The URL can be used to link to this page

Home My WebLink AboutAPA123 FERC App Vol 1 Exh A C DSUSITNA HYDROELECTRIC PROJEC FERC LICENSE APPLICATION PROJECT NO.7114-000 As accepted by FERC,July,27,1983 (I? Demeo,Inc.38-293 DATE DUE l n \j ,...., 1 Sl1~ tq~ BEFORE THE FEO=~i;L ENERGY REGULA TORY COMMISSION 1\< IJ-j "2.'3 .Sf> fl.l"t-i 357 no,\23 .... APPLJCATiON FOF=1 LICENSE FOR MAJOR PROJECT SUSITNA HYDROELECTRIC PROJECT VOLUME 1 - .... f UNiVEFlSlTY OF ALASKA ARCTIC ENV!RONMENT/U..INFORMATION AND OAT)"CENl'ER 70]A Sr£fiET f-';.N>f'.itiO'~E,AIiib 99'SO'l INITIAL STATEMENT EXHIBIT A EXHIBIT C FEBRUARY 1983 EXHIBIT 0 REVISED JULY 1983 ALASKA POWER AUTHORITY INITIAL STATEMENT - ..... BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION: APPLICATION FOR LICENSB 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 - - co v 0)co ~ o 8 LO LO '"M M (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). -2- r.--'" ,~ - "... I (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.1r;-§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 -3- 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.§134l (1977).The certificate is governed by ALASKA ADMIN.CODE tit.18, §§15.l30-l5.l80.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.§§46.40.030-46.40.040i §§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 -4- pm, - - the applicable di'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 aD). 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. -5- (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.You1 d ,its Executive Oi rector ,this 15th day of February 1982. By Eric P.Yould Executive Direct r SEAL -6- - - - - - _.JURISDICTIONAL LEGISLATION .- §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 ofthe 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 April 1,1977.(§2 ch 90 SLA 1918) Chapter 83.Alaska Power Authority. Article 1.Creation and Org3nization (n 44.83.010 -44.83.0501 2.Purpose and Powers (n 44.83.070 -44.83.090) 3.Financial Provisions en 44.83.100 -44.83.160) 4.Power ProducLionCost Assistance (n 44.83.162 -....83.164) 5.Power Project Fund II 44.83.170) 6.General Provisions (n 44.83.177 -44.83.240) 7.Susitna River Hydr~leclric Projeh (n 44.83.300-44.83.3601 Article 1.Creation and Organization. -Seelior\ 10.Legislative finding and policy 2O.Crration of aU.lhorily 30.Membership of the authority 40.OO'icera and quorum Section 45.Qualifications.power ••and dUlies of office,..and directors. 50.lRepealed! Sec.44.B3.0lt)'Legislative rmding 8,nd policy..(a)The legislature finds,determines and declares that 250 §44.83.020 STATE GOVERNMENT §44.83.030 (1)there exist numerous potential hydroelectric and fossil fueJ 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 o(amendment.-The 1978 amendmenl in subseclion lal,subsliluled ·poWIIT at the lowest reasonable cosl"for "lower toat power"in paragraph (2)and ·Iowesl reasonable consumer power costs lind beneficial"for "tower conwmH pOWH cosU and",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 develorment. (b)The commissioners of community and regional affairs.natural resources,transportalion and public facilities,and revenue shall have the rights and privileges of directors except for the right to 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 this section. 251 144.83.040 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 deterr'Q.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 membl: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,and 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 lJ1annel'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 stafT as necessary.In addition to its starr 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 b9ard 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 cll 156 SLA 1978. Editor',note.-The repealed section derived from §1.ch.278,SLA 1976. Article 2.Purpose and Powers. Section 70.PUf?OIIe of tne lIuthority BO.Powen or the authority Section 90.Power contracls and the Alaska Public litLlities 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 25-2 §44.83.080 STATE GOVERNMENT §44.83.080 constructing,acquiring,financing and operating power productiDn facilities limited to fossil fuel,wind power,tidal,geothermal hydrDelectric,or solar energy production and waste energy conservation facilities.(§1 ch 278 SLA 1976;am §5 ch 156 SLA 1978) Effect o(amendment.-The 1978 amendment $ubstituted the Jangua!:e 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: (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; (4)tD 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 Dut any of its corporate purposes and powers,including the acquisition or construction of a project tD be owned or leased,as lessor or lessee,by the authDrity,or by another person,or the acquisition of any interest in a project or any right to capacity ofa project,the establishment Dr 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,conveyor 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; (0)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 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 253 254 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 authori ty first determi nes 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; (0)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 :1 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) ALASKA STATUTES §44.83.080 power ~cncraled by a project.or any right to lhe capacity of it"following "enter into contracts"near the beginning of para· graph (III,added the Jan!:uage ucginning "for the purchase.sale.exchange"to the end of paragrapn (Ill,and deleted "hydroelectrical and fossil fuel"following "with respect to"and "gcnerating"follow. inl("power"in paraKraph 1131. The 19HO amendment inserted in the middle of pMaj;(rllph (131,"feasibility studirs,and en~in.~crin~lind design,"and lidded parafo(rupn (161. Effect of amendments.-Thc 1978 amendment substituted "equip,operate. and maintain"for "equip and opcrate"in paragraph (51,inserted "or by nnother per' son"in paragraph 161.substituted "a projecl"for "it"in t .....o places in paragraph (61,substituted "any person"for "a federal agency or an agency or instrumentality of the slate.municipality,private organiution or other sourcc"in Pllra~raph (81.inserted "linancing"near the middlc of parlll:raph ~101.delctt'd "for the purchase. sale.uchange.trllnsmission.or use of §44.83.080 - - - - - A~IENDMENTS §44.81.270 ALASKA STATUTES SUPPLEMENT §44.81.280 f"!'" I 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.(§'8 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'-OffiCers 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 for 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 "at 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 commissionel of com- merce and economic developmen t"in para- graph (2). Editor's notes.-Section 15,ch.U8, 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 twa-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 [~ §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 (1)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 of its 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 exerCise 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,conveyor 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 §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 ofthe credit of the state to·guarantee repayment of all or any portion of revenue bonds issued to assist in construction ofpower 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 - -i r ! r- I I"""! P"" I ! - SUS I TNA HYDROELECTRIC PRO,JEeT VOLUf1E 1 EXHIBI TA PROJECT DESCRIPTION ,~ -SUSITNA HYDROELECTRIC PROJECT VOLUME 1 EXHIBIT A PROJECT DESCRIPTION- TABLE OF CONTENTS ...... ..... - 1 -PROJECT STRUCTURES -WATANA DEVELOPMENT . 1.1 -General Arrangement . 1.2 -Main Dam . (a)Typ i cal Cr 0 ss Sec t ion . (b)Crest Details and Freeboard ...........•.............. (c)Grouting and Pressure Relief System . (d)Instrumentation ....•.;. 1 .3 -Di ver si on . (a)Tunnels . (b)Cofferdams . (c)Tunnel Portals and Gate Structures . (d)'Final Closure and Reservoir Filling . 1.4 -Emergency Release Facilities . 1.5 -~ut 1et Fac i 1 it i es . (a)Approach Channel and Intake . (b)Intake Gates and Trashracks .. (c)Shaft and Tunnel .. (d)Di scharge Structure . (e)Fixed-Cone Discharge Valves ......................•... (f)Ring Follower Gates .. (g)Discharge Area .. 1.6 - Main Sp i 11 way ........•..........................,. (a)Approach Channel and Control Structure .....•......... (b)Spi 11 way Gates and Stop logs .. (c)Spillway Chute ........................•.............. (d)F1i P Buc ket ,.......•........•........• 1.7 -Emergency Sp i 11 way . (a)Fuse Plug,and Apprc}ach Channel.,. (b)Discharge eh,annel .........•.......................... I.B"-Power Intake ....T ••••••••'••••••••••••••'••••••••••••'••••••• f a)Intake Structure '."......•............• (b)Approach Channel ......................•...•••.•...... {c)Mechan;'caT Arr'angement .........•..•.................. 1.'9 -15encs:ftoc kSi''......••...•.•.....'"''.•"'..•.. (a')Steel Liner .•••.......•.'...•.''..........•...•'. (b);Concrete Li o1ong •....'..........••.......•........•..., (c)Grotfti,ng a'nGl Pregsur~Rel i:ef System ................•. Page A-l-l A-l-l A-I-2 A-I-3 A-I-3 A-I-4 A-I-5 A-I-5 A-I-5 A-I-6 A-I-6 A-I-7 A-I-8 A-I-9 A-1-9 A-I-9 A-I-I0 A-l-lO A-l-11 A-l-11 A-l-11 A-l-11 A-I-12 A-I-12 A-l-13 A-I-13 A-I-14 A-I-14 A-I-14 A-1-15 A-I-15 A-I-15 A-I-16 A-l--ll A-I-IS A-I-18· A-I-I8 TABLE OF CONTENTS (Continued) 1.10 -Powerhouse . (a)Access Tunnel s and Shafts . (b)Powerhouse Cavern ...............................•... (c)Transformer Gallery .. (d)Surge Chamber . (e)Grouting and Pressure Relief System . (f)Cable Shafts . (g)Draft Tube Tunnel s . 1.11 - Tail r ac e . 1.12 -Ac ce ssP 1an.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . •. . (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 . 2 -RESERVOIR DATA -WATANA . 3 -TURBINES AND GENERATORS -WATANA . 3.1 -Un it Cap ac it Y . 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 Facil ities . (a)Corr i dor ..............................•.............. (b)Components . (c)Right-of-Way ................•........................ (d)Tran.smission Lines . (e)Switching and Substations ......................•..... (f)Cable Crossing . (g)Dispatch Center -Energy Management Center and Communi cat ions .......•........................... 4.3 -Construction Staging . Page A-1-18 A-1-19 A-1-19 A-1-20 A-1-20 A-l-21 A-1-21 A-1-21 A-1-21 A-1-22 A-1-22 A-1-22 A-1-23 A-1-24 A-1-24 A-1-25 A-1-25 A-1-25 A-1-26 A-1-27 A-1-28 A-1-28 A-1-29 A-1-29 A-1-30 A-1-30 A-2-1 A-3-1 A-3-1 A-3-1 A-3-2 A-3-2 A-3-3 A-3-3 A-3-3 '7'·1 A-4-1 A-4-1·· A-4-1 A-4-1 A-4-2 A-4-5 A-4-6 A-4-8 A-4-9 A-4-10 A-4-10 ";., ..... .... - 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)El evators . (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-Fi 11 ed Cable .. (f)Control Systems . (g)Station Service Auxiliary AC and DC Systems . (h)Grounding System . (i)Lighting System . (j)Commun i cat ions . 5.3 -Switchyard Structures and Equipment . (a)Single Line Diagram . (b)Switchyard Equipment ................•................ (c)Switchyard Structures and Layout . 6 -LANDS OF THE UN ITED STATES . 7 -PROJECT STRUCTURES -DEVIL CANYON DEVELOPMENT . 7.1 -General Arrangement . 7 .2 -Arc h 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 . A-5-1 A-5-1 A-5-1 A-5-1 A-5-1 A-5-1 A-5-2 A-5-2 A-5-4 A-5-5 A-5-5 A-5-5 A-5-6 A-5-6 A-5-6 A-5-7 A-5-7 A-5-10 A-5-12 A-5-12 A-5-12 A-5-12 A-5-12 A-5-12 A-5-12 A-6-1 A-7-1 A-7-1 A-7-2 A-7-2 A-7-3 A-7-4 A-7-4 A-7-4 A-7-5 A-7-6 A-7-6 A-7-6 A-7-6 A-7-7 A-7-7 A-7-8 TABLE OF CONTENTS (Continued) 7.5 - 0 ut 1et Fac i 1 it i es . (a)Outlet . (b)Fixed-Cone Valves . (c)Ring Follower Gates ........•.......................... (d)Trashracks . (e)Bul khead Gates . 7.6 -Main Spillway . (a)Approach Channel and Control Structure . (b)Spi llway Chute . (c)Flip Bucket . (d)Plunge Pool . 7.7 -Emergency Spillway . (a)Fuse Plug and Approach Channel . (b)Di scharge Channel . 7.8 -Devil Canyon Power Facilities . (a)Intake Structure . (b)Intake Gates . (c)Intake Bul khead Gates . (d)Intake Gantry Crane . 7.9 -Penstocks . (a)St ee 1 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)Ri ght-of-Way . 7.13 -Site Facilities . (a)Tempor ary Camp and Vill age . (b)Si te Power and Ut il iti es . (c)Contractors'Area ....................................• A-7-8 A-7-8 A-7-9 A-7-9 A-7-9 A-7-10 A-7-10 A-7-10 A-7-11 A-7-11 A-7-12 A-7-12 A-7-12 A-7-12 A-7 -13 A-7-13 A-7 -13 A-7 -13 A-7-14 A-7-14 A-7-14 A-7-14 A-7-14 A-7-14 A-7-15 A-7-16 A-7-16 A-7 -17 A-7-17 A-7-17 A-7-18 A-7-18 A-7-18 A-7-19 A-7-19 A-7-19 A-7-19 A-7-20 A-7-21 A-7-22 8 -DEVIL CANYON RESERVOIR '..............................A-8-1 TABLE OF CONTENTS (Continued) Page 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 .- I 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)£1 evators . (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 Servi ce Aux i1 i ary AC and DC Systems . (h)Other Accessory Electrical Systems . 11.3 ""Switchyard Structures and Equipment ''".. (a)Singl e Line Di agram . (b)Switchyard Structures and Layout ••...........•..... REFERENCES LIST OF TABLES A-1O-1 A-ll-1 A-ll-1 A-ll-1 A-ll-1 A-ll-1 A-1l-2 A-1l-2 A-1l-2 A-1l-2 A-1l-2 A-1l-3 A-1l-3 A-1l-3 A-1l-3 A-1l-4 A-1l-4 A-1l-4 A-ll-S A-1l-6 A-1l-6 A-1l-6 A-1l-6 - .... r- I - LIST OF TABLES A.I Principal Project Parameters i - I~ - 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 Elevat ion 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-l ined pen- stocks,each 17 feet in di ameter,wi 11 1ead 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 ri ver vall ey and across the embankment near the down- stream toe.Turbine discharge will flow through six draft tube tunnels A-1-1 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 th is flood assumes on ly two units of Watana operat i I1g and the pool elevation going from 2185 to 2193 from flood surcharge.The up- stream gate structure wi 11 be adjacent to the power intake and wi 11 convey flows through a 28-foot diameter concrete-l 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 spi llway operat ions. 