuel cell is still an e11erging technology with
commercial availability scheduled for the late 1980 1 S, it
was not chosen as a major block in the Railbelt generation
future. No prototypical plant was selected for further
study.
0-4-36
r ~,
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~.·
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(vi) Natural-Gas -Fuel-Cell -Combined-Cycle
(vii)
These plants would consist of a fuel conditioner that con-
verts natural gas to hydrogen and carbon dioxide, molten
carbonate fuel cells that produce de power by electrolytic
oxidation of hydrogen, and heat recovery boilers that use
waste heat from the fuel cells to raise steam for driving a
steam turbine-generator. A power conditioner converts the
de fuel cell power to ac power for distribution. If they
attain cornnercial maturity as envisioned, fuel-cell
combined-cycle plants should demonstrate a substantial
improvement in efficiency over conventional, combustion
turbine-combined-cycle plants. Although the potential
capital costs of these plants currently are not well known,
the reduction in fuel consumption promised by the fore-
casted heat rate of these plants would result in a baseload
plant less sensitive to inflating fuel costs and less
consumptive of limited fuel supplies than conventional
combined-cycle plants. An added advantage is the likely
absence of significant environmental impact. Operation-
ally, these plants .appear to be less flexible than conven-
tional combined-cycle plants and will be limited to base-
load operation.
Because of the early stages of development of these plants,
additional study within the scope of ~his project was be-
lieved to yield little additional useful information. Con-
sequently, no pro~otypical plant was selected for study.
Conventional Hydroelectric Plants
Substantial hydro resources are present in the Railbelt
region. Much of this could be developed with conventional
(approximately 15 MW installed capacity or larger) hydro-
electric plants. The data and alternatives considered were
the same as those discussed in Section 3 of this exhibit.
(viii) Small-Scale Hydroelectric Plants
Small-scale hydroelectric plants include facilities having
rated capacity of 0.1 Mlrl to 15 MW. Several small-scale
hydro sites have been identified in the Railbelt and two
currently undeveloped sites (Al 1 ison and Grant Lake) have
been subject to recent feasibility studies. Although
typically not as economically favorable ·as conventional
hydro because of higher capital costs, small-scale hydro
affords similar long-term protect ion from escalation of
costs.
D-4-37
Two small-scale hydroelectric projects were selected for
consideration in Railbelt electric energy plans: the
Allison Hydroelectric Project at Allison Lake near Valdez
and the Grant Lake Hydroelectric Project at Grant Lake
north of Seward. These two projects appear to have
relatively favorable economics compared with other small
hydroelectric sites, and relatively minor environmental
impact.
(ix) Microhydroelectric Systems
Microhydroelectric systems are hydroelectric installations
rated at 100 kW or less. They typically consist of a
water-intake structure, a penstock, and turbine-generator.
Reservoirs often are not provided and the units operate on
run-of-the-stream.
Microhydroelectric systems were chosen for analysis because
of public interest in these systems, their renewable char-
acter and potentially modest environmental impact. Con-
crete information on power production costs typical of
these facilities was not available when the preferred tech-
nologies were selected. Further analysis indicated, how-
ever, that few microhydroelectric reservoirs could be de-
veloped for less than 80 mills/kWh, and even at consider-
ably higher rates, the contribution of this resource would
likely be minor. Because of the very limited potential of
this technology in the Railbelt, it was subsequently
dropped from consideration. However, installations at
certain sites (for example, residences or other facilities
remote from distribution systems) may be justified.
(x) Large Wind Energy Conversion Systems
Large wind energy conversion systems consist of machines of
100 kW capacity and greater. These systems typically would
be installed in clusters in areas of favorable wind re-
source and would be operated as central generating units.
Operation is in the fuel-saving mode because of the inter-
mittent nature of the wind resource.
Large wind energy conversion systems were selected for
consideration in Railbelt electric energy plants for
several reasons. Several areas of excellent wind resource
have been identfied in the Railbelt, notably in the Isabell
Pass area of the Alaska Range, and in coastal locations.
The winds of these areas are strongest during fall, winter
and spring months, coinciding with the winter-peaking elec-
tric load of the Railbelt. Furthermore, developing hydro-
electric projects in the Railbelt would prove complementary
0-4-38
!''>--
~I
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II"*
-f
to wind energy systems. Surplus wind-generated electricity
could be readily "stored" by reducing hydro generation.
Hydro operation could be used to rapidly pick up load
during periods of wind insufficiency. Wind machines could
provide additional energy, whereas excess installed hydro
capacity could provide capacity credit. Finally, wind
systems have few adverse environmental effects with the
exception of their visual presence and appear to have
widespread public support.
A prototypical large wind energy conversion system was
se 1 ected for further study. The prototype consisted of a
wind farm located in the Isabell Pass area and was com-
prised of ten 2.5 I~W rated capacity, Boeing MOD-2, horizon-
tal axis wind turbines (Battelle 1982, Vol. XVI).
(xi) Small Wind Energy Conversion Systems
Small wind energy conversion systems are small wind tur-
bines of either horizontal or vertical axis, design rated
at less than 100 kW capacity. Machines of this size would
generally be dispersed in individual households and in
commercial establishments.
Small wind energy conversion systems were selected·for
consideration in Railbelt electric energy plans for several
reasons. Within the Railbelt, selected areas have been
identified as having superior wind resource potential and
the resource is renewable. Also, power produced by these
systems appeared possibly to be marginally economically
competitive with generating facilities currently operating
in the Railbelt. However, these machines operate in a
fue 1-saver mode because of the intermittent nature of the
wind resource and because their economic performance can be
analyzed only by comparing the busbar power cost of these
machines to the energy cost of power they could displace.
Data for further analysis of small wind energy conversion
systems were taken from the techno 1 ogy profi 1 es. Further
analysis of this alternative indicated that 20 MW of in-
stalled capacity producing approximately 40 GWh of electric
energy possibly could be economically developed at 80 mill
marginal power costs, .under the highly unlikely assumption
of full penetration of the available market (households).
Furthermore, in this analysis these machines were given
parity with firm generating alternatives for cost of power
comparisons. Because the potential contribution of this
alternative is relatively minor even under the rather
liberal assumptions of this analysis, the potential energy
0-4-39
production of small wind energy conversion systems was not
included in the analysis. of Railbelt electric energy
plans.
(xi i) Tidal Power
Tidal power plants typically consist of a "tidal barrage"
extending across a bay or inlet that has substantial tidal
fluctuations. The barrage contains sluice gates to admit
water behind the barrage on the incoming tide and
turbine-generator units to generate power on the outgoing
tide. Tidal power is intermittent, available, and requires
a power system with equivalent amount of installed capacity
capable of cycling in complement to the output of the tidal
plant. Hydro capacity is especially suited for this
purpose. Alternatively, energy storage facilities (pumped
hydro, compressed air, storage batteries) can be used to
regulate the power output of the tidal facility.
Tidal power was selected for consideration in Railbelt
electric energy plans because of the substantial Cook Inlet
tidal resource, because of the renewable character of this
energy resource and because of the substantial interest in
the resource, as evidenced by the first-phase assessment of
Cook Inlet tidal power development (Acres 198la).
Estimated production costs of an unretimed tidal power
facility would be competitive with principal alternative
sources of power, such as coal-fired power plants, if all
power production could be used effectively. The costs
would not be competitive, however, unless a specialized
industry were established to absorb the predictable, but
cyclic, output of the plant. Alternatively, only the
portion of the power output that could be absorbed by the
Railbelt power system could be used. The cost of this
energy would be extremely high relative to other
power-producing options because only a fraction of the
11 raw" energy production could be used. An additional
alternative would be to construct a retiming facility,
probably a pumped storage plant. Due to the increased
capital costs and power losses inherent in this option,
busbar power costs would still be substantially greater
than for nontidal generating alternatives. For these
reasons, the Cook Inlet tidal power alternative was not
considered further in the analysis of Railbelt electric
energy plans.
D-4-40
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-[
(xiii) Refuse-Derived Fuel Steam Electric Plants
These plants consist of boilers, fired by the combustible
fraction of municipal refuse, that produce steam for the
operation of a steam turbine-generator. Rated capacities
typically are low due to the difficulties of transporting
and storing refuse, a relatively low energy density fuel.
Supplemental firing by foss-il fuel may be required to
compensate for seasonal variation in refuse production.
Enough municipal refuse appears to be available in the
Anchorage and Fairbanks areas to support small refuse-
derived fuel-fired steam-electric plants if supplemental
firing (using coal) were provided to compensate for sea-
sonal fluctuations in refuse availability. The cost of
power from such a facility appears to be reasonably com-
petitive, although this competitiveness depends upon re-
ceipt of refuse-derived fuel at little or no cost. Advan-
tages presented by disposal of municipal refuse by combus-
tion may outweigh the somewhat higher power costs of such a
facility compared to coal-fired plants. The principal
concerns relative to this type of plant relate to potential
reliability, atmospheric emission, and odor problems.
Cost and performance characteristics of these alternatives
as used in the Battelle study (Battelle 1982, Vol. II) are
summarized in Table 0.30.
D-4-41
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5 -CONSEQUENCES OF LICENSE DENIAL
5.1-Cost of License Denial
The forecast energy demand for the Railbelt through the year 2020 can
be met without constructing the Watana-Devil Canyon hydroelectric
project provided that other, albeit more costly, alternatives are
developed. The best alternative generating system is outlined in
Section 4.5 of this Exhibit. However, the economic comparison
described in Section 4.7 concludes that the Susitna project will yield
an expected present valued net benefit of $1.8 billion under the
Reference Case.
The economic consequences of license denial will be the probable costs
mentioned above.
The Susitna project makes a significant contribution to the energy
independence of both the State and the nation. Generation of power by
a renewable resource in the State allows for export of non-renewable
resources to the lower 48 states. Denial of the license will negate
this effort.
The most likely alternative to Susitna is subject to a great deal of
cost risk due to the uncertain future in fossil fuel prices and the
unresolved issues about development in the Beluga coal fields. License
denial will force the State into pursuing a less certain program in
meeting power needs.
5. 2 -Future Use of Damsites if License is Denied
There are no present plants for an alternative use of the Watana and
Devil Canyon damsites. In the absence of the hydroelectric project,
they would remain in their present state.
D-5-1
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(,..,.:
6 -FINANCING
6.1 -Forecast Financial Parameters
The financial parameters used in the financial analysis are summarized
in Table 0.12. The interest rates and forecast rates of inflation are
of special importance. They have been based on the forecast inflation
rates and the forecast of interest rates on industrial bonds {Data
Resources Inc.) and conform to a range of other authoritative
forecasts. To allow for the factors which have brought about a
narrowing of the differential between tax exempt and taxable
securities, it has been assumed that any tax exempt financing would be
at a rate of 80 percent rather than the historical 75 percent or so of
the taxable interest rate. This identifies the forecast interest rates
in the financing periods from 1985 in successive five-year periods as
being on the order of 8.6 percent, 7.8 percent, and 7 percent. The
accompanying rate of inflation waul d be about 7 percent. In view of
the uncertainty attaching to such forecasts and in the interest of
conservatism, the financial projections which follow have been based
upon the assumption of a 10 percent rate of interest for tax-exempt
bonds and an ongoing inflation rate of 7 percent.
6.2 -Inflationary Financing Deficit
The basic financing problem of Susitna is the magnitude of its ,.infla-
tionary financing deficits." Under inflationary conditions these
deficits {early year losses) are an inherent characteristic of almost
all debt financed, long life, capital intensive projects (s€e Figure
0.10). As such, they are entirely compatible (as in the Susitna case)
with a project showing a good economic rate of return. However, unless
additional state equity is included to meet this 11 inflationary financ-
ing deficit,. the project may be unable to proceed without imposing a
substantial and possibly unacceptable burden of high early-year costs
on consumers.
6.3-Legislative Status of Alaska Power Authority and Susitna Project
The Alaska Power Authority is a public corporation of the State in the
Department of Commerce and Economic Development but with separate and
independent legal existence.
The Authority was created with all general powers necessary to finance,
construct and operate power production and transmission facilities
throughout the State. The Authority is not regulated by the Alaska
Public Utilities Commission, but is subject to the Executive Budget Act
of the State and must identify projects for development in accordance
D-6-1
with the project selection process outlined within Alaska Statutes.
The Authority must receive legislative authorization prior to
proceeding with the issuance of bonds for the financing of construction
of any project which involves the appropriation of State funds or a
project which exceeds 1.5 megawatts of installed capacity.
The Alaska State Legislature has specifically addressed the Susitna
project in legislation (Statute 44.83.300 Susitna River Hydroelectric
Project). The legislation states that the purpose of the project is to
generate, transmit and distribute electric power in a manner which
wi 11 :
(1) Minimize market area electrical power costs;
(2) Minimize adverse environmental and social impacts while enhancing
environmental values to the extent possible; and
( 3) Safeguard both 1 ife and property.
Section 44.83.36 Project Financing states that 11 the Susitna River
Hydroelectric Project shall be financed by general fund appropriations,
general obligation bonds, revenue bonds, or other plans of finance as.
approved by the legislature."
6 . 4 -Fin an c in g P 1 an
The financing of the Susitna project is expected to be accomplished by
a combination of direct State of Alaska appropriations and revenue
bonds issued by the Power Authority but carrying the "moral obligation"
of the State. On this basis it is expected that project costs for
Watana through early 1990 will be financed by approximately $1.8
billion (1982 dollars) of state appropriations. Thereafter completion
of Watana is expected to be accomplished by issuance of approximately
$2.0 billion (1982 dollars) of revenue bonds. The year-by-year
expenditures in constant and then current dollars are detailed in Table
0.31. These annual borrowing amounts do not exceed the Authority 1 s
estimated annual debt capacity for the period.
The revenue bonds are expected to be secured by project power sales
contracts, other available revenues, and by a Capital Reserve Fund
(funded by a State appropriation equal to a maximum annual debt ser-
vice) and backed by the "moral obligation 11 of the State of Alaska.
The completion of the Susitna project by the building of Devil Canyon
is expected to be financed (as detailed in Table 0.31) by the issuance
of approximately $2.0 billion of revenue bonds (in 1982 dollars) over
the years 1994 to 2002 with no state contribution.
Summary financial statements based on the assumption of 7 percent
inflation and bond financing at a 10 percent interest rate and other
estimates in accordance with the above economic analysis are given in
Tables 0.32 and 0.10, for the $1.8 billion state contribution and 100
percent debt financing cases, respectively. Figure 0.10 shows the cost
of energy from Susitna assuming the $1.8 billion state contribution.
D-6-2
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-
The actual interest rates at which the project will be financed in the
1990s and the related rate of inflation cannot be determined with any
certainty at the present time. Also, while the market for Susitna
power is relatively insensitive to the world oil prices analyzed, the
finance plan is affected by those prices through their impact on the
wholesale prices Railbelt utilities would face in the absence of
Susitna.
A material factor will be securing tax exempt status for the revenue
bonds. This issue has been extensively reviewed by the Power
Authority•s financial advisors and it has been concluded that it would
be reasonable to assume that by the operative date the relevant
requirements of Section 103 of the IRS code would be met. On this·
assumption the 7 percent inflation and 10 percent interest rates used
in the analysis are consistent with authoritative estimates of Data
Resources (U.S. Review July 1982) forecasting a CPI rate of inflation
1982-1991 of approximately 7 percent and interest rates of AA Utility
Bonds (non exempt) of 11.43 percent in 1991, dropping to 10.02 percent
in 1995.
Because of the above conditions, the financing plan is the subject of
continuing review and development. ,~"'''
D-6-3
,.....
i
-
-(
,...
REFERENCES
Acres American Inc. 1981a. Preliminary Assessment of Cook Inlet Tidal
Power. Prepared for the Othce of the Governor, State of AI aska.
. December 1981b. Susitna Hydroelectric Project Development
------~selection Report. Prepared for the Alaska Power Author1ty.
. March 1982a. Susitna Hydroelectric Project Feasibility Report
----'T"·7 Vo 1 umes). Prepared for the At ask a Power Authon ty.
. April 1982b. Susitna Hydroelectric Project Reference Report,
----.,..Economic, Marketing and F1nanc1al Evaluabon. Prepared for the
Alaska Power Author1ty.
. April 1982c.
--~studies. Prepare
Planning
Alaska Agreements of Wa~es and Benefits for Construction Trades.
effect January 198 .
In
Alaska Department of Commerce and Economic Development. July 1980.
The Alaska Economic Information and Reporting System.
B.C. Business. August 1981.
Batte)le Pacific Northwest Laboratories. 1980. Beluga Coal Market
Study, Final Report. Richland, Washington.
. 1982. Railbelt Electric Power Alternatives Study (17
--Trvo·l umes).
Volume I: Railbelt Electric Power'Alternatives Study: Evaluation
of Railbelt Electr1c Energy Plans:
Volume II: Selection of Electric Energy Technologies for
Consideration 1n Ra11belt Eiectr1c Energy Plans.
Volume IV: Candidate Electric Energy Technologies for Future
Application 1n the Ra1 !belt Reg1on of Alaska.
Volume VII: Fossil Fuel Availability and Price Forecasts for the
Railbelt Region of Alaska.
Volume IX: Alaska Economic Projections for Estimating Electricity
Requirements tor the Ra1 lbelt~
Volume XII: Coal-fired Steam-electric Power Plant Alternatives
for the Railbelt Reg1on of Alaska.
Volume XIII: Natural Gas-Fired Combined-Cycle Power Plant
Alternatives for the Ra1 !belt Reg1on of Alaska.
Volume XVI: Wind Energy Alternative for the Railbelt Region of
Alaska.
Volume XVII: Coal-Gasification Combined-Cycle Power Plant
Alternatives for the Ra1 !belt Reg1on of Alaska. Prepared for the
Off1ce of the Governor, State of Alaska.
Baumol, W.J. September 1968. On the Social Rate of Discount.
American Economic Review (Volume 58).
Bechtel Civil and Minerals, Inc. 1981. Chakacharnna Hydroelectric
Project Interim Report. Prepared for the Alaska Power Author1ty.
Canadian Resourcecon Limited. May 1980. Industrial Thermal Coal Use
in Canada, 1980 to 2010.
Caterpi 11 ar Tractor Co. October 1981. Caterpillar Performance
Handbook. Peoria, Illinois.
Coal Week International. Various issues.
-Code of Federal Regulations. 1981. Title 18, Conservation of Power
and Water Resources, Parts 1 and 2. Government Printing Office,
Washington, D.C.
_ Commonwealth Associates Inc. January 1982. Anchorage-Fairbanks
Intertie Route Selection Report. Prepared for the Alaska Power
Authon ty.
A Data Resources, Inc. November 1981. Personal communication.
Data Resources Inc. 1980. U.S. Long-Term Review, Fall 1980.
Lexington, MA.
Federal Energy Regulatory Commission, Office of Electric Power
Regulation. August 1979. Hydroelectric Power Evaluation.
Japanese Ministry of International Trade and Industry. January 1982.
Personal communication.
Mishan, E.J. 1975. Cost-Benefit Analysis. George Allen and Unwin.
London.
National Energy Board of Canada, Ottawa, Canada. October 1981.
Personal communication.
Noroil. October 1981. Natural Gas and International LNG Trade (Volume
9).
p:·---
-
-
Phung, Doan L. April 1978. A Method for Estimating Escalation and
Interest During Construct1on. trst1tute for Energy Analys1s, Oak
R1dge Assoc1ated On1vers1t1es.
Prest, A.R. and R. Turvey. 1965. Cost-Benefit Analysis: A Survey.
Economic Journal (Volume 75).
Roberts, J.O. et al. January 1980. Treatment of Inflation in the
Development of Discount Rates and Levelized CCosts 1n NEPA Analyses
to~ the'EJectrlc Ot1 l1ty Industry. U.S. Nuclear Regulatory
CommlSSlon, Wash1ngton, O.c.
Roberts, WilliamS. July 1976. Regionalized Feasibility Study of Cold
Weather Earthwork. Cold Reg1ons Research and Eng1neer1ng
laboratory, Spec1al Report 76-2.
SRI International. October 1981. Personal communication.
Segal, J. December 1980. Slower Growth for the 1980 1 S. Petroleum
Economist.
Segal, J. and F. Niering. September 1980. Special Report on World
Natural Gas Pricing. Petroleum Economist.
U.S. Department of Commerce. Survey of Current Business. Various
issues.
U.S. Department of Energy. 1980. Annual Report to Congress. Energy r Information Administration. Wash1ngton, D.C.
U.S. Department of Labor. Monthly Labor Review. Various issues.
Wharton Econometric Forecasting Associates. Fall 1981. (Reported in
Economic Council of Canada CANDIDE Model 2-0 Run, dated December
18, 1981). Philadelphia, PA.
World Bank. 1980. Commodity Trade and Price Trends. Washington, D.C.
January 1981. Personal communication.
!"""
TABLE 0.1: SUMMARY OF COST ESTIMATE
!"""' January 1982 Dollars $ X 10 6
Cata~ory t:lat:ana Dev1 I Canyon rat: a 1
Production Plant $ 2,293 $ 1,065 $ 3,358
Transmission Plant 456 105 561
r-General Plant 5 5 10
Indirect 442 206 648
"""
Total Construction 3,196 1,381 4,577
~ Overhead Construction 400 173 573
TOTAL PROJECT
CONSTRUCTION COST $ 3,596 $ 1,554 $ 5,150
~
ECONOMIC ANALYSIS (OGP-6, 0 percent inflation, 3 percent interest)
Escalation
,...., AFDC 485 180 665
TOTAL PRO~IECT COST $ 4,081 $ 1,734 $ 5,815
SUSITNA COST OF POWER (Table 0.10, 100% Debt Finance) -Escalation 2,560 3,200 5,760
AFDC 1,796 1,610 3,406
,_
TOTAL PROJECT COST 7,952 6,364 14,316
FINANCIAL ANALYSIS (Table 0.32, $1.8 Billion State Appropriation)
Escalation 2,560 3,200 5,760
AFDC 314 1,610 1,924
!"""' TOTAL PROJECT COST $ 6,470 $ 6,364 $ 12,834
Line
Nurber rEscription
PR(X)£TIQ\l PLANT
Land & Land Rights
TABLE D. 2: ESTIMl\TE SIJvMARY -WATANA
331 Powerplant Struc~ures & hnprovements .•....•.•••...•••••.•..•....••••••
332 Reservoir, Dans & Waterwaj!S . ~ ., ••••••• ~ ••.••.•••••. Ill •••••••••••••••••••
333 WaterW!ee l s, Turbines & G=ner ators ................................... .
334 Jlccessory Electrical Equi prent •••••••.•.••••••.•..••..•••••.••••..•..•
335 Miscellaneous Powerplant Equipment (Mechanical) .•••••••.•.•••••••.••.•
~ Roa::ts & Rai 1 roa::ls •••••••••••••••••••••••••••••••••••••••••••••••••••••
Stiltota 1 ............................................................. .
U:>rlt i nger\Cy e .......................................................... .
TOTPJ.. ~OOl...CTIOO PLANT •••••••• e ••• Ill •••••••••••••••••••••• ,. ••••••••••••
Arount
(x lCP)
$ 51
74
1,547
66
21
14
214
1,987
D)
Total~
(x HF)
$ 2,293
Ranarks
91eet 1 of 5
l l
TABLE 0.2 (Cont•d)
Line NUTber
350
352
353
354
356
359
!:escription
TOTJIJ... BRt:lGIT FCRWAAD
TRANSMISSIOO PUWT
Lard & LCild Rights ••••••••••••••••.•••••.••••••••••••••••••••••••••.•.
Substation & ~tching Station Structures & bnprovements ••••••••••••••
Substation & Switching Station Equipment ••••••••••••••••••••••••••••••
Stee-l TO'Aers & Fixtures ............................................... .
ClverheOO Condoctors & l:evices •••••••••••••••••••••••••.•••••••••••••••
Roa:Js & Trai 1 s ••••••••••••••••••••••••••••••••••••••••••••••••••••••••
SLbtotal ..............................................................
Writ i ngerJCy ........................................................... .
TOT.I\1._ l'R,OJ\J~ISSIOO PUWT •••.••••• II ••••••••••••••••••••••••••••••••••••
1 l
Arount
(x 100)
$ 8
12
131
131
100
13
395
61
Total~
(x 1<J-')
$ 2,293
456
$ 2,749
l
Ranarks
Sheet 2 of 5
TABLE 0.2 (Gont'd)
Line
Nurber
l39
300
391
392
393
394
395
396
397
398
399
rescription
TOTJIL BRCLG-IT FffiWAA.D
GENERAL PLANT
Land & Land Rights
Stroctures & Irrproverents . ~~~ ..•.....••••••.•.•...• ., .................... .
Office FUYlliture/Equiprent ......... ,. . a •••••••••••••••••••••••••••••••• Ill
TranSJX)rtatioo EquiPTJE!f1t ••• II •• II ••••••••••••••••••• a ••••••••••••••• Ill •••
Stores Equi prent . ., .•.•..•.• ~~~ ..•.. It •••••••••••••••••••••••••• tl ........ ~~~ (!o
Too 1 s Stlop & Garage Equi PTJE!I1t ••••••••••••••••••••••••••• ., •••••••• & ••••
Lctloratory Equip-rent .•••••••••• ~~~ ••••••••••••••. ~~ ...................... o
Power-Operated EquiPTJE!I1t
Carmunications Equiprent
Mi see 11 aneous Equi prent
Other Tangible Property ·······························••&••••'~'·····(!o··
TOT Jl.l. GENERAL PLAAT ................................................... "
l
Amunt
(x lCP)
$
5
Tota66 (x 1 ) Ranarks
$ 2,749
Inc l LKied lJlder 330
Included under 331
Inc 1 LKied lJlder 399
!I ..
II II
II II
II u
II II
II II
II I!
$ 5
$ 2,754
Sheet 3 of 5
l
1 J ·~ l l
TABLE 0.2 (Cont'd)
Line
Nlllber
61
62
63
64
65
66
68
69
ll:!scription
IDTJIJ.. BROLGIT FffiWAAD
INDIRECT COSTS
Temporary Construction Facilities
Constroction EquiJ]TB1t ............................................... .
Carp & CaTmi ssar-y •••••••••••••••••••••••••••••••••••••••••••••••••••••
Lmr Ex~se ........................................................ .
.5LJJ)E!ri nta1det1<:e .••..•••.••••••.•••.•••••••••••••.••••••••.•••.••..••••
Ins~ar1ee .............................. , .............................. .
Mitigatioo ........................................................... .
Fees ...••.•••..••.•••.••.••••••••.••.••••••.••••••.•.•••••••••••••••••
rt>te: Costs l.llder accounts 61, 62 2 64, G5, 66, ct1d 69
are inclLKI~ in the appropnate d1rect costs
listed itlove.
Stbtotal
Conti nga1e:y ...........•...............................................
TOTJll INDIRECT COSTS
IDTJll CONSTROCTIOO COSTS
l
$
373
29
402
40
Total~) (x 100
$ 2,754
$ 442
$ 3,196
l
Ranarks
5ee rt>te
See rt>te
See rt>te
See rt>te
See ttlte
Sheet 4 of 5
l
TABLE 0.2 (Gont•d)
Line
Number Description
TOTAL CONSTRUCTION COSTS BROUGHT FORWARD ••••••••••••••••••••••••••••••
OVERHEAD ~STRUCTIO'J COSTS (PROJECT INDIRECTS)
71 En,gineering/ A:tninistration ........... 8 •••••••••••••••••••••••• e ••• 1\ .. 8
ErlviroYJTB1tal rvblitoring o1 o1 o1 ol o1 I o1 o1 ol ol ol ol o1 ol ol o1 o1 o1 o1 ol o1 o1 o1 o1 a e e ole. e e e e e e II e e ol a. e 8 e e e
72 Leg a 1 Ex(JE!lses ......................................................... ..
75 Taxes ..•.•.••.•..•.•••• e ................................................ .
76 A:tninistrative & General Expenses ••••••••••.••••••••••••••••••••••••••
77 Interest .................................... ~~ ........................ .
80 Earnings/Expenses During Construction •.•.•••••..•••••••.•..•••••••••••
i J
Total CNertleaj ..................... ,. ................................. .
TOTI'l_ ffiQJECT COST ••••••••••• I •••••••• Ill ••••••••••• II •••••••••••••• Ill ••••
l
J
Aro~ (x 1 ) Tota66 (x 1 ) Ranarks
$ 3,1~
$ 336
14
Inclooed in 71
l'bt app1icro1e
Inclooed in 71
l'bt inc 1 ooed
l'bt inc 1 ooed
400
$ 3,596
Sheet 5 of 5
Line Nurber
:m
331
332
333
334
335
3))
l l
TJlJ3LE 0.3:. ESTIMl\TE St..Mv\llRY -r:IVIL CANYOO
~scription
PROO.CTIOO PLANT
Land & Land Rights $
Pov.erp 1 ant Structures & IovrovSJalts ••••••••••••••••••••••••••••••••••
Reservoir, Dans & Waterwaj'S ••••••••••••••••••••••••.••...••••..•.•••..
WaterWleels, Turbines & ~er~tors ....•.••....•............ ,.. ......... .
kcessory Electrical EquiPTBlt ....................................... .
Miscellaneous Powerplant Equipment (Mechanical} •••••••••••••••••••••••
Roa::Js & Rai 1 roa::Js •••••••••••••••••••••••••••••••••••••••••••••••••••••
St.btotal ................................ , ............................. .
C:O,t; nQ€!1CY ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••.
TOTJlJ.. ffioo.cTIOO PLANT ••••••••••••••••••••••••••••••••••••••••••••••••
22
69
646
42
14
11
119
923
142
Total~
(X l<P}
$ 1,())5
l )
Ranarks
Sheet 1 of 5
TABLE 0.3 (Cont•d)
Line
Nurber
350
352
353
354
356
359
~l
f.escription
TQTJ\1... MCl.Gff fffi~D 111 • • • • • • • • • • • • D • • • 11 • e • • • • a 11 • e 111 • • • • t1 11 • e 11 e • o:~ u e a o e 1!1 e e
lRANSMISSIOO PLANT
Lm & La1d Rights .............................. e " • ~ ••••• ll't •••• II II II • IIIII II • Ill .. !)
SLbstation & Switching Station Stroctures & fullroverents ..•.•.•••...••
SLbstation & SMritching Station Equipment .•••..••.•....••.•.••.•.•.••••
Stee 1 To~rs & Fixtures ••..•• e ......................... ., •• Ill Ill •••••••••••
Overhead Conductors & Devices ·······························~~·········
RoOOs & Trails ••••••••••••••e•••••••• .. •••••••••····~~· .. •o••o•····"·l!l···
$ -
7
21
29
34
SLbtota l ••.•...••..•..•.•.•••• " •••••••• II •••••• e •••• Iii •••• " 1!1 ••••••• e • It II l!l 91
WntingetlCy ••••••• , ................................... •o •••••••••••• ~~·. 14
TOT J\1... l"RAN3v1I ss I ()'J PLmT ••••••••••••••••••• D ••••••••••••• Ill •••••••• II • 0 •
l 0
~'
Total~
(x 100)
$ 1,(65
$ 105
$ 1,170
~J
Ranarks
Included in Watana
Estimate
Included in Watana
Estimate
Sheet 2 of 5
l
TABLE 0.3 (Cont•d)
Line
Nurber
139
:ro
391
392
393
394
395
396
397
398
399
Description
TOTPL BRQGff FffiWilRD
rENERJlJ... PlJ\NT
Land & Land Rights
Structures & Irrt:>rovare1ts •...••.•••••.••.•..•••.•.••••••.••..••..•...•
Office Fumiture/Equi_prent ........................................... .