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 bya 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 confl uence.The darn wi 11 be of compacted earth and rockfill construction and will consist of a central imper- vious core protected by fine and coarse fi lters upstream and down- stream.The downstream outer shell will consist of rockfill and allu- vial gravel underl ain by a toe drain and fi Her,and the upstream outer shell of clean alluvial gravel.A typical cross section is shown on Plate F6 and is described below. A-1-2 r--- - (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 fi Her 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 fi Her foundat ion contact. They are sized to provide protection against possible piping through transverse cracks that coul d occur because of sett 1ement 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 materi al: 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 Pl ate F7.Because of the t-narrowing at the dam crest,the fi Her zones are reduced in width and the upstream and downstream coarse fi Hers are el imi nated.A 1ayer of fi 1ter 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. The nominal crest elevat ion of the Watana Dam,after est imated static and seismic settlement have taken place,will be 2205. """, """A-I-3 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 sett 1ement 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 sett 1ement allowances are conser- vat i ve when compared with observed settlements of s imil ar 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 run up 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.Linder normal operation this spi 11 way will be sealed by a fuse pl ug dam across the entrance channel.Thi s pl ug wi 11 be a gravel dam with a lowest crest el e- vat ion 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 Plat e Fl8. (c)Grouting and Pressure Relief System A combination of consol idation grouting,cutoff curtain grouting and installation of a downstream pressure relief (drainage)system will be undertaken for the Watana Dam. A-I-4 - ~ I (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. I nstrument at i on Instrumentation will be installed to provi de 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: -Pi ezometers Pi ezometers are used to measure static pressure of f1 ui d in the pore spaces of soil,rockfi11 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 a1 i gnment markers Seismographic records and seismoscopes Flow meters to record discharge from drainage and pressure relief system 1.3 -Diversion - (a)Tunnels Diverslutl of the river flow during construction will be accom- plished with two 38-foot di,ameter circular diversion tlifineTs.The tunnel s wi 11 be concrete-lined and located on the north bank of A-1-5 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 tunnels are des i gned to pass a f1 ood 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)will 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 rei nforced concrete gate structure wi 11 be loc ated at the up- stream end of each tunnel,each housing two closure gates (see P1 ate Fl1). 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 heat i ng the gates and gate gui des.The gate in Tunnel No.1 will be designed to operate with the reservoir at Elevation A-1-6 (d) 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 operat i ng 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 rei nforced concrete structures with gui des for stoplogs.. Final Closure and Reservoir Filling As discussed above,the upper diversion tunnel (No.1)wi1.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 1et,coarse trashracks wi 11 be install ed 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 divers i on Tunne 1 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 34H-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 pl ugs.The gate arrangement wi 11 cons i st of one emergency gate and one operat i ng gate in the -upstream pl ug 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 hydraul ic units will be installed,one for the emergency gates,one for the upstream operating gates and one for the downstream operating gates.Each gate wi 11 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 cyl inder 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 pl ugs 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 fl ip bucket in the exit channel (Pl ate F20). A-1-8 r o .- I"'" I I I 1.5 -Outlet Facilities The primary function of the outlet facilities 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 UTe 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 val ves whi ch wi 11 di scharge 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 si ng1 e 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 level. Two fixed-wheel gates will 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 c10suregates to isolate the downstream tunnel i""'.and allow dewatering for maintenance of the tunnel or ring gates located in the di scharge structure.Stop log gui des will be pro- vided upstream from the two fixed-wheel gates to permit dewatering of the structure and access to the gate guides for maintenance. (b)Intake Gates and Trashracks The gates will be of the fixed-wheel vert ica1 1ift type with down- stream skinplate and seals.The nominal gate size will be 14 feet 'Wide by 28 feet high.Each gate will be operated by a single drum - A-1-9 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 spaci ng of 6 inches and wi 11 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 monitori ng 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 fl ip 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 ..... 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'lOi sts. (el Fixed-Cone Discharge Valves 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. (f)Ring Follower Gates A ring follower gate wi 11 be installed upstream from each val ve 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 hydraul ic cyl inders 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 A-l-ll 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 ~OOO 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 ogee 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 spi 11 way 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 contro 1 structure wi 11 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 monol iths 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 cO'nfirm the precise geometry of the contro!l struc- ture. The sides of the approach channel will be excavated to lH: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 lH:3V to ensure sufficient contact stress and therefore prevent leakage. The mai n dam grout curtain and drai nage 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 runn i ng through the ogee wei r. (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- A-1-12 ..... - - (c) (d) 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 rai sed in the event of loss of power to the spi 11 way gate hoi st 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 incl ined 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 curtai nand 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 excavat ions. A series of four aeration galleries will be provided at intervals down the chute to prevent cav it at i on damage of the concrete. Details of these aeration devices are shown in Plate F14. Fl ip Bucket The funct i on of the fl iP bucket will be to direct the sp ill way flow clear of the concrete structures and well downstream into the river below.A mass concrete block will form the flip bucket for A-l-13 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 FlB).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 wi 11 have a width of 310 feet and invert elevatlon of 2170. The mai n access road to the dam and powerhouse wi 11 cross the channel by means of a bri dge.The fuse plug wi 11 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 fi Her zones upstream and downstream.It wi 11 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 channe 1 downstream from the fuse pl ug wi 11 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 re 1 i ct channe 1.It is estimated that flows down the channel would continue for a per i od of 20 days under PMF cond it ions.Some ero s ion ;n 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. A-1-14 1.8 -Power Intake .... ...... ..... - - (a) (b) Intake Structure The power intake will be a concrete structure located deep in the rock on the north bank.Access to the structure will 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 gui des 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 install ed on the trashrack gui des 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. 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 i n- 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- 1ing 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 IS-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 acci dental 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. A-I-16 - - - (iv)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- lowers for hand1 ing the trashrack shutters and bul khead gates.The crane will be radio-cantrall ed with a pendant or cab control for backup. (v)Intake Bulkhead Gates One set of intake bulkhead gates will be provided for clos- ing anyone of the six intake openings upstream from the intake gates.The bul khead 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. (vi)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 hydrau1 ic cy1 inder type hoist.The length of acyl inder 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 ba1 anced 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 P1 ates 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-l-17 appropri ate to withstand des i gn internal pressures.The 1ateral 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 hori zontal. The design static head on each penstock is 763 feet at centerl ine 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 1iner wi 11 be surrounded by a concrete infi 11 with a mi nimum th ickness of 24 inches.The internal di ameter 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 agai nst seepage from the hi gh 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 complex will 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. A-I-I8 ""." - 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 cable 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 gall ery and crane wi 11 be located in the surge chamber cavern,above the maximum anticipated surge level.Provision wi 11 also be made in the surge ch amber for tail race tunne 1 i nt ake sto p- 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 pedestri an access to the transformer gall ery and the draft tube gate gallery.El evator access will al so be provi ded 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 des i gn output capabi 1ity of A-I-19 170 MW.The length of the cavern will allow for a unit spacing of 60 feet,with a 1l0-foot long service bay at the south end for routine maintenance and for construction erection.Vehicular access wi 11 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 ation and maintenance of heavy equipment using the powerhouse cranes. (c)Transformer Gallery The transformers wi 11 be located underground in a separate gal- l ery,120 feet upstream from the mai n 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.Pedestri an access wil T 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 -I The chamber will be common to all six draft tubes,and under nor- mal operation will discharg'e equally to the two tai lrace 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 gall ery and crane wi 11 be locat'ed in the same cavern,abDve the maximum anticipated surge level.The crane has also been designed to allow installation of tailrace tunnel intake stoplogs for emergency closure of eith'er tai lrace tunnel. -The chamber will generally be an 'unl ined rock excavation,with local i zed rock support as necess,ary for stabi lityofthe roof arch and walls.The gate gui des for the draft tube gates and tai lrace stop10gswi 1.1 be of embedded in reinforced concrete anchored to the rock by rock bolts.- Access to the draft tube gate gall ery will beiby an adit from the r-main access tunnel.This access will b,e widened locally for stor- age of tailrace tunnel intake stoplogs. (e)Grouting and Pressure Relief System Control of seepage in the powerhouse area will be achieved by a grout curtai n upstream from the transformer gall ery and an ar- rangement of drainage holes downstream from this curtain.In addit ion,drain holes will be dri 11 ed from the caverns extending to a depth greater than the rock anchors.Seepage water wi 11 be collected by surface drainage channels and directed into the powerhouse drainage system. (f) (g) Cable Shafts Cabl e shafts will be 8.5 feet in excavated di ameter.Although not required for rock stab;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 -Tallrace Two tailrace pressure tunnels will be provided at Watana to carry water from the surge chamber tD 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 mlnlmUm 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 0 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 0 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 corr i dor runn i ng west to east from the Parks Hi ghway to the damsites on the south side of the Susitna River;and A corridor running north to south from the Denal i 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 communit ies.Where adverse environmental impacts are unavoidable or project objec- A-1-22 r··' - (c) 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 1i cat i on . 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 railheadfacil ity the road will follow an existing route to the junction of the George Parks and Denal i 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 mil es. Pl ate F32 shows the proposed access pl an route.Pl ate 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 vol urnes 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% 5° 80 k axle,200 k total HS -20 I~ These design parameters were ~hosen for the efficient,economical, and safe movement of supp 1i es and are in accordance with current highway des i gn standards.Adheri ng 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 Ufitll the road within the topography and thereby enhance the visual qual ity of the surrounding 1andscape.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 bi ke path will be provi ded 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 wi 11 be made to the intersect i on 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 aforement i oned st andards.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 ina mi ni mum of di sturbance to areas away from the al i gnment.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 fl attened and covered with excavated peat materi al.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 - ,.... - 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 Denali Highway section. 1.13 -Site Facilities (a)General 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 st aff and f ac il it i es to support the permanent oper at i on 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 poss i b1e duri ng construct ion of the Devil Canyon developmenL Other site facilities include contractors I work areas,site power,services,and communications.Items such as power and communi cat ions will be required for construct i on operations independent of camp operations.The same will be true regarding a hospital or first aid room. - - ,~ (b) Permanent f ac i 1 it i es requ i red 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 Plate F36. Temporary Camp and Village The proposed location of the camp and village will be on the north bank of the Sus Hna Ri ver between Deadman and Ts'uselM Creek, approximately 2.5 mnes northeast of the Watan:a Darn.The north s ide of the Sus Hna Ri ver was chos-en:because the mai nacces-s wi 11 be from the north and south-f ac i ng 51 opes can be used for sit tng the st ruct ures.The 10cat ion is shown in Pl ate f34 ~ The camp willconsi st of {Jortable waodfrarne do-rmitoriesfor hache- 1'OI"S wtth modul ar mess flalls~re'creational b11i ~dings.bank,post ofHce,fire station,warebouses,hos-pUal ,office.s,~t{:.The camp wnl be a Single -stat~s camp for appro'ximately '3UOn 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 vi 11 age and camp areas will be separated by approx imately 1.5 miles to provide a buffer zone between areas.The hospital will serve both the main camp and village. The camp 1ocat i on wi 11 separate 1i 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 st ages to accommodate the peak work force.The facilities have been designed for the peak work force pl us 10 percent for turnover.The turnover wi 11 in- clude allowances for overlap of workers and vacations.The con- ceptual 1ayouts for the camp and vi 11 age are presented on Pl ates F36 and F37. (i)Site Preparation Both the camp and the vi 11 age areas wi 11 be cl eared 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 )Fac il it i es 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 ~- r - .- .~ ~, (d) -Single family dwellings; -Multifamily dwellings; -Hospital; -Schoo 1; -Fi re st at i on; - A town center wi 11 be constructed and wi 11 contai n 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 campi 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 duri ng the peak camp popul at ion year is est imated 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 I work areas.The est imated peak popul at ion 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 reservo i rs wi 11 provi 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 Plate F34.Detail s of the ut i 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 camp/- 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 "in-village"col- 1ect i on systems will be run through the uti 1i 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 Al askan and EPA standards.The sewage plant wi 11 di scharge its treated effl uent 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 l Area The on-site contractors will require office.shop.and general work areas.Part i al space required by the contractors for fabri- cation shops.maintenance shops.storage or warehouses.and work areas wi 11 be located between the mai n camp and the mai n access road. 1.14 -Relict Channel A rel ict channel exists on the north bank of the reservoir approxi- mately2600 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 channel represents a potential source of leakage from 'the 1~atana reservoir.Along the buried channel thalweg.the highest or control- 1 ing bedrock surface is some 450 feet below reservoir level.while A-1-28 ('T::--', .- 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 hydraul ic gradi ent along any flow path in the buri ed 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- slan 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 el evation of 2210 wi 11 be constructed to provi de protecti on agai nst extreme reservoi r water 1evel sunder 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 di ke before the emergency fuse pl ug washes out.The freeboard di ke will consist of compacted granul ar 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 plplng 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.Furt-her 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 um is establ ished with respect to permafrost and seepage gradients in the buried channel area. If the permeability of the basealluviul11 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. ,..... A-1-29 (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. A-I-30 """' ~- -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 IIdam ll 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. A-1-31 ,.... 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. A-2-1 - .- """ 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 full 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."fhe 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. A-3-1 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 compri sing three si ngl e-phase transformers.The generators will be connected to the transformers by isolated phase bus through generator ci rcui t breakers di rect ly 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 Capac ity 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 cont i nuous ly 095.5 MW)at a voltage of +5 percent without exceeding 80°C temperature rise in accordance with ANSI Standard C50.1O. The generators wi 11 be capabl e of cont inuous operat ion 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. A-3-2 (b)Unit Dimensions Approximate dimensions and weights of the principal parts of the generator ar~given below: It shoul d be noted that these are approx imate fi gures and they will vary between manufacturers. - Stator pit diameter Rotor di ameter Rotor length (without shaft) Rotor wei ght Total weight 36 feet 22 feet 7 feet 385 tons 740 tons - - .... I (c)Gen er ator Exc it at ion System The generator will be provided with a high initial response type static excitation system supplied with rectified exci- tat ion 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. A-3-3 .- 4 -TRANSMISSION FACILITIES FOR WATANA DEVELOPMENT 4.1 -Transmission Requirements The purpose of the project transmission facilities will be to del iver power from the Susitna River basin generating 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 ri ver bas in 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 corri dor.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 Al aska Rai lroad 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 ik Arm.The corri dor enters mil itary re- served territory and is constrained to pass near the northern and eastern perimeter of Fort Richardson through the reservat i 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 l.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 A-4-1 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 wi 11 be provi ded on the "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 1 ines,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 stat i on. From the Watana substation,both lines will continue·in a northwest di recti on,a di stance of approx imately two m"il es cross i ng Tsuesen a Creek,then wi 11 turn west and sh are 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 rai lroad 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 1 ines 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 al so wi 11 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 wi 11 share the same right-of-way north,generally following the Railbelt 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 mil es 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 Ri ver 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. A-4-2 .,." .- ..... At Ester substation provlslon 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 abil ity.The Ester switchyard will al so 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 tv buses at Ester consisting of units with +200/-100 MVAR continuous,and +300/-100 IVlVAR short time rat"il1gs.The ratings of the VAR control equipment wi 11 be confirmed and,if necessary, refined during final design.Access to the Ester Substation w"ill be provi ded by an all-weather gravel road 1inked 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 1es 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 arrangement for rel i abi 1ity.Th is switch ing 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 remai ni ng 1i nes.The Wi 11 ow site access wi 11 be provided with an all -weather gravel road about 1 mil e long across Wi 11 ow Creek to the Wi 11 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 Wi llow and from Fairbanks to Healy wi 11 be augmented and extended to provide a A-4-3 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 n,.i 1es,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 mil itary reservat ion forming Fort Ri chardson.The route wi 11 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.Doub1e- 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. A-4-4 r;---' .- ,~- - - -i (c) 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 1evel 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 shoul d be noted that the Al aska Power Authority is proceeding with an "Intertie tl project to build approximately 170 miles of one of the 345 kV 1 ines between Healy and Wi 11 ow on the Fairbanks to Anchorage corridor (Commonwealth Associates 1982).This line will be bui It to operate eventually at 345 kV but will be energi zed 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 i ncl ude that area necessary for the addit ions 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 1d Creek and Dev il Canyon,where ult i- mately 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 mi le,as wi 11 be the spare phase.The width of the bed A-4-5 affected by the cross i ng wn 1 be approx imatel y one mil 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 1d Creek Switchyard 16 Fai rbanks (Ester)Substat i on 25 Willow Substation 25 Knik Arm Substation 15 Anchorage (University)Substation 45 Rights-of-way for permanent access to switchyard and substat ions 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 corri dor,except at areas such as major river cross i ngs and deep rav ines where an access stri p woul d not be ut i1i 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 IIRail"(45/7)Aluminum Conductor Steel Reinforced (ACSR)or a single 2156 MCM "Bluebird ll (84/17)ACSR conductor,both of which provide comparable levels of corona and radio noise within normally accepted limits.The single "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 bal anced out due to the extra work invol ved in handl ing the twin bundl e.SeTection of the optimum conductor arrangement will be made in final design.The conductor will be sp.ecified to A-4-6 ,.". - - - 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 hand1 e the output of Dev il 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 IIcorona free"des i gn 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 porce1 ain or gl ass di sc type suspens ion units.A chai n of 18 units is expected to be sufficient to provide acceptable flashover performance of the line.The configuration will be 11M" type with vertical strings on the outside phases and a IIV II 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 IIV n ,guyed lIyll,guyed delta and the guyed portal are the most common economical arrange- ments.The guyed IIX II design has been se1 ected 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 1arger angl e 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 A-4-7 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 "wea thering ll 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 facil itate 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 parall el to and under the 1ines.These wi 11 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-co 1umn type foot i ngs with suffic i ent depth -of- bury to avoid the active freeze-thaw layer.Backfill immediately around footings will be granular to avoid frost heave effects. A-4-8 rc--· - - _. 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-ha1f 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.Protecti ve re1 ayingschemes 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- i ar y power at 480 V;t he normal 480 V ac power wi 11 be supp 1i 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 220kV 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 A-4-9 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 controlled from a central di s- 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 facil 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 communi cat ions requi rements wi 11 be provi ded by means of a microwave system.The system wi 11 be an enl argement 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 ik 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 A-4-10 .... .- ,... The transmission will consist of two circuits from Watana to the load centers.The conductor for the sect ions from Wat ana to Kn ik Arm and Watana to Fairbanks will consist of bundled 2 x 954 kcmil,ACSR.The section between Knik Arm and University will 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 se1f-contain~d oi1- filled.For project ~urposes,the cable size will be 500 rrrn.A size of up to 1500 mm may be install ed if duty requi rements are in- creased.For reliability,a spare cable will be included on a standby bas is. 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 . --A-4-11 5 -APPURTENANT MECHANICAL AND ELECTRICAL EQUIPMENT -WATANA 5.1 -Miscellaneous Mechanical Equipment (a) (b) Powerhouse Cranes Two overhead travel ing-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 equi pment;and -Subsequent dismantling and reassembly of equipment during main- tenance overhauls. Each crane will have a main and auxil iary 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 equal izing 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- binewater 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 bu1 k- 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 installation and removal of the draft tube gates as well as the tailrace tunnel intake stop1ogs.