T r C11S(X)rtat i oo Equi pre1t ••••••••••••••••••••••••••••••••••••••••••••••
Stores ECfl.Ji pre1t ••••••••••••••••••••••••••••••••••••••••••••••••••••••
Tools StlcJp & Gar-~e EquiJllBlt ......................................... .
Lcix>ratory Equi JlTBlt •.••.•••••• ,. ••••.••.••....•.••.•••.•.•...........•
Po~r Q:Jerated Equiprent
Communications EquiJlTBlt
Miscellaneous Equipment
Other Tangible Property
IDT M.. (Jl:NER,QJ_ PLJWT" • • • • • • • • • • • • • • • • • • .. • • • • • • • • • • • • • • • • • • • • • • • • • • • • . • ••
Aroun:t
(x HP)
$
5
1 l l
Tota~ (x 1 ) Ran arks
$ 1,170
Inc 1 Lded under :m
Inc 1 Lde:1 lllder 331
Inc 1 Lded under 399
II II
II II
II II
II II
II II
II II
II II
$ 5
$ 1,175
Sheet 3 of 5
TABLE 0.3 (Gont'd)
Line
Nurber
61
62
63
64
65
66
68
69
l:escription
TOTPL BRon-rf FffiWJlRD
INDIRECT OOSTS
Temporary Construction Facilities
Construction Equipment
Carp & CcJrrniSSOY""Y • • • • • • • • • • • a • • • • • • • • • • • • • e • a • • • • • • • • • • • • • • • • • a 6 • • e • • 11
L~r Ex~se .................................... 8 ............. !I •••••••
StJ~ri nterlderJC.e ......... 8 ••••••••••••••••••••••••• " •••• e ••••• e 8 ••• !J •••
Ins~artee "' .•.. Ill •••••••••••••••••••• ., ••••••••••••••••••••••••••• ~~ ••••••
Mitigation ................................................ ., ............ .
F~ ..... I ..................................................... " " G •••• II
l'bte: Costs lllder accounts 61, 62, 64, 65, 66, tr~d 69
are included in the appropnate direct costs
l i sted .:Dove.
St.btotalj' •••••••••••••••••5•••••••••••••••••fill••••••••••o••••e••••••••••
Cc>nt i nget1Cy a a a a a a a a a a a a a a • ••••••• • ••••••• G • • ••••••••• a •••• • • •••• D ••• 8 8
TQTjlJ_ INDIRECT COS"TS .....•••••.••••••.•...••••••••• o •••••• " •••••••••••
TOTPL COOSlRLCTION OOSTS
"" !
Armrrt.
(x 100)
$
184
4
188
18
Tota~ (x 1 )
$ 1,175
$
$ 1,:~n
Ranarks
&'€! l'bte
&'€! l'bte
See llbte
~ llbte
See f'bte
See llbte
Sheet 4 of 5
] 1 1 1 1
TABLE 0.3 (Cont'd)
Line
Nt.rrber ~scription Aro~ Tota~ (x 1 ) (x 1 ) Ran arks
mTAL COOSTRLCTIOO COSTS BRarnT FCRWARD ............................. . $ 1,l31
OVEru£AD a:JNSTRLCTIOO COSTS (PROJECT INDIRECTS)
71 Engineering/ A::tnini strati on ..................•........................ $ 167
Envir<ll'lTBltal tblitoring ............................................. . 6
72 Leg a 1 Ex.JB1Ses ••••••••••••••••••••••••••••••••••••••••••••••••••••••• Inc liXIed in 71
75 T ax.es •••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• tt>t Jlppliccble
76 A::tninistrative & General Expenses •••••••••••••••••••••••••••••••••••• IncliXIed in 71
77 Interest ....... · ..................................................... . tt>t Inc liXIed
00 Earnings/Expenses I:AJring Constnction •••••••••••••••••••••••••••••••• N:Jt Inc liXIed
Tot a 1 <Jverhea:l Costs -· •••••••••••••••••••••••••••••••••••••• .-••••••••• 173
IDT PJ... ffiUJECT OOST ................................................... . $ 1,554
Sheet 5 of 5
TABLE 0.4: MITIGI\TIOO r.£ASLRES -St.JvMllRY (F OJSTS INCCRPCRATED
IN C~l£Tia-1 COST ESTI~TES
COSTS INCCRPCRATED IN COOSTRLCTII]l ESTIMl\TES WAT~ $X 1 ll:VIL ~Y(}I $ X 1
Outlet Facilities
Main D~ at ~vil CCJl~ 14,600
Tunnel pillway at Wa <Jla 47,100 ~·
Restoration of Borrow Jlrea D 1,600 ND.
Restoration of Borrow Jlrea F 600 NA
Restoration of Camp <Jld Village 2,3)) 1,0Xl
Restoration of Construction Sites 4,100 2,0Xl
Fencing around Camp 400 2CO
Fencing around Garbage Disposal Jlrea 100 100
Multilevel Intake Structure 18,400 NA F-
C~ Facilities Associated with trYing
to eep \lbrkers out of Local Carmunit1es 10,200 9,CXX)
;:c---·
Restoration of Haul Roads 800 500
SUBTOTAL 85,600 27,400
Contingency 20% 17,100 5,500
TOTAL Cl:NSTRLCTHJI 102,700 32,~
Engineering 12.5% 12,80) 4,100
TOTAL ffiOJECT 115,500 37,())) 152,500
1 -.. 1 1 l
TABLE 0.5: ~y <F a>ERATH}I JlND Ml\INTENANCE OOSTS
Po\\er & Transnission Q:leration/
Maintena1ce
Contracted Services
Pennanent TO\'Klsite Q:lerations
Allowance for Environmental
Mitigation
Contingency
Additional Allowance from 2002
to Replace Gammunity Facilities
Total Q:lerating and Maintenance
Expenditure Estimate
Po~o.er l:eveloprent illd Transmission
Facilities
( 1) Incrarenta 1
LciJor -
53])
540
WATJ1NA1
($ ooo•s Omitted)
EXpense
I tens Stbtotal
9!X) 6320
nl nl
340 ffi()
1000
nl
400
WAT.ANA m,4tn
I
($ ooo•s Onitted)
EXpense
LciJor I tens Stbtotal
1920 500 2420
400 400
120 00 ax>
1000
500
DEVIL CANY(}I 4,00)
) .. . i
TABLE 0.6: VARIABLES FOR AFDC COMPUTATIONS
Effective Interest Rate (x)% Escalation Rate (y)% Construction Per1oa (B) yrs. Watana Devil Canyon
Economic
3
0
8.5 7.5
Analysis
Financial
10
7
8.5 7.5
F --
-1 -1 -.·-1 ] l l I ----1
TABLE D. 7 -SUSITNA HYffi(lLEClRIC ffiOJECT
Watana iJld l:efil Canj{)ll Ct.m.Jlative a1d Jlnnual Cash Flow
JANl.lDRY 1982 OO...LJIRS -IN MILLIOOS
v~ ~rMA PlfJIJJI[ ~v~~~voo ammto ;JLM!ATIVE ~= EFIJ (f ~ ~ WAt . L IN D
1981 27.6 27.6 27.6 27.6
82 12.9 12.9 40.4 40.5
83 '2B.7 '2B.7 69.2 69.2
84 48.5 48.5 117.7 117.7
85 199.5 199.5 317.2 317.2
ffi '2B3.9 283.9 601.1 601.1
87 295.4 295.4 896.5 896.5
88 369.0 369.0 1265.5 1265.5
89 4l3.4 4l3.4 1703.9 1703.9
!X) 627.6 627.6 2331.5 2331.5
91 600.8 4.9 613.7 2940.3 4.9 2945.2
92 429.0 47.9 476.9 3369.3 52.8 3422.1
93 153.2 68.6 221.8 3522.5 121.4 3643.9
94 73.7 64.3 1l3.0 3596.2 185.7 3781.9
95 64.9 64.9 250.6 l346.8
96 115.3 115.3 365.9 3962.1
97 201.3 201.3 567.2 4163.4
98 291.8 291.8 854.0 4455.2
99 279.7 279.7 11l3.7 4734.9
20l) 241.7 241.7 1:ID.4 4976.6
2001 156.0 156.0 1536.4 5132.6
2002 17.6 17.6 1554.0 5150.2
mTAL 3596.2 1554.0 5150.2
TABLE 0.8: JlNCI-mArE FAIRBAN<S INTERTIE
PROJECT COST ESTIMATE
Total Line 175.1 miles
Total Sl.bstation Cost
Slbtotal
R/W Acquisition ($40.00/Mile)
MX>ilization -furd:lilization 5%
Surveying
Engineering 6%
Construction MillagBTErtt 5%
Sl.btotal
Contingencies 25%
Tot a 1 Sept. 1981 I)J 11 ars
Inflation @ 10%/)ear - 2 )ears
TOTAL COST
(Thousands of DOllars)
56,556
9,449
66,005
6,784
3,DJ
3,100
3,960
3,3Xl
86,449
21,612
lOO,a>l
13),754
~urce: Canron\\ealth Associates, January 1982
-
-
-
-
F"
,...
TABLE D.9: SUMMARY OF EBASCO CHECK ESTIMATE
The following figures and comments are taken from EBASCO's estimate dated
March 26, 1982.
PROJECT COST SUMMARY
The hydroelectric development cost in January 1982 dollars is as follows:
DESCRIPTION
Hydraulic Production Plant
Transmission Plant
General Plant
Total Direct Construction Cost
Indirect Construction Cost
Subtotal for Contingency
Conti.ngency
Total Specific Construction Cost
Professional Services
Cl i ent Costs
Total Project Cost
WATANA
$2,502,053,000
411,774,000
1' 113,000
$2,§14,940,000
362,681,000
$3,277,621,000
503,979,000
$3,7sl,6oo,ooo
280,000,000
Not Included
$4,o61,6oa,ooo
DEVIL CANYON
$ 955,723,000
77,712,000
$1,033,435,000
170,688,000
$1,zo4,1z3,ooo
184,177 '000
$1,3aa,3oo,ooo
115,000,000
Not Included
$1,5o3,3oo,ooo
The above costs are based on quantities contained in the Revision 4 Estimating
Package dated February 12, 1982, as prepared by Acres American. We have not
considered any quantities contained in the Revision 5 Estimating Package dated
March 4, 1982, since the transmittal was received one month later than the
revised information cutoff date of February 8, 1982~
Major cost quantities have been checked to verify Revision 4 quantities as
compared to Acres• Project drawings. We have provided an asterisk next to the
accounts added bY Ebasco to reflect costs not properly included in other
accounts. Unit prices supplied by Acres American Incorporated are footnoted.
REVISED SUMMARY (BY ACRES)
Watana Cost $4,062 X 106
Devi 1 Canyon Cost 1,503 X 1Q6
Total Project (Rev. 4) 5,565 X 106
Adjustment for Revision 5 -79 X 106
Adjustment Total Project $5,486 X 106
NOTE: Adjustments were given by EBASCO in meeting in
New York on April 14, 1982.
i~~ ~~;[~~,]~~-~ILLS
46~ !!<FLAT IC~ p,Jfl<
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-----J~c-~------------------
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7% INFLATION 10% INTEREST
SHEET 2 OF 6
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TABLE 0.10
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lS.E 21.2
38.3 39.<;
l3C~.~ 128~.<;
lU .3
It. 4
He .t c.c
E:E o.c
212.2
187.2 c • c
152S7 .c
31?..4 c.c c.c
1 7. ~
32c;.e
In. 1
~~~:;
o.c
R:6 c.c
227.1
1es.e o.c
1541C.7
2C 12
'::t::23
3 6. 7<;;
787.42
28S.72
1744 .s
1 l g. 7
lt25.2 22.1
4 I • 7
12H .C --------
3~0.2
3~C.2 o.c c.c
IE. 1
3t;8.B
12 l • 7
18.1
2 1 a • ~
c.c
8:8 c.c
2~3.C
l'i2.t c.c
155~2.~
2 c 13
t 1 ~ e
3 4. C2
~42.5~
<et.U
IH 2, C
I 2?. 1
l(~~.c
2 ~. 3
~3.6
1244.2
3H .~
31C.5 c. c c.c
2C.C
3t;C.5
l3C.2
2C.C
2~(.4
c.c
E:E
r..c
2tC.C
1t:;S.5 c.c
I~H2.t
<Cl4
t 317 31.27 <; c • ~ 2
<~I.Et
lt43.4
2 c. (
if 5. ~
1 Z2 C. I
~c:~.7 c. c c.c n. 4
425. I
1 ~ 9. :!
21. 4 2t4,4
c • c
8:f
c.c
27~,2
1112eE c 4 c
l~BC!.<;
==~===== ~====:== ~=~===== ======== =======~ ======== ~======= ~~~===== =====~== ====~=:=
r;.o
121".7
3 2 .; • 0
13611.8
c.o
6024.'1
1.0 5
c.c
14~3.1
~~c. 5
110~ .5
r..c
6t24.9
1. 0 5
r..o
H4S.'1
35~.5
l3JS2.8
G,ll
6t'~.9
1.06
G.O
IE~?.'J
367.3
132(}3.5
o.o
604.9
1.06
c. c
2 1!: I • 4 1e3.c
13C3S,4
c.c
662~.<;
1.07
c.c
24~a.3
3>9.~
12e~e.e
c.c
t62~.'l
1. c 1
NO STATE CONTRIBUTION SCENARIO
7% INFLATION 10% INTEREST
SHEET 3 OF 6
~,
' '
c. c' 27',C.6
4 if..<;
1261:0.1
c.r
662~.'l
1. c e
c.c
~cgo.o
4 ~ 5. 5
12441.6
c.c
6~24.9 ] • c 8
c .. c
~~~~-1
Ot. S
n~:t.e
c.c
U24 .s
).(<;
TABLE 0.10
]
73 =h4~n ~v '3'.-J:i
~21 :::. E AL r•: I C ~-I' ILL~
4b·~ I N FlAT I C'. It· J E >-
r:~') ''" 1v:-~1LL~
-----1 ,'JCC•1 -----------------., 1 ') ~t:vc·;u,
111 LCSS 'W"'.'·\1 1:;( c.:··-~ r s
Si7 2 't
l r> "? q (', G I r.. ~ t~ 1' L •4 J C I ~: T \: R ":. ~ T r: ~ ~~ ! ; ·: U :J 1\ fUN:: ., .:} ') Ll: ~s PlltRoST Cli S 1-!Cf', T TER11 ;: ill
111 l :: s s I';T•:p~~T r, ~I L cr.G lE ~~~~ 0 er
':i4 ~ ~I : T E_ ~ f ~ I~~ C ~ f r. ~l ~· 'JP•:E S
-----C\SY SllUfl CF M;o USE----
Cj4S ;a~H ~~~~M~ ~rr~ or~r~
rt ·~ :2. •l~T-CUNTAI LTI!l~
l'tJ lCr..G TI:Rl-1 0[~1 D~ t.4Sr:•;~S
) " ~ .. -., •JI> c.\ p D"OT DP. A·~:jr:rH\5
)4 .. 1 r.JHL S·JU 'H.·: S Jr rur': s
'ZU l "ss Cl\PITt.l O:PEI'\IJ I TU PE .. , 4 J Lr: ~~ i·i"JH~Afl 1\t~C FLJ'~CS
(~ ,J c l. ,, s s D~UT Ri.:!'AY'IP;TS
3 ') 5 l r:;:; PllY'1::~;T TC jJAE
I'd CA5H S~RDL~SICEFICITI
~4) Sh':f;. T HRI~ D!':nT
4 It 4 CA~H F ECfJHR'"'D
-----!lAl MIC f: SHc"T----------
?2: 11[S 1.;F.VC l\NC C•J~:T. r '~"::
l71 IT~~~ WC~YI~( CA~~T£L
4')-4 r.IC-H SU~PllJS feET~ 'IE<.l
J 7ll c CJ~'. CAPILH fX:'EI\DITUR':
"' f~ ') C 4i' IT .. ~l r/'Dl1YED
.I 1 5111.: CJ'.T?I':t;T!CtJ
' 1 ~ET~!Mrc l~P~l~Gi 3.
~' Ji:.ET OUT STAh:J HoG-SI1C!tT Ti:RI'
J4 Jc er UUTSTANOING-Ll!NG T ~ D.t·l
L,2 .~:~N:J~~L c g T 'J.~ -l-wW: C~IN t 1 'l :] 2
;3 c lJf~. 0 er '):{A,~·~c cv,•, 1l'l:32 1'l .J c e r s.: :l. ICE Cf:V'R
2C15 2C16 20 17 2013 2C19 2C2C
CASh FU.:'n SUflfiP.RY
===(i~TLLI~Nl====
6449 U16 u 1ee 6760 01'3 tiS~4 >.'3.<;4 ~6.6~ 11~~=2~ 11H:H 2!·1j t:5~:H 9'·4.63 10 lo L 1 2 6 .4
2/'Jol't ?75o::>e 274o86 ~16.)1 27~.44 275.C<;
1JCCo1 1E2lo1 184~.c 1€67.7 l'3S3.5 1921.1
146.6 I 'it.<; I 'J 1. 9 179 0 b 1'72.2 2CS.t ------------------------------------------------1!.~1:~ 166 4 0 ~ 2<;. 1675.7 H.!l 1688.1 34. 11§!:~ 17!~:~
47.7 ;c.c 52.4 '>5.1 57.9 60.S 11'13.7 1164,(; 1132.6 tcn.4 lCSf,7 1Cl6,l ----------.------------------------------------------~J<;,<; 479.4 522.6 56<1.1 621.2 6 77. ~
43'1.G
O.IJ
47'J. 4 c.c 'i 2 ii:R 569,7 o.o 62~.2 .c 676:t
c.c c • c 0.0 c.o c.c c.c E.9 -~ 4. 5 zt:.? 28.1 3C.C 32.1 -------- -------- ------------------------_____ .._ __
't62,1 ~r.;.; ~ 'f c.!] 5'>7.a -~51.2 1C<;,t
149.0 15S,5 17 c. 6 lE 2 .(, 19~.4 2CS,C
2?.9 24.5 ?f..? Z£ .1 3C.C 3.2. 1 2 l.j c. g j 1 <;. g 3 'j I.<) 387.1 42:. s 4cf.4 r;.a c.c C.O o.o Coo c.c ------------------------___ .... ____ ----------------c.o c.c o.o OoO o.c DoC c.o c.c c. ·1 o.o c.c c.c
~ n c.c c.o c.o c.c c.c ,. '
~97.6 Jle.s )1, r:. 3 364.6 3SC,2 q 7. ~
~Cl.2 < c s o e lC G .. -~ 2l'o.C ?1?..'5 2 23.3 r.. 0 CoC o.o o.o c.n c.c 15750o9 l611C,4 lt2B 1.0 16463.6 H 6 ~ E ,<; lt€61.S ======== ======== ======== ======== ======== =~======
16450.7 166)4.7 16931.) l7C42 o2 l7267.to 175cs.e
::::;::-::o:::::;: ======== =====:== ======== ======== ======== G. 0 c.o c.o c.o c.c c.c
'• 3 c 5. :l 47l4o4 5306.9 561l:.6 64S7,:~ 1175.~
4")S.3 ~?4 .. 3 3:'0.6 57S. 7 6CE,7 64C.E
llc~S.9 11326. c 1C17't.1 l05G6.'1 lOHl.l ~692.7
O.IJ s.o r.J.o c.o c.c o.c
6024.rJ 6n4.'1 6624.'l 66~4o9 6624.9 t624.9 1.10 1. 11 loll 1. 12 1. n 1.14
NO STATE CONTRIBUTION SCENARIO
7% INFLATION 10% INTEREST
SHEET 4 OF 6
-I
2021 TClAL
6'184 1448C2
19.~<; 1~47o 4 E:EE
279.3 I o.cc
1'l5C.6 429~2.6
22CoC 21t~.5 ----------------17~~:1 40 Hl:l
1';4,1 >65.<;
<;6q.~ 3teno7 ----------------73~.9 7914o<
7)t',g
c.c 7'11~=~
r..c 14Jp .1 3~., t 5.2 ----------------
77 3. 3 £2<; (f o5
22 3.7 17C'il.t
3~.4 ns o2
515.3 513S.7
r:oc CoC -----------..... ----c.c c.o c.c CoC c.c o.o
4'•6.1 446.7
223.5 223.5 o.c c.c
I1C91, 6 17C<;1.6 ==·====== ===::::;:;
177t6.e 177l:c,8
;.::;.:;;::~=== =:.=-=-~=-::-= c.c OoC
7914.2 H 14.2
t7 s 0 2 t75. 2
Sl17.4 9117.4
OoC H24.9
6624.q 6l:24.9
1. 15 c.oo
TABLE 0.10
Cost in Nominal $
Operdtin9 Expenses
Capital Renewals
Debt Service Cost
Total
Operating Expenses
Capital Renewals
Debt Service Cost
Total
Operating Expenses
Capital Renewals
Debt Service Cost
Total
ANNUAL PROJECT COSTS
Mi 11 s/kWh
1993 1994 1995 1996 1997 1998 1999
8 11 12 12 13 13 14
0 8 9 10 10 11 12
252 279 274 273 272 270 270
260 298 295 295 295 294 296
2003 2004 2005 2006 2007 2008 2009
17 18 19 19 20 20 21
14 15 15 16 17 17 18
318 310 303 293 284 276 268
349 343 337 328 321 313 307
2013 2014 2015 2016 2017 2018 2019
24 25 26 27 28 30 31
21 22 23 24 25 27 28
242 235 230 224 222 219 216
287 282 279 275 275 276 275
NO STATE CONTRIBUTION SCENARIO
7% INFLATION 10% INTEREST
SHEET 5 OF 6
'i
2000 2001 2002
15 15 15
12 13 9
269 266 320
296 294 344
2010 2011 2012
22 22 23
19 19 20
259 253 247
300 295 290
2020 2021
33 35
30 32
212 212
275 279
TABLE 0.10
l
Cost in Real $
Operating Expenses
Capital Renewals
Debt Service Cost
Total
Operat in9 Expenses
Capita 1 Renew a 1 s
Debt Service Cost
Total
Operating Expenses
Cdpltal Renewals
Debt Service Cost
Total
] -1
ANNUAL PROJECT COSTS
Mills/kWh
1993 1994 1995 1996 1997 1998 1999
4 5 5 5 5 4 4
0 4 4 4 4 4 4
116 119 109 102 95 88 82
120 128 118 111 104 96 90
2003 2004 2005 2006 2007 IQQJ! 2009
4 4 4 4 4 3 3
3 3 3 3 3 3 3
75 68 62 56 50 46 42
82 75 69 63 57 52 48
2013 2014 2015 2016 2017 2018 2019
3 3 3 3 3 2 2
3 2 2 2 2 2 2
28 26 24 22 20 19 18
34 31 29 27 25 23 22
NO STATE CONTRIBUTION SCENARIO
7% INFLATION 10% INTEREST
SHEET 6 OF 6
2000 2001 2002
4 4 4
4 3 2
77 72 80
85 79 86
2010 2011 2012
3 3 3
3 3 3
38 34 31
44 40 37
2020 2021
2 2
2 2
16 15
20 19
TABLE 0.10
TABLE 0.11: SUSITNA OOST 0:: ITh£R
First Full Year of Watana & cevil Cc11}Un -2003
Total Plant Investrrelt
Inc. I.D.C (RL.M?o -r 466)
I. Fixed Chanres (a) Cost 5f M?ney
{b) l:a>rec 1 at 10n
(l!JX 50 yr S.F.)
(c) Insurance
{d) Taxes
1. Federal Incare
2. Federal
Mi see 11 aneous
3. State & Local
II. Fixed Q:Jerating Costs
Percent
10.00
.09 .10
.00
0.00
o.oo
0.00
~
$'s Per Net Kilowatt
1982 $'s
2116
215.62
(a) (J:Ieration & Maintenance
Including Administrative
Clld General Expense (RL171 divided by 466) 9.l3
Total Jlrlnual Capocity Costs 225.00
flbtes: (1) RL = Reference Line on far left of printout on Tcble 0.10.
r
I
-
-
TABLE D.12: FORECAST FINANCIAL PARAMETERS
Project Completion -Year
Energy Level -1994 -2002 .
-2020
Costs in January 1982 Dollars
Capital Costs
Operating Costs -per
annum
Provision for Capital Renewals -per.annum (0.3 percent of Capital Costs)
Operating Working Capital
Reserve and Contingency Fund
Interest Rate
Debt Repayment Period
Inflation Rate
Watana
1993
3,596.2
~ill ion 10.4
mi 1l ion
$10.79
Devi 1 Canyon Total
2002
2,957 GWh 4.555 II
6,934 II
1,554.0 5,150.2
~i 11 ion ~ill ion 4.8 15.20
m"il lion million
$4.66 $15.45
15 percent of Operating Costs 10 percent of Revenue
100 percent of Oper9ting Costs 00 percent of Prov1s1on for Capital Renewals
10 percent per annum
35 years
7 percent per annum
TABLE 0.13: TOTAL GENERATING CAPACITY WITHIN THE RAILBELT SYSTEML1982
Jlbbrevi at ions Railbelt Utility Installed Capacity!
JM..P Pncho~ M.Jnicipal Light & Po\\er 311.6
Cep t
CEA Dluga:h Electric Associ at ion 463.5
GVEA Golden Valley Electric Association 221.6
FMJS Fairbanks M.Jnicipal Utility System 68.5
~I
rvEA Matanuska Electric Association 0.9
f-EA J-brer Electric Association 2.6
SES Seward Electric Systan 5.5
APJld Alaska PO\\er fldninistration 3).0
U of A University of Alaska 18.6
TOTAL 1122.8
0
2
) Installed c~a:ity as of 1982 at o·F ( ) ExclLdes National Mense installed capacity of 101.3 MfJ
-
-
TABLE D.14 {Sheet 1 of 5)
EXISTING GENERATING PLANTS IN THE RAILBELT REGION
-Nameplate Generating
Prime Fuel Capacity Capacity Heat Rate
Plant/Unit Mover Type Date (MW) @ 0°F (MW) {Btu/kWh) -
Alaska Power Administration
Ekl utna( a) H 1955 30.0
,_ Anchorage Municipal Light and Power ' ---
Station #1 {b)
Unit #1 SCCT NG/0 1962 14.0 16.3 14,000
Unit #2 SCCT NG/0 1964 14.0 16.3 14,000
Unit #3 SCCT NG/0 1968 18.0 18.0 14,000
Unit #4 SCCT NG/0 1972 28.5 32.0 12,500
Diesel 1 (c) D 0 1962 1.1 1.1 10,500
Diesel 2(c) D 0 1962 1.1 1.1 10,500 r-
Station #2(d)
Unit #5 SCCT 0 1974 32.3 40.0 12,500
Unit #6 CCST 1979 33.0 33.0
Unit #7 SCCT 0 1980 73.6 90.0 11,000
Unit #8 SCCT NG/0 1982 73.6 90.0 12,500
Chugach Electric Association
-·Beluga
Unit #1 SCCT NG 1968 15.25 16.1 15,000 -Unit #2 SCCT NG 1968 15.25 16.1 15,000
Unit #3 RCCT NG 1973 53.3 53.0 10,000
Unit #4(e) SCCT NG 1976 10.0 10.7 15,000
Unit #5 RCCT NG 1975 58.5 58.0 10,000 -Unit #6 CCCT NG 1976 72.9 68.0 15,000
Unit #7{f) CCCT NG 1977 72.9 68.0 15,000
Unit #8 CCST NG 1982 55.0 42.0
-
TABLE 0.14 (Sheet 2 of 5)
EXISTING GENERATING PLANTS IN THE RAILBELT REGION
Nameplate Generating
Prime Fuel Capacity Capacity Heat Rate
Plant/Unit Mover Type Date (MW) @ 0°F ( MW) (Btu/kWh),~
Chu~ach Electric Association (Continued)
Cooper Lake(g)
Unit #1 ,2 H 1961 15.0 16.0
International
Unit #1 SCCT NG 1964 14.0 14.0 15,000
Unit #2 SCCT NG 1965 14.0 14.0 15,000
Unit #3 SCCT NG 1970 18.5 18.0 15,000
Bernice Lake
Unit #1 SCCT NG 1963 7.5 8.6 23,400
Unit #2 SCCT NG 1972 16.5 18.9 23,400
Unit #3 SCCT NG 1978 23.0 26.4 23,400
Unit #4 SCCT NG 1982 23.0 26.4 12,000
Knik Arm{h)
Unit #1 ST NG 1952 0.5 0.5
Unit #2 ST NG 1952 3.0 3.0
Unit #3 ST NG 1957 3.0 3.0
Unit #4 ST NG 1957 3.0 3.0
Unit #5 ST NG 1957 5.0 5.0
Homer Electric Association
Kenai
Unit #1 0 0 1979 0.9 0.9 15,000
Pt. Graham
Unit #1 0 0 1971 0.2 0.2 15,000
Seldovi ai
,~-~-\
Unit #1 0 0 1952 0.3 0.3 15,000
Unit #2 0 0 1964 0.6 0.6 15,000
Unit #3 0 0 1970 0.6 0.6 15,000
r-TABLE D.14 (Sheet 3 of 5)
EXISTING GENERATING PLANTS IN THE RAILBELT REGION
Nameplate Generating
Prime Fuel Capacity Capacity Heat Rate
Plant/Unit Mover Type Date (MW) @ 0°F (MW) (Btu/ kWh) -!"""' Matanuska Electric Association
Talkeetna .,....
t
Unit #1 D 0 1967 0.9 0.9 15,000
!"'"" Seward Electric System
SES(j)
Unit #1 D 0 1965 1.5 1.5 15,000
Unit #2 D 0 1965 1.5 1.5 15,000
Unit #3 D 0 1965 2.5 2.5 15,000
~
Military Installations -Anchorage Area
P""' Elmendorf AFB
Total Diesel D 0 1952 2.1 10,500
Total ST ST NG 1952 31.5 12,000
Fort Richardson
Total Difsjl(c) D 0 1952 7.2 10,500
Total ST 1 ST NG 1952 18.0 20,000
Golden Valley Electric Association
Healy Coal ST Coal 1967 64.7 65.0 13,200
He a 1 y Di ese 1 {c) D 0 1967 64.7 65.0 10,500
North Po 1 e .-
Unit #1 SCCT 0 1976 64.7 65.0 14,000
·~ Unit #2 SCCT 0 1977 64.7 65.0 14,000
~~
! Zendher
GTl SCCT 0 1971 18.4 18.4 15,000
GT2 SCCT 0 1972 17.4 17.4 15,000
GT3 SCCT 0 1975 2.8 3.5 15,000
GT4 SCCT . 0 1975 2.8 3.5 15,000
.....
Combined Diesel D 0 1960-70 21.0 21.0 10,500
,...