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. (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 monorai 1 hoi st in the transformer gall ery for trans- former maintenance; A-5-1 - 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; A-5-2 ..... ""'" _. - (i v) (v) -Generator brakes; -Draft tube water level depression; -Air blast circuit breakers;and -Governor accumulator tanks. For the preliminary design,two campressed air systems have .been assumed:a 100-ps ig ai r system for servi ce ai f,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 ai r system and circuit-breaker ai r system may be provided. 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 beari ngs and the governor pumping system. Forprel iminary design purposes,two oil rooms have been included,one in the transformer gallery and one in the powerhouse service bay. 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.ydrainage system. The unit dewatering and filling systems will consist of two sumps each with two dewatering pumps and associ ated 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. Un less the drai nage gallery is below the bottom of the draft tube elbow,it will not be possible to completely dewater the draft tube through the dewateri ng header.If necessary,the remainder of the draft tube can be dewatered A-5-3 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 drai n 1i ne from an adj acent unit. Filling the unit to headwater pressure will be accomplished by "cracking"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·intain 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 heat i ng wi 11 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 bui lding 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 bui lding 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 si ngl e 1ine diagram,Pl ate F30.The arrangement of equipment in the powerhouse,transformer gallery,and cable shafts is shown on Plates F25 through F27. (a)Transformers and KV Connections Ni ne si ngl e-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 isol ated phase bus located in indi- vidual bus tunnels.The HV terminals of the transformer will be F-' I 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 wi 11 be of the two- winding,oil-immersed,forced-oil water-cooled (FOWl type,with rating and electric characteristics as follows: Rated capac ity High voltage winding Basic insulation level (BIL) of H.V.winding Low voltage winding Transformer impedance 145 MVA 345 /13 kV,Grounded Y 1300 kV 15 kV,Delta 15 percent The temperature ri se above ambi ent (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 equi pment,automat ica lly 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 potent i al transformer cubicl e,exc it at i on 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 (Bll) 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 ambi ent. (d)Generator Circuit Breakers The generator circuit breakers will be enclosed air circuit break- ers suitable for mounting in line with the generator isolated. phase bus i:1ucts.They are rated as follows: A-5--£ Rated Current Voltage Breaking capacity, symmetrical,amps 9,000 Amps 23 kV c1ass,3-phase,60 Hertz 150,000 ,..... i "..., - r"" ! 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 terminal s of the transformer and the surface switchyard.Cables from two transformers will be installed in a single vertical cable shaft. The cable wi 11 be rated for a cont inuous max imum 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 Ilpressure 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 BOO-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 Devi 1 Canyon power pl ants~ The control center will be 1 inked through the supervisory system to the Central Di spatch Control Center at Wi 11 ow as described in Exhibit B,Section 3.6. The supervisory control of the entire Alaska Railbe1t 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: -St art/s top'and loadi ng 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 addit i on,the computer system wi 11 be capable of re- trieval of technical data,design criteria,equipment char- acter i st ic sand operat i ng 1i mit at i on s,schemat ic 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 ll operation "in the event of a complete blackout or co 11 apse of the power system.The control systems of the two pl ants 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 synchroni ze it with the system -Load the un it -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). A-5-8 - ...... ""'"! ... (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 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, commi ss i on i ng,and mai ntenance of the turbi nes 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 . - .- (v)Load-Frequency Control The load-frequency system will provide remote control of the output of the generator at Watana and Devil Canyon from A-5-9 the central dispatch control center through the supervisory and computer-aided control system at Watana.The basic method of load-frequency control wi 11 use the pl ant error (differential)signals from the load dispatch center and wi 11 allocate these errors to the power pl ant 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 control system wi 11 be des i gned 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 capac ity wi 11 be avai 1- able; - A spare aux i 1i ary transformer wi 11 be mai ntai ned,con- nected to Unit 5;and -"Black start ll 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 A-5-10 ,.... ! l r r l r l (i i ) normal operating conditions~t-h~station-service load is divided and connected to each of the two-end incoming transformers.In the event of failure aione 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- p1 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,beari ng oi 1 pumps,coo 1i 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 1i ght i ng systems for the access roads and tunnels wi 11 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 b1e hi gh security power supply will be pro- vided for the computer control system. DC Auxiliary Station Service System The dc 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 IIfl ashi ng ll power from the dc bat- tery.The dc auxiliary system will also supply the emer- gency lighting system at critical plant locations. A-5-11 F'", - """ 6 -LANDS OF THE UNITED STATES The Susitna Hydroelectric Project win 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. A-6-1 ~. DAMSITES,QUARRYSITES AND RESERVOIR AREAS (Federal Ownership) SEWARD MERIDIAN,ALASKA 1""'" SEC.24 FPA TOWNSHIP/Section OWNER PLATE U.S.ACREAGE ACREAGE* T31N,R1W F Section 1 BLM**66 640.0 0 Section 2 BLM**66 640.0 0 I ~ T32N,R1W Section 35 BLI~**G6 320.0 0-Section 36 CIRI G6 0 28.5 T31N,R1E Section 1 CIRI G7 0 235.5 Section 2 eIRI G7 0 340.7 ~Section 3 CIRI G7 0 367.5 Section 4 CIRI 66&G7 0 188.2 Section 5 CIRI 66 0 19.4 Section 6 BLM**66 607.4 88.7 Section 7 BLM**66 152.1 0 Section 8 BLM**.G6 160.0 0 Section 9 BLM**G6 60.0 0.7 ~Section 10 BLM**G7 00.6 00.6 Sect ion 11 BLM**G7 00.5 00.5 T321~,R1E Section 31 CIRI G6 0 264.4 Section 32 CIRI 66 0 370.0 ,~Section 33 CIRI G6&G7 0 251.8 Section 34 BLM**G7 22.9 22.9-T31N,R2E Section 1 CIRI G8 0 189.3 Section 4 BLM**67&G8 137.4 137.4 Section 5 BLM**G7 200.2 200.2 Section 6 BLM**G7 275.0 27'5.0 Section 7 BLM**G7 57.9 57.9 Section 8 BLM**G7 00.7 00.7 Section 12 CIRI G8 0 197.1 Sect i on 13 BLM**G8&69 207.5 207.5 ~Section 24 BLM**69 07.4 07.4 A-6-2 DAMSITES,QUARRYSITES AND RESERVOIR AREAS (Cont'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**GlO 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 (Gont'd) SEG.24 FPA TOWNSHIP/Section OWNER PLATE U.S.ACREAGE ACREAGE* T31N~R5E Section 3 BLM**G13&GI5 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&GI4 160.0 0 Section 20 BLM G13&GI4 560.0 0 "'""Section 21 BLM G13&614 640.0 0 Section 22 BLM 613 ~GI4&GI5 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 GIRl G15 0 327.2 Section 27 GIRl G13&GI5 0 238.3 Section 28 GIRl G13 0 47.3 Section 29 BLM 613 640.0 0 Section 30 GIRl G13 0 38.1 ~Section 31 GIRl G13 0 127.7 Section 32 GIRl G13 0 196.5 Section 33 eIRI 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 0Section14BLMG18243.2 0 Section 15 BLM G18 507.2 0 If"" ..... 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 GIS 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**G17 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--..···, 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 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 Sect i on 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&GI9 624.1 0 Section 29 BLM G17 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 n3N,R7E F"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 nON ,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 Sect i on 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 640.0 476.8r-Section 16 BLM G24&G23 280.3 128.6ISection17BLMGI9,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* BON,R9E Section 1 BLM G26 143.0 33.5 Section 12 BLM G26 105.3 03.8 Section 13 BLM G26 05.8 0 BIN,R9E Section 6 BLM G24 49.2 0 Section 7 BLM G24 00.7 0 Sect ion 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 BON,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 Sect i on 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 B1N,R10E Section 31 BLM G26&G27 143.2 74.4 T29N,R11E Section 1 BLM G29 45.2 45.2Section2BLMG29199.2 199.2Section3BLMG29222.6 222.6Section4BLMG2968.2 68.2 A-6-7 DAMSITES,QUARRYSITES AND RESERVOIR AREAS (Cont'd) ~'J!I\ll!1! SEC.24 FPA TOWNSHIP/Section OWNER PLATE U.S.ACREAGE ACREAGE* T29N,R11E (Cont'd)-Sect i on 5 BLM G29 176.6 101.5 Section 6 BLM G29 135.3 12.3 Section 9 BLM G29 00.4 00.4-Sect i on 10 BLM G29 204.5 103.1 nON,RllE Sect i on 7 BLM G27&28 293.8 165.1 Section 8 BLM G28 01.8 0.18 Sect i on 17 BLM G28 241.0 167.1-Sect ion 18 BLM G27&G28 280.4 195.7 Sect i on 20 BLM G28 445.9 206.7 Section 21 BLM G28 00.9 0.0 """Sect i on 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 Sect i on 32 BLM G29 482.7 293.1-Section 33 BLM G29 437.3 385.4 Sect ion 34 BLM G29 640.0 270.8 Sect i on 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 Sect i on 10 U.S.Army G30 33.29 .p--' Sect ion 11 U.S.Army G30 05.31 Sect i on 13 U.S.Army G30 14.15 Section 14 U.S.Army G30 44.50 Section 24 U.S.Army G30 24.64 T31N,IW 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,RIE r:c:'l Section 13 BLM**G39 11.77 Section 23 BLM**G39 34.22 Section 24 BLM**G39 33.23 Section 26 BLM**G39 07.35 Sect i on 27 BLM**G39 38.03 Section 28 BLM**G39 38.03 Section 29 BLM**G39 37.95 Section 30 BLM**G39 02.70 A-6-9 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 Sect ion 17 BLM**G39 07.91 Section 18 BLM**G39 42.13 T33N,R2E Section 25 BLM**G40 34.20 Section 34 BLM**G40 09.28 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 Sect i on 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~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'd)(",,' 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 TlS,R8W Section 24 USAF G48 23.27 Section 25 USAF G48 51.86 Section 26 USAF G48 51.86 TlS,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 Sect i on 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 I\1ERIDIAN 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) FAIRBANKS MERIDIAN,ALASKA TOWNSHIP/Section OWNER PLATE U.S.ACREAGE* Tl8S,R4W rm".Section 16 BLM G53 19.80 Section 21 BLM G53 24.74 Section 22 BLM G53 00.23-Sect i on 27 BLM G53 02.09 Sect ion 28 BLM G53 23.43 Section 33 BLM G53 20.00 Section 34 BLM G53 06.41 Tl9S,R4W Section 4 BLM G53 29.59 Section 5 BLM G53 06.41 Section 8 BLM G53 29.94 ~Section 16 BLM G53 20.70 i Section 17 BLM G53 08.41 Section 21 BLM G53 23.57 Section 22 BLM G53 04.95 Section 27 BLM G53 25.35 Section 34 BLM G53 25.61 '"""T20S,R4WI I Section 3 BLM G53 25.35 .....Sect i on 10 BLM G53 26.73 Section 14 BLM G53 18.93 Sect i on 15 BLM G53 08.25 Secfi on 23 BLM G53 22.64 Section 24 BLM G54 12.48 Section 25 BLM G54 24.86 Sect i on 36 BLM G54 24.97 """T21S,R4W Section 1 BLM G54 28.28 Section 11 BLM G54 34.94 Section 12 BLM G54 03.36 Section 14 BLM G54 24.63 Section 23 BlM G54 24.38 Sect i on 26 BLM G54 24.38 Section 27 BLM G54 00.11 Sect ion 34 BLM G54 25.30 Section 35 BLM G54 01.00 """ A-6-12 SEWARD MERIDIAN,ALASKA T31N,RIW 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,RIE 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 ACCESS CORRIDOR RIGHT-Of-WAY ACREAGES (Contld) TOWNSHIP/Section OWNER PLATE U.S.ACREAGE* T32N,R3E Section 2 BLM**G57 01.15 Section 3 BLM**G57 37.09 Sect i on 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 ~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 Section 15 BLM G56 09.51 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 .... .p"". .