'"--,_
TABLE D.14 (Sheet 4 of 5)
EXISTING GENERATING PLANTS IN THE RAILBELT REGION
,.:-~,
Nameplate Generating
Prime Fuel Capacity Capacity Heat Rate
Plant/Unit Mover Type Date (MW) @ OOF (MW) (Btu/kWh),,n
University of Alaska-Fairbanks
51 ST Coal 1.50 1.50 12,000
52 ST Coal 1980 1.50 1.50 12,000
53 ST Coal 10.0 10.0 12,000
D1 D 0 2.8 2.8 10,500
D2 D 0 2.8 2.8 20,500
Fairbanks l~unicipal Utilities System
Chen a
Unit #1 ST Coal 1954 5.0 5.0 18,000
Unit #2 ST Coal 1952 2.5 2.5 22,000
Unit #3 ST Coal 1952 1.5 1.5 22,000
Unit #4 SCCT 0 1963 5.3 7.0 15,000 t:':""">
Unit #5 ST Coal 1970 21.0 21.0 13,320
Unit #6 SCCT 0 1976 23.1 28.8 15,000
Diesel #1 D 0 1967 2.8 2.8 12,150 r"'"
Diesel #2 D 0 1968 2.8 2.8 12,150
Diesel #3 D 0 1968 2.8 2.8 12,150
r-
Military Install at ions -Fairbanks
Eielson AFB
51, 52 ST 0 1953 2.50
53, 54 ST 0 1953 6.25
Fort Gree 1 ey
D1' 02 . ?3 ( i ) D 0 3.0 10,500 ,~
D4, D5C 1 D 0 2.5 10,500
Ft. Wainwright(j)
s1c ·F, s3, s4 ST Coal 1953 20 20,000
55 1 ST Coal 1953 2
-
r-l
Legend H
Notes
0
SCCT
RCCT
ST
CCCT
NG
0
TABLE 0.14 {Sheet 5 of 5)
EXISTING GENERATING PLANTS IN THE RAILBELT REGION
Hydro
Diesel
-Simple cycle combustion turbine
-Regenerstive cycle combustion turbine
-Steam turbine
Combined cycle combustion turbine
Natural gas
Distillate fuel oil
(a)Average annual energy production for Eklutna is approximately 148 GWh.
{b)All AMLP SCCTs are equipped to burn natural gas or oil. In normal
operation they are supplied with natural gas. All units have reserve
oil storage for operation in the event gas is not available.
(c)These are black-start units only. They are not included in total capacity.
(d)Units #5, 6, and 7 are designed to operate as a combined-cycle at plant.
When operated in this mode, they have a generating capacity at OoF of
approximately 139 MW with a heat rate of 8500 Btu/kWh.
(e)Jet engine, not included in total capacity.
{f)Beluga Units #6, 7, and 8 operate as a combined~cycle plant. When operated
·in this mode, they have a generating capacity of about 178 MW with a heat
rate of 8500 Btu/kWh. Thus, Units #6 and 7 are retired from 11 gas turbine
operation .. and added to 11 Combined-cycle operations ....
(g)Average annual energy production for Cooper Lake is approximately 42 GWh.
{h)Knik Arm units are old and have higher heat rates; they are not included in
in total.
(i)Standby units.
(j)Cogeneration used for steam heating.
Source: Battelle Pacific Northwest Laboratories. Existing Generating
Facilities and Planned Addition for the Rallbelt Reg1on of Alaska,
Volume Vl, September, 1982; updated by Harza-Ebasco Sus1tna Jo1nt
Venture, 1983.
TABLE 0.15: SCHEJ)JLE lF PLANNED lJTILITY JliDITIOOS (1982-19ffi)
Avg. Energy
Utility Lnit Twe Year (GWl)
)..,--,-·-.,
flPA Broc!ley lake Hyjro. ~.0 1988 347
;::-~
flPA G--ant Lake Hjdro 7.0 1988 33
mTAL 97.0
r---,
-
TABLE 0.16: CPERATING AND Ecoo-1IC PJlR.Lil'IETERS Fffi SELECTED HYLROELECTRIC PLANTS
r Max. Average (1981 $) Econanic2
G-uss Installed Jlilnual Plant Capital Cost of
rea:~ Capa:ity Energy Foctor Costl Energy
rb. Site River (ft) (lvW) (GW1) (%) ($lcP) ($/lcm KWl)
1 SnaN SnON 690 50 220 50 255 45 -2 Bruskasna 1\enana 235 l) 140 53 239 113 ' 3 Keetna Talkeetna 3lJ 100 395 45 463 73
4 Ca:he Talkeetna 310 50 220 51 564 100 ,-5 BroW'le fEn ana 195 100 410 47 625 59
6 Talkeetna-2 Talkeetna 350 50 215 50 500 90
7 Hicks Matanuska 275 60 245 46 529 84
8 Dlakcr:hama3 Olaka:hatna 945 500 1925 44 1480 l) ,_
9 Allison A 11 i son Creek 1270 8 33 47 54 125
10 Strandline
Lake Beluga 810 20 85 49 126 115
!l!ll/lil!l.
,...,. rbtes:
I
(1) Including engineering and ownerts-administrative costs but excluding AFDC. -(2) Including IDC, Insurance, Amrtization, and QJeration and Maintenance Costs.
{3) Jlil independent study by Bechtel has proPJsed an installed capa:ity of 3lJ f>'W,
1500 GWl annually at a cost of $1,405 million {1982 dollars), incllrling AFDC.
TABLE 0.17: RESULTS OF ECONOMIC ANALYSES OF ALTERNATIVE GENERATION SCENARIOS
Installed Capoc1ty (fi'W) by Total Systan Tota 1 Systan
Category in 2010 Installed Present hbrth
Generation Scenario OJP5Run 1nennal R}dro Capocity in Cost -
lype t:escn pt 10n Locrl Forecast Id. fib. Coal Gas Uil ana ~r.w) ($1o6)
All Thennal fib Renewa 1 s ~illTI L.ME1 900 001 50 144 1895 8131
Thenna 1 Plus fib Renewals Plus: r-.b:::li l1Tl L7Wl 600 576 70 744 19Xl 7000
Alternative Chakochffitla ( 500) L 1993
H}dro Keetna (100)-1997
No Renewals Plus: r-.b:::li l1Tl LFL7 700 501 10 894 7040
Chakochama ( 500)-1993
Keetna (100)-1997
mw ( 50)-2002
No Renewa 1 s Plus: ~ilJTI LWP7 500 576 60 822 1958 7~4
Chakochffitla (500)-1993
Keetna (100)-19%
Strandline (20)t
Allison Creek (8),
Snow ( 50)-1998
No Renewals Plus: ~ilJTI LXF1 700 426 822 1978 7041
Chakochffitla ( 500)-1993
Keetna (100)-1996
Strandline (20),
Allison Creek (8),
mw (50)-2002
No Renewa 1 s Plus: M=dillTI L403 500 576 ]) 922 2028 7008
Chakochffitla (500)-1993
Keetna ( 100) -1996
mw (50), Coche (50),
Allison Creek (8),
Talkeetna-2 (50),
Strandline (20)-2002
Notes:
(1) Installed caoacity. >; ':l: j J ) I J
.. ~
T.ABLE 0.18: SIJ.MllRY IF 1HERMl1l ~ERATING RESCX.RCE PLJWT P~Sn98~~ -CaJbined Gas
~lR.J Turbine Diesel
Parareter 2001-W 70 r.w lOMol
!-eat Rate ( Btu/kWl}
Earliest Availabil1ty i~oco ~~ i§M200 i§oo500
1M Costs
,/""'\
Fixed W1~($/~ 16.83 7.25 2.7 0.55
Variable $/ ) 0.6 1.69 4.8 5.l3
i~ Mages
Pl armed Mages t%) 8 7 3.2 1
Forced Mages ( ) 5.7 8 8 5
Constroction Perioo (yrs) 6 2 1 1
Startup Tirre (yrs) 6 4 4 1
Unit Capital Gost ($/kW)l
Railbelt -1,075 627 856 &luga 2 ()51
tEn ana 2:107
!""' Unit Capital Gost {$/kW)2
Rail belt 2,242 1,107 6:E g;g
&luga -,.,..,, tEnana 2,3)9
NJtes: -,!""""
fB fls estimated by Battelle/Ebasco without JlfOC.
Inclooing !DC at 0 ReCent escalation and 3 percent interest,
assuning an S-shapea expenditure curve.
Source: Battelle 1982, Vol. II, IV, Xi!!, XIII
TJlBLE 0.19: (3~u~~E 1 ~DJ~~s)ffi BELLrA MEA STATIOO(a)(c)
Cons~r~tion Labor Cll nsuranc:e ~tr'f,tion pp 1es ~S~1rflJ5or Equiprent Rent We~~~ Stbcontroc:ts Di~ta~st
1. Lmprovements to Site $ 350,00) $ 2,100 $ $ ~1,00) $ 110,00) $ $ 1,1>3,100
2. Earthwork and Piling 2,541,00) 3,1388,00) 5,7()),00) 16,00) 12,151,00)
3. Circulating Water System 2,511,00) 174,200 2,391,cro 1,235,00) 10,00),00) 16,311,200
4. Concrete 5,733,00) 540,00) 1,(91,00) 2,137 ,00) 9,751,00)
5. StS~~~sSteel, Lifting Equip., 1,757,00) 7,155,00) 8,912,00)
6. Buildings 682,00) 8)),00) 1,482,00)
7. Turbine-Generator 1,8)),00) 19,500,00) 21,3)),00)
8. Steam Generator and Accessories 15,764,00) 21,00),000 37 ,564,00)
9. Air Q.Ja 1 i ty Contro 1 System 12,400,00) 27 ,100,00) 39,500,00)
10. Other Mechanical Equipment 8,950,00) 8,950,00)
11. Coal a1d Ash Handling 576,00) 1,500,00) 5,ooo,cro 7 ,076,00)
12. Piping 14,435,00) 9,00),00) 23,435,00)
13. Insulation and L~ging 1,500,00) 1,500,00)
14. Instrurentation 3,00),00) 3,00),00)
15. Electrical Equipment 1,00),00) lJ,OO),OO) 31,00),00)
16. Painting 1,015,00) 1,100,00) 2,115,00)
17. Off-Site Facilities 3,00),00) 3,00),00)
18. Waterfront Construction 600,00) 600,00)
19. Stbstat ion 1,275,00) 22,00) 92,00) 2,6ffi,OOO 4,075,00)
20. Indirect Construction Cost ~
Jlrchitect/Engineer Services b) 44,515,00) 50,~7,00) 2t562,00l 2,004,00) 9,00) 100,077 ,00)
Stbtotal $1()), 354,00) $55,533,3)) $2,562,00) $12,265,00) $103,348,00) $53,100,00) $333,162,3))
Controc:tor's Overheoo and Profit 21,00),00) 9,00),00) 3),00),00)
Contingencies 47,00),00)
TOTAL PROJECT fiST $410,162,DJ
(a) ltle gp?Jecalncost esfima~e ras devel~ped ~y S •. J. crovfs iiJd SOOs ~Cil~ •. rt> all~w~~ ~tE~t for ~d ~ ~Cil~rights, client charges OWl r 1mstra 1on , axes, 1n eres dur1ng cons ruct1oo or tr sm ss1oo cos s e t s s at1oo SWl c Y •
(b) Inc1txles $~~ f{l! for fonstructio9 f~6 H1tnJ·~ for en~ineerin~se)vifeff ~ $29~548~ f~f other 1 1ndil~~costf incltxling construction equ1prent 66 s, cons rue 100 re a u ngs serv1c s, norm ua s a sa ar1e , era payro re a cos s.
(c) Source Battelle 1982, Vol. XII.
TJ\BLE D.a:l: (S~u~~E 1 ~lbCVl~s)rn NEr-LLWA J-IREA SfATHl~(a}(c}
Con~r'fntion Lct>or nSurillCe Co~'(ltion 1es E~ui~t Re a1 ctlor Equiprent Rent ~re~~~ St.bcontrocts DiJglatost
1. hnprovements to Site $ 350,an $ 2,100 $ $ ~1,an $ 110,an $ $ 1,353,100
2. Earthwork and Piling 2,1oo,an 13,CXXl 5,400,an 16,an 7 ,529,CXXl
3. Circulating Water System 2,561,CXXl 174,200 2,391,an 1,235,an 11,500,an 17,861,200
4. Concrete 5,982,CXXl 540,CXXl 1,cm,CXXJ 2,l37,an 10,CXXl,CXXl
5. StS~~~sSteel, lifting Equip., 1,757,CXXl 7 ,155,CXXl 8,912,CXXl
6. Buildings 682,an ro.>,an 1,482,CXXl
7. Turbine-t:enerator 1 ,ro.> ,CXXl 19,500,an 21,lXJ,CXXl
8. Steam Generator and Accessories l5,662,CXXl 1l3,CXXl 12,an 21,81J,CXXl 37,612,CXXl
9. Air QJality Control System 12,400,CXXl 27,100,an 39,500, CXXl
10. Other fvkhM!ical Equiprent 8,950,an 8,950,CXXl
11. Coal and Ash Handling 1,937 ,CXXl 18,CXXl 150,CXXl 5,785,(00 7,~,CXXl
12. Piping 14,435,an 9, CXXl, CXXl 23,435,CXXl
13. Insulation and Lagging 441,CXXl 46,an 11,CXXl 1,049,CXXl 1,547 ,CXXl
14. Instri.JTentation 3,CXXl,an 3,an,CXXl
15. Electrical Equipment 12,7a:l,CXXl 1,150,an ro.>,CXXl 18, CXXJ, an 32,670,CXXl
16. Painting 1,142,CXXl 58,an 25,an 575,CXXl l,ro.>,CXXl
17. Off-Site Focilities 4,827 ,CXXl 3,600,CXXl 3,260,an 11,687 ,CXXl
18. Waterfront Constroctim N/A
19. Substation -Switchyard 1,623,CXXl 34,an 143,an 3,017,an 4,817,CXXl
20. Indirect Constroction Cost ~ Architect/Engineer Services b} -54;943,cm -42;560,cm ·2;882,ffi) -2;617-,cm ------9,00J .... -.. 103;011,()))
Stbtotal $135,352,an $44,733,JXJ $2,882,CXXl $17,141,CXXl $132,748,CXXl $11 , 500 ,an $344,l56,JXJ
Contractor•s Overhead and Profit 21,CXXl,CXXl 9,an,CXXl ]), CXXl, CXXl
Contingencies 47,CXXl,CXXl
TOTAL PROJECT COST $42l,li6,:m
NJA = t'bt Jlpp l iciD le.
(a} rue g:<;>Jeccdncost eslim~e ras devel~~ ~ydS •. J. trovis m ~ns ~an~ •. rtl allw~e ~t~£~tetfor ~d oo~ ~~rights, client charges O\'ll r 1n1stra 1on , axes, 1n res urmg cons rue 100 or r sn ss1m cos s e.}Q s s a 100 sw1 c y •
{b) Includes ~8t~'w. for tonslr.octi~ £:?6 Ha 1 m,~ for al~ineerin~serviteff ffl $30~89~ f~t other 1 1ndif~~costf including construction equ1pment s, cons roc 1on re a u ngs servlC s, norm ua s a sa ar1e , era payro re cos s.
(c) ~urce Battelle 1982, Vol. XII.
TABLE D.21: BID LINE ITEM ~10s)FOR NATURAL GAS-FIRED COMBINED-CYCLE
200-f'4J Station c (January 1982 £bllars)
~r~~~p~~or ~pprfMon R~S~i~or Equiprent Rent ~~pq~~ DiJ2t~st
1. bnprovanents to Site $ 95,600 $ $ 109,700 $ 83,700 $ 13,00) $ lJ2,00J
2. Earthwork and Piling 313,00) 2,666,3)) 87,3Xl 151,600 3,218,200
3. Circulating Water Syst811 2,455,600 484,400 16,100 28,500 4,400,00) 7,134,600
4. Concrete 3,450,700 348,00) 372,700 226,600 1,496,00) 5,894,00)
5. Structural Steel Ct1d Life Equiprent ])5,00) 1,900,00) 2,205,00)
6. Buildings 192,200 491,00) 683,200
7. 1-efu §ecover~~s~toGas 5,197,200 172,500 250,00) 31,200,00) }},819,700 ur 1nes, er rs
8. Steam Turbines and Generator 3,631,900 115,00) 200,00) 8,600,00) 12,546,900
9. Other M=cha1ical Equiprent 2,588,700 115,00) 65,00) 4,946,200 7,714,900
10. Piping 3,164,500 345,00) 120,00) 4,500,00) 8,129,500
11. Insulation and Logging 126,500 86,:nl 50,00) 250,00) 512,3Xl
12. Instrurentation 379,500 46,00) 10,00) 700,00) 1,135,500
13. Electrical Equiprent 4,586,00) 57,500 15,00) 5,250,00) . 9,~,500
14. Painting 632,600 11,500 2,500 500,00) 1,146,600
15. Off-Site Facilities 2,451,400 211,00) 3,621,100 2,693,600 979,200 9,956,400
16. Waterfront Construction 14,400 31,80) 23,700 131,700 201,600
17. Sttlstation 948,3Xl 23,00) 10,00) 4,035,500 5,017 ,:nl
18. Construction Camp Expenses 4,292,400 12,362,00) 16,654,400
19. Indirect Construction Costs ~g 26,341,900 4,313,900 1,301,600 1,588,700 33,546,100
Architect/Engineer Services )
5,518,900 69,393,400 162,978,00) SUBTOTAL 61,167,900 21,357,500 5,540,lXl
Contractor's Overhead and Profit 15,00),00) Contingencies
WTJlL PROJECT COST 22,224,200
$200,202,200
(a) lWar~~jfck~~~~ ~~Wfsir~fl~f,et~, binfer~st ttoJr~ ~n~&:wmagf • tr~~l ~~~~~o~fs ~~~ f~ili~~i~ crifgJlg~~~: 1 ient
(b) Jgg~~~tl~·~~?~~ 6S~lar,g~~~n~e~~~J~;sn~~~~t 7~~fPDst9~~~~;r arigd~~~f g~~1 1~~~l~ gg~{~~uction equipment and tools,
(c) Source Battelle 1982, Vol. XIII.
i '1
i l J 1 71
I J
-TABLE 0.22: ECONOMIC ANALYSIS SUSITNA PROJECT -BASE PLAN
1982 Present Worth gf System Costs
$ X 10 ,_
1993-Estimated 1993-Plan Components 2020 2020 2021-2051 2051
Non-Susitna 600 MW Coal-Beluga 3,930 479 3,386 7,316
400 MW Coal-Nenana
840 MW GT ,_
200 MW CC
Susitna 1020 llo1W Watana 3,396 316 2,093 5,489
?'""" 600 MW Devi 1 Canyon
490 MW GT
200 MW CC
Net Economic Benefit 1,827 r-of Susitna Plan
l'""''
TABLE 0.23: ~ORECASTS OF ELECTRIC POWER DEMAND NET AT PLANT
Reference -2 Percent r---l
Case DRI DOR Escalation
Year Mw GWh MW GWh MW GWh MW GWh
1990 844 4054 850 4085 793 3808 848 4072
2000 1020 4898 1158 5558 950 4567 959 4610
r-""'\
2010 1306 6280 1599 7681 1206 5799 1168 5628
2020 1672 8039 2208 10615 1528 7364 1422 6868
-
-
,..
,....
r-
1
TABLE 0.24:-
Plan
Reference Case
ftln-Sus i tna
Susitna
au
ftln-Susitna
Susitna
em.
N:Jn-Susitna -
Susitna
-2 Percent
ftln-Susitna
Susitna
-CL£CTRI£ -ffinffi £EMl\ND SENSITIVITY JlNilJ...YSIS
1982 Present W::lrth of Systan U:lsts ret ~efits
-$X lofi $X 1o6
1993-Estimated 1993
2020 2020 3)21-2051 2051
393) 479 3l36 7316
3396 316 2003 5489 1827
4~ 624 4330 9286
4004 499 3384 7468 1818
2640 334 2392 5032
3259 283 1858 5117 -85.2
1941 186 1056 2997
3220 263 1711 4931 -1934
TABLE D.25: DISCOUNT RATE SENSITIVITY ANALYSIS
1982 Present Worth of System Costs ($ x 106)
Real Net
Oi scount Rate 1993-Estimated 1993-Economic
Plan (Percent} 2020 2020 2021-2051 2051 Benefit
!"'__..__,
Non-Susitna 2 4,829 457 5,418 10,247
,~~-:'
Sus itna 2 3,679 276 3,058 6,737 3,510
Non-Susitna 3 3,930 479 3,386 7,316
Susitna 3 3,396 316 2,093 5,489 1,827
Non-Sus itna 5 2,669 562 1,374 4,043 r··,--,
Susitna 5 2,925 423 1,048 3,973 70
r·-
~-
TABLE 0.26: · ·GAP.IT.AJ:.. ·aJST-SENSITIVITY· .ANALYSIS
.-1~-Present WJrth of Systen Costs ( $ x 1o6)
rEt
,_ Plan
1993-2010 2010 Estimate:! 2011-2)51 1993-2051 ~rw~c -Watata C~tal Coats Costs up · · Percent ,_
rtm-Susitna 3,93) 479 3,l36 7,316
Susitna 3,839 347 2,DJ 6,139 1,117
,..... Watana Capita 1 Costs i Costs Less 23 Rercent
flbn-Susitna 3,93) 479 3,l36 7,316
r-Susitna 2,977 2ffi 1,899 4,876 2,440
!"""'
r-TABLE D.27: · FUEL PRICE -SENSITIVITY ,LINll.L YSIS
-I·
1982 Present WJrth of Systen ilists ($ x lo6)
Costs of Costs of flet
rbl-Susitna Susitna Econanic
Ploo P1an Benefits
I"'"'
Reference Case 7,316 5,489 1,827
Fuel Costs Increase:!
r-· 20 Percent 8,281 5,607 2,674
F ue 1 Costs !kreased
20 Percent 6,474 5,418 1,056
,...
TJlBLE 0.28: Sl.M'111RY CF SENSITIVITY ftNAL YSIS IN!:I:XES
Cf" NET ECQ\OvliC BENEFITS
BASE REFERENCE CASE ~$1,827 MILLHX'~)
Oil Price Forecast au
1m
-2 Percent
Oi scount Rates
High (5%)
l..oil (2%)
Wata1a Capital Cost
+ 20 Percent
-23 Percent
Fuel Price
+ 20 Percent
-20 Percent
Real Fuel Price Escalation
l'b Esc a 1 at ion after 2020
Index. Values
100
100
-5
-leD
4
192
61 134
146
58
53
l ,,m-J] l l ,.r----~1 ----'l 1
TABLE D.29: BATTELLE fll TERNATIVES SlWY Fffi RAILBEL T CANDIDATE ELECTRIC ENERGY GENERATING TECHNOLOGIES
Resource Principal Sources Fuel Base for Railbelt , , Conversion Generation Technology Tfiical · Jlpp ication Availabilit~or Canrerci a 1 er
Coal Beluga Field, Cook Inlet Crush Direct Fired Steam-Electric Baseloa:l Currently Available
l'elana Field, 1-Ealy Gasification , Direct-Fired Steam-Electric Baseloa:l 1985-1990 Carbined C)(: le Base load/C.}(: ling 1985-1990 Fuel-Cell -Carbined-C.}(:le Baseloa:l 1ID-1995
L iquefoction Direct Fired Steam-Electric Baseloa:l 1985-1990
Carbined C~le Baseloa:l/~ling 1985-1990
Fuel-Cell tation Base 1 oa:l/ :}(: 1 i ng 1985-1990
Fuel-Cell -Carbined-C.}(:le Base load 1ID-1995
Natural Gas Cook Inlet Direct-Fired Steam-Electric Baseloa:l Currently Available
t-brth Slope Carbined C~le Baseloa:l/~ling Curren~ Available Fuel-Cell tation Baseloa:l/ :}Cling 1985-1 .
Fuel-Cell -Carbined-C.}(:le Baseloa:l 1ID-1£l5 Carbustion Turbine Baseloa:I/C.}(:ling Current y Available
Petroleun Cook Inlet Refine to Direct-Fired Steam-Electric Baseloa:l Currently Available
rt>rth Slope distillate and Carbined C~le Base load/~ ling Curren~ Available residual fractions Fuel-Cell tations Base 1 o?J:J/ :}(: 1 i ng 1985-1
Fuel-Cell -Carbined-C.}(:le Base load liD-1995 Carbustion Turbine Baseloa:l/~ling Currently Available Diesel Electric Baselooo/ :}Cling Currently Available
Peat Kenai Peninsual rt>ne Direct-Fired Steam-Electric Baseloa:l Currently Available
Lower Susitna Valley Gasification Direct-Fired Steam-Electric Baseloa:l 1ID-2Cro
Garb i ned C)(: 1 e Baseloa:I/C.}(:ling 1ID-2Cro
Fuel-Cell -Carbined-C.}(:le Baseloa:l 1ID-2Cro
Mmicipal Refuse Jlnchor~ Sort & Classify Direct-Fired Steam-Electric Base loa:l( a) Currently Available
FairbcrJ s
~Waste Kenai fug Direct-Fired Steam-Electric Baseloa:l(a) Currently Available
Jlnchorage falcrJa Fairbanks
TABLE 0.29 Continued
Resource Principal Sources Fuel Eeneration
Base for Railbelt Conversion Technology
G:othermal Wrangell Mountains
Chigmit Mountains
Hot Dr~ Rock-Steam-Electric
Hydrot ermal-Steam-Electric
Hydroe 1 ectric Kenai Mountains Conyent ion a 1 H}droe 1 ectric
Alaska Range Sma 1-Scale HJ9roelectric
~crohydroelectric
Tidal Po1t.er Cook Inlet Tidal Electric
Tidal Electric w/Retime
Wind Isabell Pass L~ Wind Energy ~tans Offshore Sna 1 Wind Energy ~tans
Coastal
Solar Throughout Region Solar Photovoltaic
So 1 ar Therma 1
Lraniun lrrp:>rt Enridment & Light Water Reactors
Fabrication
(a) SupplEJ!Bltal firing (~/coal) W)Uld be required to supjX)rt base loa:!
pperat1oo due to c)1;1lcal fuel supply. (b) May be baseloa:l/cycl1ng or fuel saver depending t4J0n reservoir capacity.
J l
~f{ical ftpp icatioo
Baselooo
Base loa:!
Baselooo/Cycling
(b)
Fuel Saver
Fuel Saver
Baseloa:I/Cycling
Fuel Saver
Fuel Saver
Fuel Saver
Fuel Saver
Baselooo
'I
I
Availabilit~or
Carrrerc i a 1 er
19!:0-200)
Currently Available
Currently Available
Currently Available
Currently Available
Currently Available
Currently Available
1985-1~ 1985-1~
1985-1990
1995-2cm
Currently Available
!"""'
TABLE D.JJ: MTTELLE PlTERNATIVES STIJDY, Sl.f+\llRY CF 00ST JlND
· · · · · · PERFffiMil.NCE CHilAACTBHSTICS -CF-SELECTEO AL !ERNATIVES
CapJity Aver:r .Llnnua Capital Varitble
Alternative a) ~~~j f~fi 1 tbil ity tp;J;~Y f§7~w) H7i;Wr ~lls/khtl) (~)--.
Coal Steam-Electric (Beluga) 200 lO,CXXl 87 201) 16.70 0.6
Coal Stean-Electric (f'Enana) 200 10,00) 87 2150 16.70 0.6
Coal Gasifier-Gambined Cycle 2al 9,~ 85 14.00 3.5
Natl. Gas Carbustion Turbines 70 13,800(b) 89 T5J 48
Natl. Gas Carbined Cycle 200 8,200(c) 85 1050 7.-JJ 1.7
Natl. Gas Fuel Cell Stations 25 9,200 91 sg) 42
Natl. Gas Fuel Cell Garb. Cyc. 200 5,700 83 50
Bradley Lake H}{lroelectric 90 94 3!1-7 31~ 9
Olaka:hama H}{lroe 1 ec. ( 33J rvw) (d) 33J 94 1570 l360 4
r Olaka:hama H}{lroe 1 ec. ( 480 rvw) (e) 480 94 1923 2100 4
l_pper Susitna (Watana I) 600 94 3!1-59 4669 5
LPper Susitna (Watana II) 340 94 168 5
LPper Susitna (l:elil Canyoo) 600 94 333!1-2263 5
,,...... Snow Electric 63 94 220 5850 7
Keetna H)droelectric 100 94 395 5480 5
Strandline Lake H}{lroelec. 20(17) 94 85 7240 44
r-BrMle H}{lroe 1 ectric 100(00) 94 43J 4470 5
Allison H}{lroelectric 8 94 37 4820 44
r ~ant Lake H}{lroelectric 7 2840 44
Istbell Pass Wind Farm 25 36 8 24~ 3.70 3.3
Refuse-Derived Fuel
Steam Electric (Jlnchor~e) 50 14,00) N/A 2980 140 15
Refuse-Derived Fuel
Steam Electric (Fairbanks) al 14,())) N/A 3320 140 15
(a) Configuration in parentheses used in cnalysis of Railbelt electric energy plus taken fran earlier
estim tes (Alaska Po~ Authority 1900)
(b) A heat rate of 12,cm Btu/khtl was used in cnal,Y.Sis of Railbelt electric energy ilanso 13,00) Btu/khtl
is pro!;ltbly rrore re~sentative of partial loa:! ~ratioo charocteristic of ~ ing duty.
~c} .Lln earlier estimate of 8500 Btu/khtl was used in t e cnalfsis of Rai"lbelt electric en~ plans.
d Configuratioo selected in ~reliminar;{. feasibility stLKlf Bechtel Ci)il and Minerals 1 )
r-e Configuration selected in ailbelt a tematives StLKly EBasco 1982b
TABLE 0.31: FINANCING REQUIREMENTS -$ MILLION
FOR 1.8 BILLION STATE APPROPRIATION
1 ~l 1
****~~****¢**9************~0**¢**~*~**~~*****~~~·*~*·*~**~~~**~*~**¢~4*0*****~~4~~~~~~*~~~~*~~~~***~**~~*0*~00~*~*~~~**~~~~~¢~¢ D~TA12K,D1L hATANA ION L1NE }9931-51,8 6NCS19821 ST~TE FV~CS-J~FLATJC~ 7t-1~1EREST lC~-C~FCCSl !5.15 B~ 23-JL~-~3 ·········~···~·······~····································~···················~~··················~·······~·····~···~··~,~·~···
73 F.N~RGV Glm
~21 RE~L P~ICE-~1Ll5
466 I~FLAT10N INDEX
121 I'~ ICI='-MILLS
-----INC~Mr----------------
)1" ·~ ~1/UlUt
17l l~SS CPE~ATI~G COSTS
>17 JPERATI~G I~C~~e
214 ACC l~TEREST F.A~~~C 0~ FUNDS
,; '> '' l <0 S S I NT E R c S T C N 5 H C R T T E R H 0 E 'lT 3~i L:SS I~T~RES1 CS LC~G l~R~ DEBT
541 ~~~ E~QNI~GS FR0H ~P~RS
-----CASH S::'URC~ A'ID I:SE----
~4i CASH I~CO~~ FRO~ CPFRS
446 iTATE CDNT~I~UTIGN
141 LO~G T~RM DE?T Q{A~DCW~S 243 WORCAP D~eT DRAWCCW~S
•i4l TOT ~L SllURC:'S ]F fUNDS
320 li:SS CAPITAL EXPE~DITUPE
443 LESS ~ORCAP AhD FUNDS
260 LESS DE3l REPAYMENTS
31~ LESS PAYMENT TO ST&TF
141 CASH SURPLUSCCEfiCITI 24o SHCRT TERM DC:eT
444 CASH RECrV~PfC
-----BALANCE SHE~T----------22·> RESEKIIE: A.'l~ CONT. FUND
171 OTHER WCRKI~G CAPITAL '.54 CA~H SIJRDL'JS RI:BI'IEO
170 CL~. ClPIT!l CXPfNOITUR[
~~~ ~T~T~ CS~:TPJ~tiTl:~~· 'f ~) 2 .::. r -r A 1:! c: :1 ~: ·\c."~ 1 r..: c-;
5 'i; ; ;:, e T ~1 U 1 :; T 'r ') l ~I~-"; 1-' C '( 1 F il.l>'
554 F~T U'JlST!<I·')J''.:O-Lr;r;r, TER:1
'i ,, 2 4~ ~IJ.\L De. e T 'J•· f-lh'D(r!N 11 'i'12
54] CU~. c=2T 0qAH~C~~N il~12 s1(1 JEeT s~~vJC[ ccv~r
1985
0
ll~=~·~ o.oo
c.o o.o
o. 0 c.o
c.o c.o
o.o
c.o 4C2.C
o.c c. a
402.0
402.0 c.o c.o
0.1)
c.o o.o o.o
c. c
c.o
'J.C
't c 2. c
4C2.C c .. c c.o o.c
c.c o.c o.oo
l'l86
0 c.co
135.59 o.oo
o.c o.c
c.c o.o c.o c.o
c.o
c.c
384.9
o.o c.c
3 84." c.c c.c c.c
c.o c.c c.o
c.c
c.o c.o
7P6. 9
7~6.<;
c.c c.o c.o
c.c c.c
IJ,OC
l:l B 1 1H9
C~S~ FLO~ SU~MAR~
===lt~ILLIO~I===•
0 0 0 o.co c.oo c.cc
l~s.ca 155.24 l6t.lC o.oo o.oo o.oc
c.o c.o
c.o c.o
o.o c.o
c.o
c.o
4~8.6
c.o o.a
42 A. 6
429.6 o.o c.c a.o
o.o c.o o.o
c.c
o.o o.o
1115.5
121~.5 c.o
'l.C c,n
c.r.