- 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 spi llways,saddl e 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 fockfill 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 elevatiDn 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 3D-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 complex will be by means of an unlined 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- i ng units will be operat i ng.Each out 1et conduit will have a fi xed-- 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 ogee control struc- ture with three vertical fixed-wheel gates and an inclined concrete chute and fl iP bucket des i gned to pass a max imum di scharge of 123,000 cfs.This spillway,together with the outlet facilities,will thus be capab 1e of di schargi ng the est imated 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- dat ion .All bedroc k i rregu 1ar 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 qual ity rock will be excavated and supplemented with dental concrete. A-7-2 - ..... I'''' (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.Withi n the rock these gall eri es wi 11 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 prov i ded up to crest El ev at i on 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 radi i.The hori lontal 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 angl es on both si des 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 ri ver.The net effect of thi s two-center 1ayout 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 0 to 100 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 10 6 cubic yards. (c)Thrust Blocks The thrust blocks are shown on Pl ate 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 adj acent 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 1ters 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. A-7-4 r-, (- 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 materi al -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 materi al 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 fi Her zones are reduced in wi dth and the upstream and downstream coarse fi lters are eliminated.A layer of filter fabric is incorporated to protect the core materi al from damage by frost penetrat ion 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- t i on 1469.In add it ion,an all owance of one,percent of the hei ght 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 A-7-5 conditions,the freeboard will range from 15 feet at the abutments to 17 feet at the center of the dam.Further allowances wi 11 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- terl ine 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 Pl ate F47. A grout ing and drai nage tunnel wi 11 be excavated in bedrock be- neath the dam along the centerl i ne of the core and wi 11 connect with a simi 1ar tunnel beneath the adj acent 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)Instrumentat 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-l 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- fi le are shown on Pl ate F51. A-7-6 (b) 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 wi 11 be 39,000 cfs.The maximum water surface elevation upstream of the cofferdam wi 11 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 fi Hers,and rock and/or gravel shells with riprap on the upstream face.The downstream cofferdam wi 11 be a simil ar closure dam constructed from Elevation 860 to 898,with a cutoff to bedrock. The upstream cofferdam crest el evat i on wi 11 have a 3-foot free- board allowance for sett 1ement and wave runup.Under the proposed schedule,the Watana development will be operational when this cofferdam is constructed.Therma 1 studi es conducted show that discharge from the Watana reservoir will be at 34°F when passing through Devi 1 Canyon.Therefore,an ice cover will not form up- stream of the cofferdam,and no freeboard allowance for ice wi 11 be necessary. (c)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 I5-foot wide water passages will 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 hi gh by I5-foot wi de fixed-wheel 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 gO-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 mai n dam,in conjunct i on with the power fac il it i es, 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 wi 11 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 function of these releases is to provi de an emergency drawdown for the reservoi r,.shoul d 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- terl ine)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 - (b) chambers within the dam.Provisions will be made for maintenance and removal of the val ves and gates.The gates and val ves 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 ation are both from the south side. The valve and gate assemblies will be protected by individual trashracks install ed 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 gO-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 hydraul ic operators. Operation of the valves will be from either Watana or by local operation. (c)Ring Follower Gates Ring follower gates will be installed upstream of each valve. The ring follower gates will have nominal diameters of 102 and gO 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 toe ring follower gates will be as for Watana. .... - (d)Trashracks A steel trashrack will be installed at the upstream entrance 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 1eve 1• A temporary cover wi 11 be placed in the bul khead 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 Pl ate F54).The upstream control structure will be adjacent to the arch dam thrust block and will discharge down an inc 1i ned concrete-l 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 ogee-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 F-- - - - (b) (c) 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 cont i nuat ion of the grout curtain and drai nage beneath the main dam.The main access route will cross the control structure deck upstream of the gate tower and bridge structure. Spi 11 way 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-l ined with invert and wall sl abs anchored to the rock. The velocity at the lower end of the chute wi 11 be approximately 150 ft/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 spi 11 way chute and stabi 1 ity 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 util izing 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 exc av ated down to so und rock to prov i de a plunge 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 bri dge cons i st i ng of concrete pi ers,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 f1 atcrested concrete weir p1 aced 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,1ead-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 1y dur i ng an event of very rare frequency.The mat er ia1 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. A-7-12 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).Duri ng the peri od 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 unl ined 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 portal s 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 bal anced head condit ions to permit dewatering of the pen- stock and turbine water passages for turbine inspection and main- tenance,will also be capable of closing under their own ~v'eight 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 stat ic head on eac h penstock will be 638 feet,as meas ured 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 tunnel s are fully concrete-l 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 1i ner,extendi ng 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 th ickness of the concrete 1in i ng wi 11 vary with the des i gn 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. A-7-14 - - 7.10 -Powerhouse and Related Structures The underground powerhouse complex 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 isol ated 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. Vert ical shafts wi 11 be required for personnel access by el evator to the underground powerhouse,for oi l-fi 11 ed cable from the transformer gallery,and for surge chamber venting. The draft tube gate gall 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 spac i ng between the underground caverns wi 11 be fixed so as to be at 1east 1.5 times the main span of the larger excavation. ,1;fIRdJt. (a)Access Tunnels and Shafts The 3,OOO-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 tunnel to the foot of the arch dam for rout i ne mai ntenance of the fixed-cone valves.Branch tunnel s from the secondary access tunnel wi 11 provi de construct i on access to the lower sec- tion of the penstocks at Elevation 820.Separate branch tunnels from the main access tunnel will give vehicle access to the trans- former gall ery at Elevat ion 896 and the draft tube gate gall ery 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 mai n 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 pedestri an 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 llO-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 mai n powerhouse floor.The wi dth 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 tunnel s.Access wi 11 al so be avail abl e 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 and 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 powertlOuse cavern,with four interconnecting tunnels for the isolated phase bus.There will be 12 single-~hase transformers with one group of three transformers for each generating unit.Each transformer is rated at 15/345,70 MVA.For increased rel i abi 1 ity,one spare transformer and one spare HV circuit will be provided.The station service transfor- A-7-16 - - - (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 mai n powerhouse floor.The overall si ze 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 i501 ated 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 si ze 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 stabil ity of the roof arch and wall s. The gui de blocks 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 D •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 tunnel 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 A-7-17 section,which reduces both the maximum outlet velocity (8 ft/sec) as well as the velocity head losses.Vertical stop10g 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 rai 1head and storage faci 1ity 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 avail abil ity 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 1road crosses Jack Long Creek small bri dges 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: rr'---' Maximum grade Maximum curvature Design loading 2.5% 10 0 E-72 These parameters are consistent with those presently being used by the Alaska Railroad. A-7-18 (c)Connecting Road 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 Watanadamsite. The overall length of the road is 37.0 miles. In general the al i gnment crosses good soi 1 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 lt 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 fill i ng.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. (d)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 sidehilT 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 p1 anned operat ion 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. A-7-19 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 I 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 Ri ver between the dams ite and Portage Creek,approx i- mate1y 2.5 miles southwest of the Devil Canyon Dam (see Plate F70).The south si de 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 lone.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 wi 11 be constructed in stages to accommodate the peak work force.The facilities will be designed for the peak work force plus 10 percent for "turnover".The "turnover"wi 11 include provisions for overlap of workers and vacations.The conceptual 1ayouts for the camp/v;11 age are presented in Pl ates F72 and F73. A-7-20 Construction camp buildings will consist largely of trailer-type factory-bui 1t 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 roodu1es 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 ale 1ad din 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 duri ng construct i on is est imated at 20 MW for the camp/village and 4 MW for construction re- quirements.The distribution system for the camp/village wi 11 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. (i i i)Wastewater One wastewater colt ection and treatment system wi n serve the camp/village.Gravity flow lines with lift stations will be used to collect the wastewater from all of the camp and village facilities.The lIin-camp"and "in-village A-7-21 co 11 ect i on systems will be run through the permawa 1ksand utilidors so that the collection system will always be protected from the elements. At the village,an aerated collection basin will be in- st all 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 pl ant. The sewage treatment system will be a biological system with 1agoons.The system wi 11 be des i gned to meet Al askan 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. A-7-22 -I ! ..... ,I~ 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.IrmJedi 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. A-8-1 I~ .- - 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 MWbased 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 will be capab 1e of cont i nuous operat i on 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 e1bow-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 min imum head 9.3 -Generators The four generators in the Devi 1 Canyon powerhouse will be of the vert i ca l-shaft,overhung semi -umbre 11 a type direct ly 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 Capac ity: 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 ini mum) 98 percent (minimum) A governor system with electric hydraul ic governor actuators wi 11 be provided for each of the Devil Canyon units.The system will be the same as for Watana (See Section 3.4). A-9-2 - -..- 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 Devi 1 Canyon switchyard at the power development and the Gold 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 Devi 1 Canyon need in order to 1imit ri ght-of-way requi rements.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. A-10-1 -11 -APPURTENANT EQUIPMENT -DEVIL CANYON 11.1 -Miscellaneous Mechanical Equipment I"'"' - - - (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 inspect i on and maintenance of the turbi nes.The arrangement of the draft tube gates wi 11 be the same as for Watana,except that on 1y two sets of gates wi 11 be provided,each set with two 21-foot wide by 1O.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. A-11-1 (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 5.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 only for governor as well 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. (9)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 mai ntenance work at the pl ant. The facilities will not be as extensive as at Watana.Some of the larger components will be transported to Watana for necessary machinery work. A-1l-2 11.2 -Accessory Electrical Equipment (a)General The accessory electrical equipment described be10~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 dc 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 s ing1 e 1i ne di agram (Pl ate F68).The arrangement of equi pment in the powerhouse,transformer gallery,and cable shafts is shown in Plates F63 to F65. (b) (c) Transformers and HV Connections Twelve single-phase transformers and one spare transformer will be located in the transformer gallery.Each bank of the three s ing1 e-phase transformers will be connected to one generator by iso1 ated phase bus located in bus tunnel s.The HV terminal s of the transformer will be connected to the 345 kV switchyard by 345 kV sing1e-phase,oi1-fi11ed cables installed in 800-foot10ng 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 si ng1 e~phase,two-wind ing,oi 1- 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: - -I Rated capacity: High Voltage Winding: Basic Insulation Level (BIL)of HV Winding: Low Voltage Winding: Transformer Impedance: A-1l-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 sirnil ar to the bus at the Watana power pl ant.