IJ.'l c.cc
o.u o.o
o.o o.o
o.o c.o
o.o
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572.8
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$1.8 BILLION (1982 DOLLARS) STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
SHEET 1 OF 6
3 73 .o
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TABLE 0.32
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$1.8 BILLION ( 1982 DOLLARS) STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
'1
J l
SHEET 2 OF 6
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TABLE 0.32
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7% INFLATION AND 10% INTEREST
SHEET 3 OF 6 TABLE 0.32
n
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=::::-::: .-::::; = = ";;:======.::: :::;: = =::;::::::; = ===:o-==== .;:.:::::::::;.:::.::: :::::::::::::::::::: =====-=== :;;:::::;::::::::::;:::
; r_~. T:: CC\T~ I ;::T I::. 2·:~~·7.3 2t s 7. 3 2t>'l7.) 21: '11 • 3 2'>f:7.3 .26F.7.3 26t17.1 Zo n. J
) ::__ T.\ I.'J-.:; 1rr:n:c J~22.1 3573.6 3'>~9.7 4377.1 4S3C,7 t'323.8 5%a.c ~2t:J.C
') ~ \JT cursrH.JI!\C-:;HcPT 1 [ R ~~ 7J~.J 7G4.7 ~2~.~ no. 2 91S.'1 sse.t 'l'lC.C ssc.c
:J E e T nUTSfAN01~G-LO~G H qr~ aJ5J • .3 e364.7 el51.3 Hll:.S 765e.2 7374.} 7f61.t 1Ctl.t
~. N~~:_; 1\L DeBT 'JI: A\~Wl' C~H~ t1>o2 r::. :::. c.c iJ.C c.o c.c c.c o.c 39E4 ol c u ~~. c ~ 2T ~R A rl'tt.) =:'1':-J II 'J8 2 JJ8'··1 );,~4.1 398 11.1 39!!4.1 Pe4.1 3984.1 3984.1 39e4.1
J[~T St.RVICE ccv:=R 1. ~ 1 I • 2 5 1.2~ 1.25 1.25 l. 2 5 1. 2 o; c.oo
$1.8 BILLION ( 1982 DOLLARS) STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
SHEET 4 OF 6 TABLE 0.32
l .... -l l -1 . -~ .1
ANNUAL PROJECT COSTS
Mills/kWh
Cost in .Real $ 1993 1994 1995 1996 1997 1998 1999 2000
Operating Expenses 8 10 10 11 11 12 13 14
Capital Renewals 0 8 9 10 10 11 1-2 12
Debt Service Cost 111 132 130 129 129 128 128 127
Total 119 140 149 150 150 151 153 153
2003 2004 2005 2006 2007 2008 2009 2010
Operating Expenses 16 17 18 18 19 20 20 21
Capital Renewals 14 15 15 16 17 17 18 19
Debt Service Cost 225 219 214 207 201 195 189 184
Total 255 251 247 241 237 232 227 224
2013 ' 2014 2015 2016 2017 2018 2019 2020
Operating Expenses 23 24 25 26 27 29 30 32
Capital Renewals 21 22 23 24 25 27 28 30
Debt Service Cost 171 166 163 159 157 155 153 150
Total 215 212 211 209 209 211 211 212
NOTE: FOR ANNUAL ENERGY SOLD, SEE LINE 73 OF SHEETS 1-3 OF THIS TABLE
ANNUAL ENERGY COST
$1.8 BILLION STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
SHEET 5 OF 6
l 1
2001 2002
14 15
13 9
126 224
153 248
2011 2012
22 22
19 20
179 174
220 216
2021
34
32
150
216
TABLE D.32
l
ANNUAL PROJECT COSTS
Mills/kWh
Cost in Real $ 1993 1994 1995 1996 1997 1998 1999 2000
Operatiny Expenses 4 4 4 4 4 4 4 4
Capital Renewals 0 4 4 4 4 4 4 4
Debt Service Cost 51 57 52 48 45 42 39 36
Total 55 65 60 56 53 48 47 44
2003 2004 2005 2006 2007 2008 2009 2010
Operating Expenses 4 4 4 4 3 3 3 3
Capital Renewals 3 3 3 3 3 3 3 3
Debt Service Cost 53 48 44 40 36 32 30 27
Total 60 55 51 47 42 38 36 33
2013 2014 2015 2016 2017 2018 2019 2020
Operating Expenses 3 3 3 3 2 2 2 2
Capital Renewals 3 2 2 2 2 2 2 2
Debt Service Cost 20 18 17 15 14 13 12 11
Tot a 1 26 23 22 20 18 17 16 15
NOTE: FOR ANNUAL ENERGY SOLD, SEE LINE 73 OF SHEET 1-3 OF THIS TABLE
J
ANNUAL ENERGY COST
$1.8 BILLION STATE APPROPRIATION SCENARIO
7% INFLATION AND 10% INTEREST
SHEET 6 OF 6
2001 2002
4 4
3 2
34 56
41 62
2011 2012
3 3
3 3
24 22
31 28
2021
2
2
10
14
TABLE 0.32
......! CUMULATIVE CASH FLOW (MILLIONS OF DOLLARS) I _, -~ ; § .. .. .. • .. § .. 0 0 0 0 0 0 0 D 0 0 0 D 0 D D I -i .. I I ;a ....1 • .. ~ I ,_J • • ~ (") • c .. ~:~~:~~~::~I~SJ~~!=!~::=J~=!=~:~mr~~:;~;?~'=?ll I 1 I 1 ·I I I -J s: ~ c • . r r.:.:.:.:.: :.:4:-:.:.:.x.:.:.:~:f! :.~· :((((((((((((ff:.((•)J((((I)))))J., 1 I I I I I I c..> ..... • );>=~ • .. Z<> cm--1 );>);>);> a • :0 z • -<Z);> l~!lllJJII!IIIlll"ll ~llill!lilft,l{f"l! llllll'~=:x.t''''''''*='===~=~=m~=~=:~;m-s;~ -0 a l l l I l ,'fl!ft.IIIJ; ~);>~ • ... . ... .. coz< • ~liljllllll~llllilllil jll!1llllljlliilli lfllllt~illilil! l:jll!IJIIII11'1l!l!l!l!1 l\l~llllll\f~!l1~lillilllil[!~ =ill\lll .. 1\:)zm i , D i ocr ~ l l -O>O l!lllillll!ill!ll!i1l [~lill\\1!! 111111111 !ifl~lllilll ·lllllll\111 llillll~; .. j < rr"'' ... ... ros= .. -~ >>m ~ll!!llilllilllllllfll .illllll !lt~llll ~~-i~illi: ~~~= """" .. l -:o(J)z ; "' ) • ::~: CJ):r:--1 .. ~~: 'T1 i illll!llllilll~tli 111 \ l l -r .. 0 ~ ii ~~j~~~~l\ijl~lil 1\ .. I I """" • I I 1 I I I ~ I • .. .. I l J I l I I l I -i • I I I . I l ' I I l I ...J j ... L "Tl 0 0 ... .. • i 8 • I ...J D D .g 0 ; 0 G) 0 0 D 0 c ANNUAL CASH FLOW (MILLIONS OF DOLLARS) ::D m 0 I .....1 .... I ...... ....
.-.
~ 2 0 0 0 .----.--------.----.-----.-----.-----~--.--1--, -.-~------.,--------.--------.-----. 4 0 0 ~
0 Ow ...J
...J
0 0
CUMULATIVE CASH Fl '\
~ Q
0 1 50 0 1-----1-----I-----~---J--------+----+---+---+----+---:.,.--:::.~t-::===~'f-------l 3 0 0 ~
(/) z
0
....1
_J
:2
'-'
~ ,
0 0
1----l---l---+----B:~.*:~f*r*~:=:::+~===b====~· /,~~~~~~~~~~::iij;[/I~Jz'l;:;:ll/;f/ll;:;::l!!i;:;::!Ji!<:Bi[/J<:B~~~~*'~j~~jj;r=M/[/;~/1/!:e::///[~'[/~l/!::i:j/ :.::;:iii.::;:III/I~Jifl;;;:/l~/l!~/~~·jli'"!ii!~jj"!!j"J!!iff.! ----lf-----1 ,
0 0
~
i 0 .1:::-·: ! ''!1''':'11!'1•.•1111
1
11111: 1'11·11111111111·
1
11111111/1 I!lfflll/1111111111
1
1 ,... {.. 0 i
0 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001
YEARS
DEVIL CANYON DEVELOPMENT
CUMULATIVE AND ANNUAL CASH FLOW
JANUARY, 1982 DOLLARS
]
2002 2003
FIGURE 0.2
1
5:..--.
0~
-l<(
LL-l
:c-1
wO
<(0
OLL
wO
> -(f)
1-z
<(0
-1-
:)...J
~....I
:)~
o~
0] l
,~00
6000
~500
5000 1--·--lf·---
4000 1---·+--+--·
s~oo 1---+----
5000
2000
2000
1~00 1------1----+-
1000 1----11----1~--
1ge2 198, 1984 198~ 1986 198F Hl88 19Bt IUO IStl 1~92 1119S 1994 1995 1996 1997 "" 1999 2000 2001 2001 2005
UAAS
SUSITNA HYDROELECTRIC PROJECT
CUMULATIVE & ANNUAL CASH FLOW ENTIRE PROJECT
JANUARY 1982 DOLLARS
6~0
100
~00
-l(f)
<(z
2~0 ~ 0 z_
Z-1
<(~
zoo ~
150
100
FIGURE 0.3
l 0 l
...... .r:: .s:
c:l
,...
c:l
a:::
w z
w
9000r-------,----------,----------,----------.----------,---------~·
aooor-------T----------T----------+----------+----------,_--------~
7000+-------+---------~----------+---------~-------
6000
5000
4000
THERMAL AND
OTHER HYDRO
GENERATION
1993 1995
ENERGY DELIVERIES
FROM Sl:JSISTNA
ALONE --+---'""'T""'WATANA AND DEVIL CANYON----~-
2000 2005 20 Hl 2015 2020
YEARS
ENERGY DEMAND AND DELIVERIES FROM SUSITNA
FIGURE D .4
....... .c.
~
~ ......
C/}
_.J
_.J
~
'-'
C/}
UJ
0
a:
0..
0 z
<(
C/}
t-
C/}
0
0
>-
C)
a:
UJ z
UJ
SYSTEM THERMAL COSTS AVOIDED BY DEVELOPING SUSITNA
COMPARED WITH BEST THERMAL OPTION IN MILLS PER UNIT
OF SUSITNA OUTPUT IN CURRENT DOLLARS
800 -
700
INCREASING THERMAL ______---:;::!
FUEL COSTS AVOIDED L/
600
/
500
400
300
200
~/
AVOIDS COSTS OF FURTHER --v ........
200 MW COAL~FIRED UNITS / /~ /v ~ .-.-/ .....---_ __..,..
,(__ /
-_../ r---..-
100
/ AVOIDS COST OF 200 I DEVIL CANYON ON STREAM IN 2002 J -=--... MW COALj"FIRED UNIT
WATANA ON / STREAM IN 1993 -0 I
,_--
94 2000 2005 2010 2015
YEARS
.-.-
SYSTEM THERMAL COSTS AVOIDED BY DEVELOPING SUSITNA
.-----
2020
FIGURE 0-5
SITE
PREVIOUS
STUDIES
ENGINEERING
LAYOUTS AND
COST STUDIES
CRITERIA
ECONOMICS
ENVIRONMENTAL
OBJECTIVE
ECONOMICS
4 ITERATIONS
SNOW ( S)
BRUSKASNA (B)
KEETNA ( K)
CACHE ( CA)
BROWNE ( BR)
TALKEETNA-2 (T· 2)
HICKS (H)
CHAKACHAMNA ( C H )
ALLISON CREEK ( AC)
STRANOLINE LAKE ( Sl)
DATA ON DIFFERENT
THERMAL GENERATING
SOURCES
COMPUTER MODELS TO
EVALUATE.
-POWER AND
ENERGY YIELDS
CRITERIA
ECONOMICS
• CH, K
~ CH t K Is
CH,K,S a THERMAL
LEGEND
. c H • K 'sIs L, AC
• CH ' K I s • SL I AC
-CH,K,S,SL,AC,CA,T-2 STEP NUMB~~
IN STANDARD
PROCESS
(APPENDIX A)
FORMULATION OF PLANS INCORPORATING NON-SUSITNA HYDRO GENRATION
FIGURE 0.6
]
"""' '
-
-
-
-
•••• ••••
••
... ~-t------
I 1"£1'11 ECUAl.S A,pPIRQ)CIMAf[L'f -40 M•Lf.S
6 G 0
0. 6:5 ... 2' ·tOO ...-w , .co .....
I, STDA"-C\.1~ L. '3. ••·us•t"s 2&. SOlO* !~. LAI<( .. ,LC*(~ 8(LUGA 14, COA~ 21. •uo.u LOWE~ 40, TOKICH1TIIIIA
3. ... C•EA" L4KE. "'· ~~. CMLrUT'IIILI, Zl. Gf:IOSTLt 41, T('lriiiTNA
4, .£~ ... •50111 '"~ ••• OHOO n. T&-~. 42. C.lT><f:DI'IAl. S..UI'S
~. :•£SCEiloT LAlli. 17. LO•t!lt CMUI.I""A XI. 811U5116"'A 4!. .10 .... 5010
~. GII'""T LAII( "· CACM( !1. ... A,. ns....:.. "~ . ... -£
T .. eCLLiM IAT 19 • G!lttt'ISTOfot: !Z. UP I'£~ 8£ LUGA ., . JUNCTION IS
e. v~(!lt MELLI£ JU.l" zo. T&uUTNA Z !3. COf'f££ 46. VACMOOI 1$
'· I'OW£• C!itt[ll ill. "''"""'' QOI'G( lot, GUI.U,.A "· 47. TAZil'IA
10, SILV[It ~.lA( zz. ll[ffN.t. lS. KlUT-••• K[NAI LAlli.
II • SOc 01110" GUlCH 23. SKEU' CltUIC sa. e•AOL[T lAA£ .,_ C"""ACI<-
'2. TUST\110("" 24. , .. ,,., .... 57. "'Cil'S SITE
25. TIK.ofiCI<UI.ITN<I !e. LOW£
SELECTED AL TERNATJVE HYDROELECTRIC SITES
FIGURE D. 7
PREVIOUS
STUDIES
UNIT TYPE
SELECTION
COAL: 100 MW
250 MW
500 MW
COMBINED CYCLE' 2~0 MW
GAS TURBINE : 75 MW
DIESEL : 10 MW
PLAN
FORMULATION
OBJECTIVE
ECONOMIC
COMPUTER MODELS
TO EVALUATE
SYSTEM WIDE ECONOMICS
EVALUATION
OBJECTIVE
GAS RENEWALS
NO GAS RENEWALS
ECONOMIC
NO GAS RENEWALS
LEGEND
STEP NUMBER IN
STANDARD PROCESS
(APPENDIX A)
FORMULATION OF PLANS INCORPORATING ALL-THERMAL GENERATION
FIGURE 0.8
'3,-------------------------------------------------------------------------
-3:
~
0 2
0
0 --.
>-
1-
()
!"""·
<(
a. 1
<(
() -
0 -I
-8
-
6
r-
J:
3:
Cl
0
0
;:4
• >--Cl a:
UJ z
UJ
2
1980 1990
TOTAL
DISPATCHED
ENERGY
1990
LEGEND
c=J HYDROELECTRIC
[]] COAL FIRED THERMAL
2000
YEAR
2000
YEAR
1955
1949
956
813
2010
2010
-~ GAS FIRED THERMAL
.. OIL FIRED THERMAL
CNOT SHOWN ON ENERGY DIAGRAM}
ALTERNATIVE GENERATION SCENARIO
REFERENCE CASE LOAD FORECAST
2020
2020
FIGURE 0.9
(/)
UJ
0
a: a..
0 z
<(
(/)
1-
(/)
0
0
>-
Cl a:
UJ z
UJ
l
BOO-~:---~---
-............ ----700 ~----------------~-----------------+----------------~-----------------r-_--~/~--------~
~ -l 0 0 % 0 E B T F IN AN C IN G ,-
MILL RATE COST BEST J/
600 -+-----------t--------------;-THERMAL OPTION ---
1
,,1-----+----------
7% INFLATION,
10%iNTEREST I
""' /1 L------------1-----------------: ~~//.
100% DEBT FINANCING / $1.8 BILLION STATE CONTRIBUTION
SUSITNA MILL RATE COST 1 SUSITNA MILL RATE COST
400-1--WITH 7% INFLATION, WITH 7% INFLATION, ----1 --
3 OO ············ ••·•·•••••1~ %•IN s.~.: .. ~ ••••••••••••••••;:.·• ;; ;; ... ·;:·.:: ... ::::· .• :·:) p -' -' -' 1 0% 1 N T E \ E S T
r INFLATIONARY FINANpt'N'a' .DEFJCIT:~:})~{:~::t-·-------\
:\:~\\~j~ll~~~~~l\l\\\l\ll\\~\\g~\§UJt%L&tt~¥Ji~:@~ --. - -----------~ -_1 -- -- -- --
200 MJ~ --------_/ O%·~~:~X~~~~~:.c~~~~~T
/ 100 ~---~---~N7.E~G~L~I~G~IB~IL+.E~~FI~N~A~N~C~I~N~G~D~E~F~I~C7-IT~~\I~T~H-Z~E~R~O-I~N~F~L~A~T~IO~N~_4r-------------.~~~--{-------------------~--
500
"" ...
SUSITNA COST WITH 0% INFLATION ,3~ IN TEA EST _A'
0 ~------------~~-------------+--------------~-------------+------------~
94 2000 2005 2010 2015 2020
YEARS
ENERGY COST COMPARJSON-0 AND 7% INFLATION
FIGURE 0.10
~ l l l
-
SUSITNA HYDROELECTRIC PROJECT
VOLUME 1
EXHIBIT D, APPENDIX D-1
FUELS PRICII~G STUDIES
-
I"""
I
-
-
-
APPENDIX D-1
FUELS PRICING STUDIES
Introduction
There are thermal alternatives to the Sus itn a Hydroelectric Project
fueled by natural gas or coal. The economic vi abi 1 ity of these
alternatives and their competiveness with the Susitna Project depend
heavily on the future availability and price of the required fuels.
The availability and price of fuels to meet Railbelt generation needs
through the year 2040 are analyzed in this Appendix. The primary fuels
that are analyzed are natural gas, coal, and distillate fuel oil.
There are other potentia 1 fue 1 s such as peat and wood, but these are
not discussed due to the findings of previous studies that these fuels
are not economically competitive when compared to natural gas and coal.
Multiple data sources were employed including previous studies by
consultants, information from state and federal agencies, and data,
plans and other information from electric and gas utilities in the
Railbelt Region of Alaska. Projections of future natural gas and
distillate fuel prices are tied to the future world price of oil.
Projections of future world oil prices are presented in Exhibit B,
Section 5.4 of the Application.
Results concerning the availability and price of natural gas, coal and
distillate oils are used as inputs into the Optimum Generation Planning
Model (OGP) in the determination of the cost of thermal generating
alternatives.
1. Natura 1 Gas
1.1 Resources and Reserves
Known recoverable reserves of natural gas are located in the Cook
Inlet area near Anchorage and on Alaska's North Slope at Prudhoe Bay.
Gas is presently being produced from the Cook Inlet area. Some of the
gas is committed under firm contract but considerable quantities of gas
remain uncommitted and could be used for power generation. There are
substantial recoverable reserves on the North Slope that could be used
for power generation, but until a pipeline or electrical transmission
line is constructed, the gas cannot be utilized. Undiscovered gas
resources are believed to exist in the Cook Inlet area and also in the
Gulf of Alaska where no gas has ·been found to date. Estimates of
potential gas resources in these areas have been made by the United
States Geological Survey and the Alaska Department of Natural
Resources. The quantities of proven, potential and undiscovered gas
from these areas are discussed below.
01-1
(a) Cook Inlet Proven Reserves
The locations of the Cook Inlet gas fields are shown in
Figure D-1.1. Estimated recoverable reserves from the Cook Inlet
fields and the commitment status of those reserves are shown in
Figure1 )o*.1.2. This table has been developed from an earlier
study~ and, updated and rearranged to reflect current
conditions. Recoverable reserves are from..)the Alaska Oil & Gas
Conservation Commission 1 S latest estimate.~L
New (~a.ntracts between Enstar and Shell & Marathon are
shown jJ in Figure D-1.2 as well as the five-year extension
of the Ph ill i ps/Mar<rahon LNG contract with Tokyo Gas and Tokyo
Electric Companies.~ ) Reserves that were formerly committed
to Pacific Alaska Liquified Natural Gas (PALNG) Company are shown
for reference purposes, but are included as uncommitted reserves,
since PALNG 1 s contracts for the gas expired in 1980. This is
discussed further under Section 1.2(c). Much of the proven gas is
not at present under contract. Figure D-1.2 shows that 1,654
billion cubic feet (BCF) of proven reserves is uncommitted.
In addition to proven recoverable reserves in the Cook Inlet area,
there is the possibility of additional supplies in the form of
undiscovered gas.
(b) Cook Inlet Undiscovered Gas
Earlier estimates of additional natural gas resources in the
Cook(~qlet area ranged from 6.7 trillion cubic feet (TCF) to 29.2
TCF. J These estimates may be high since subsequent
drilling by Mobil and Arco in Lower Cook Inlet has not resulted in
producing wells.
A recent study by the Department of Natural Resources of the State
of Alaska presents estimates of undiscovered gas and (%~1 and
assigns probabilities to finding those quantities. The
mean or average quantity that is expected to be found is about 3.0
TCF. The estimate is presented in Table D-1.1.
The Department also estimated 11 economically recoverable 11 resources
by assuming a recovery factor of 0. 9 and a minimum commercial
deposit size of 200 BCF. These are also presented in
Table D-1.1. with an estimate of undiscovered gas is about 2.0
TCF.
*References for the Natural Gas section are given on p. 01-23.
01-2
-
(c)
-
(d)
-
-
-
-
-
-
North Slope Gas
Estimated recoverab 1 e natura 1 gas reserves from the North Slope
are about 29 TCF for the Sadlerochit Reservoir at Prudhoe Bay.
Addit~qnal gas from the North Slope is estimated to be 4.5
TCF.t J The State of Alaska royalty share of Prudhoe Bay
reserves is 12.5% or 3.6 TCF. North Slope gas is currently either
shut-in or reinjected into reservoirs. to maintain pressure for oil
extraction since there is no pipeline to areas where the gas can
be utilized for electrical generation, heating or other uses.
Gulf of Alaska Gas
The Gulf of Alaska lies to the east of the Kenai Peninsula and
Anchorage and is close enough to the Railbelt area to be
considered as a potential source of gas for Railbelt electric
generation (see Figure D-1.3). To date, no oil or gas has been
discovered in the Gulf of Alaska. The United States Geological
Survey (U.S.G.S.) has, however, developed estimates of the
quantities of gas that might exist in the Gulf.
The U.S.G.S. presents its estimates of undiscovered gas in terms
of the probability of finding "economically recoverable" gas.
Economically recoverable resources are those that can be
economically extracted under price-cost relationships and
technologic9.~) trends prevailing at the time of the
assessment .l For their 1 ow estimate, there is a
probabi 1 ity of 95% that the estimated value wi 11 exceed. For the
high estimate, there is.a 5% probability that the estimated value
will exceed recovering the cost of those volumes. The U.S.G.S.
analysis can also be interpreted as having a probability of 90%
that the amount of undiscovered gas wi 11 be between the 1 ow and
high estimates. In addition to low and high estimates, the
U.S.G.S. also provides a mean value as the quantity of gas most
likely to be found. The U.S.G.S. estj~~tes for the Gulf of Alaska
Shelf (to a depth of 200 meters) are:\ J
Low 0.46 TCF
High 9.24 TCF
Mean 3.14 TCF
The estimate for the Gulf of Alaska Slope, i.e. those Gulf areas
with a water depth from 200 meters to 2,400 meters, is:
Low
High
Mean
0.36 TCF
3.70 TCF
1. 53 TCF
The long-term availability of Gulf of Alaska gas for electrical
generation is at this time highly speculative. First, the gas (if
Dl-3
any} must be found and developed; second, a pipeline must be
constructed to deliver the gas to where electric generation would
take place and third, the delivered price would have to be
competitive with alternative fuels. Therefore, at this time, gas
from the Gulf cannot be depended upon to supply Railbelt
generation needs.
1.2 Production and Use of Natural Gas
Natural gas is produced and used in Alaska for heating, electrical
generation, l iquified natural gas (LNG) export and the manufacture of
ammonia/urea. Most of the production and use (other than reinjection)
currently takes place in the Cook Inlet area but the large proven
quantities located on the North Slope and undiscovered potential in the
Gulf of Alaska make these areas worthy of consideration for future use.
Current and potential production from the three areas is discussed
below.
(a) Cook Inlet Cur~ent Production and Use
The production and use of Cook Inlet gas for the past five years
is shown in Table D-1.2. Gas that has been injected (or actually
reinjected) was not consumed and is still available for heating,
electrical generation, or other uses. The use of gas in field
operations is the gas consumed at the wells and gathering areas to
assist in the lifting and production of oil and gas. Use depends
on the level of activity in oil and gas production which has been
fairly constant over the last five years.
LNG sales are for export to Japan and the manufactured
ammonia/urea is exported to the lower forty eight states. These
uses of gas have been fairly constant in the past and are expected
to remain so in future years.
Natural gas is used for electrical generation by Chugach Electric
Association and Anchorage Municipal Light and Power. The use of
gas by both of these utilities has been increasing to meet
increases in electrical load and to replace oil-fired generation.
The military bases in the Anchorage area, Elmendorf AFB and Fort
Richardson, use gas to generate electricity and to provide steam
for heating. The military gas use has been fairly constant in the
past and is expected to remain so in the future.
The gas utility sales shown are made principally by Enstar and are
for space and water heating, and other uses by residential,
commercial, and industrial customers in the Anchorage area. These
sales grow with increases in population and increased use by
existing consumers. The growth is expected to continue in the
future and will increase when Enstar begins gas service to the
Matanuska Valley in 1986.
01-4
r~·-,
-
....
-
,....
' !
-
The item, Other Sales, shown in Table D-1.2 is a residual figure
according to the Alaska Department of Natural Resources and is the
difference between total sa 1 es as published by the Oi 1 and Gas
Commission and the sum of gas obtained from the utilities,
Phillips/Marathon, Collier Chemical and other large users.
(b) Cook Inlet Future Use
The future consumption of Cook Inlet gas depends on the gas
needs of the major users and their ability to contract for needed
supplies. Since there is a limited quantity of proven gas and
estimates of undiscovered reserves in the Cook Inlet area have yet
to be proven, gas reserves will be exhausted by the late 1990's.
In addition, there may not be sufficient gas for electrical
generation beyond some point because of higher priorities accorded
other uses, either through contract or by order of regulatory
agencies such as the Alaska Public Utilities Comission. To
estimate the quantity of Cook Inlet gas available for electrical
generation, the requirements and priorities of the major users are
discussed below.
Phillips/Marathon LNG currently have 360 BCF of gas under contract
and Collier Chemical has 377 BCF (Figure D-1.2). It is highly
probable that both entities will obtain enough of the uncommitted
gas in Figure D-1.2 to meet their needs through 2010. The reason
is that both Ph-Jllips/ Marathon LNG and Collier are established,
economically viable facilities. They are also owned by Cook Inlet
gas producers who control part of the uncommited reserves.
Phi 11 ips/Marathon LNG and Collier are therefore estimated to
consume 62 BCF and 55 BCF respectively per year from 1982 through
2010.
At present, En star has enough gas under contract to serve its
retail customers until after the year 2000, but si nee En star also
sells gas to the military, Chugach Electric Association, and
Anchorage Municipal Light and Power for electric generation, it
may have to seek additional reserves in order to meet the needs of
those larger customers. It is assumed, however, that Enstar will
be able to acquire sufficient gas to meet the needs of its retail
customers (including new Matanuska Valley customers). Further, it
is reasonable to assume that those customers' needs wi 11 have
priority over the use of gas for electrical generation. Retail
use is estimated to increase from about 18 BCF in 1982 to 52 BCF
in 2010. This estimate incorporates an annual growth rate in
sales of 3.5% from 1982 to 1998 plus additional sales of 1.5
BCF/year. beginning in 1986 (and growing at 3.5% annually) to
customers in the Matanuska Valley. Sales from 1999 to 2010 were
obtained by extrapolating total sales at the 1982-1998 growth rate
of 3.5% per year. The effective growth rate for total sales from
1982-1998 is 4.5%. The Enstar estimate is reasonably close
Dl-5
to a State of ('t~yka estimate which provides for a growth rate of
4. 7% per year.
Gas used in field operations and the residual, 11 0ther Sales" vary
from year to year but together are estimated to aver age about
25 BCF/yr. over the period 1982 to 2010 based on historical use as
shown in Table D-1.3.
After satisfying all of the forementioned needs, there is still a
considerable amount of gas remaining that could be used for
electrical generation, at least for a number of years. Chugach
Electric Association has 285 BCF committed through contract (see
Figure D-1.2) and Enstar has 759 BCF contracted, some of which
will be sold to Anchorage t~unicipal Power and Light and Chugach
Electrical Association for electrical generation. Assuming that
the Anchorage/Fairbanks intertie is completed in 1984-85, the
electrical requirements of both cities could be met (at least in
part) with generation using Cook Inlet gas.
An estimate of the quantities of Cook Inlet gas that would be
required to meet all Railbelt electrical requirements was made
using the estimated load and energy forecast (Reference Case) for
the Railbelt area. Estimated generation from the existing Eklutna
and Cooper Lake hydro units, and the proposed Bradley Lake hydro
units, was subtracted, as well as generation from the existing
Healy coal-fired unit. Average heat rates for the gas-fired units
(principally simple-cycle combustion turbines) were assumed to be
15,000 Btu/KWh until 1995 when the heat rate would decrease to
8500 Btu/kWh to reflect the installation of high efficiency,
combined cycle units.
The estimated annual gas requirements for power generation
increase from 35 BCF in 1983 to 54 BCF in 2010. The quantity of
gas used for electrical generations would, of course, vary with
the load and energy use forecast that was assumed. The quantities
calculated for electrical generation incorporate electrical energy
use from the Reference Case forecast (see Exhipit B, Section 5.4).
If the forecast for the DOR Mean case were assumed, the Cook Inlet
proven reserves would provide for generation for a longer period
while if the forecast for the SHCA Basecase was assumed, proven
reserves would last for a shorter period.
The forecast annual and cumulative use of gas for each of the
major users, and the total use of gas for the Railbelt, is shown
in Table D-1.3. The remaining proven and undiscovered (mean or
expected quantity) gas resources are also shown and as can be
seen, proven reserves will be exhausted by about 1998, and
expected undiscovered resources by about 2007. The estimated use
of Cook Inlet proven reserves and undiscovered resources is
graphically illustrated in Figure D-1.4.
Dl-6
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The data from Table D-1.3 indicates that relying on all gas-fired
electrical generation to provide the Railbelt 1 S needs past the
year 2000 is risky because it depends on the future availability
of undiscovered reserves for electrical generation.
Other developments could also reduce or eliminate the availability
of proven natural gas reserves for use in electrical generation.
For example, there is the view that using natural gas for electric
generation does not constitute the best use for the gas and that
the g9-h ;;hould be conserved and used for space heating and process
heat.~ J
The uncommitted, proven reserves and any undiscovered resources
could be acquired by entities not shown in Table D-1.3, reducing
or eliminating the availability of Cook Inlet gas for electric
generation. This possibility is discussed next.
(c) Competition For Cook Inlet Gas
Known potentia 1 purchasers for the uncommitted, recoverab 1 e and
undiscovered Cook Inlet gas reserves, in addition to those shown
in Table D-1.3, are Pacific Alaska LNG Associates and whoever
would own and operate the proposed Trans-Alaska Gas System
(TAGS).
The proposed Pacific Alaska LNG (PALNG) project was initiated
about ten years ago, but has been repeatedly delayed due to
difficulties in obtaining final regulatory approval for a terminal
in California. The project has also had difficulty in contracting
for sufficient gas reserves in order to obtain Federal Energy
Regulatory Commission (FERC) approval of the project. At one
time~ PALNG had 980 BCF of recoverable reserves under contract.
The contracts expired in 1980, but producers did not give written
notice of termination so the contracts have been in limbo.
Recently, however, Shell Oil Company sold 220 BCF of gas that was
formerly committed to PALNG to Enstar Natural Gas Company. This
reduced reserves committed to the PALNG project to 760 BCF (see
Figure 0 -1. 2) .
The FERC has approved the PALNG project, but with the condition
that PALNG obtain 1.6 TCF of r.e;;zrves for Phase I of the project
and 2.6 TCF for Phase II.P J Pacific Gas and Electric
Company, one of the PALNG partners, does not plan to invest any
more funds in the project and has filed with the California Public
Utilities Commission (CPUC) for permission to place the expended
funds into its 11 Plant Held for Future Use" account. PALNG also
claims it requires additional equity partners to make the project
viable, but, to date, has found none. Although PALNG is still
searching for additional gas reserves, there is little chance that
the project would begin construction prior to the erly 1990's.
01-7
Implementation of the project would depend primarily on the
availability and price of alternative sources of natural gas for
the lower forty eight market and particularly for the California
market. According to one expert, Thomas J. Joyce, there are
sufficient proven and probable reserves of conventional gas in(t~e
lower forty eight states to 1 ast fifteen to twenty years. J
When all of these factors are considered, it does not appear that
the PALNG project will be implemented prior to 1995. The
recoverable reserves originally committed to PALNG can, therefore,
probably be acquired by other purchasers such as Chugach Electric
Association and Enstar.
The proposed TAGS project would build a natural gas transmission
line from Prudhoe Bay on the North Slope to the Kenai Peninsula
(near N·ikishka). The gas from the North Slope would b1 4Jiquefied
and sold to Japan and other Asian countries.t ) The
proposed project is an alternative method of bringing North Slope
gas to market. If implemented it would eliminate the need for the
Alaska Natural Gas Transportation System (ANGTS) which would pipe
the gas across Alaska, through Canada and to market in the lower
forty eight states.
If the project were implemented, Cook Inlet gas producers might be
able to sell their gas to Trans Alaska Gas System for liquefaction
and sale to Asia. Sale will depend on the capacity of the
liquefaction plant and the market for LNG. The price paid by TAGS
to Cook Inlet producers might be high enough to outbid competing
purchasers, since the Cook Inlet gas would not be burdened with
the costs of the transmission line from Prudhoe Bay (although
shorter transmission and gathering lines ·.-~ould probably be
required). Any estimate of the probability of whether TAGS will
be implemented is difficult at this time, since the report on the
project has just been published, and there has not been sufficient
time for the proposal to be analyzed by many concerned and
interested parties. However, an estimate of the maximum price
that TAGS would probably be willing to pay Cook Inlet producers
for gas delivered to the TAGS liquifacation plant has been made.
(See a following section entitled, Current Prices).
(d) North Slope Gas
Over ninety percent of the North Slope gas is currently
reinjected. Some is used in field operations, by Trans Alaska
Pipeline System, by Prudhoe Bay refineries, and for North Slope
local electrical generation. A small quantity from the South
Barrow field is also used to meet residential heating needs.
Table D-1.4 shows North Slope production and use for 1982. The
problem in using North Slope gas for Railbelt electrical
generation is that a pipeline must be constructed to bring the gas
Dl-8
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to where it is needed, i.e. Fairbanks or Anchorage.
Alternatively, an electrical transmission line must be built so
that power generated on the North Slope can be brought to load
centers. The major proposals for utilization of North Slope gas
are discussed below.
Alaska Natural Gas Transportation System (ANGTS): In this plan a
p1pel ine would be constructed from the North Slope via Fairbanks
and thro~gh Canada to the lower forty eight states. The project
has been temporarily shelved due to a high estimated delivered
price and the resulting difficulty in obtaining financing. The
project will probably not be operational before the early to
mid-1990s, so it is uncertain when North Slope gas can be
transported to the Railbelt for electrical generation by this
system.
Trans Alaska Gas System (TAGS): This alternative was recently
proposed by the Governor•s Economic Committee on North Slope
Natural Gas. A pipeline would be constructed from Prudhoe Bay to
the Kenai Peninsula where the gas flf~)ld be liquified and sold to
Japan and other Asian countries.l Some of the gas could
be utilized for power generation at Kenai (or conceivably from a
tap at Fairbanks although an additional processing plant would
have to be installed since the gas is to be piped in an unpro-
cessed state). Implementation of TAGS is highly uncertain at this
time and therefore cannot be counted on to provide gas for future
electric generation.
Pipeline to Fairbanks: In this plan, the North Slope gas would be
transported to Fairbanks vi a a small diameter pipeline where it
would be used to generate electricity for the Railbelt Area and
also to meet residential and commercial heating needs in
Fairbanks. Cost estimates indicate that this method is
economically inferior to other proposed methods for utilization of
~orth Slop{lfi)gas and will therefore probably not be
1mplemented.
North Slope Generation: This proposed plan is an alternative to
transporting the gas by some means, for the gas would be utilized
in combustion turbines located on the North Slope and the
electricity transmitted to the Railbelt !A(llQ.. The costs of this
plan are also believed to be prohibitive. J
(e) Gulf of Alaska Gas
To date, there have been no discoveries of gas in the Gulf of
Alaska. This potential source of gas for Railbelt electrical
generation is therefore too speculative at this time to
incorporate its use into the future Railbelt generation
alternatives.
01-9
1.3 Current Prices of Natural Gas
There is no single market price of gas in Alaska since a well
developed market does not exist. In addition, the price of gas is
affected by regulation via the Natural Gas Pol icy Act of 1978 (NGPA)
which specifies maximum wellhead prices that producers can charge for
various categories of gas (some categories will be de regula ted in
1985). There are some existing contracts for the sale/purchase of Cook
Inlet gas which specify wellhead prices but since there are no existing
contracts for the sale of North Slope gas, the North Slope well head
price can only be estimated based on an estimated final sales price and
the estimated costs to deliver the gas to market. The current wellhead
prices of natural gas for the Cook Inlet area and the North Slope are
discussed be1ow.
(a) Cook Inlet
Currently there are four contracts for the sale/purchase of Cook
Inlet gas where the agreements were negotiated at arms length and
the contracts are public documents. These are:
( 1) Chugach Electric Assn ./Chevron, ARCO, She,\1 ) contract for
purchase of gas from the Beluga River Field.~ 8
(2) Enstar/Union, Marathon, ARC0 19 yhevron contract for purchase
of gas from the Kenai Field.l
(3) Enstar/Shelt 20 pntract for purchase of gas from the Beluga
R i v er F i e l d . l !
(4) Enstar/Marathon contractr 20qr purchase of gas from the Kenai
and Beaver Creek Fields.\ IJ
The Chugach contract current price is about $0. 28/MCF and under
the terms of the contract is estimated to increase to about
$0.38/MCF in 1983 dollars by 1995. The contract will not be
deregulated in 1985 by Subtitle B, Section 121 of the NGPA. The
contract terminates in 1998 or whenever the contracted quantity of
gas has been taken. At the maximum annual take of 21.9 BCF/yr.,
the contract wi 11 terminate in 1995 since 285 BCF remained under
the contract on January 1, 1982 (See Figure D-1.2).
The Enstar/Union contract current wellhead price is about
$0.27/MCF and becomes about $0.64/Mcf when delivered to Anchorage
because of the addition of transmission costs. The wellhead price
remains at $0.27/MCF until 1986 where the price becomes the
average price that Union/Marathon receives from new sales to third
parties. If there are no new sales, the price will remain at
$0.27/MCF until contracted reserves are taken (estimated to be
1990 by Battelle) or the contract expires which is in 1992. Like
01-10
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the Chugach contract, this gas will not be deregulated by the NGPA
in 1985.
The Enstar/Shell and Enstar/Marathon contracts were both signed in
December 1982 and are essentially the same in that they have a
base wellhead price of $2.32/MCF in 1983 with an additional demand
charge of $0.35/MCF beginning in 1986. The base price and the
demand charge are to be adjusted annua 11 y based on the price of
No. 2 fuel oil at the Tesoro Refinery, Nikiski, Alaska. The
contracts terminate in 1997 or whenever the contracted quantity of
gas has been taken. The wellhead price of the gas under these
contracts will be deregulated in 1985 under the NGPA.
The Phillips/Marathon LNG gas (see Section 1.2(b)) is not
regulated and has a wellhead price that fluctuates with the
delivered price of LNG in Japan which is tied to the world price
of ojh) Sources have quoted the..)wellhead price as $2.07/MCF in
1980\ and $2.02/MCF in 1982.tl-i
Estimated Price For New Purchases: If all current and future
Ra1lbelt electncal requwements are to be met with gas
generation, new purchases of uncommitted Cook Inlet gas will be
required. The price that will have to be paid for the additional
gas is important in the evaluation of thermal alternatives versus
the Susitna hydroelectric alternative.
Previous contracts for gas such as the Chugach/Chevron and
Enstar/Union agreements are not indicative of the price that would
have to be paid today for uncommitted gas since these contracts
were entered into long ago and their current prices are
substantially below any energy equivalency with oil or coal.
Although low price gas from these contracts will be used for
future electrical generation, the contracts expire in the 1990 -
1995 period therefore they are not relevant in the Susitna vs.
gas-fired unit alternative economic analyses which covers the
period 1993-2040. There may, however, be some marketing effects
in the period 1993-1995 where electric ut"ilities are still using
low cost gas for fuel.
The price for new purchases would seem to depend heavily on
whether the Cook inlet gas can be economically exported as LNG.
With the postponement or demise of PALNG this possibility seems
remote at the present time. Assuming therefore, that there is no
competition from LNG exporters, the gas and electric utilities in
the area would be the primary, remaining potential purchasers.
The actual price that would be agreed upon between producers and
the utilities is impossible to predict but an indication is
provided by the Enstar/Shell and Enstar/Marathon contracts
described below.
01-11
The well head price agreed on in the Enstar contracts was $2. 32/MCF
with an additional demand charge of $0.35/MCF beginning in 1986.
The demand charge of $0. 35/MCF in the Enstar/Marathon contract
applies to all gas taken under the contract from January 1, 1986
to contract expiration. Under the Enstar/Shell contract, the
demand charge of $0.35/MCF applies only if daily gas take is in
excess of a designated maximum take. Enstar expects they will
incur the demand charge because of electric utility requirements
that increase the daily take. Estimated severance taxes of
$0.15/MCF and a fixed pipeline charge of $0.30 for pipeline
delivery from Beluga to Anchorage are additional costs. Future
prices (Jan. 1, 1984 and on) are to be determined by escalating
the wellhead price plus the demand charge based on the price of #2
fuel oil in the year of escalation versus the price on January 1,
1983. If it were assumed that the generating units were located
at the source of gas, the pipeline charge would be eliminated
giving a Jan. 1, 1983 price of $2.47/MCF. (See Table 0-1.5).
The price in Table D-1. 5 represents the best estimate currently
available for the cost of Cook Inlet gas for electrical
generation. Therefore this price was used as the base price of
fuel for gas-fired generation in the thermal alternatives to
Susitna over the period 1993-2040. Since the price is tied to the
future price of oil, it was escalated based on the estimated
future price of oil to obtain prices for 1993 to 2040 (See
Projected Gas Prices Section).
Although the possibility of uncommitted Cook Inlet reserves being
purchased for LNG export seems to be remote at the present time,
conditions may change in the future. The price producers might be
able to obtain if LNG export opportunities existed might then
become important. A method that can be used to estimate well head
prices for LNG export is to begin with the market price for
delivered LNG and then subtract shipping, liquifaction,
conditioning, and transmission costs to arrive at the maximum
wellhead price.
Asian countries are probably the primary market for Alaska LNG,
specifically Japan and Korea. Phillips/Marathon is presently
selling LNG to Japan, and the TAGS study previously mentioned
plans on selling to the Asian countries. LNG would compete with
imported oil in those markets and its price would therefore be
dependent upon the world price of oil. An example of this LNG/oil
price competitivenesss is the existing contract between
Phillips/Marathon and the Tokyo Gas and Toyko Electric Companies
where the delivered price of gas is (CZQ.IJ..al to the weighted average
price of oil imported to Japan. :.5 J For an imported oil
price of $34/bbl, the equivalent LNG price would be about
$5.85/Mcf (1000 Btu/CF gas) and for an oil price of $29/bbl, about
$5.00/MCF.
01-12
....
Conditioning, liquefaction, and shipping cost estimates were
recently developed by the Governor's Economic Committee in their
study of a Trans Alaska Gas System (TAGS) which would transport
North Slope gas to the Kenai P~2a~sula via pipeline, then liquefy
and ship the LNG to Japan.~ J These estimated costs are
based on the large volumes of gas available from the North Slope.
An LNG facillity for only Cook Inlet gas would be considerably
smaller and there might be some economies of scale in going from a
small to a large facility. These economies are not believed to be
large however. In addition, it is just as l'ikely that the TAGS
will be implemented as a Cook Inlet only LNG facility and
producers might therefore have the opportunity to sell their gas
to either facility. The estimated costs for conditioning,
1 iquefaction, and shipping of $2.00/l'vlCF from the TAGS study are
therefore believed to be representative for estimating the
wellhead price of Cook Inlet gas where LNG export opportunities
exist .
The estimated, netback, wellhead price of Cook Inlet gas for LNG
export is shown in Table D-1.6. The price would vary depending on
the average price of oil delivered to Japan so prices based on
$34/bbl and $29/bbl oil are shown. The maximum price that could
be paid to producers is $3.00-$3.85/MCF and these prices are
higher than the estimated prices where no LNG export opportunities
exist as shown in Table 0-1.5. Therefore, if LNG opportunities
did exist, the price of Cook Inlet gas for electrical generation
would be higher than the price assumed herein (Table D-1.5) since
the utilities would have to outbid potential LNG exporters.
(b) North Slope
The relevant price of North Slope gas for use in Railbelt
electrical generation is the "delivered price", that is,· the price
of gas delivered to generating units located near the electric
1 oad centers or if generation were to take place on the North
Slope, the equivalent price for electricity delivered to the load
centers.
The delivered price is dependent upon the wellhead price that must
be paid the North Slope producers and the cost of delivering the
gas (or electricity) to the Railbelt load centers. The price
that producers would accept is unknown but it is evident that they
do not have a large number of alternatives to utilize the gas.
They can shut the gas in or reinject as they are present 1 y doing
or sell to some entity that ·will transport the gas (or
electricity) to market. There is a maximum price that the
producers can charge since the gas is regulated by the Natural Gas
Policy Act of 1978 but the only minimum would seem .to be the value
obtained from reinjection. ·
01-13
One,method of estimating a North Slope wellhead price is to begin
with a known or estimated price that the gas would bring in a
given market and subtract the estimated costs to deliver the gas
to that market. Since the sales price depends on the market to
which the gas is delivered and the costs depend on the distance
and method of delivery, it is best to anl ayze the North Slope
wellhead price and the cost of using the North Slope gas for
electrical generation by the transportation method employed. This
is done below for those transportation methods described under the
section, 11 Production and Use of Natural Gas".
Alaska Natural Gas Transportation System (ANGTS): The ANGTS
project if constructed as currently proposed, would deliver North
Slope gas to the lower forty eight states by means of a large
diameter pipeline traversing central Alaska, and Canada. A portion
of the proposed line would be routed near Fairbanks, Alaska. Due
to the line 1 S proximity to Fairbanks, it would be feasible to
construct a l atera1 1 ine from the main ANGTS trunkl i ne to
Fairbanks, and thus bring North Slope gas to Fairbanks for use in
both electric generation and heating. In a study conducted by
Battelle, first year transportation costs to Fairbanks were
estimated by apportioning the Alaska segment of the pipeline
between Fairbanks customers and lower forty eig2S) customers and
adding the full costs of gas conditioning.\ Battelle 1 s
estimated transportation costs in 1982 dollars were $3.79/MMBtu
($4.03 in 1983 dollars) and at the maximum wellhead price of
$2.30/MMBtu {June 1983) the delivered price to Fairbanks would be
$6.32/MMBtu in 1983 dollars.
In a 1982 study for the U.S. General AccountiQ~6 0ffice (Study I),
the fixed costs for ANGTS were estimated.\ ) If the same
allocation method that was used by Battelle is applied to the
results of the General Accounting Office study, the first year
transportation costs are about $4.60/MMBtu in 1982 dollars
{$4.88/MMBtu in 1983 dollars). If the costs are levelized over
the project 1 S life, the costs would be about $3.87/M~IBtu in 1983
do 11 ars.
In a separate 1983 study, the General Accounting Office (Study II)
has also estimated (29JJ)ditioning and transportation costs
associated with ANGTS. The estimated cost of delivery to
the lower forty eight is $5.25/MMBtu (1982$). When the allocation
method used by Battelle to determine delivered costs at Fairbanks
is employed, the conditioning and transportation costs are
$2.80/MMBtu in 1983 dollars. With a maximum wellhead price of
$2.30/MMBtu, the delivered price in Fairbanks is $5.10/MMBtu. The
cost estimates of Battelle and the GAO are summarized below in
1983 dollars per MMBtu.
01-14
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Maximum
Transportation Maximum Tot a 1 Cost
Estimate Costs Well head Price Delivered to Fbks.
Battelle (1st yr.) $4.03 $2.30 $6.32
GAO Study I
First Year 4.88 2.30 7.18
Levelized 3.87 2.30 6.17
GAO Study II 2.80 2.30 5.10
First Year
None of the cost estimates inc 1 ude severance or state of Alaska
property taxes. These taxes are roughly estimated to total
somewhere between $0.50 and $1.00/MMBtu.
The estimated costs delivered to Fairbanks are well above the
Cook Inlet estimated gas costs for 1983 even with a North Slope
wellhead price of $0.00. Because implementation of the ANGTS
project is doubtful, its estimated gas costs are not considered to
be reasonable prices to use as inputs to the thermal
alternatives.
Trans Alaska Gas System (TAGS): The TAGS proposes to deliver gas
to the Kenai Peninsula for liquefaction and export as LNG. Some
of the gas could undoubtedly be used for electric generation at
Kenai. The costs to electric utilities of the gas can be
estimated from inform at ion in the TAGS report. This information
is presented in Table D-1. 7 for the total TAGS system and Phase I
of the system. A low tariff which would provide a 30% after tax
return to equity investors, and a high tariff which would provide
40%, are shown for both the total system and Phase I.
The price that electric utilites would have to pay is dependent
upon the LNG sales price in Japan so prices of $5.85/MMBtu and
$5.00/MMBtu have been shown. These correspond to oil prices in
Japan of $34/bbl and $29/bbl respectively.
Using the netback approach, shipping and liquefaction costs are
subtracted from the sales prices for these would be avoided by
TAGS if the gas was sold to electric utilities at the LNG plant.
As can be seen, prices vary from $3.03/MMBtu to $4.19/t~MBtu but
the lower prices may not be realistic since they may result in low
or negative wellhead prices to the producers. In addition, at an
estimated sales price of $5.00/MMBtu, the TAGS would probably not
be implemented.
01-15
Subtraction of gas conditioning costs and pipeline transmission
costs gives the wellhead price which varies from a negative $1.34
to $1.81/MMBtu depending on the system, tariff, and sales price
assumed.
If it is assumed that TAGS would be implemented only at an LNG
sales price of $5.85/IVI\VIBtu or above, that the total system would
be constructed and that some point between the low and high tariff
was acceptable to investors and North Slope producers, then the
price of gas to electric utilities at Kenai would be
$3.96-$4.19/MMBtu.* These assumptions seem to be reasonable and a
1983 cost of North Slope gas of $4.00/MMBtu delivered to the Kenai
Peninsula for electric generation will therefore be assumed.
Pipeline to Fairbanks: Transportation costs of a small diameter
pipeline to Fairbanks have br!m)estimated to be about $4.80/MMBtu
for electrical generation.· Using the average of the
reasonable TAGS wellhead prices discussed above of $1.28/MMBtu
(ave. of $0.75 and $1.81/MMBtu) provides a delivered cost in
Fairbanks of $6.00/MMBtu. This cost is considerably higher than
the estimated cost from TAGS and was therefore not used in the
analysis of thermal ~ternatives.
North Slope Generation: This alternative uses the North Slope gas
without incurr1ng transportation costs for the gas. However, the
generated electricity must be transmitted to the Fairbanks load
center thereby requiring the construction of an electrical
transmission line. The capital costs and O&M costs of this line
have also been estimated 9~%)they are about 80% of the cost of the
gas transmission lines.~ Based on this, an equivalent
11 gas 11 transportation cost would be $3.84/MMBtu (0.8 x $4.80/MMBtu)
which when added to a wellhead price of $1.28/MMBtu would result
in an "equivalent delivered" cost of gas of $5.12/MMBtu. This is
less than the small diameter pipeline alternative but still
considerably more than the TAGS delivered cost. This price was
therefore not used in the analysis of thermal generation
alternatives.
The estimated delivered cost of gas to Railbelt load centers based
on transportation costs and assumed wellhead prices are shown in
Table D-1.8. The only cost for North Slope gas used as an input
to the thermal alternatives analysis, however, is the cost derived
from the TAGS study which was found to be about $4.00/r~MBtu in
1983 doll ar s.
*This would provide investors an after-tax return on equity between 30
and 40% and North Slope producers a wellhead price between $0.75 and
$1.81/MCF.
01-16
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1.4 Projected Gas Prices
The estimated 1983 costs of Cook Inlet and North Slope gas were
developed in the previous sections. Since the analysis of thermal
alternatives covers the period 1983-2040, a method for projecting the
1983 price must be utilized.
The method se 1 ected is to tie the price of natural gas to the world
price of oil since the two fuels can be substituted in many cases and
particularly since the recent Enstar gas purchase contract price is
tied to the price of oi 1. The En star price was used as the 1983
estimated price of gas for the Cook In 1 et area and it is assumed to be
representative of future contracts for Cook In 1 et uncommitted and
undiscovered gas.
If North Slope gas is sold as LNG to Japan or Korea, the delivered
price will probably be tied to the world price of oil in the same
manner as the existing Phillips/Marathon LNG contract. Electric
utilities who purchase gas from future LNG exporters will probably also
have to pay a price which is adjusted to the world oil price.
The future price of Cook Inlet natural gas was calculated by escalating
the base 1983 price from Table D-1.5 with the world oil price change
scenarios from Exhibit B, Section 5.4. , Future gas prices using
alternative oil price projections are shown in Table D-1.9.
The future price of North Slope natural gas was calculated by
escalating the base 1983 price from Table D-1.8 with the same ~vorld oil
price change scenarios used for Cook Inlet gas. The estimated future
prices are shown in Table D-1.10.
The natural gas prices from Tab 1 es D-1. 9 and D-1.10 were used as the
price of gas fuel in the evaluation of Railbelt thermal alternatives.
1.5 Effect of Gas Price Deregulation
The wellhead price of all interstate and intrastate natural gas in
the United States is currently set by the Natural Gas Policy Act of
1978 (NGPA). Among other things, the NGPA sets the maximum ceiling
prices which can lawfully be changed for specific categories of gas
production; extends federal price controls over the interstate market
to include intrastate gas; and deregulates as of November 1, 1979 the
price of certain categories of 11 high cost .. gas, i.e. deep gas,
geopressurized gas, coal seam gas and Devonian shale gas. In addition,
the NGPA provides a schedule for price deregulation of additional
categories of gas beginning January 1, 1985.
To speed up the process of natural gas price decontrol, the Reagan
Administration has recently proposed a bill, appearing as S.615 in the
Senate and as H.R.1760 in the House. It would deregulate the price of
Dl-17
all natural gas, regardless of production category, for which a new
contract had been entered, or an old contract amended, after the
effective date of the legislation when passed. Several legislative
proposals have surfaced in both the Senate and House in oppositon to
this proposal. Primarily, the opposition is committed to retaining
price controls on "old price, that is, gas which has been dedicated to
interstate commerce prior to passage of the NGPA. Further, opponents
would maintain, and in some areas restrict, the present NGPA schedule
of phased decontrol of new gas. Representative of this oppositon is a
measure sponsored by Senator John Heinz, (R-Pa.) Heinz's bill, the
Natural Gas Policy .Amendment of 1983 (S.689), would continue
indefinitely price controls on all old gas, and for certain old gas
would actually roll back the current price to November 1, 1978 levels.
Further, it would continue the NGPA schedule for decontrolling the
price for certain new gas categories by January 1, 1985.
In this section, an analysis and comparison has been made of the
potential costs of both Cook Inlet and North Slope natural gas under
several legislative scenarios. First, examination is made of the
effects on existing Cook Inlet contracts and potential future
contracts of continuing present NGPA pricing and phased decontrol
prov1s1ons. Second, proposed legislative changes either to accelerate
deregulation of both old and new gas, or to limit deregulation,
are examined for their most likely effects on Alaska gas prices. These
most likely resulting Alaska gas prices are then analyzed to determine
the potential cost of electrical generation from thermal alternatives
in the Railbelt area.
(a) Existing Law
Title I, Subtitle A, the NGPA establishes discrete categories of
natural gas production, and sets a maximum ceiling price for each
category of gas. In defining these categories, the NGPA draws a
distinction between "old gas," which was under contract prior to
passage of the NGPA, and "new gas," or post-NGPA supplies. Old
gas generally has lower ceiling prices than new gas, and is
governed by Sections 104 and 106 in the case of interstate
contracts, and Sections 105 and 106 in the case of intrastate
contracts. New gas is governed generally by Sections 102 and 103.
In addition to enjoying higher ceiling prices under Subtitle A,
this gas is potentially subject to decontrol in 1985 under the
provisions of Subtitle B, Section 121. Further, North Slope gas
to be transported by ANGTS can only be priced under Section 109
and is not eligible for decontrol under Section 121.
To adequately evaluate the effect of NGPA pricing on Alaska gas,
all existing contracts are individually analyzed. Potential
future contracts are also addressed.
(i) Chevron, ARCO, Shell Contract. Chugach
Electnc o-op as a contact w1th hevron, ARCO and Shell
for purchase of Beluga field gas, in the Cook Inlet area.
Dl-18
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I
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Production under the contract began in 1968, and the
current price is approximately 27¢/mcf.
As an existing intrastate contract at the time of the
NGPA 1 s adoption, gas prices under this contract would be
governed by Section 105 of the NGPA. Section 105 provides
that the maximum lawful price shall be the lower of the
existing contract price, or the new natural gas maximum
price as computed under Section 102. The Section 102
ceiling price was $1. 75/MMBtu in April, 1977, and has been
escalating monthly since that time, in accordance with the
terms of Section 101 of the NGPA. The contract price of
the 27¢/mcf for this Cook Inlet Area gas (which has an HV
of approximately 1000 Btu/ft3) obviously is lower than
the Section 102 price. Therefore, in accordance with
Section 105, the contract price must serve as the ceiling
price, at least until 1985, when some of the gas under
contract may be eligible for decontrol. However, Section
121(a)(3) pertaining to deregulation of prices for gas
under existing intrastate contracts provides that such gas
prices wi 11 only be deregu 1 a ted if the price for such gas
would exceed $1.00/MMBtu on December 31, 1984. As gas
under this contract is at present expected to stay at
27¢/MMBtu on December 31, 1984, deregulation may not change
the contract price of this gas.
(ii) Enstar, Union, Marathon, ARCO, Chevron Contract. This
contract for purchase of Kenai field gas from Union,
Marathon, ARCO, and Chevron was originally executed by
Enstar in 1960, but has been amended several times. The
price currently is about $0.64/Mcf. As such~ it too is
governed by Section 105 of the NGPA. As explained in the
discussion of the Chugach/Chevron contract under Section
105 the contract price would serve ·as the NGPA ceiling
price, for it also is lower than the Section 102 ceiling
price.As with the Chugach/Chevron contract, some of the gas
to be produced under this contrct may be eligible for
decontrol in 1985. But if the price under this contract
remains under $1.00/MMBtu on December 31, 1984, decontrol
will not alter this contract price.
(iii) Ens tar /Shell, Ens tar /Marathon Contracts. These contracts
were signed in December, 1982 for purchase by Enstar of
Kenai field gas from Shell and Marathon. The current price
is $2.32/Mcf. Most of the gas under contract is new gas
governed by Section 102 of the NGPA. The contract also
includes some Section 103 gas. The maximum prices for
these categories of gas in June 1983 were $2. 78/MMBtu and
$3.42/MMBtu, respectively .
Pursuant to Subsection B, Section 121, prices for Section
102 and 103 gas would be decontrolled on January 1~ 1985,
therefore gas prices under these two contracts are subject
to eventual decontrol.
D1-19
(iv) New Cook Inlet Contracts. Contracts for Cook Inlet gas
signed between now and January 1, 1985 will probably be
regulated as to maximum price by Subtitle A, Section 102 or
Section 103. The current maximum prices for these
categories of gas (June 1983) are $3. 42/MMBtu and
$2.78/MMBtu respectively. The prices are allowed to
increase at a rate in excess of the i nfl at ion rate for
Section 102 gas and at the inflation rate (GNP deflator)
for Section 103 gas.
New contracts will probably be decontrolled by Subtitle B,
Section 121(a) of the NGPA on January 1, 1985. Further,
Section 121(a)(3) provides for decontrol of existing
intrastate contracts where the contract price of the gas is
in excess of $1.00/MMBtu on December 31, 1984.
(v) North Slope Gas. There are currently no contracts for
sale/purchase of gas from the North Slope. Morever, Section
102(e) and Section 103(d) specifically exclude from
regulation gas produced from the Prudhoe Bay Unit of Alaska
and transported through ANGTS. North Slope gas transported
via ANGTS is regulated under Section 109, Ceiling Price For
Other Categories of Natural Gas. The base price under
Section 109 was $1.45/MMBtu in April 1977 and adjusted for
inflation gives the current price of $2.30/MMBtu (June
1983). If the North Slope gas were transported under
another system, e.g. TAGS or a small diameter pipeline to
Fairbanks, presumably it would be controlled under Section
102 or 103.