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- struct i on wi th oi 1 fl owi ng through a central 0;1 duct wi th in 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- A-1l-4 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 kVsystem 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 be 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 suppl ied 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 mai n 480 V switchgear will be suppl i ed by two 2000 kVA,15,000/480 V grounded wye sealed gas dry-type transformers.A th ird,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 dc aux il i ary system wi 11 be si mil ar to th at prov i ded at the Watana plant ~nd will cDnsist of two 125 V dc lead-acid batteries.-Each battery system will be supplied by a double-rectifier charging system.A 48 V dc battery system will be provided for supplying the supervisory and communi- cations systems. 1\-11-5 (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 ext ens i ve damage incase of an earthquake.Due to the lower heights,it is also easier to maintain. A-1l-6 ~ I ..... - -r REFERENCES Commonwealth Associ ates Inc.January 1982.Anchorage-Fairbanks Transmission Intertie Route Selection Report.Prepared for the Alaska Power Authority. - Item Hydrology TABLE A.l:PRINCIPAL PROJECT PARAMETERS Watana Dev i I Canyon - - - - -Average River Flow (cfs) -Peak Flood Inflows (cfs) •PMF •10,000-year •50-year •25-year -Peak Flood Flows through the Dam (cfs) PMF 10,000-year 50-year Reservoir Characteristics -Normal Maximum Operating Level (ft) -Maximum Level,PMF (ft) -Minimum Operating Level (ft) -Area at NMOL (acres) -Length (mi les) -Total Storage (acre-feet) -Live Storage (acre-feet) Project Outputs -Plant Design Capabil ity (MW) -Annual Generation (GWh) •Firm •Average Dams -Type -Crest Elevation (ft) -Crest Length (ft) -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 EI evation (ft) •Maximum U/S Water Leve I (ft) -Tunnels •Number/Type •Diameter (ft) •Capacity (cfs) 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 1O~ 3.7xl0 1,020 2,620 3,460 Earth/Rockfil I, Centra I Core 2,210 4,100 885 35 2.4:1 2:1 Rockf i II, Central Core 1,545 1,472 1,536 2 -Circular, concrete-I i ned 38 80,500 9,080 345,000 with Watana 362,000 without Watana 165,000 with Watana 16i,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 1,455 1,466 1,405 7,800 26 6 1.1 x 10 6 0.35 x 10 600 2,718 3,450 Concrete Arch (Earth/Rockf i I I Saddle) 1,463 (1472) 1,650 (950) 646 (245) 20 (35) (2.4:1) (2:1) Rockf i I I, Central Core 947 898 944 1 -Horseshoe, concrete-I i ned 30 39,000 TABLE A.1 (Cont'd) Item Outlet Facll ities -Central Structures -Diameter (i n1 -Water Passage Diameter (ft) -Capacity (cfs) Main Spi Ilways -Capacity (cfs) -Control Structure •Type •Crest Elevation (ft) •Gates (H x W,ft) -Chute Width (ft) -Energy Dissipation Emergency Spi I Iways -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-I ined Powerhouses -Type -Cavern Size (L x W x H,ft) -Turbine/Generator -Speed (rpm) -Design Unit Capabil ity •Net head (ft) •Flow (cfs) •Output (MW) -Rated Unit Capability •Net Head (ft) •Full-Gate Flow (cfs) •Full-Gate Output (MW) •Best-Gate Output (MW) 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 plug 2200/2201.5 310/200 Multi-level,gated 4-20 x 30 2,030 120 3,870 6 Incl ined/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 FI ip 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 Francis/ Synchr. 225 542 3,680 150 590 3,790 164 140 - - - - \~ TABLE A.1 (Cont'd) Item -Transformers •location •Cavern Size (L x W x H,tt) •Number/Type •Vo I tage (kV) •Rating (MVA) Tailrace Tunnels -Number/Type -Diameter (tt) -Surge Chamber Size (L x W x H,tt) -Capacity (cfs) Watana Upstream ga I Jery 314 x 45 x 40 9 -single phase 15/345 145 2 -Horseshoe, concrete-II 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-II ned 38 240 x 75 x 190 15,500 - SUSITNA HYDROELECTRIC PROJECT VOLUlvlE 1 EXHIBIT C PROPOSED CONSTRUCTION SCHEDULE - ~, - SUSITNA HYDROELECTRIC PROJECT VOLUME 1 EXHI BIT C PROPOSED CONSTRUCTION SCHEDULE TABLE OF CONTENTS 1 -WATANA SCHEDULE . 1.1 -Ac cess . 1 .2 -Sit e Fac i 1 it i es . 1.3 -Diversion . 1.4 -Ma in Dam . 1.5 -Spillways and Intakes . 1.6 -Powerhouse and Other Underground Works . 1.7 -Transmission Lines/Switchyards . 1.8 -General . C-l-l C-I-2 C-I-2 C-I-2 C-I-2 C-I-3 C-I-3 C-I-3 C-I-3 2 -DEV IL 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.1 Watana Construction Schedule C.2 Devil Canyon Construction Schedule i - 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,respect i vely.These schedul es 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.2.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 initi al 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 Commencement of construction: 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: r- I !Four of six units Six units -January 1994 -July 1994 The Watana schedules were developed to meet two overall project constraints: -FERC 1 icense 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 facilities,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- it i es. 1.3 -Diversion Construction of diversion and dewatering faci1ities,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 pl aced 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:-, Fi 11 Accumul ated El evat ion Quant ity Quant ity October 15 ~ (yd 3 x 10 6)(yd 3 x 10 6 )I Year (feet) 198'i 3 1988 6 9 1989 12 21 1660 1990 13 34 1810 1991 13 47 1950 1992 12 59 2130 1993 3 62 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 materi al s. 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 tunnel into the powerhouse comp 1ex has been schedul ed 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 1ines 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 £ould 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 energi zed init i ally 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 1-0_1t-+---+-F_E_R_c_L_Ic_E_N_S_E-Wl ~_+_----------__\----- 02 INITIAL ACCESS 03 ~----------+---------!---------+-----------1-----------+---- 04 MAIN ACCESS ........1,P'....................................................+- I-+-------------t-----------f-----------t----------+---------- 05 06 SITE FACILITIES ---------------- 07 =+=±=======~[====Iiir~~~C~Ofl.~'P~L~ET~E~~~N~n~2~~;~;N;O;.;-Lt1II11lllllllilltlllljllllllil'.08 DIVERSION TUNNELS _'---t 09 ~•Nn E _f--I------------------, 10 COFFERDAMS 111II11II1II1Iutllll~1Il1l1l1ll1ll1ll1l1ll11l1l I ---; II ==t===-1I--r-_~&"'.,R"'_'_"T.M"'.ENT"..:.RI'~R R"".1 12 MAIN DAM---f----1IIIIIIIIYtIllIllIIllIlIlIllIl;",f--I------------+----------l----------+---------'-===F"----== :;'""~'~""-~-.--------+----------+=-----+--l - f--f------~------+----------_+-----------j-----------f-------------+---- 16 MAIN SPILLWAY ±= 17 2B f r--------t=---I-- ;:_R_GE_N_C_Y_S_P_'_LL_W_A_Y -+_____=i=---------+---------~_~__~___+--- 20 OUTLET FACILITIES ==±=t~-~-'t-~-P:-:-S-:-:-:-:-~-A-K-E---=l--==-~--=:.--=-------=_~ 1-:-2:+P-0-W-E--R-H-0-U-S-E---=l--=--=--_f-_---=--=f----+f------- 29 I--- 30 TAILRACE/SURGE CHAMBER :ru"""~","ro,,E .=t-=I------------+---~~-~~~ 34 MECH,/ELECT.SYSTEMS =l=---------f-----------1- 35..--L-I ~~TCHYARD /C5JNTROL BLDG._-+--------------- 37 ~-+---J-- :TRANSMISSION LINES t==-----f---==------+-----,---~ 1 40 IMPOUNDMENT ==F .=t --r-'-------------=1--------------.----------- 41 ::TEST AND COMM'SSION_.F---~ 44 =r=-----=------=-_--=1--....---"-_ cor 1988 1989 1990 1991 1992 1993 1994 01 02 03 04 05 " IT','I':.'1""""'''''''06 ~~E .J~NNEL Lt>W~R TIIN'1=1 DI "" 07 --NT,,...,...,.,...108 T I 09 I I 10 ~Jt:,;rVlnll"fEh1-6 60'~'O I ~~O ~1 ~O ~10 II ;rART "R VEL I ililii'lllllllill 1l11111111ii'l},)i'ilili'ili)i''h"li """""""",,"""""""""""'-""""''''''"",""""""""",:-..""""""""".12 I 13 I 11111I11111111I111111I11 ,"""""""""",--- - -.,,,,,,,,,,,,,,,,,14 :15 1111111I11111111I111111111I11 11111!!!!!I1III'I!!!1111'!!!!!!11 1!!!"I'"!!!'II'!!!!!!!!!?"!!!!"""'"••,.,.,•••1.16 :FUSE PLII" 17 111111I11I111111111I1111 11I1111110111111I11I11 18'"'''''' I 19 111111111111111I111I11 11I11111I111111I11111111111111.11I11I11111 1.11 1.,.,•••,.,.,.,20 I 21 111I.11I11 111I11111011111 """"""1,.'..,.,.,.,.,.,."22 I 23 11111111I1111I111111111111111111 111111I11I11111111I11111111I111I111111I111 24 ":' I STAGE 2 25__-M;CESS I VAIIIT STAGE I 1111I11I1111111I"11I1"11111I"11111111I1 111111111101'11111I1 I 26,I TRANSFORMERS 27 I GALLERY/SHAFTS I .I.'.~.'.'2811111111111I111111I1111111111I111111I11111I I I if I 29 111111111I1111111111111111111I11I11111111I -- 11I1111I1 I 30""'''''''',I 31 •,.1.1.,.,.,.1.,.,~,.,.,.,.,.,.,.,.,..,.,...,.,.,.,•.•.1·'·1 32 J 1 I I 33 PH CRANES.,.,"•...1.'.'.',••,.,.1.',.1.,.,~I.'~'.'.'.'.'.'.'.'.I.'.,.,~34 EXCAVAT~"ILL FOUNDAnON""TRII"T E"/EOUIPMENT I 35 1111111111111111111111 1111I111 II r """"""''''''11111"1,.,.,.'.,.,.\I 36 I ::37ACCESSCLEAR.NG FOUNDATIONS 1 TOWE S/STRINGING P'"""jllllllill 11111111111 '"""'''.'.11 11.1.1.,.,.11\ I 38 *~~:~~5 .~50 I 39 ~---._----_.------!I 40 J,1----,__2 __3 4 J,5 __6 ON-LINE 41 '...,.,.,.lI.I.l.I.,.I,.,••••••1.••,J'42,,,,. 43 .....44 LEGEND """,..ACCESS/FACILITIES 11111111111111111 EXCAVATION/FOUNDATION TREATMENT ......"-"""FILL-CONCRETE-.,.,.,.MECHANICAL/ELECTRICAL---IMPOUNDMENT - WATANA rRUCTION SCHEDULE FIGURE C.I DESCRIPTION 1992 1993 1994 1995 1996 01 02 MAIN ACCESS r..r-.-..-..-..-..-..-.~!:ilII"",-,,-,,-,,-,,-,'-''-''-''-'.IloII !:ilII"".-..-..-..IloII 03 04 SITE FACILITIES "",,-':1""'---,--_1:"__1:7'1- 05 06 OIVERSION TUNNELS 111111I11111111I1111111 '11I1111 07 08 COFFERDAMS .",' 09 10 MAIN DAM ABI1111I11111111I1 II 12 SADDLE DAM , 13 14 OUTLET FACILITIES 15 16 MAIN SPILLWAY 11 18 EMERGENCY SPILLWAY 19 20 POWER INTAKE 21 22 PENSTOCKS 23 24 POWERHOUSE 25 26 TRANSFORMER GALLERY /CABLE SHAFTS 27 28 TAILRACE/SURGE CHAMBER 29 30 TURBINES/GENERATORS 31 32 MECH./ELEC~SYSTEMS 33 34 SWITCHYARO /CONTROL BLDG. 35 36 TRANSMISSION LINES 37 ~8 IMPOUNDMENT 39 ~ 40 TEST a COMMISSION 41 42 ~1 43 44 .... - CONS 1997 1998 1999 2000 2001 2002 2003 01 02 03 ."",.1""1111"1",.04 DIVERSION PLUG 05., I 06 .""OSE I 07 ...,~""~...",,,I 08•RIV"RR.n ::09 f1~~"~filill 1ll111111111111111111Uillliilhiiliiiii ,10 I I ".,"""'""""""I 121111I11I111I111I11111111111111111I :I 13 1'.'.1.1.'.1..,.,.,.'.1.1 I 14 I I~ IIIIIIIIIIIIIIIIIIIIIIIIIIIIIL IIIIIi'III111'II1111111111i 1ll i'i """"I .1.,.,g'.'.I."'.16 FUSE PLUG :17 111I11111111111111111111111111 11I11I1111111111I11111111I111I11I ~"",18 I 19 111I11111111I1111I1111111I1111 .t.Ii 1111 .'.1.'.'•••'.'.I 20 ~I 2'I 11I11I1111111111I1111 11I11I I 22 ACCESS !23VAUTSTAGE1STAGE2 11111111I1111111I1111111111I1111I 1~1I1111111111111111 24 1'1'"I TRANSFORME 25S 1Iy'1I;lIft~hMmil(lfI~nrrl'ITIIIIIII I •......,.26 I , !I I 27 111111111 111111I11111111I111111111I11111111I111I11I 111111I1111111111I1111111111I111 1 I 28 ,it I " 29 ~I.'I.'.I.I.'.'.'.'..'.'.1.'.'.'.'.1.11 ,.1.'.1·'1 30 J ,I :31PHCRANES '.1.'.1 ••1 11.'.1.'.'.I.'.I.'.I.'.I~I.I.1.1.'.'."32 EXCAYATION/FI L FOUNDAT,ON'" I I 33STRUCTURES/EOU'PMENT III II 111111111 IL""""IIU.I.'.I.J~I 34 .I I 35 FOUNDAT'ONS TOWERS/STRINGING 1111111111111I1111 ""iiiihllllll 1'.'.1.'.'.\ ,36I•I I "5r --___-"_1 ~-_.~_. 36, *1-;1'1 '1 2 ,it 3 '1 4 ~N-L1NE 3S i'.'1 I.,.f.,.,1,.,.1 40 41 ",.,,.'.'<42 43---4~ LEGEND I r,"'"ACCESS /FAC'LITIES 111111I1111111111 EXCAVATION/FOUNDATION TREATMENT .""",ALL-CONCRETE .1.'.1.'MECHANICAL/ELECTR'CAL---'MPOUNDMENT - :DEVI L CANYON rRUCTION SCHEDULE FIGURE C.2 SUSITNA HYDROELECTRIC PROJECT-VOLUME 1 EXHIBIT D PROJECT COSTS AND FI NANC ING - ..... - ..... - .."" SUSITNA HYDROELECTRIC PROJECT VOLUME 1 EXHI BIT 0 PROJECT COSTS AND FINANCING TABLE OF CONTENTS 1 -ESTIMATES OF COST D-l-1 1.1 -Construction Costs 0-1-1 (a)Code of Accounts .•..•.•....•....•............•0-1-1 (b)Approach to Cost Estimating ..........•.....•..0-1-2 (c)Cost Data III III 0-1-3 (d)Seasonal Influences on Productivity .....•.....0-1-4 (e)Construction Methods .....•.........•.•........0-1-5 (f)Quantity Takeoffs •.....................~0-1-5 (g)Indirect Construction Costs 0-1-5 1.2 -Mitigation Costs ....•..............................0-1-7 1.3 -Engineer-ing and Admini stration Costs 0-1-8 (a)Engineering and Project Management Costs ..~..•0-1-8 (b)Construction Management Costs 0-1-9 (c)Procurement Costs ....................•........0-1-10 (d)Owner I s Costs ...........•.....................0-1-10 1.4 -Operation,Maintenance and Repl acement Costs 0-1-10 1.5 -Allowance for Funds Used During Construction ....•..0-1-11 1.6 -Escal ation 0-1-12 1.7 -Cash Flow and Manpower Loading Requirements 0-1-12 1.8 -Contingency 0-1-13 1.9 -Previously Constructed Project Facilities 0-1-13 1.10-EBASCO Check Estimate 0-1-13 2 -ESTIMATED ANNUAL PROJECT COSTS 0-2-1 3 -MARKET VALUE OF PROJECT POWER ..........•...........•.....0-3-1 3.1 -The Rail belt Power System 0-3-1 3.2 -Regional Electric Power Demand and Supply 0-3-1 3.3 -Market and Price for Watana Output in 1994 .....•...0-3-1 3.4 ~Market and Price for Watana Output 1995-2001 0-3-2 3.5 -Market and Price for Watana and Devil Canyon OutplJt in 2003 0-3-3 3.6 -Potential Impact of State Appropriations 0-3-3 4 -EVALUATION OF ALTERNATIVE ENERGY PLANS ....•..............0-4-1 4.1 -General ...•...........................•....•.......0-4-1 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 eo .. (a)Selection Process .••••••••..••••••..•.••.•••.• (b)Selected Sites •.••..•.••.••••...•.•.•••..•..•• (c)Lake Chakachamna •••..•••.••..••••.••.•••••.••• 4.5 -Thermal Options -Development Selection •••..•..•.•• (a)Assessment of Thermal Alternatives •.•.••.••••• (b)Co a1-Fir ed Steam •.•••...•.•••••..•.•••••.•••.. (c)Combined Cycle ••.••.•...•••.••...•••••.••.••.• (d)Gas-Turbine 41 •••• (e)Diesel Power Generation ..•..••.•....•..•••••.• (f)Plan Formulation and Evaluation •••••.•.•...•.• 4.6 -Without Susitna Plan •••...•.••.•..••.•...•.•.••••.. (a)System as of Jan uary 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 •••••••••~I). 6.1 -Forecast Financial Parameters ••••.•••..•..•..•.•... 6.2 -Inflationary Financing Deficit ..•.•••.•.•.•.•.••..• 6.3 -Legislative Status of Alaska Power Authority and Susitna Project ••••.••.••••...•.••.•...•...•••. 