(b) Proposed Changes to the NGPA
Bills have been introduced into Congress which would change the
NGPA and its effect on natural gas prices. Chief among these are
the Reagan Administration bill (S.615) and a bill introduced by
Senator Heinz of Pennsylvania (S.689.) A House bill advancing
similar concepts as S.689 has been introduced by Congressman
Philip Sharp (0-Ind.) The effects of S.615 and S.689, and the
probable effect on Alaska natural gas prices of efforts to
accelerate, or alternatively restrict, gas price decontrol are
discussed below.
The Administrations' Bill. This proposed bill would immediately
remove federal price controls from all gas not presently committed
by contract. In addition, any existing contract could be
abrogated by either seller or purchaser during a period from Jan.
1, 1985 to Nov. 15, 1985. If the contract was not abrogated
during that period, its existing terms and conditions would remain
in effect until contract expiration.
The Chugach/Chevron, ARCO, Shell contract would undoubtedly be
abrogated by the producers if the Administration bill were
01-20
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(c)
implemented. The price of gas under that contract is estimated to
be $0.32/MCF on Jan 1, 1985 and that price is well below any
reasonable estimate of market price at that time (see
Tab 1 e D -1. 9) .
The Enstar/Union contract would also undoubtedly be abrogated
since the estimated price of gas under that contract will be
$0.64/MCF on Jan. 1, 1985, again well below estimates of market
value.
The Enstar/Shell and Enstar/Marathon contracts signed in Dec.
1982 may or may not be abrogated depending on what the producers
and Enstar believe the market price of gas to be relative to the
contract price in 1985. The base contract price of $2.32/IVlCF
(plus $0.35/MCF beginning in 1986) changes ~oJith the price of
No. 2 fuel oil and is estimated to be about $2.16/MMBtu in 1985,
jumping to about $2.51/MMBtu in 1986 (See Table D-1.9-Reference
Case). The estimated maximum price that will be obtainable for
Cook In 1 et gas if deregulation occurs is discussed in a 1 ater
section.
The Heinz Bill. Introduced by Senator Heinz of Pennsylvania, the
bill would amend the NGPA to prevent deregulation of certain
intrastate contracts that would otherwise be deregulated in 1985
(Section 121 (a) (3)-Intrastate Contracts in Excess of $1.00)
and declare indefinite price escalators to be null and void. The
bill apparently makes no change in the status of North Slope gas,
i.e. the gas will remain regulated as Section 109 gas, provided
it is transported via ANGTS.
The bill waul d deregulate New Natural Gas and New Onshore
Production Wells that are now scheduled for deregulation under
Sections 121(a)(1) and 121(a)(2) of the NGPA. Any uncommitted or
undiscovered gas in the Cook Inlet area and the Gulf of Alaska
would therefore not be controlled after passage of the Bill.
The principal differential effect this bill would seem to have on
Alaska gas when compared with the NGPA would be the nullification
of the escalation clauses in the En star/Marathon and Enstar/Shell
contracts.
Deregulated Cook Inlet Gas Prices
Of the proposed bills, implementation of the Reagan bill would
have the greatest effect on natural gas prices in Alaska. The
greatest potential effect would be on Cook Inlet gas prices where
producers would undoubtedly exercise their market out rights in
1985 for two of the existing contracts and possibly for the
remaining two. There waul d probab 1 y be no effect on the price for
future sales of North Slope gas for the wellhead price of that gas
01-21
is dictated by the cost to deliver the gas to market and all
estimates show that the netback wellhead price is already below
the NGPA regulated price.
The price that Cook Inlet producers would be able to command for
their deregulated gas is of course unknown, but an estimate of the
maximum price that they would be able to charge for sales of gas
to use in the generation of electricity is possible. The maximum
price would be that price at which electric utilities became
indifferent to whether they generated using gas or coal. If
producers attempted to charge a higher price, the electric
utilities would build coal-fired rather than gas-fired units~
The cost of generation using coal can be estimated from the
capital, fuel, and operating and maintenance expense associated
with coal-fired generation. The capital and operating and
maintenance expenses for a gas-fired unit can also be estimated
and when these costs are subtracted from the total costs of coal
generation, the maximum amount that can be paid for gas fuel is
left. This dollar difference can then be translated into a cost
per MMBtu through use of the gas-fired units heat rate and annual
generation.
The calculation of an indifferent gas fuel price is presented in
Figure D-1.5. The size of both coal and gas-fired units are
assumed to be 200MW and generate 1.5 billion kWh per year. Other
key paramters for the two units are listed in the figure.
The resulting indifferent gas price is $3.19/MMBtu. This price is
the maximum estimated 1983 price that gas producers could charge
electric utilities for gas fuel under full deregulation of gas
prices. Future year prices for deregulated gas would be obtained
by escalating the estimated 1983 price at the oil price rates of
change from Exhibit B, Section 5.4.
01-22
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1.6 References and Notes
1. Battelle Pacific Northwest Laboratories. Railbelt Electric Power
Alternative Study: Fossil Fuel Availability and Price Forecasts,
Volume VII, March 1982.
2.
3.
1982 Statistical Report, State of Alaska, Alaska Oil and Gas
Conservation Commission, p. 24.
Gas Purchase Contract; Marathon Oil Company and Alaska Pipeline
Company, dated Dec. 16, 1982: Gas Purchase Contract; Shell Oil
Company and Alaska Pipeline Co., dated Dec. 17, 1982.
4. 11 Japan to Keep Phillips Gas Connection 11
, Anchorage Daily News,
Tuesday, January 4, 1983.
5. Sweeney, et al., Natural Gas Demand & Supply to the Year 2000 in
the Cook Inlet Basin of the South-Central Alaska, Stanford
Research Institute, November 1977, table 18, page 38.
6.
7 .
Letter from Mr. Ross G. Schaff, State Geologist, Department of
Natural Resources, Division of Geologic~ and Geophysical Surveys,
to Mr. Eric P. Yould, Executive Director, Alaska Power Authority,
February 1, 1983.
Historical and Projected Oil & Gas Consumption, January 1983,
State of Alaska, Department of Natural Resources, Division of
Miner a 1 s and Energy Management, p. 4. 3.
8. Geological Survey Circular 860, Estimate of Undiscovered
Recoverable Conventional Resources of Oil and Gas in the United
States, 1981.
9. U. S. Department of the Interior Geological Survey, Conditional
Estimates and Marginal Probabilities for Undiscovered Recoverable
Oil and Gas Resources By Province, Statistical Background Data for
U.S. Geological Survey Circular 860, Open-File Report 82-666A.
10. Historical and Projected Oil and Gas Consumption, Jan. 1983, State
of Alaska, Department of Natural Resources, Division of Mineral
and Energy Management, pgs. 3.13, 3.14, B.10.
11. State of Alaska 1983 Long Term Energy Plan (Working Draft),
Department of Commerce and Economic Development,.Division of
Energy and Power Development, State of Alaska, p. I-13.
01-23
12. Initial Decision Approving South Alaska LNG Project Including
Siting of Facilities Near Pt. Conception, California, to Regasify
Indonesian and South Alaska LNG. FERC, Docket Nos. CP75-140, et
~., CP74-160, ~ ~., CI78-453, and CI78-452, August 13, 1979--.
13. ·Joyce, Thomas J., 11 Future Gas Supplies 11
, Gas Energy Review,
American Gas Assn., Vol. 7, No. 10, July/August 1979, p.8.
14. Trans Alaska Gas System: Economics of an Alternative for North
Slope Natural Gas, Report by the Governor's Economic Committee on
North Slope Natural Gas, January 1983.
15. See reference 18.
16. Issues Facing the Future Use of Alaskan North Slope Natural Gas,
General Accounting Office, GAO/RCED-83-102, May 12, 1983, p. 86.
17. Reference 20, p. 86.
18. Battelle, Op. Cit. p.A.2
19. Battelle, Op. Cit. p.A. 10
20. See Reference 3.
21. Battelle, Op. Cit. p. 2.20
22. Reference 8, p.A.3.
23. Anchorage Daily Times, January 4, 1983.
24. See Reference 18.
25. Battelle, Op. Cit. p.6.5
26. Tussing, Arlan R. & Barlow, Connie C., The Struggle For An Alaska
Gas Pipeline: What Went Wrong?, for the GAO, October 26, 1982.
27. Issues Facing the Future Use of Alaskan North Slope Natural Gas.
Report to the Honorable Ted Stevens, United States Senate, by the
Comptroller General of the United States, GAO/RCED-83-102, May 12,
1983, p. 16.
28. Use of North Slope Gas for Heat and Electricity in The Railbelt,
Draft Final Report, Feasibility Level Assessment to the Alaska
Power Authority, Ebasco Services Inc., January 1983. (Costs on a
$/MMBtu basis were not calculated in this report. However, using
the reports estimated capital and O&M costs and estimated average
gas throughout produces a rough estimate of about $4.80/MMBtu).
D1-24
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2 -Coal
This analysis of coal ava-ilability and cost in Alaska has been
developed to provide the basis for evaluating thermal alternatives to
the Susitna Hydroelectric Project. This assessment has been developed
by a careful review of available literature plus contacts with Alaskan
coal developers and exporters. The literature reviewed included the
Bechtel (1980) report executive summary, selected Battelle reports
(e.g., Secrest and Swift, 1982; Swift, Haskins, and Scott, 1980) and
the U.S. Department of Energy (1980) study on transportation and
marketing of Alaskan coal. Numerous other reports were used for data
confirmation. In addition, Paul Weir Company of Chicago was engaged to
develop the estimated cost of a mine in the Beluga field for the
purpose of electric power generation for the Railbelt only.
2.1. Resources and Reserves
Alaska has three major coal fields: Nenana, Beluga, and Kukpowruk.
It also has lesser deposits on the Kenai Peninsula, in the northwest
and in the Matanuska Valley. Alaska deposits, in total, contain some
130 billion tons of resources (Averitt, 1973), and 6 billion tons of
reserves as shown in Table D-2.1. The Nenana and Beluga fields are the
most economically promising Alaska deposits as they are very large and
have favorable mining conditions. The Kukpowruk deposits of North
Slope cannot be mined economically, and also face substantial
environmental problems (Kaiser Engineers, 1977). The northwest
deposits in the area of Kotzebue Sound and Norton Sound are small and
have high mining costs associated with them, although little is known
about these fields (Dames and Moore 1980; Dames and Moore, 1981a; Dames
and Moore, 1981b). The Kenai and iv1atanuska fields are also small and
present additional mining difficulties (Battelle, 1980).
The Nenana Field, located in central Alaska, contains a reserve base of
457 million tons and a total resource of nearly 7 billion tons as is
shown in Table D-2.2. Its subbituminous coal ranges in quality from
7400-8200 Btu/lb. It is high in moisture content, low in sulfur
content, and very reactive (see Table D-2.3). Some 84% of this coal is
contained in seams greater than 10 ft. in thickness, and stripping
ratios of 4:1 are commonly encountered (Energy Resources Co., 1980).
The Beluga Field contains identified resources of 1.8 billion tons
{Department of Energy, 1980) to 2.4 billion tons (Energy Resources Co.,
1980). The quality of this subbituminous coal varies according to
report. Several analyses are shown in Table D-2.4. Beluga deposits
typically are in seams greater than 10 ft. in thickness (Energy
Resources Co., 1980) and may be up to 50 ft. thick in places {Barnes,
1966). Stripping ratios from 2.2 to 6 are commonly found.
Dl-25
2.2 Present and Potential Alaskan Coal Production
Currently there is only one significant producing mine in Alaska, the
Usibelli Coal Co. mine located in the Nenana Field. This mine produces
830 thousand tons of coal/yr for use by local utilities, military
establishments, and the University of Alaska-Fairbanks. These users
operate 87 Megawatts (MW) of electrical generation capacity, as shown
in Table 0-2.5. Plans exist at Fairbanks Municipal Utility System
(FMUS) to increase the total coal-fired electric generating capacity in
Alaska to 108 MW (Swarts, 1983). The FMUS capacity shown in Table
D-2.5 also serves the Fairbanks district heating system.
To produce the 830 thousand tons/yr., Usibelli Coal Co. employs a 33
cubic yard dragline and a front end loader-truck system. This mine,
with its existing equipment, has a production capacity of 1. 7-2.0
million tons/yr. Much of that capacity would be employed when the
Suneel Alaska Co. export contract for 880 thousand tons (800 thousand
metric tons)/yr becomes fully operational. That contract calls for
full-scale shipments, as identified above, to the Korean Electric Power
Co. beginning in 1986.
Production at the Usibell i mine ultimately could be increased to 4
million tons/yr (Department of Energy, 1980; Battelle, 1982). The
mine, which has been in operation since 1943, has 300 years of reserves
remaining at current rates of production. Thus, at 4 million tons of
production, mine life would exceed 70 years. This production, which
may not be able to be used at the mine mouth for environmental reasons
due to proximity to the Denali National Park (Ebasco, 1982), may be
shipped to various locations via the Alaska Railroad.
The Beluga Field, which totally lacks infrastructure, currently is not
producing coal; however, several developers have plans to produce in
that region. These developers include the Diamond Alaska Coal Co., a
joint venture of Diamond Shamrock and the Hunt Estates; and Placer Amex
Co. Involved in their plans are such infrastructural requirements as
the construction of a town, transportation facilities to move the coal
to tidewater, roads, and other related systems. These auxiliary
systems are necessary if one or more mines are to be made operational.
Diamond Alaska Coal Co. holds leases on 20 thousand acres of land
(subleasing from the Hunt-Bass-Wilson Group), with 1 billion tons of
subbituminous resources. Engineering has been performed for a 10
million ton/yr mine designed to serve export markets on the Pacific
Rim; and the engineering has involved a mine, a 12 mile overland
conveyor to Granite Point, shiploading facilities at Granite Point,
town facilities, and power generation facilities. The mine itself
involves two draglines plus power shovels and trucks. The target
timeframe for production is 1988-1991. Placer-Amex plans involve a 5
million ton/yr mine in the Beluga field, also serving the export market
(Department of Energy, 1980).
D1-26
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As can be seen, the primary plans for the Beluga Field are for
exporting of coal to the Pacific Rim. The proponents of exports
believe that Alaskan coal can compete on a cost basis with Austrailian
coal, that Alaskan coal is more competitive than lower 48 U.S. coal
(Swift, Haskins, and Scott, 1980), and that policy decisions in Japan
and Korea to diversify their sources of coal supply favor the exporting
of Alaskan coal (Swift, Haskins, and Scott, 1980). The export of U.S.
coal to Japan also is seen as a means for treating the balance of
payment problems between the two countries, and this could work in
favor of Alaskan development. Certain factors, however, might impede
development of an Alaskan coal export market, e.g. quality of coal
and Japanese coal specifications (Swift, Hasins and Scott, 1980).
It is also feasible to develop the Beluga Field at a smaller scale for
local needs, however. This potential is recognized, inferentially, by
Olsen, et. al. (1979) of Battelle and supported explicitly by
Placer-Amex (McFarland, 1983). Diamond Alaska Coal Co. currently is
performing detailed engineering studies on a 1-3 million ton/yr mine in
this field. As a consequence, it is reasonable to conclude that
production in both the Nenana and Beluga fields could be used to
··support new coal fired power generation in Alaska, with or without the
development of an export market.
2.3. Current Alaskan Coal Prices
The issue of coal prices can be addressed either from a production
cost perspective or a market value perspective, or from a combination
of the two. The production cost perspective is particularly
appropriate if electric utilities serve as the primary market, since
their contracts with coal suppliers typically are based upon providing
the coal operator with coverage of operating costs plus a fair return
on investment (typically treated as 15 percent after taxes __ See
Bechtel, 1980; Stanford Research Institute, 1974; and other reports for
use of this 15% ROI). The market value perspective is particularly
appropriate when exports become the dominant coal market. These
concepts are employed separately for Nenana and Beluga coal.
(a) Nenana Field
Coal pnc1ng data exist for Usibelli coal, and these data
provide a basis for estimating the cost of coal at future power
generation facilities.
Currently, Usibelli coal is being sold to the Golden Valley
Electric Association (GVEA) Healy generating station under
long term contract at a price of $1.16/MMBtu (Baker, 1983), and to
FMUS at a mine-mouth price of $1. 35/MMBtu. The current average
price for Usibelli coal is $23.38/ton of 7800 Btu/lb coal, or
$1.50/IVJMBtu. This value is based, to a large extent, on labor
01-27
productivity of 50 tons/man day. That is a slight decline in
productivity, as Usibelli had achieved 60 tons/man day a value
confirmed by the National Coal Association (1980).
The $1.50/IV1MBtu reflects the price of coal from the Usibelli mine
operating at about 50 percent of capacity. If production were
increased to 1.6 million tons/yr, coal prices would decline to
$20/ton ($1.28/MMBtu). An immediate 10% increase in all coal
prices associated with that mirre can be expected in order to
comply with new land reclaimation regulations. As a consequence,
the marginal cost of Usibelli coal can be calculated (in 1983
dollars) as:
$20/ton x 1.1 x ton/15.6 million Btu= $1.40/MMBtu
The Usibelli mine could be expanded to 4 million tons/yr., given
the reserve base available. At such production levels, the
additional 2 million tons of production would exhibit the same
prices as the current mine when operating at full capacity.
This pricing perspective of the additional two million tons of
capacity, however, is not universally shared. The Department of
Energy coal transportation study (USDOE, 1980), estimates that
coal from the additional 2 million tons/yr. will cost
$1.88-$2.03/~IMBtu in January 1983 dollars ($1.62-$1.75/MMBtu in
1980 doll ar s) .
Because there is an apparent disagreement on coal prices from a
second unit of production, and because the Suneel contract is not
yet in place, the $1.40/mill ion Btu is used as a conservative base
price for Nenana Field coal at the mine mouth. Such coal must be
transported to market by railroad, however. FMUS, for example,
pays $0.50/million Btu for rail shipment of Usibelli coal.
Battelle (1982) developed railroad cost functions for coal
transport and, on this basis, the following charges should be
added to Usibell i coal:
Destination
Nenana
Will ow
Matanuska
Anchorage
Seward
Charge (1983 $/million Btu)
0.32
0.51
0.60
0.70
0. 78
Therefore, the delivered price of coal to a new power plant is
estimated to be $1.72-$2.18 depending upon location. On this
basis it is likely that new power plants fueled by Usibelli coal
would be in the communities of Nenana or Willow. The appropriate
01-28
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(b)
base coal prices for use in power plant analysis are therefore
$1.72-$1.91/MMBtu.
Beluga Field
The methods for estimating the price of coal from the Beluga
field depends, in large measure, on whether or not the export
market for Alaskan coal develops in the Pacific Rim. If that
market exists, then both marketing and production cost analyses
may apply, with production costs establishing a minimum price. In
the absence of that market, production costs must be estimated for
smaller mines.
The factors affecting development of an export market for Alaskan
coal have been previously noted. In this section the existence of
the export market is assumed. Estimates of the magnitude of that
potential market have been developed by Sherman H. Clark and
Associates (Clark, 1983), and by Mitsubishi Research Institute
(MRI, 1983). The Sherman H. Clark values are shown in Figure
0-2.2 for Japan and Korea. As this figure illustrates, the
projected total market in Japan alone could exceed 100 mill ion
metric tons by the end of this decade. The data from MRI are shown
in Figures 0-2.3 and 0-2.4, with particular emphasis on the use of
coal in electric utilities. l"lRI forecasts a smaller total coal
market in Japan in 1990, some 72.7 million tons (vs. Sherman H.
Clark•s 108.1 million tons). l"lRI estimates that the U.S. share of
that Japanese market is 11.1 million tons, as is shown in Table
D-2.6.
There are other estimates of the export market in the Pacific Rim
countries. The U.S. Department of Energy Inter agency Task Force
estimates that U.S. exports to the Pacific Rim will be 15 million
tons in 1990, and 52 mill ion tons in the year 2000; and Barry
Levy, in Western Coal Survey, estimates U. S. exports to the
Pacific Rim at 25 million tons in the year 2000 (Levy, 1982).
These values are consistent with the MRI export estimate of 11.1
million metric tons to Japan in 1990, since they would assume
smaller amounts of coal being exported to Korean and Taiwan (see
Figures 0-2.3 and 0-2.4).
Regardless of whether the Japanese market will be 73 or 108
million metric tons in 1990, these forecasts do illustrate that a
large potential market exists. They are consistent with the data
from Swift, Haskins, and Scott (1980).
The Pacific Rim export market is potentially highly available to
the Alaskan mines due to their favorable transportation cost
differentials compared to other supply sources (Swift, Haskins,
and Scott, 1980). Transportation cost differentials are based
upon the distance to market, as illustrated in Figure 0-2.5. Levy
01-29
(1982) argues this point most strongly when he states that Alaskan
coal exports will 11 dwarf current production 11 in Alaska by the
1990 1 S, and states that most western coal that is exported will
come from the Alaskan fields, notably Beluga. Levy estimates that
15 -20 million tons of coal will be exported each year from
Alaska by the year 1995 (Levy, 1982). The ultimate proof of the
viability of a Pacific Rim export market, and the ability of
Alaskan coal to penetrate that market, is the existence of the
Sun eel Alaska KEPCO contract. This 15-year contract
demonstrates that Alaskan coal can compete successfully in the
P ac if i c R i m .
Because of the strong evidence for an export market, particularly
in Japan (MRI, 1982), it is essential to place a market value on
the Alaskan coal. Various 11 shadow pricing 11 or 11 net back 11
approaches have been used previously to achieve this value (see,
for example, Secrest and Swift, 1982). The approach taken here is
quite similar. The value of coal in Japan is based upon the FOB
price of coal at ports in the competing nations of Australia,
Canada, and South Africa obtained from Clark ( 1983), and the
transportation charges associated with that coal as estimated by
Diamond Shamrock Corp. (1983). The value of coal in Japan,
therefore, is $2.37-$2.49/ million Btu as is shown in Table D-2.7.
Deductions are taken from this value to reflect the lower quality
of Alaskan coal, and to reflect the transportation costs from
Alaska to Japan. The market value of Alaskan coal FOB Granite
Point is $1.78-$1.94/million Btu, as is shown in Table D-2.8.
Frequently it is argued that the market value FOB mine is
substantially lower than the market value FOB Port. In arguing
this case, all capital and operating charges associated with
transporting the coal from mine to tidewater have to be deducted
from the $1.78-$1. 94/mi 11 ion Btu. However if the market value of
coal assumes exports, then it necessarily assumes that the coal
transport facilities are in place. The assumption of such
transport facilities being in existence means that all capital
costs associated with coal transport to tidewater must be treated
as sunk costs, and that the only charges to be netted out are
incremental O&M costs associated with whether the specific coal is
or is not moved to tidewater. These charges would be minimal
assuming the operation of the export system. As a consequence the
values of $1.78-$1.94/million Btu are assumed to hold.
Production cost estimates for Beluga coal have also been
developed. They are based upon large mines (5-10 million tons/yr)
producing coal for export, and smaller mines (1-3 million tons/yr)
serving only the power plant market (200-600 MW).
Production cost estimates have been made for large mines serving
the export market, and these are reported in Table D-2.9. The
01-30
;;-;--,
-
-
-
lower bound values range from $1.16/m"11lion Btu. to $1.27/million
Btu and the higher bound values range from $1.65/million Btu to
$1.74/million Btu. The average of these estimates, taken as a
group, is $1.45/million Btu. ·
For the purposes of deriving a coal cost estimate assuming
exports, the difference between the market value and the
production cost value must be addressed. Battelle approached
reconciliation by simple averaging (Secrest and Swift, 1982).
That approach· is shown here as well, with the average of the
market values ($1.86/million Btu) being averaged with the
production cost of $1.45/million Btu to achieve a price of
$1.66/million Btu.
While this averaging technique provides one basis for analysis, it
appears that the market value is a more meaningful number to use.
If a coal operator could sell coal at $1.86/million Btu FOB Port,
and if there were few cost savings to be achieved by not
transporting the coal to tidewater, then there would be no reason
to sell at some average price. Rather, assuming the export of
5-10 million tons/yr at 7200-7800 Btu/lb coal, the practice of
selling at the average price rather than the market value would
result in decreased revenues to the coal operation of $15-$32
million per year. It is not reasonable to assume that the
operator waul d forego revenues based on market value, therefore
the market value of coal is assumed.
The Beluga mines as currently projected have largely been
considered as sources of coal to be exported to Pacific Rim
countries such as Japan, Korea, and Taiwan. Further, there is a
substantial constituancy promoting such exports (see Resource
development Council of Alaska, 1983). Whether or not this market
develops, however, is still a matter of uncertainty.
In the absence of strong export markets, production costs for
smaller mines have to be considered. Production costs for smaller
mines have been reported by various potential vendors, at
$1.50/MMBtu to $2.00/MMBtu.
Independent estimates were made of the cost of producing Bel1..1ga
coal at rates of one mi 11 ion tons/year and three mill ion
tons/year. These estimates were made by Paul Weir (1983)
consulting mining engineers. These coal price estimates were
developed under the following assumptions:
(1) a 100% equity investment,
( 2) rates of return at 10%, 15%, and 20%,
01-31
(3) a mine investment including an ancillary town for workers
(with town costs divided between the mine and the power
p 1 ant) ;
(4) an investment including a road or conveying system between
the mine and a power plant 1 ocated at tidewater.
Because of the low levels of production, Paul Weir assumed that a
truck-shovel operation would be more cost effective than a
dragline operation on a bucket wheel excavator system. On this
basis, Paul Wier estimated the delivered cost of coal to be
as follows:
Cost of Coal
Private Financing
At 10% ROE
At 15% ROE
At 20% ROE
State Financing
At 3. 5% ROR
1 Million Ton/Year
$2.72
3.20
3.76
2.23
3 Million Ton/Year
1. 91
2.23
2.65
1.61
Under the private financing case, it was assumed that the coal
mine was financed without debt. If a 25 percent debt were
incorporated into the analysis, the cost of coal would decrease
slightly.
Paul Weir Company also estimated the cost of coal under the
assumption that the State of Alaska would own and operate the
mine. A real cost of capital of 3.5% was assumed and the
resulting estimated cost of coal is shown in the table above.
This cost can be compared with the private ownership, 10% ROE case
which is close to the real rate of return that private equity
investors would require as a minimum.
2. 4. Co a 1 Price Esc a 1 at ion
Agreements between coal suppliers and electric utilities for the
sale/purchase of coal are usually long term contracts wllich include a
base price for the coal and a method of escalation to provide prices in
future years. The base price provides for recovery of the capital
investment, profit, and operating and maintenance costs at the level in
existence when the contract is executed. The intent of the escalation
mechanism is to recover actual increases in labor and material costs
from operation and maintenance of the mine. Typically the escalation
mechanism consists of an index or combination of indexes such as the
producer price index, various commodity and labor indexes, or the
consumer price index. The index selected is applied to the beginning
D1-32
--
-
.....
i
-
operating and maintenance expenses so that the level of operating and
maintenance expense increases or decreases over time with changes in
the index. The original capital investment is not escalated, so the
price of coal to the utility tends to increase with general inflation,
provided the escalation index selected reflects the general rate of
inflation.
The free market price of coal, however, could increase or decrease at a
rate above or below the general rate of inflation because of
demand/supply relationships in the relevant coal market. The utility
with an existing contract tied to a cost reflective index would not
experience these real changes until the existing contract expired and
was renegotiated, or a contract for new or additional quantities of
coal was executed.
Several free market price escalation rates were estimated for uti 1 i ty
coal in Alaska and in the 1 ower 48 states, and they range from
2.0-2.7%/year as is shown in Table 0-2.11. These are real escalation
rates, that is in addition to or in excess of the inflation rate.
Several more real market rates have also been developed by Sherman H.
Clark and Associates and by DRI, and these are shown in Table 0-2.12.
These rates of escalation can be compared to the real historical rate
of ·increase of 2.3%/yr. experienced by Golden Valley Electric
Association, since 1974. It is difficult to use that historical GVEA
rate, however, for the following reasons: (1) the rate relates to an
existing contract, and (2) the rate covers a period of time when the
substantial provisions of the Coal Mine Safety Act of 1969 were being
implemented thereby affecting the price of coal.
The estimates of Sherman H. Clark and DRI are based more upon
supply-demand analyses rather than upon extrapolations of historical
data. The demand/supply relationship varies for different types of
coal which results in different estimated future price escalation
rates. This relationship is shown in Figure 0-2.6 where future real
escalation rates for western coal (average 2. 9%/year) and western
lignite (average 2.3%/yr.) are graphed using data from Sherman Clark
and Associates.
The SHCA estimated real escalation rates for new contract domestic U.S.
coal are shown below by period.
01-33
Period
1980-1990
1990-2000
2000-2010
Average 1980-2010
Real Escalation Rate-%/yr.
Western Coal Western Lignite
2.9
2.0
3.9
2.9
2.8
2.0
2.0
2.3
The rates of price change from period to period for domestic U.S. coal
are directly related to mine capacity utilization. The lignite price
changes reflect projected declines in capacity utilization in Texas and
North Dakota fields (Clark, 1983), while western coal capacity
utilization is expected to increase. Capacity utilization rates in
Alaska depend upon future use by electric utilities and cannot be
readily determined. Therefore, when a domestic escalation rate is
applicable, the long-term average rate is employed rather than period
rates.
DRI•s estimated real escalation rates (Spring 1983) for new contract,
domestic, U.S. coal are shown below by period (DRI does not
differentiate by coal type).
Period
1981-1990
1991-2000
2001-2005
Average 1983-2005
Real Escalation Rate -%/yr.
3.1
1.7
2.5
2.6
For coal exports, SHCA is forecasting a 2.6%/yr. growth in demand by
Japan and a 5.2%/yr. demand growth by South Korea (Figure D-2.1). This
growth in demand together with a forecast weakening in United States
currency versus the currencies of the two Asian countries results in an
estimated real price escalation rate of 1.6%/yr. which is below the
forecast U.S. domestic rates.
The forecasts by SHCA and DRI of future coal prices are based on
demand/supply analyses performed by knowledgable, experienced firms.
The forecasts are reasonable assessments of the future price trends and
have been applied to Alaskan coal produced from the Nenana and Beluga
fields.
Coal from the Nenana Field is used principally to supply Alaskan
domestic markets. Therefore a domestic price escalation rate of
2.6%/year based on the average of SCHA western coal and lignite (2.9%
and 2.3%) and the DRI forecast (2.6%) has been assumed. The 2.6% rate
is applied to the 1983 estimated mine-mouth price of $1.40/t~MBtu to
provide the future cost of coal at the Usibelli Mine. Prices for
01-34
.....
,._
-i
~
I
Nenana coal that is consumed at other locations are determined by
adding transportation costs which are shown in Table D-2.13. Composite
real escalation rates which include transportation costs are shown
below for Usibelli coal used at Nenana and Willow.
Location
Usibelli mine-mouth
Nenana
Wi 11 ow
Composite Real
Escalation Rate-%/yr.
2.6
2.3
2.2
Assuming that an export market for the Beluga field develops, all coal
sold from the field will probably be at a price dictated by Pacific Rim
market conditions. This includes sales to electric utilities for use
as fuel for electric generation. Therefore, it is reasonable to
escalate the estimated $1.86/MMBtu 1983 base price of Beluga Field coal
at the estimated export market rate of escalation of 1.6%/yr.
(Table 0-2.12)
The resulting fuel prices for Nenana and Beluga field coal for the
period 1983-2010 are shown in Table D-2.14. There are no known
projections of coal prices past the year 2010.
If an export market for Be 1 uga co a 1 does not deve 1 op, the 1983 base
price should be assumed to be based on the production costs for a
small 1-3 mi 11 ion ton per year mine. This waul d result in higher coal
costs, especially in the initial years when consumption in the Beluga
steam plant would be in the 1 million ton per year range required by
one 200 MW unit.
While there has been some carrel at ion between export coal prices and
world oil prices historically, such a correlation is tenuous, at best,
with respect to utility coal contracts. Technical correlations must
accommodate differences which exist between coal and oil fired units in
the areas of capital costs ($/kW), operating costs, and fuel purchasing
agreements. Further such carrel at ions must accommodate significant
differences in market flexibility and market opportunity between coal
and oil suppliers. For these reasons it is necessary to treat coal
prices as being independent of world oil prices.
Several scenarios of future world oil prices have been used in the
economic analysis of thermal alternatives. Natural gas prices for
these scenarios move •.vith the oil prices since it is assumed that
future natural gas prices in both the Cook Inlet area and the North
Slope will be tied directly to the future price of oil (See
Section 1.4).
Coal prices are treated independently of oil prices, but a coal price
scenario is required with each oil and natural gas price scenario in
01-35
order to carry out economic analysis of the thermal alternatives. Coal
price escalation rates are summarized below for each oil price scenario
analyzed and shown year-by-year in Table D-2.14.
Real Coal Price Escalation Rate -%/yr.
Oil Price N en an a F i e l d Beluga Field
Scenario M1ne Nenana Willow Export Domestic
DOR Mean 0.0 0.0 0.0 0.0 0.0
DOR 50% 0.0 0.0 0.0 0.0 0.0
DOR 30% 0.0 0.0 0.0 0.0 0.0
DRI 2.6 2.3 2.2 1.6 2.6
SCHA Base Case 2.6 2.3 2.2 1.6 2.6
Reference Case 2.6 2.3 2.2 1.6 2.6
Constant Change
+2% 2.6 2.3 2.2 1.6 2.6
0% 0.0 0.0 0.0 0.0 0.0
-1% 0.0 0.0 0.0 0.0 0.0
-2% 0.0 0.0 0.0 0.0 0.0
For the DOR scenarios, and the constant change scenarios of 0%, -1.0%,
and -2%, the real coal price for both the Nenana and Beluga fields is
assumed to have a zero rea 1 escalation rate for the years 1983-2010.
Even though there is only a tenuous correlation between oi 1 and coa 1
prices, the oil prices for all of these scenarios is so low Call below
$30/bbl in 1983 dollars by 2010) that it would be unrealistic to expect
coal prices to escalate in real terms over the 1983-2010 period.
In summary, then, an ample coal supply does exist in the Railbelt area
to support coal fired power generation with 1983 prices ranging from
$1.72 -$1.91 delivered at the power plant. The effective real rates
of escalation will range from 1.6% to 2.6% depending upon the extent to
which exports influence the market and the specific location(s) of
projected power plant development.
01-36
,~--,
-
2.5 References and Btbliography
Arthur D. Little, Inc. 1983. Long Term Energy Plan, Appendix
B. DEPD, Anchorage, Alaska.
Averitt, P. 1973. Coal in United St~tes Mineral Resources.
U.S. Survey Professional Paper 820., U.S. Government Print-
ing Office, Washington, D.C.
Barnes F. 1967. Coal Resources in Alaska. USGS Bulletin 1242-B.
Barnes, F. 1966. Geology and Coal Resources of the
Beluga-Yentna Region, Alaska. Geological Survey Bulletin
1202-C. U.S. Government Printing Office, Washington, D.C.
Battelle Pacific Northwest Laboratories. 1982. Existing
Generation Facilities and Planned Additions for the
Railbelt Region of Alaska Vol VI. Richland, WA.
Bechtel Incorporated, 1980. Executive Summary, Preliminary
Feasibility Study, Coal Export Program, Bass-Hunt-Wilson
Coal Leases, Chintna River Field, Alaska.
-Beluga Coal Company and Diamond Alaska Coal Company. 1982.
-i
-
-
Overview of Beluga Area Coal Developments.
Clark, Sherman H. and Associates, 1983. Evaluation of World
Energy Developments and Their Economic Signifiance, Vol.
11. Menlo Park, C4.
Coal Task Force. 1974. Coal Task Force Report, Project Inde-
pendence Blueprint. Federal Energy Administration,
Washington, D.C., November.
Dames and Moore. 1980. Assessment of Coal Resources of North-
west Alaska -Phase I, Volume I. For Alaska Power Authority.
Dames and Moore. 1981a. Assessment of the Feasibility of
Utilization of Coal Resources of Northwestern Alaska For
Space Heating and Electricity. Phase II. For APA.
Dames and Moore. 1981b. Assessment of Coal Resources of Northwest
Alaska. Phase II. Volume III. For APA.
Dean, J. and K. Zollen. 1983. Coal Outlook. Data Resources,
Inc.
Demonstrated Reserve Base of Coal in the United States as of
January 1, 1980. U.S. Department of Energy, Washington,
D • C.
01-37
Ebasco Services Incorporated. 1982. Coal-Fired Steam-Electric
Power Plant Alternatives for the Rai lbelt Region of Alaska.
Vol XII. Battelle Pacific Northwest Laboratories, Richland,
WA.
Ebasco Services Incorporated.
for Heat and Electricity
1983. Use of North Slope Gas
in the Railbelt. Bellevue, WA.
Energy Resources Co. 1980. Low Rank Coal Study: National
Needs for Resource Development, Vol 2. Walnut Creek, CA.
(For U.S. DOE, Contract DE-AC18-79FC10066).
Heye, C. 1983. Forecast Assumptions in Review of the U.S.
Economy. Data Resources, Inc. -
Integ-Ebasco 1982. Project Description. 800 MW Hat Creek
Plant. Ebasco Services Incorporated, Vancouver, B.C.
Kaiser Engineers. 1977. Technical and Economic-Feasibility
Surface Mining Coal Deposits North Slope of Alaska. For
USBM. Oakland, CA.
Levy, B. 1982. The Outlook For Western Coal 1982-1985. Coal
Mining and Processing. Jan. 1982.
Mclean Research Institute. 1980. Development of Surface Mine Cost
estimating equations. Fol. U.S. DOE. Mclean, VA.
MRI 1982. Future Energy Demand and Supply in East Asia Mitsubishi
Research Institute, Toyko, Japan (For Arthur D. Little,
Inc .
National Coal Association. 1980. Coal Data 1979/1980. NCA,
Washington, D.C.
Olsen, M., et. al. 1979. Beluga Coal Field Development:
Social Effects and Management Alternatives. Bettelle
Pacific Northwest Laboratories, Richland, WA.
Resource Development Council for Alaska, Inc. 1983. Policy
Statement No. 6: Coal Development (draft). Reviewed by
RDCA, Mar. 29, 1983, Anchorage, AK.
Secrest, T. and W. Swift.
Alternatives Study:
Forecasts. BAttelle
Richland, WA.
1982. Railbelt Electric Power
Fossil Fuel Availability and Price
Pacific Northwest Laboratories,
Scott, J. et.al. 1978. Coal Mining. The National Research
Council/National Academy of Sciences, Washington, D.C.
01-38
Stanford Research Institute, 1974. The Potential For Developing
Alaska Coal For Clean Export Fuels. Menlo Park, CA. (For
the Office of Coal Research).
Swift, W., J. Haskins, and M. Scott. 1980. Beluga Coal Market
Study. Battelle Pacific Northwest Laboratories, Richland,
WA.
U.S. Department of Energy. 1980. Transportation and Market
Analysis of Alaska Coal. USDOE, Seattle, WA.
Paul Weir Company, 1983.
Hypothetical Mine.
Mining Cost Estimates Beluga Area
Chicago, ILL.
01-39
3-Distillate Oil
Distillate oil, i.e., fuel oil used in diesel engine and gas turbine
generating units, is not a significant factor in the analysis of Rail-
belt generation alternatives for the years 1993 to 2040. With an
electric interconnection between Anchorage and Fairbanks, generation
with diesel engines will be eliminated except for small isolated com-
munities. Both thermal and hydroelectric alternatives will utilize gas
or coal for required thermal generation. Any generation provided by
oil-fired units will either be the same for all alternatives or the
differences will be so small that they can be ignored in the economic
comparison of the alternatives. However, to provide a complete picture
for fuels actually used in the Railbelt for electrical generation, the
following information on distillate oil availability and price is
presented.
3.1 Availability
According to Battelle, there isl/J.dequate availability of distillate
oil during the analysis period.-Although part of the distillate
oil used in Alaska is imported, this fact alone will not affect its
availability. It has been assumed that distillate oil in the required
quantities will be available during the economic analysis period 1993
to 2040 from refineries within Alaska or the lower forty-eight states.
3.2 Price
The average current price for medium distillate fuels in Anchorage
and Fairbanks is shown in Table ~i·l. These prices will change with
the world market price for oi 1.-The estimated price changes for
several projections of future world oil prices have been applied to the
1983 price of distillate oil to obtain the future prices during the
period 1983 to 2040. These are shown in Table D-3.2 •
..!./Battelle Pacific Northwest Laboratories. Rai"lbelt Electric
Power Alternative Study: Fossil Fuel Availability and Price
Forecasts, Volume VII, March 1982, p. 8.1.
2/ See Battelle, p. 8.3-8.5.
D1-40
-I
r
-
-
.....
Tab 1 e D-1.1
PRELIMINARY ESTIMATES OF UNDISCOVERED GAS RESOURCES IN PLACE A~2)
ECONOMICALLY RECOVERABLE GAS RESOURCES FOR THE COOK INLET BASIN
Probability-%(2)
99
In P 1 ace
0.47
0.93
1.24
1. 98
3.07
4.38
5.84
6.93
9.06
Quantity of Gas -TCF
Economically Recoverable
0.00
95
90
75
50
25
10
5
1
0.22
0.43
0.93
1. 76
2.78
4.04
4.90
6.83
(1) Source: Letter to Mr. Eric P. Yould, Executive Director, APA from Ron G.
Schaff, State Geologist, State of Alaska, Department of Natural
Resources, Division of Geological and Geophysical Surveys, dated February
1, 1983.
(2) Probability that quantity is at least the given value. Mean or as
expected value for Economically Recoverable gas is approximately 2.0 TCF
due to skewed distribution.
USE
Injection
Field Operations:
Vented, Used on
shrinkage
Sales:
LNG
Ammonia/Urea
Tab 1 e D-1. 2
HISTORICAL AND CURRENT PRODUCTION AND
USE OF COOK INLET NATURAL GAS
QUANTITY -BCF
1978 1979 1980 1981
114.1 119.8 115.4 100.4
lease,
23.5 17.5 28.0 20.6
60.9 64.1 55.3 68.8
48.9 51.7 47.6 53.7
Power Generation:
Utilities 24.6 28.2 28.7 29.1
Military 5.1 5.0 4.8 4.6
Gas Utilities* 13.5 14.0 15.5 16.2
Other Sales 3.3 4.8 5.1 5.7
Total Sales 156.3 167.8 157.0 178.1
Total 293.9 305.1 300.4 299.1
1982
103.1
21.3
62.9
55.3
30.5
4.7
17.7
9.5
180.6
305.0
Source: 11 Historical and Projected Oil and Gas Consumption, Jan. 1983",
State of Alaska, Dept. of Natural Resources, Division of
Mineral and Energy Management, Table 2.8.
*Does not include sales made by gas utilities to electric utilities for
electric generation.
/(Y'---,
~-~-,
r:;;-1
,.-,---1
~'"""".,.-..-.
'~l
I 1 J ] J 1 l ·--1 1 l ] I 1 -~~
~
Trble D-1.3
ESTIMI\Tffi l£E (f OXK. INLET NATI.RJIL CAS BY l£ER -JllL IAIJv£5 IN BCF
Year Em
Enst<r Field l);er-Electric Generation Total Total Remaining Reserves
Phillips/Marathon Collier Retail ations & Gas Curulative Pr01en Plus
Veer U£/Plant Ammia/Lrea Sales Other Sales Mi lit<ry All Ott-Ers Use Gas Use Proven 1\'ean l11di scovered
193? 62 55 --rrT 25 5 13.4 203.1 203.1 33Jl .9 5377.9
1983 62 55 19.2 25 5 40.8 207.0 410.1 3130.9 5170.9
19M 62 55 19.8 25 5 43.2 210.0 620.1 2920.9 4960.9
1985 62 55 20.5 25 5 45.5 213.0 833.1 2707.9 4747.9
1986 62 55 22.8 25 5 47.6 217.4 1050.5 2490.5 4530.5
1~7 62 55 23.6 25 5 49.7 220.3 1270.8 2270.2 4310.2
1988 62 55 24.4 25 5 46.5 217.9 1488.7 2052.3 4ffi2.3
1~ 62 55 25.3 25 5 48.5 220.8 1709.5 1831.5 1371.5
19q) 62 55 26.1 25 5 50.5 223.6 1933.1 1607.9 li47.9
1991 62 55 27.1 25 5 51.8 225.9 2159.0 1382.0 3422.0
1992 62 55 28.0 25 5 53.1 228.1 2137.1 1153.9 3193.9
1993 62 55 29.0 25 5 54.5 230.5 2617.6 923.4 2963.4
19~ 62 55 Xl.l 25 5 55.8 232.9 2850.5 6q).5 2730.5
1995 62 55 31.1 25 5 32.5 210.6 3061.1 479.9 2519.9
1996 62 55 32.2 25 5 33.1 212.3 3273.4 267.6 2307.6
1997 62 55 34.4 25 5 33.8 215.2 3488.6 52.4 2092.4
1998 62 55 34.6 25 5 34.5 216.1 3704.7 (163. 7) 1B76.3
1999 62 55 35.8 25 5 35.1 217 .9· 3922.6 1658.4
2(XX) 62 55 37.0 25 5 35.8 219.8 4142.4 14J3.6
2001 62 55 38.3 25 5 36.8 222.1 4364.5 1216.5
2002 62 55 39.7 25 5 37.7 224.4 45&l.9 9~.1
2003 62 55 40.1 25 5 40.0 227.1 4816.0 765.0
2004 62 55 42.6 25 5 41.0 230.6 5046.6 534.4
2m) 62 55 44.1 25 5 42.0 233.1 5279.7 301.3
2())) 62 55 45.6 25 5 44.6 237.2 5516.9 64.1
2007 62 55 47.2 25 5 46.0 240.2 5757.1 ( 176.1)
2Cffi 62 55 48.9. 25 5 47.3 243.2 600).3
200.1 62 55 50.6 25 5 48.7 246.3 6246.6
2010 62 55 52.4 25 5 50.1 249.5 6496.1
1sased on historical use fran Trble D-1.2 inl teleptune conversations with Mr. Jim Settle of Phillips Petroleum Co. arrJ Mr. George
Ford of Collier Chemical.
2Estimate JrCNided by Mr. Harold Schnidt, VP Enstar Co,, Ftil. 14, 1983. Inc li.KEs sales to Mataruska Valley custarers beginnirg in
1986. Consurptim fran 1991-2010 rrojected by Harza/Ebasco at averag:! 9"Mh rates in Enst<r estimates.
3t:stirnate based 01 historic use sturKJ in Toole D-1.2.
4Estirnate based on historic use sturKJ in Trble D-1.2. '
5calculated based 01 tt-E Reference Case load am energy fom:ast; inclusion of g:!neration fran Eklutna, Coq:ler Lake arrJ Bra:lley Lake
hyrro units am 1-Ealy coal unit; am assLJTffl average Railbelt heat rates of 15,000 Btu/kv.h fran 1982-1995 IIIlich irx::ludes old:!r, hi9l
heat rate lJlits, am 8,500 Btu/ki-Al fran 1996-2010, 1\hich assliD2S Jredaronately carbined c_ycle lJlits.
6Proven reserves of 3,541 BCF on Jan 1, 1982. See Exhibit D-1.1. ·
7rnclll(Jes rr<Nen revenues of 3,541 HCF plus expected valt.e for lJldiscCNere:l a:onanically ra:CNer~Jle reserves frmt Figtre D-1.1.
Table D-1. 4
CURRENT PRODUCTION AND USE OF
NORTH SLOPE GAS FOR 1982
Use
Injection
Field Operations:
Vented, Used on
shrinkage
Sales
Power generation (civilian)
Gas utilities (residential)
Other sales
Refineries
Trans Alaska Pipeline System
Misc.
Total
Quanity -BCF
671.0
50.2
0.4
0.5
0.5
11.9
0.2
734.7
Source: "Hi stori cal and Projected Oil and Gas Consumption
Jan. 1983", State of Alaska, Dept. of Natura 1
Resources, Division of Minerals and Energy
Management, Table 2.7.
-
r
"""'
,....
....
I"'"'
!
Wellhead Price
Additional demand
Severance tax(2 )
Tab 1 e D-1. 5
ESTIMATED BASE PRICES FOR NEW
PURCHASES OF UNCOMMITTED AND UNDISCOVERED
COOK INLET GAS
Without LNG Export Opportunities
1983-1986
$2.32/Mcf
charge(l) 0.0
0.15
Total (unescal ated) (3) $2. 47/Mcf
Transmission charge(4) 0.30
Delivered to Anchorage $2.77 /Mcf
1986-1997
$2.32/Mcf
0. 35
0.15
$2.82/Mcf
0.30
$3.12/Mcf
(1 )Demand charge of $0.35/MCF on Enstar/Marathon contract applies
from January 1, 1986 on while demand of $0.35 on Enstar/Shell contract
applies only if daily gas take is in excess of a designated maximum
take.
(2)Severance taxes are the greater of $0.064/MCF or 10% of the
wellhead cost adjusted by the "Economic Limit Factor." The economic
limit factor is based on actual monthly production versus the wells
production rate at the economic limit. See Alaska Statutes, Chapter 55,
Section 43.55.013 and 43.55.016. The tax of $0.15/MCF was estimated
based on conversations with Enstar Natural Gas Co.
(3)Prices are escalated based on the price of No.2 fuel oil at the
Tesoro Refinery, Nikiski, Alaska beginning Jan. 1, 1984.
(4 )Estimated transmission charges would be about $0.30/MCF. Per
telephone conversation with Mr. Harold Schmidt, VP Enstar.
Tab 1 e D-1. 6
ESTIMATED 1983 BASE PRICES FOR NEW
PURCHASES OF UNCOMMITTED AND UNDISCOVERED
COOK INLET GAS
With LNG Export Opportunities
LNG Price -Japan(1 ) $5.85/MCF $5. 00/IVJCF
Less:(2 )
Conditioning 0.34 0.34
liquefaction 0.95 0.95
Shipping 0. 71 0. 71
Subtotal 2.00 2.00
Maximum Price to Producer(3 ) $3.85/MCF $3.00/MCF
(1 )Based on oi 1 prices of $34/bbl and $29/bbl.
(2 )Based on implementation of the Trans-Alaska Gas System (TAGS)
total System, lower tariff. Trans Alaska Gas System: Economics
of an Alternative for North Slope Natural Gas, Report by the
Governor's Economic Committee on North Slope Natural Gas, January
1983. See Exhibits C1, C2 and page 18 and 46 of the Marketing
Study Section. (Costs shown in the report were stated in 1988
dollars and were converted to 1983 dollars using the reports'
assumed inflation rate of 7%/yr.)
(3 )Delivered to LNG liquefaction facility. Transmission costs
assumed to be negligible.
r:---,
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Table D-1.7
ESTIMATED COST OF NORTH SLOPE NATURAL
GAS FOR ELECTRIC GENERATION AT KENAI
ASSUMING IMPLEMENTATION OF THE TRANS
ALASKA GAS SYSTEM (TAGS)
(1983 Dollars/MMBtu)
Total System Phase I System
Low High Low High
Tariff Tariff Tariff Tariff
Estimated 1983
LNG Price Per MM Btu(1 ) $5.85 $5.00 $5.85 $5.00 $5.85 $5.00 $5.85 $5.00
Less Costs:(2)
Shipping 0. 71 0. 71 0. 71 0. 71 0. 71 0. 71 0. 71 0. 71
Liquefaction 0.95 0.95 1.18 1.18 1.00 1.00 1. 26 1.26
Subtota 1 $1.66 $1.66 $1.89 $1.89 $1.71 $1.71 $1.97 $1.97
Minimum 1983 Price(3 ) $4.19 $3.34 $3.96 $3.11 $4.14 $3.29 $3.88 $3.03
Conditioning Costt 4 ) 0.34 0.34 0.42 0.42 0.42 0.52 0.51 0.51
Pipeline Costs(5 ) 2.04 2.04 2.79 2.82 2.82 3.86 3.86 3.86
Wellhead Price l. 81 0.96 0.75 (0.10) 0.90 0.05 (0.49) ( 1. 34)
(1 )LNG prices are delivered prices to Japan and are equivalent to $34/bb1 oil
for the $5.85/MMBtu price and $29/bbl oil for the $5.00/MMBtu price.
(2 lcosts in the report are shown in nominal 1988 dollars which were con-
verted to 1983 dollars using an inftation rate of 7%/yr.
(3 )Minimum price TAGS wouJd accept from utilities for purchase of gas at
LNG gas conditioning facility.
(4)For pipeline from North Slope to Kenai Peninsula.
(S)Maximum price that TAGS would be able to pay North Slope producers.
Source: Trans Alaska Gas System: Economics of an Alternative for North Slope
Natural Gas, Report by the Governor's Economic Committee on North
Slope Gas, January, 1983. See Exhibits C1 and C2 and pgs 18 and 46 of
the Marketing Study Section.
Table D-1.8
ESTIMATED 1983 DELIVERED COST OF NORTH
SLOPE NATURAL GAS FOR RAILBELT ELECTRICAL GENERATION
{1983 Dollars/MMBtu)
Estimated Value
Cost Used
Delivery Method. $/MMBtu $/MMBtu
ANGTS(1 ) 4.03-5.30 N.A.
TAGS(2) 3.96-4.19 4.00
Pipeline to Fairbanks{3) 4.80-6.08 N.A.
North Slope Generation(4 ) 3.84-5.12 N.A.
N.A. Not Avail able
(1 )cost of $3.80/MMBtu in 1982$ assuming a zero wellhead cost
was estimated by Battelle. This was adjusted to 1983$ to provide
the $4.03/MMBtu. The $5.30/MMBtu includes an assumed wellhead cost
of $1. 28/MMBtu.
{2)costs estimated using a "netback" approach. See Table D-1.7.
Value of $4.00/MMBtu selected as reasonable value for thermal
generation alternatives analysis.
{3)costs estimated using capital and O&M costs from Reference 31.
The cost of $4.80/MMBtu assumes a wellhead price of zero while the
$6.08/MMBtu price assumes a wellhead price of $1.28/MMBtu.
(4 )costs estimated using capital and O&M costs from Reference 31.
These costs are "equivalent" costs for the gas would be burned on
the North Slope and the electricity delivered to Railbelt load
centers via an electric transmission line. The "equivalent" costs
were determined by comparing the costs of the electric transmission
line with the costs of the gas pipeline to Fairbanks. The
$3.84/MMBtu assumes a wellhead price of zero and the $5.12/MMBtu a
wellhead price of $1.28/MMTbu.
1
Tc:b1e 0-1.9 (~eet 1 of 2)
PROJECTED COO< INLET WELLI£IID NATlM.. Gl\5 PRICES
· In 1983 [b 11 ars Per MvBtu
Reference Case COnstant Change Cases
(OCR IXR IXR DRI ~enncrJ C1 ark ( ~enncrJ C1 ark
Year ·M=an) lJ'Io 50% Spring 1983 Base Case NSD Case) +2/yr Ufo/yr. -1.0/yr. -2.(J'Ic,/yr.
1983(1) 2.47 2.47 2.47 2.47 2.47 2.47 . 2.47 2.47 2.47 2.47
84 1.97 1.94 2.05 2.07 2.27 2.27 2.43 2.47 2.35 2.33
85 l.ffi 1.79 2.10 2.22 2.16 2.16 2.48 2.47 2.33 2.29
&5(1) 2.18 2.07 2.19 2.74 2.51 2.51 2.00 2.73 2.66 2.58
87 2.14 1.99 2.14 2.92 2.51 2.51 2.94 2.73 2.63 2.53
88 2.17 1.97 2.12 3.11 2.51 2.59 3.00 2.73 2.60 2.48
89 2.20 1.95 2.11 3.31 3.82 2.66 3.()) 2.73 2.58 2.43
1990 2.23 1.83 2.09 3.52 3.82 2.74 3.12 2.73 2.55 2.l3
91 1.76 2.02 3.68 3.93 2.83 2.73
92 1.73 2.00 3/84 4.05 2.91 2.73
93 1.65 1.92 4.01 4.17 3.00 2.73
94 1.63 1.88 4.19 4.l) 3.09 2.73
95 2.l3 1.59 1.87 4.37 4.43 3.18 3.45 2.73 2.43 2.15
96 1.57 1.79 4.50 4.56 3.27 2.73
97 1.53 1.79 4.64 4.70 3.37 2.73
98 1.52 1.78 4.79 4.84 3.47 2.73
99 1.51 1.76 4.94 4.98 3.58 2.73
2(X)) 2.54 1.48 1.74 5.09 5.13 3.69 3.80 2.73 2.31 1.95
01 5.15 5.31 3.00 2.73
02 5.20 5.50 3.91 2.73
03 5.26 5.69 4.03 2.73
04 5.32 5.89 4.15 2.73
05 2.71 l.l3 1.64 5.l3 6.09 4.27 4.20 2.73 2.10 1.76
()) 5.44 6.31 4.40 2.73
07 5.56 6.53 . 4.53 2.73
00 5.62 6.76 4.67 2.73
09 5.68 6.99 4.81 2.73
2010 2.89 1.28 1.56 5.74 7.24 4.95 4.64 2.73 2.09 1.59
Table D-1.9 (Sheet 2 of 2)
ffiOJECTED COO< INLET W£LLHEJID NI\TLRJlL GI\S ffiiCES
In 1983 [b 11 ars Per M13tu
Refereoce Case ConstCl1t 01Cl1ge Cases
(OCR OCR OCR ffil ShennCl1 Cl ark (Shermer~ Clark
YEAA M:!an) 3J% 50'/o Spring 1983 Base Case NSD Case) +2/yr CJX,/yr. -1.0/yr. -2.CJY./yr • ....------
2011 5.81 7.34 5.00 2.73
12 5.87 7.46 5.20 2.73
13 5.93 6.68 5.33 2.73
14 6.00 7.00 5.47 2.73
2015 3.00 1.18 1.47 6.00 7.91 5.60 5.12 2.73 1.98 1.44
16 6.07 8.03 5.74 2.73
17 6.13 8.15 5.89 2.73
18 6.20 8.27 6.04 2.73
19 6.27 8.40 6.19 2.73
2020 3.28 1.10 1.39 6.34 8.40 6.34 5.65 2.73 1.89 l.:D
21 6.41 8.40 6.44
22 6.48 8.40 6.53
23 6.55 8.40 6.63
24 6.62 8.40 6.73
2025 3.50 1.10 1.32 6.69 8.40 6.83 6.24 2.73 1.79 1.17
26 6.77 8.40 6.93
27 6.84 8.40 7.(}l
28 6.92 8.40 7.14
29 6.99 8.40 7.25
20]) 3.74 1.10 1.25 7.07 8.40 7 .?h 6.89 1.71 1.05
31 7.15 8.40 7.43
32 7.23 8.40 7.51
33 7.31 8.40 7.58
34 7.39 8.40 7.66
2035 3.99 1.10 1.18 7.47 8.40 7.73 7.61 1.62 0.96
?h 7.55 8.40 7.81
37 7.63 8.40 7.89
l3 7.72 8.40 7.97
39 7.00 8.40 8.(1)
2040 4.25 1.10 1.12 7.89 8.40 8.13 8.40 2.73 1.54 0.87
(!)Estimated 1983 price of Cook Inlet gas from Table D-2.5.
(2)Jldditional denand charge of $0.35/MvBtu applies from 1986 for~d iJ1d is escalated by price of oil change.
4 " '1 l l l ,i J _I
1 . -l l -1 -~ 1 J ~ ... _ ·~~ .~~~l c1 '1 I
Table D-1.10 (Sheet 1 of 2)
PROJECTED NORTH SLOPE DELIVERED NATURAL GAS PRICES
In 1983 [b ll ars Per M'-'Btu
Reference Case Constant Charge Cases
(DOR IXR DOR DRI Sherman Clark (Sherman Clark
YEAR tlean) 30% 5a'k Spring 1983 Base Case NSD Case) +2/yr (J'k/yr. -1.0/yr. -2JJ'k/yr.
I983"(1) 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00 4.00
1984 3.31 3.14 3.32 3.48 3.82 3.82 4.00 4.00 3.96 3.92
1985 3.13 2.9) 3.40 3.73 3.64 3.64 4.16 4.00 3.92 3.84
1986 3.09 2.81 3.05 3.98 3.64 3.64 4.00
1987 3.03 2.70 2.97 4.23 3.64 3.64 4.00
1988 3.07 2.66 2.95 4.51 3.64 3. 75 4.00
1989 3.11 2.64 2.94 4.00 5.53 3.86 4.00
199) 3.15 2.48 2.9) 5.11 5.53 3.98 4.59 4.00 3.73 3.47
1991 2.38 2.81 5.69 4.00
1992 2.34 2.78 5.86 4.00
1993 2.24 2.66 6.04 4.00
1994 2.20 2.61 6.22 4.00
1995 3.36 2.15 2.59 6.34 6.41 4.61 5.07 4.00 3.55 3.14
1996 2.12 2.49 4.00
1997 2.07 2.48 4.00
1998 2.06 2.46 4.00
1999 2.04 2.44 4.00
20CO 3.59 2.01 2.42 7.39 7.43 5.35 5.60 4.00 3.37 2.84
2001 4.00
2002 4.00
2003 4.00
2004 4.00
2005 3.83 1.86 2.29 7.81 8.82 6.20 6.18 4.00 3.21 2.56
2006 4.00
2007 4.00
2CXB 4.00
2009 4.00
2010 4.00 1. 73 2.16 8.24 10.48 7.18 6.83 4.00 3.05 2.32
2011 4.00
2012 4.00
2013 4.00
2014 4.00
2015 4.36 1.60 2.05 9.20 11.29 . 8.13 7.54 4.00 2.9) 2.10
Table D-1.10 (Sheet 2 of 2)
PROJECTED NCRTH SLOPE DELIVERffi NATLRf-\l GAS PRICES
In 1983 Dollars Per MMBtu
Reference Case
(OCR OCR OCR DRI Sherman Clark Sherman Clark
YEAR M2an) 30'/o 50).; Spring 1983 Base Case NSD Case +2/yr
2ol6
2017
2018
2019
2020 4.65 1.49 1.~ 9.20 12.16 9.20 8.32
2021 12.16
2022 12.16
2023 12.16
2024 12.16
2025 4.96 1.49 1.83 9.71 9.91 9.19
2026 12.16
2027 12.16
2028 12.16
2029 12.16
203) 5.29 1.49 1. 73 10.26 12.16 10.67
2031 12.16 10.15
2032 12.16
2033 12.16
2034 12.16
2035 5.64 1.49 1.64 10.84 12.16 11.22 11.20
2036 12.16
2037 12.16
2038 12.16
2039 12.16
2040 6.02 1.49 1.55 11.45 12.16 11.79 12.37
(!)Estimated 1983 price of North Slope gas fran Table D-1.8.
' J
Cf!o/yr. -1.0/yr. -2 .CJ'Io/ yr .