6 .4 -Fin an c i n9 Plan ~1;1 ••Il •••••••••••••••• LIST OF TABLES LIST OF FIGURES REFERENCES APPENDIX 0-1 FUELS PRICING STUDIES Page 0-4-3 0-4-4 0-4-4 0-4-5 r"·-~"' 0-4-5 0-4-9 0-4-9 0-4-9 0-4-12 0-4-15 0-4-16 0-4-16 0-4-18 0-4-19 0-4-19 0-4-20 0-4-20 0-4-21 0-4-24 0-4-29 0-4-30 0-4-31 0-5-1 0-5-1 0-5-1 0-6-1 0-6-1 0-6-1 0-6-1 0-6-2 i iii -- ..... .... LIST OF TABLES -0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 0.10 0.11 0.12 0.13 0.14 0.15 0.16 0.17 0.18 0.19 0.20 0.21 0.22 0.23 0.24 0.25 0.26 0.27 Summary of Cost Est i mate 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 the 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 Parameters/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 D.30 Battelle Alternatives Study,Summary of Cost and Performance Characteristics of Selected Alternatives D.31 Financing Requirements-$Million for $1.8 Billion State Appropriation D.32 $1.8 Billion (1982 Dollars)State Appropriation Scenario 7%Inflation and 10%Interest ii LIST OF FIGURES IJ1M1iIJ· - 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 0.10 Watana Development Cumulative and Annual Cash Flow January 1982 0011 ars Devil Canyon Development Cumulative and Annual Cash Flow January 1982 0011 ars Susitna Hydroelectric Project Cumulative and Annual Cash Flow Entire Project,January 1982 Dollars Energy Demand and Del iveries 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 Generat i on Alternative Generation Scenario Reference Case Load Forecast Energy Cost Comparison -100%Debt Financing o and 7%Inflation iii - -, EXHIBIT 0 -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 Devi 1 Canyon projects is summari zed in Table 0.1.A more detailed breakdown of cost for each development is presented in Tables 0.2 and 0.3. 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 arriving at the estimates.For general consistency with planning studies,all construction costs developed for the project are in January 1982 doll ars . (a)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: Group Production Plant Description Costs for structures,equipment,and facilities necessary to produce power. 0-1-1 Transmission Plant General Pl ant Indirect Costs Costs for structures,equi pment,and facil ities necessary to transmit power from the sites to load centers. Costs for equipment and facilities required for the operation and mai ntenance of the product i on 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 pl ant costs. ~, Overhead Construction Costs Costs for engineering administration. and Further subdivision within these groupings was made on the basis of the various types of work involved,as typically shown in the following exampl e: Group: -Account 332: -Main Structure 332.3: -Element 332.31: -Work Item 332.311: -Type of Work: Production Plant Reservoir,Darn"and Waterways Main Dam Main Dam Structure Excavation 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, 0-1-2 - ..... (c) 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 appropri ate; -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 informati on was obtained from stand ard est imat i ng sources, from sources in Al aska,from quotes by major equipment suppl iers and vendors,and from represent at i ve recent hydroe 1ectri c projects.Labor and equi pment costs for 1982 weredevel oped 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 lO-hour shi fts per day,si x days per week.Due to the severe compression of construction activities in 1985-86,it has been assumed that most work in thi s peri od will be on two l2-hour shifts,seven days per week. The la-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 basi s with an appropri ate all owance incl uded for transportati on to site.A represent at i ve 1i st of construction 0-1-3 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 guidel ine costs on major power plant equipment. The costs of materials required for site construction were estimated on the basis of suppliers '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 associ ated 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 critical ity of the schedule.Underground activities are generally not affected by cl imate and should continue throughout the year. Studies by others (Roberts 1976)have indicated a 60 percent or greater decrease in effi ci ency in constructi on operat ions under adverse winter conditions.Therefore,it is expected that most contractors would attempt 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 0-1-4 - -(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 fi ve-month peri od 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 est imate 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 excav at ion.Convent i onal equi pment has al so been considered for major fill and concrete work. (f)Quantity Takeoffs 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). -f' (g)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: -Mobil ization 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 0-1-5 -Yard cranes and floats -Utilities including electrical compressed air -Small tools -Safety program and equipment -Fin anc i ng -Bond s and sec urit i es -Insurance -Taxes -Permits -Head office overhead -Contingency allowance -Profit. power,heat,water,and "".., 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 contr actor I s expected that this Contract packaging would provide for the supply of major materials to contractors at site at cost.These include fuel,el ectri c power, cement,and reinforcing steel. D-1-6 - - 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 pl anned during the construction of the project to reduce si mi 1 ar impacts caused by construct i on act i vites.These measures and facil ities 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 directly rel ated to the proj ect 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 Dev il Canyon Total Project $32 million (Approximately) 5 million (Approximately) $17 mi 11 ion I"" 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 0-1-7 -Right-of-way studies;and -Socioeconomic planning studies. The costs for the above work have been incl uded 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 I 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 and Preparation of the license application to the FERC; -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 rel ated to cost and schedule of the project; 0-1-8 - - -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 manual s. (b)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 equi pment 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 -Qual ity 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 proj ect;and -Legal costs. 1.4 -Operation,Maintenance and Replacement Costs The facil ities and procedures for operation and maintenance of the project are described in the Susitna Feasibil ity Report (Acres 1982a, 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 r'--'- - - and permanent town site support personnel.A total of 105 wi 11 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 handl.e all but major overhauls.A nominal allowance has been made for major maintenance work which would utilize contracted labor.It is unlikely that major overhaul s wi 11 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 pl ans are possible which would el iminate the need for permanent town site fac il it i es and rely on more remote superv i sor y systems and/or operations/maintenance crews transported to the pl ant 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 al so 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-l-ll 1 +f co 1 1 -----:::---_ 2 11 +2 JLBln(1 +f) where ~ 1 +f co =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 C as 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 Tab 1e D.1. 1.6 -Escalation All construction costs presented in this Exhibit are at January 1982 level s and consequently incl ude 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 escal ation 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 incl ude adjustments for advanced payments for mobil i zation or for holdbacks on construction contracts.The results are presented in Table 0.7 and Figures D.l through D.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. D-l-12 -, - 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. 0-1-13 - - 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 proj ected year-by-year energy trend s of the project and a summary of revenue (RL516),operating costs (170), interest,and cash sources and uses.These costs are in nominal doll ars assuming 7 percent infl ation 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 doll ars and real doll ars is shown on Sheets 5 and 6, respectively,of Table 10. The cost of power (capacity)from the project is shown on Table D-1l. Thi s cost is determined in accordance with FERC procedures and is the sum of the annual pl ant investment cost and the annual fixed operating cost.As can be seen from Table 0.11,the total annual capacity cost in 1982 dollars is $225/kW. No taxes have been assessed to the project I s annual costs.Although these taxes would be expressed as a percentage of project pl ant 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. D-2-1 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 del iveries 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 Susitna1s 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 sol d at approximately 136 mill s per kWh price are considered in Section 6 of this Exhibit. The Power Authority wi 11 seek to contract with Rail belt uti 1ities for the purchase of Sus itna capacity and energy on a bas is appropri ate 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 exces s 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 Oevil Canyon project comes on line.This effect is illustrated on Figure 0.4. 0-3-2 3.5 -Market and Pri ce for Watana and Devil Canyon Output in 2003 After the Devil Canyon project comes on line,the Susitna project will prov i de about 90 percent of the energy demand.The avoi ded 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 additional 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 will 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. D-3-3 - 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 feasibil ity 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 pl anning 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 Ranbelt 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 studi es were independent,several key factors were consi stent.Both studies used the approach of comparing costs by using generation planning simulation models.Thus,selected alternatives were put into a pl an 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. D-4-1 4.2 -Existing System Characteristics (a)System Description The two major load centers of the Railbelt region are the Anchorage-Cook Inl et area and the Fairbanks-Tanana Valley area which at present operate independently.The existing transmission system between Anchorage and Wi 11 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 0.13 summarizes the total generating capacity within the Railbelt system in 1982,based on information provided by Railbelt utilities and other sources.Table 0.14 presents the resulting detailed listing of units currently operating in the Railbelt, information on their performance characteristics,and their on-l ine and projected retirement dates for generation pl anning purposes.The total Railbelt installed capacity of 1122.8 I"1W consists of two hydroelectric plants totaling 46 MW plus 1076.8 MW of thermal generation units fired by oil,gas,or coal,as summari zed in Tabl e 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 al so consulted.Based on these sources,the following retirement periods of operation were adopted for use in this analysis: 17"·'-, -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: D-4-2 30 years 35 years 20 years 30 years 30 years 30 years 50 years (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 proj ects are assumed to be added to the Rai 1be It 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. ,.-, ,-I 4.3 -Fairbanks -Anchorage Intertie Engineering studies have been undertaken,equi pment 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 "with Susitna"scenarios,the costs of adding circuits to the intertie corridor were added to the Susitna proj ect cost.For the non-Sus itn a un its,transmi ss i on 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 D-4-3 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 1 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 Recl 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 1981b).Step 1 of this process essentially established the overall objective of the exercise as the selection of an optimum Ranbelt 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 CDE National Hydropower Study and the Power Admi ni str at i on report "Hydroel ec- tric Alternatives for the Alaska Ra"ilbelt.1I 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- D-4-4 - - (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 selected potential non-Sus itn a basin hydro developments 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). ......r - 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 initi ated 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 mil es west of Anchorage.Its water surface 1i es at about El ev a- tion 1140 . Two basic alternatives have been identified to harness the hydrau- lic head for the generation of electrical energy.One is via the vall ey of the Chakachatn a Ri ver.Thi s ri ver 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 all uvi al flood pl ain.A max imum hydrostatic head of about 740 feet could be developed via this alternative. 0-4-5 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 1ake outlet.A max imum hydrostatic head of about 960 feet could be harnessed by this diversion. (i)Project Layout The Bechtel study eval uated 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 al so the time required for construction of the tunnel.Cost comparisons neverthe- 1ess favored the shorter 10-mi 1e,25-foot di ameter tunnel. The second al ignment running more or less parallel to the Chakachatna River in the right (southerly)wall of the valley afforded two opportunities for intermediate access adits.These,pl us the upstream and downstream portal s 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 requi rements in the Chakachatn a Ri ver red uced 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 0-4-6 ~, 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 identifi ed 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 favorable based on a 1981 fi el d reconnai ssance.