4.00
4.00
4.00
4.00
4.00 2.76 1.89
4.00
4.00
4.00
4.00
4.00 2.62 1.71
4.00
4.00
4.00
4.00
4.00 2.49 1.55
4.00 2.49 1.55
4.00
4.00
4.00
4.00 2.37 1.40
4.00
4.00
4.00
4.00
4.00 2.26 1.26
-
-
.-
-
-
-
Table D-2.1
DEMONSTRATED RESERVE BASE IN ALASKA AND THE U.S: BY TYPE OF COAL
(values in millions of short tons)
Type of Coal
Anthracite
Bituminous
Subbituminous
Lignite
Total
Percent of Total
Alaska
697.5
5,443.0
14.0
6,154.5
1. 3%
Total U.S.
7341.7
239,272.9
182,035.0
44,063.9
472,713.6
l 00%
Source: Demonstrated Reserve Base of Coal in the United States
on January 1, 1980.
Table D-2.2
RESERVES AND RESOURCES OF THE NENANA FIELD
Reserve/Resource Type Quantity
(tons x 106)
Reserve Base 457
Resources
Measured 862
Indicated 2,700
Inferred 3,377
Total 6,938~/
~/Totals do not add due to rounding on measured and
inferred.
Source: Energy Resources Co., 1980.
,:.---"
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-
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,....
-
Table D-2.3
PROXIMATE AND ULTIMATE ANALYSIS OF NENANA FIELD COAL
Proximate
Analysis
Moisure
Ash
Volatile Matter
Fixed Carbon
Ultimate Analysis,
As Received
(wt %)
Hydrogen
Carbon
Oxygen
Nitrogen
Sulfur
Chlorine
Moisture
Ash
Higher Heating
Value (Btu/lb)
Weight
Percent
26.1
6.4
3 6. 3
31. 2
3.6
47.2
15 . 5
l. 05
0. 12
26.1
6.4
7,950
Source: Hazen Laboratory Analyses for Fairbanks Municipal
System.
Table D-2.4
U-LTIMATE ANALYSIS OF BELUGA COAL
Element/
Compound Analyses
(wt %)
Stanford2./
Battelle.!?_/ Research
Institute Waterfall Seam)
Carbon 44.7
Hydrogen 3.8
Nitrogen 0.7
Oxygen 15.8
Sulfur 0. 2 0.18
Ash 9. 9 16.0
Moisture 24.9 21.0
Higher
Heating
Value
(Btu/lb) 7200 7536
a;stanford Research Institute, 1974
~/Swift, Haskins, and Scott, 1980
c;oiamond Shamrock Corporation, 1983
Diamond-Shamrock~/
Alaska Coal Co.
45.4
2 . 9
0.7
14.4
0.14
7 . 9
28.0
7800
r::-~-,
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-
-'
-
-
,.._
Table D-2.5
COAL FIRED GENERATING CAPACITY IN ALASKA
He at
Owner Location Rate
Golden Valley
Electric Assn.
University of
Alaska
U.S. Air Force
Ft. Wainwright
Fairbanks
Municipal Utility
System
Tot a 1
Healy
Fairbanks
Fairbanks
Fairbanks
N/A
Source: Battelle, Vol VI, 1982.
(Btu/kWh)
13,200
12,000
20,000
13,300-
22,000
13,000-
22,000
Capacity
(MW)
25
13
20
29
87
Table D-2.6
PROJECTED NATIONAL SHARES OF JAPANE~~ COAL MARKET
F 0 R I M P 0 R T S I N T H E Y EAR 1 9 9 0-
Market Share
Nation Percentage Million Tons
Australia 41.8 30.4
Can ad a 11.9 8. 7
United States 15 • 3 11. 1
China 16. 0 11.6
USSR 5.6 4.1
South Africa 4.2 3.0
A 1 l Others 5.2 3.8
Total 100.0 7 2. 7
a/Includes steam co al and metallurgical coal.
Source: MRI, 1982
r···
~-~-
-
-
-
Table D-2.7
THE VALUE OF COAL DELIVERED IN JAPAN BY COAL ORIGIN
(Jan. 1983 Dollars)
Nation of
Coal Origination
Australiaa;
South Africabj
Canadac;
Value of Coal
(FOB Port)
$45.00
37.50
45.00
Shipping Cost
($/ton)
10.50
15.30
10.35
a;From Sherman H. Clark and Associates, 1983
bfFrom Diamond Shamrock Corp.; 1983
V. a 1 u e of Co a 1
($/ton)($/million Btu)
$55.50
52.80
55.35
$2.49
2.37
2.48
CfAssumes 11,160 Btu/lb per Japanese Specification
-in Swift, Haskins, and Scott, 1980.
Table D-2.8
THE MARKET VALUE OF COAL FROM THE BELUGA FIELD
FOB GRANITE POINT, ALASKA
(Jan. 1983 Dollars)
The Value of Coal in
Japan~/
Price Discount Based
upon the impact of
lower quality on
plant capital
costs (1.6%)~/
Net Value of Coal
in Japan
Cost to Transport CoalCf
Net Value of Coal at
Granite Point
a;From Table D-2.7
Value of Coal
($/Million Btu)
Low
$2.37
$0.04
$2.33
$0.55
$1.78
~
$2.49
$0.04
$2.45
$0.51
$1. 94
bfSee Swift, Haskins, and Scott (1980) analysis on Waterfall
-Seam Coal, pp. 7-5, 7-6.
c;cost is $8.00/ton. Low value column reflects 7200 Btu/lb
coal and high value column reflects 7800 Btu/lb coal (see
Table D-2. 4).
)~.
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-
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-
Table 0-2.9
PRODUCTION COST ESTIMATES FOR BELUGA COAL IN 1983 DOLLARS
Coal Price a;
Source Mine Site Location
(tons/yr) (FOB)
Range
$/million
Diamond A 1 ask aE../ 10 million ship 1.20-1.70
Bechtel.S:.I 7. 7 million ship 1.27-1.65
P 1 ace r AmexEJ 5 million mine 1.16-1.74
~/All previous estimates escalated by the implicit price
deflation series. ~/Source: Styles, 1983.
%;source: Bechtel Report for H-B-W (Bechtel, 1980).
-Source: DOE, 1980.
Btu
Table D-2.10
BELUGA AREA HYPOTHETICAL MINE
SUMMARY OF SELECTED DATA
Production Rate Per Year (Tons)
Mine Life At Full Production (Years)
Average Stripping Ratio (BCY/Ton)
Personnel (Average)
Operat1ng
Maintenance
Salaried
Tot a 1
Case 1
1,000,000
30
5.93
81
74
33
188
Tons Per Man-Shift (Average)
Initial Capital Investment
Initial Capital Investment Per
Life Of Mine Capital Required
21. 3
$101,041,000
Annual Ton$101.04
$183,027,000
Average Annual Operating Costs (Per Ton)
Drainage Control and Reclamation
Stripping
Mining And Hauling Coal
Coal Handling And Transporting
Haul Road Construction And Maintenan
General Mine Services
Supervision And Administration
Production Taxes And Fees
Total Cash Costs
Average Depreciation
Average Total Cost
Average Coal Prices (Per Ton)
At 10% R.U.R.
At 15% R.O.R.
At 20% R.O.R.
Average Coal Prices (Per MM Btu)(a)
At 1o% R.O.R.
At 15% R.O.R.
At 20% R.O.R.
Note:
(a) Assumes 7,500 Btu/Lb.
$0.60
9.19
1.11
3.05
ce 1. 24
1. 22
2.96
0.35
$19.72
6.10
$25.82
$40.85
47.99
56.40
$2.72
3.20
3.76
Case 2
3,000,000
30
5.89
194
176
56
426
28.2
$186,321,000
$62.11
$353,450,000
$0.32
8.52
1. 08
1. 7 7
0.65
0.79
1. 64
0.35
$15.12
3.97
$19.09
$28.52
33.52
39.70
$1.90
2.23
2.65
Source: Mining Cost Estimates, Beluga Area Hypothetical Mine,
Paul Weir Company, June 27, 1983.
Table 0-2.11
!""". SOME PROJECTED REAL ESCALATION RATES FOR COAL PRICES
Real Escalation
Forecaster Coal Rate to 2010 -% --
.....
Battelle (1982)~/ Beluga 2 • 1
Nenana 2. 0
Acres ( 1 981 )E._/ Beluga 2.6 -Nenana 2. 3
Acres (1982)£/ Be 1 u g a 2.5
~
Nenana 2. 7
-
~/Secrest and Swift, 1 98 2.
B. I 0 i e·n e r , 1 981.
-£1oiener, 198 2.
-
-
Table D-2.12
COAL PRICE REAL ESCALATION RATES
Author
DRI
Sherman H.
C l ark
a;Hv of 10,000 Btu/lb.
tr;Hv of 7,500 Btu/lb.
Coal Types
New Coal Contracts
New Coal Contracts
and Spot Market Coal
Western Coal a;
Western Lignite~/
Coal Exports
Sources: DRI, 1983; Clark, 1983.
Long Term
Real Escalation
Rate -%
2. 6
2.9
2.3
1.6
r-,
r>;-.---
.F-.-,i
Table D-2.13
NENANA COAL TRANSPORTATION COSTS
FROM HEALY TO GENERATING PLAN LOCATION (1983 $/MMBtu)
P 1 ant Location -Year Nenana w i 11 ow Matanuska Anchorage Seward
1983 0.32 0. 51 0.60 0. 7 0 0.78 -1984 0.30 0.48 0. 57 0.67 0.74
1985 0.30 0.48 0. 57 0.67 0. 7 5
1986 0.32 0.49 0.58 0.67 0.76
1987 0.33 0.50 0.58 0.68 0. 7 7
I"'" 1988 0.33 0.50 0.59 0.69 0.78
1989 0.34 0.51 0.60 0.70 0. 7 9
1990 0.34 0.52 0.61 0. 71 0.80
r--1991 0.35 0. 52 0.62 0.72 0.81
1992 0.35 0.53 0.63 0.73 0.82
1993 0.36 0.54 0.64 0.74 0.84 -1994 0.36 0.54 0.64 0. 7 5 0.84
1995 0.36 0. 55 0.64 0. 7 5 0.85
1996 0.37 0. 55 0.65 0. 7 6 0.86
1997 0.37 0. 55 0.65 0.76 0.86 -1998 0.37 0.56 0.66 0. 77 0.87
1999 0. 3 7 0.56 0.66 0. 7 8 0.88
2000 0.38 0.57 0.67 0.78 0.88 -2001 0.38 0. 57 0.67 0. 7 9 0.89
2002 0.38 0.57 0.68 0. 7 9 0.90
2003 0.39 0.58 0.68 0.80 0.90
2004 0.39 0.58 0.69 0.81 0.91 ..... 2005 0.39 0.59 0.69 0. 81 0.92
2006 0.40 0.59 0.70 0.82 0.92
2007 0.40 0.60 0.70 0.83 0.93
!"""' 2008 0.40 0.60 0.71 0.83 0.04
( 2009 0.41 0.61 0. 7 2 0.84 0. 9 5
2010 0.41 0.61 0.72 0.85 0.95 -
Notes:
,..~ Transportation cost equations: (1983)
Healy to:
N en an a = $0.23 + 0.09 ( 0 i 1 escalation rates)
Willow = 0.36 + 0.15 ( 0 i l escalation rates)
Matanuska = 0.42 + 0.18 ( 0 i l escalation rates)
Anchorage = 0.49 + 0.21 ( 0 i 1 escalation rates)
Seward = 0.55 + 0.23 ( 0 i l escalation rates)
Table D-2.14
ESTIMATED DELIVERED PRICES OF COAL IN ALASKA BY YEAR
(In 1983 $/Btu x1o6)
Year
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
Nenana Field Coal Delivered To
Mine Mouth
(2.6%/yro)
1. 40
1. 44
1. 4 7
1. 51
1. 55
1. 59
1. 63
1. 68
1. 72
1. 76
1. 81
1. 86
1. 91
1. 85
2001
2006
2. 11
2.17
2.22
2.28
2o34
2. AO
2.46
2. 53
2o59
2o66
2.73
2.80
Nenana
(2o2%/yr)
1. 72
1. 74
1. 77
1. 83
1. 88
1. 9 2
1. 97
2. 02
2. 0 7
2.11
2 . 1 7
2o22
2 0 2 7
2o32
2o38
2o43
2.48
2.55
2.60
2066
2. 7 3
2.79
2.85
2.93
2.99
3.06
3. 14
3. 21
Willow
(2.2%/yr)
1. 91
1. 92
1. 95
2.00
2o05
2.09
2.14
2 0 20
2.24
2. 2 9
2. 3 5
2.40
2.46
2.50
2. 56
2.62
2.67
2.74
2. 7 9
2.85
2.92
2.98
3.05
3.12
3.19
3 0 26
3.34
3o41
Beluga Field Coal
With Exports
(1.6%/yr)
1. 86
1. 89
1. 9 2
1. 95
1. 98
2.01
2.05
2.08
2 0 11
2.15
2. 18
2. 21
2. 2 5
2. 2 9
2.32
2. 36
2.40
2.44
2.48
2. 51
2.55
2. 6 0
2.64
2.68
2o72
2.77
2.81
2.86
-
-
Table D-3.1
PRICES OF TURBINE AND DIESEL OIL
FOR ELECTRICAL GENERATION -1983 $/MMBtu
Location
Type Fuel Anchorage Fairbanks
Diesel oil -No. 1-y 6.87 7.46
Turbine oil -No. 1-2~1 6.23 7.02
11 Based on average of price quotes from Chevron and Tesoro Oil
Companies of about $0.95/gal. for Anchorage and $1.03/gal. for
Fairbanks (June 1983) the heating value is about 5.8 X 106
Btu/bbl.
21 Based on price quote by Tesoro Oil Comapny of $0.86/gal. in
Anchorage and $0.97/gal. in Fairbanks (June 1983) the heating
value is about 5.8 X 106 Btu/bbl.
Tct>le D-3.2
PROJEClED PRICES CF DIESB.. IWJ ~~If'£ FUEL AT ftJ'.[trnACE
Fffi VJlRIOJS OIL PRICE SCENARI~ -1983--2010
(1983 $/Mvmu)
orn orn orn au St-CA Reference ConstCllt Rates of Dlange
M=an n 50'/. Basecase Case Spring 1983 +Z'!o/yr. (Jjjyr. -1%/yr. -'do/yr.
Year Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine
1~ri! 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87
1984 5.69 5.16 5.39 4.89 5.70 5.17 5.97 5.41 6.55
1985 5.13 4.88 4.98 4.51 5.84 5.3J 6.41 5.81 6.25
1986 5.31 4.81 4.82 4.37 5.23 4.74 6.25
1987 5.21 4.72 4.63 4.20 5.10 4.63 6.25
1988 4.57 4.15 5.a> 4.59 6.25
1989 4.53 4.10 5.04 4.57 9.50
1990 5.49 4.98 4.25 3.85 4.99 4.52 8.78 7.97 9.50
1991 4.10 3.71 4.82 4.37
1992 4.01 3.63 4.77 4.32
1993 3.85 3.48 4.57 4.14
1994 3.78 3.42 4.48 4.a>
1995 5.85 5.24 3.70 3.35 4.46 4.04 10.90 9.88 11.02
19% 3.64 3.3J 4.27 3.88
1997 3.55 3.21 4.26 3.86
1998 3.53 3.20 4.22 3.83
1999 3.50 3.20 4.20 3.81
2(XX) 6.24 5.52 3.45 3.15 4.15 3.76 12.69 11.51 12.78
1/See Exhibit B Section 5.4 for projected rates of change in oil prices.
""2"/Prices fran TctJle D-3.1
6.23
5.94
5.66
5.66
5.66
5.66
8.62
8.62
9.99
11.58
6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23
6.55 5.94 7.01 6.35 6.87 6.23 6.00 6.17 6.73 6.11
6.25 5.66 7.15 6.48 6.87 6.23 6.73 6.11 6.60 5.98
6.25 5.66 7.29 6.61 6.67 6.04 6.47 5.86
6.25 5.66 7.44 6.74 6.60 5.98 6.34 5.75
6.25 5.66 7.59 6.88 6.53 5.92 6.21 5.63
6.43 5.83 7.74 7.02 6.47 5.87 6.09 5.52
6.63 6.01 7.89 7.16 6.87 6.23 6.40 5.81 5.% 5.41
7.68 6.97 8.71 7.90 6.87 6.23 6.09 5.52 5.39 4.89
8.91 8.00 9.62 8.72 6.87 6.23 5.79 5.25 4.87 4.42
" J
1 J
Tcble D-3.2
PROJECTED PRICES a= OIESB.. MD TLR~JNE FUEL AT MCI-ffiAG:
FCR VAAIOOS OIL PRICE SCEr-.Ll\RIO~ -1983-2010
( 1983 $/M13tu)
]
!XR OCR !XR l.lU SI-CA Reference CoostcYJt Rates of OlcYJge
M=an lJX 50% Spring 1983 Basecase Case +2 /yr. tJYJyr. -1%/yr. -i!!o/yr.
Year Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine DieseTTurbine Diesel Turbine Diesel Turbine Diesel Turbine
2001
2002
2003
2004
2005 6.66 5.81 3.20 2.92 3.93 3.56 13.40 12.16 15.17 13.75 10.32 9.li 10.62 9.63 6.87 6.23 5.51 4.99 4.40 3.99
2(0)
2007
20)3
2003
2010 7.10 6.12 2.97 2.71 3.72 3.37 14.16 12.84 18.02 16.33 11.97 10.85 11.73 10.63 6.87 6.23 5.24 4.75 3.98 3.61
·-
-
McARTHUR R
¢
KALGIN ISLAND ~
".;;:
&
CJO
.NORTH FORK
OA
'
N. COOK INLET
..:,.<(,,•" ,,--..
0'-'··· <?~ ....
?-s •• ••
(,. .. · ~WEST FORK •• •••• .. ···* . .. .. ·······-···--···· ..
•••••• STERLING EN AI
.
.·
. .
. . . .
8 OIL FIELDS WITH GAS
• GAS FIELDS
COOK INLET GAS FIELDS
FIGURE D-1.1
Collier Phillips/ SOCAL
Carbon ' Marathon ARCO Recoverable
Reser~es{l}
Chugach
Electric
En star Assoc. ~ Chemical LNG Rental
Bea~er Creek
Beluga River
Birch Hill
Cannery loop
falls Creek
Ivan River
Ka 1 d achabun a
Kenai
Lewh River
McArthur River
Nicolai Creek
North Cook Inlet
North fork
H. Hiddle Ground
Sterling
StlJ1Jp Lake
Swanson River
Trail Ridge
Tyonek
West fore land
Total
Notes
240
742
11
HIA
13
26
HIA
1,109
22
90
17
951
12
HIA
23
HIA
HIA
HIA
20
3,541
250(2)
220 285
256
27(6)
759 285
(1) Alaska Oil And Gas Conser~atlon Commission.
(2) Port of gos will be taken from Kenai f1eld.
(3) Participant in exploration underway In 1g80.
( 5) 377 250
110( 7)
377 360
N/A
N/A
106
N/A
N/A
N/A
0
106
(4) Based on DeGolyer and MacHoughten reserve estimate in 1975.
(5) Uncertain royalty status.
Pacific
Alaska
Uncommitted LNG
Reserves Assoc.
0
237 404
11
ll
26
120
22
90
17
814
12
23
259( 8)
20
1,654
( 3)
106(4)
99(4)
760(9)
(6) Royalty gas.
(7) This figure assumes that Tokyo Gas Co. and Tokyo Electric Co. contract5 will be met by gas from the Cook
Inlet Field. In actuality, a significant portion 1s supplied by the Kenai field.
(8) Estimate of gas available on blowdown.
(9) PALNG's lotest e5tlmate of their previously committed reserve Is 980 Bcf Jess the 220 lost to Enstar ..
Thi5 760 Bcf Is 151 ~reater than the sum of quantities from the individual fields. It is not known from
which fields the additional 151 Bcf would come.
ESTIMATED COOK INLET NATURAL GAS RECOVERABLE RESERVES
AND COMMITMENT STATUS AS OF JANUARY 1,1982
]
,.,
J
FIGURE D-1.2
l
1 l
1 l
~SHADING DENOTES
~OFFSHORE AREAS
l 1 --]
16
J 1
' \ ,.-\ --~1
,..-
r.J
r" ,. ...
I ,.
,..J
AREAS OF ALASKA ASSESSED BY THE
U.S.G.S. FOR UNDISCOVERED RESOURCES
SOlflCE: U.S. DEPARTMENT OF THE INTERIOR
GEOLOGICAL SURVEY, OPEN-FILE REPORT 82-666A, 1981.
1
GULF OF ALASKA SHELF
GULF OF ALASKA SLOPE
FIGURE D-1.3
IDOO
IODO
4000
...
0
Ill
t--._.PR.;.;;O~VEN llfliERIIEI
U)
~ aooo
a;
w
1/)
w
fl!
aooo
1000
11112
W&.IT AllY
11186 111110 111116
YEA II
2000 200~
COOK INLET NATURAL GAS RESERVES AND
ESTIMATED CUMULATIVE CONSUMPTION
l
2010
FIGURE D-1.4
-
!"""'
i
-!
-
Coal Generation Cost·
Unit Size
Unit Capital Cost
Ava i 1 ab i 1 i t y
Annual Generation
Fuel Cost
Heat Rate
0 & M Cost
Real Cost of Capital
Economic Life
200 MW
$2,340/kw
85%
1.5 x 109 kwh
$1. 70/MMBtu
9,750 Btu/kwh
$0.0032/kwh
3.5%
35 years
Annual Cagital Cost: c =($2340/kw){200,000 kw)(CRF; 35 yrs; 3.5%) = cap
Annual 0 & M C~st:
Co&M=(1.5 x 10 kwh/yr.)($0.0032/kwh) =
$22.6 X 106
$4.8 X 106
Annual Fuel Gost: cF=(1.5 x 10 kwh/yr)(9750 Btu/kwh)($1.70/106 Btu) = $24.9 X 106
Total Annual Costs
Gas Generation Cost
Unit Size (combined cycle)
Unit Capital Cost
Avai 1 abi 1 ity
Annual Generation
Fuel Cost
Heat Rate
0 & M Cost
Real Cost of Capital
Economic Life
200 MW
$650/kw
85%
1.5 x 1Q9 kwh
?
8,200 Btu/kwh
$0.0042/kwh
3.5%
30 years
Annual Ca8ital Cost: c ={$65 /kw)(200,000 kw)(CFR; 30 yrs; 3.5%)= cap
Annual 0 & M C~st: Co&M= t 1. 5 x 10 kwh/yr.) ( $0. 0042/kwh) =
Total Annual Costs Without Fuel
Gas Ft.iel Cost
$52.3 X 106
$6.8 X 106.
$6.3 X 106
$13.1 X 106
Cost of Gas Fuel = Total annual coal generation costs
less tas costs without fuel
Annua gas generat1on t1mes gas heat rate
= $52.3 X 106 -$13.1 X 106
( 1.5 x lOg kwh)(8,200 Btu/Kwh)
= $3.19/MMBtu
MAXIMUM DEREGULATED COOK INLET GAS PRICES
(BASED ON SUBSTITUTABILITY OF COAL-FIRED UNITS)
FIGURE D-1.5
(/)
-I z
< 0
0 1-
0 0
u. a:
0 1-w
(/) ~
1-cr. z
0 0
a.. -I ~ ~
~
'-'
200 ---
~
100
--------
~ ~
~ JAPAN
~ ~
30· YR. AVERAGE GROWTH RATE
150
~ ~
50 . ---
------1980 1985 1990
SOUTH KOREA
5.2 'j{,
30 -YR. AVER,GE
1995
YEAR
2000
PRESENT AND PROJECTED COAL IMPORTS
IN JAPAN AND SOUTH KOREA, 1980-2010
---~---
GROWTH RAIE
2005 2010
SOURCE: SHERMAN CLARK ASSOCIATES 1983 FIGURE 0-2.1
J -,
' J
-,
'
r
-I
r
-
GWR/YR
200,0CO~-----------------+------------------~----------------~
~.occ-r----------------~------------------+-----------------~
JAPAN
1~.~~-----------------+--------~~------+-----------------~
100,0CO~----------------~~----------------+-----------------~
TAIWAN
1980 1990 2000
YEAR
PROJECTED COAL FIRED ELECTRICITY GENERATION
IN PACIFIC RIM COUNTRIES, 1980-2000
(GWR/YR)
FIGURE D-2.2
~
<(
z 0
0 (.) -~ :j 0
~ (/J z
0
~
120+--------------------------+--------------------------+ TOTAL
110~------------------------~--------------------~?----
100
90
30
7
60
50
40
30
20
10
1980
AVERAGE ANNUAL
MARKET GROWTH
RATE :: 11.3%-JAPAN
TAIWAN
:KOREA
1990 2000
YEAR
TOTAL COAL NEEDS FOR ELECTRIC POWER
GENERATION IN PACIFIC RIM NATIONS, 1980-2010
FIGURE D-2.3
~~ .\ ~Y.· 1. 0 •••• . _.,. ··············
J
\ .. . ... ·.. . ·.. ······ .............. ····· ....... ········· ·······.
a
··. . .... ·. . '• ·. ·· .. ·.. . ...... .
..
. . .. ... ~ ....
... ··
\
.
\ . .
i : . .
... ····· .... " ............................ .
.· .. ..
TO-JAPAN
FROM-ALASKA
VANCOUVER
3320 MI.
4262 MI.
U.S. WEST COAST 4839 MI.
AUSTRALIA 4265 MI.
SOUTH AFRICA 7291 MI.
U.S. GULF COAST 9095 MI.
U.S. ATLANTIC 9504 MI.
DISTANCES FROM COAL PORTS TO JAPAN COAST
(PANAMA CANAL)
FIGURE D-2.4
$3.00
$2.00
$1.00 ~
r-
1980
WESTERN COAL ~ 30 YR AVERAGE::: @ 10,000 BTU/LB~
2.9%/YR -
WESTERN LIG NilE -;-
--
30 YR AVERAGE
(il 7,500 BY BTU/LB 2.3%/YR
1990 2000 2100
YEAR
FORECAST REAL COAL PRICES FOR WESTERN
COAL AND LIGNITE, 1980-201 O;NEW CONTRACT
AND SPOT MARKET STEAM COAL
(1982DOLLLARS)
1
1
-,
_j
-~
FIGURE D-2.5
-
-
-
SUSITNA HYDROELECTIC PROJECT
VOLUME 1
EXHIBIT 0, APPENDIX D-1
FUELS PRICING STUDIES
TABLE OF CONTENTS
1 -Natural Gas •..................................•...........
1.1 Resources and Reserves ..........................•.... a) Cook Inlet Proven Reserves ...................... .
~) Cook Inlet Undiscovered Gas ..........•...........
c) North Slope Gas ......•.........•..................
d) Gulf of Alaska Gas ..•....•.................•.....
1.2 Production and Use .....................•............•
a) Cook Inlet Current Production and Use ........... .
b) Cook Inlet Future Use ........•..•................
c) Competition For Cook Inlet Gas .......•.........•.
d) North Slope Gas ...•....•..•......................
e) Gulf of Alaska Gas ...•............•..............
1.3 Current Prices ...................................... .
a) Cook I n 1 e t ...................................... .
b ) North S 1 ope •..•...............•..•...............
1.4 Projected Gas Prices ................................ .
1.5 Effect of Gas Price Deregulation ...................•.
a) Existing Law .................................... .
b) Proposed Changes to the NGPA .•...................
c) Deregulated Cook Inlet Gas Prices ............... .
1.6 References and Notes ..•..•.........•.................
Page
Dl-1
D1-1
D1-2
D1-2
D1-3
01-3
D1-4
D1-4
D1-5
D1-7
D1-8
01-9
D1-10
D1-10
D1-13
D1-17
D1-17
D1-18
D1-20
01-21
D1-23
2 -Coal ..................... _ .......................... _ ........ Dl-25
2.1 Resources and Reserves ..•............•............... 01-25
2.2 Present and Potential Alaskan Coal Production ......... D1-26
2.3 Curr~nt Alaskan Coal Prices .........•............•... D1-27
a) Nenana Field ...•.•...•.....•...•.................. D1-27
b) Beluga Field ....•.............•.................•. D1-29
2.4 Coal Price Escalation .......•.......•................ 01-32
2.5 References and Bibliography ..•....................•.. D1-37
3-Distillate Oil ..........................•................. D1-40
3.1 Availability .•...............•....................... D1-40
3 . 2 P r i c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 1-40
Appendix D-1
LIST OF TABLES
D-1.1 Preliminary Estimates of Undiscovered Gas Resources in Place
and Economically Recoverable Gas Resources For the Cook Inlet
Basin.
D-1. 2 Historical and Current Production and Use of Cook Inlet
Natural Gas
D-1.3 Estimated Use of Cook Inlet Natural Gas by User
D-1.4 Current Production and Use of North Slope Gas For 1982
D-1.5 Estimated Base Prices For New Purchases of Uncommitted and
Undiscovered Cook Inlet Gas -Without LNG Export Opportunities
D-1.6 Estimated 1983 Base Prices For New Purchases of Uncommitted
and Undiscovered Cook Inlet Gas -With LNG Export
Opportunities
D-1.7 Estimated Cost of North Slope Natural Gas For Electric
Generation at Kenai Assuming Implementation of the Trans
Alaska Gas System (TAGS)
D-1.8 Estimated 1983 Delivered Cost of North Slope Natural Gas For
Railbelt Electrical Generation
D-1.9 Projected Cook Inlet Wellhead Natural Gas Prices
D-1.10 Projected North Slope Delivered Natural Gas Prices
D-2.1 Demonstrated Reserve Base in Alaska and the U.S. by Type of
Coal
D-2.2 Reserves and Resources of the Nenana Field
D-2.3 Proximate and Ultimate Analysis of Nenana Field Coal
D-2.4
D-2.5
D-2.6
D-2.7
D-2.8
Ultimate Analysis of Beluga Coal
Coal Field Capacity in Alaska
Projected National Share of Japanese Coal Market For Imports
in the Year 1990.
The Value of Coal Delivered in Japan By Coal Origin
The Market Value of Coal From the Beluga Field FOB Granite
Point Alaska
r
.....
r
r
-
Appendix D-1
LIST OF TABLES
D-2.9 Production Cost Estimates For Beluga Coal in 1983 Dollars
D-2.10 Beluga Area Hypothetical Mine -Summary of Selected Data
0-2.11 Some Projected Real Escalation Rates For Coal Prices
D-2.12 Coal Price Real Escalation Rates
D-2.13 Nenana Coal Transportation Costs From Healy to Generating
Plant Location
D-2.14 Estimated Delivered Prices of Coal in Alaska by Year.
D-3.1 Prices of diesel and Turbine Fuel For Electrical Generation -
1983 $/MMBtu
D-3.2 Projected Prices of Diesel and Turbine Fuel at Anchorage For
Various Oil Price Scenario
Appendix D-1
LIST OF FIGURES
D-1.1
D-1. 2
D-1. 3
D-1.4
D-1. 5
0-2.1
0-2.2
0-2.3
D-2.4
D-2.5
Cook Inlet Gas Fields
Estimated Cook Inlet Natural Gas Recoverable Reserves and
Committment Status as of January 1, 1982
Areas of Alaska Assessed by the U.S.G.S. For Undiscovered
Resources
Cook Inlet Natural Gas Reserves and Estimated Cumulative
Consumption
Maximum Deregulated Cook Inlet Gas Prices
Present and Projected Coal Imports in Japan and South Korea
1980-2010
Projected Coal Fired Electricity Generation in Pacific Rim
Countries, 1980-2000.
Total Coal Needs For Electric Power Generation in Pacific Rim
Nations, 1980-2010
Distances From Coal Ports to Japan
Forecast Real Coal Prices For \~estern Coal and Lignite,
1980-2010; New Contracts and Spot Market Steam Coal