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 del iver 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 al so 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 woul d be rel eased 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 de 1i vered to Anchorage woul d 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 Bare $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 simil ar to that of Alternatives A and B for a slightly longer power tunnel. The geologic conditions for the various project features incl uding 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 producti on,coul d del iver 1248 GWh of firm energy per year to Anchorage and provide 300 MW of peaking capability.While the river flow in the Chakachatna Ri ver below the powerhouse at the end of the canyon will not be substantially 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 1 ake out 1et to fac il itate fi sh pass age through the canyon section into the lake.In either of Alternatives C or D the environmental impact would be 1imited 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 fl ow rel ease for Alternat i ve 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, D-4-8 - - 1248 GWh of firm energy del ivered to Anchorage). .Estimated project costs for Alternatives C and Dare $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,wi nd and solar and the relevant environmental,social,and other issues involved were addressed in the Battelle alternatives study (Battelle 1982). As such,a screen ing 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 pl an. (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 pl ants bei ng considered for the rail belt thermal generat ion altern at i ves. (i)Capital Costs A detailed cost study was done by EBASCO Services Incorpor- ated as part of Battelle1s 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 fl ue 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 0-1 developed the base cost of coal _from these sources,transportation costs,if required,and real price escal ation 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's proximity to Denali National Park.A mine-mouth 0-4-10 (Revised,7/11/83) pr--'"I - ,~. .~ 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 Utnity Systems adjusted for changes in production level s and new 1 and rec1 aimation regu1 ations.Transportation costs to Nenana are estimated to be $0.32/MMBtu in 1983 dollars. Therefore,the total cost of the coal del ivered in Nenana would be $l.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 esca1 ation 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 esca1 ation 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 esca1 ated,so the base price of coal to the util ity tends to increase with general inf1 ation. Several escalation rates have been estimated for utility coal in A1 aska 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.(ORr).Because the forecasts of ORI 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 ORI 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 D.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 Bel uga.The base pr i ce of coal has been determined under the assumption of an export market and was calculated as the net back cost in A1 aska based on the val ue of coal in Japan as described in Appendix 0-1.This cost is $1.86/ MMBtu at 1983 price levels for coal with a heat content of about 7500 Btu/lb. D-4-11 An escalation rate of 1.6%/yr.of the price of Beluga coal is based on escal ation rates developed by ORI 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 escal ation rate for the Reference Case all thermal generation alternative is about l%/yr. The coal escalation rates discussed above were used for the reference case and the ORI sensitivity case.Zero real price escalation of coal was assumed for the OOR-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 si zing for pl ants 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. D-4-12 -I .... ..- (i i )Fuel Costs The avai 1abi 1i ty,use,and pri ce of natural gas are presented in Append ix D-1.Known recoverable reserves of natural gas in Alaska are located in the Cook Inlet area near Anchorage and on A1ask a I s North Slope at Prud hoe 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 transmi ss i on 1i ne is constructed,the gas cannot be utilized.Undiscovered gas resources are believed to exist in the Cook In 1et area and also in the Gu lf of A1ask 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 rei njecti on)currently takes place 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 abil ity to contract for needed supp 1i es.Since there is a 1imited qu ant ity 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 cumul ative 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 pl us the mean of the und i scovered 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 Al aska since a well developed market does not exist.In addition,the price of gas is affected by regul ation vi a the Natural Gas Policy Act of 1978 (NGPA)which specifies maximum wellhead prices that producers can charge for various categories of g as (some categori es wi 11 be deregul ated 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 $O.15/I'v1cf and a fixed pipeline charge of about $0.30/Mcf for pipeline del ivery from Bel uga to Anchorage are additional costs.The pipeline charge of $O.30/Mcf will,of course,not be incurred if the gas is used at Bel uga 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 oi 1 in the year of escal ation 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 Peri od 1984 1985 1986-1988 1989-2010 2011-2020 2021-2030 2031-2051 Rea 1 Escalation Rate % -4.6 -4.7 o 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. - :~ I~ (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 facil ity cost-effective for the Anchorage load center. (i)Capital Costs 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. ( i i ) (iii) 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 Annual operation and maintenance costs and forced outage rates are shown in Table 0.18. 0-4-15 (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 avai1able. (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.Potentia11y,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 rel i ab il ity requi red 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 pl an 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 model s 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 requi res an extensive system of specifi c data to perform its planning_function.In developing an optimal plan,the program considers tHe existing and committed units (pl anned 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 "how much"capacity to add and Il when"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 sel ected and added to the system.Finally,an investment cost analysis of the capital costs is completed to answer the question of "what kind"of generation to add to the system. The model is then further used to compare a:Jternative 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 pl anning model,a base case ll 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 un its 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 Add it ions Gas-Fired Gas-Fired Gas Turbine Combined Cycle Coal Fired Unit Year (MW)(MW)(MW) I"""1993 1 x 200 (Bel uga) 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 (Nenan a) 2011 1 x 70 2012 1 x 200 (Bel uga) ~2013 1 x 200 2014 2015 2016 2017 2018 2019 1 x 70 Total 840 200 1000 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 MWoMW o 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 nce the ri ghts are in the hands of pri vate interest s. 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 "worstll case by using the sea water from Cook Inlet as cooling water; however,this solution would add significantly to project costs. The thermal pl an 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 worl d oi 1 pri ces,the benefi t-cost assessments were subj ected to sensitivity analyses as described in Section 4.8 (oil prices)and Section 4.9 (other variables). D-4-20 (a)Economic Principles and Parameters .... .... (i ) Economic Principles -Concept of Net Economic Benefits A necessary condition for maximizing the increase in state income and economi c growth is the select i on of pub 1ic 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 val ue represents the val ue 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 consumpt i on in state.The worl d price must be adjusted through a net-back exercise which accounts for the costs of gett i ng the resource to worl d markets. The choice of a time hori zon is al so cruci al .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 anal ys is would poi nt to different generat ion 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 butal so in other infrastructure facilities such as roads,airports,hospitals,schools,and communica- tions. It therefore follows that the Susitna project,like other Alaskan investments,shoul d be appr aised on the bas is 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 whlch lS the all-thermal generation plan and assessed over 2051,uSlng scen ari os and energy. a planning period extending from 1982 to internally conslstent sets of economk appropriate opportunity values of Alaskan Throughout the anal ysi s,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 sensHive to modHied assumptlons 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 DespHe the fact that price level s 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 2051.5i nce this is consistent wHh long-term forecasts of the CPI advanced by leading economic consulting organizations, (Data Resources 1980;Wharton Econometric Forecasting Assoc i ates 1981)7 percent has been adopted as the study value.This analysis could have been done with the GNP deflator in lieu of the CPl.Results would be essential- ly the same. Discount Rates Di scount rates are requi red to compare and aggreg ate cash flows occurring in different time periods of the planning D-4-22 I~ - - 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 infl ation-adjusted (real)and infl a- tion-inclusive (nominal)values. Real Discount and Interest Rates Several approaches have been suggested for est imat i ng 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 I s real borrowi ng rate or the real cost of debt capital (Baumol 1968;Mi shan 1975; Prest and Turvey 1965). The SOC rate measures the real soci al return (before taxes and subsidies)that capital funds could earn in alternative investments.If,for example,the marginal capital investment in Al aska has an est imated soci al yield of X percent,the Susitna Hydroelectric Project shoul d be apprai sed using the X percent measure of "foregone returns II or opportunity costs.Ashortcoming of this concept is the difficulty inherent in determin- ing the nature and yields of the foregone investments. The STP rate measures society'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 soci ally-' desirable rates of investment. A subset of STP rates used in proj ect eval uat ions is the owner'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 val ues 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 r ate for the per i od 1982 to 2051. Nominal Di scount 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 Escal ation Based on present trends in construction costs,no real capital cost escal ation 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 Rail belt,an analysis was made comparing the costs of electrical energy production with and without the Susitna project. The method of comparing the "with ll and "without ll 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 annual i zed investment costs of any generating and system transmission pl ants 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 facil ities 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 basi s,annual costs have been aggregated for the peri od 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 particul ar generation alternative,the first element of the PW value represents the amount of cash (not incl uding 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 hori zon 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 escal ation,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 I1With l1 and "Without"Susitna The Reference Case compari son of the "with"and "without 11 Susitna plans is based on an assessment of the PW production costs for the period 1993 to 2051,the Reference Case val ues 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 install ation at Watana wi 11 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 pl an call s for the addition of a 70-MW gas turbine unit in each of the following years,2001,2012,2014,2015,2016,2017,and20l9. 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 0.22.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 escal ation 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 val ue cost difference between the Susitna pl an and the expansion pl an based on thermal pl ant addition is $1.8 billion in 1982 dollars. It is noted that the magnitude of net economic benefi ts ($1.8 billion)is not particularly sensitive to alternative assumptions concerning the overall rate of price infl ation 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'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 Jltest ll proposed by the State of Al aska in cases where state appropriations may be involved.* *See Alaska legislation A5 44.83.670 D-4-27 The generation pl anning analysi s has impl icitly assumed that all environmental costs for both the Susitna and the non-Susitna pl ans have been costed 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 pl an 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 pl ans were incl uded.Thi s may not be the case with the coal alternative which may underestimate environmental costs.These di fferences or added costs cannot be quantified at this stage of study on the coal alternative. The generation pl anning analysi s al so 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 pl us und i scovered reserves are exhausted woul 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 est imate 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 t he Sus itn a proj ect. D-4-28 - jl'lilli§Ol, 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,DaR-mean and -2 percent load forecasts.The fuel price escalation rates whi ch correspond to these forecasts are di scussed in Appendix 0-1.Table 0.24 depicts the results of the sensitivity analysis. As can been seen from Table 0.24,the DaR 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 pl an 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 $1.82 billion or about the same those of the Reference Case. In performing the above analysis,it was assumed that the initial operating dates of Watana and Devil Canyon would be the same as under the reference case,or 1993 and 2002 respectively.A study of the expansion programs for the sensitivity case showed that new capacity,that could be provided by Watana,would be required in 1993 in ~l cases and that Devil Canyon could be delayed by up to 5 years under the -2 percent case.However,sens itivity analyses showed that delaying Devil Canyon would not significantly affect the results of the economic analysis. D-4-29 4.9 -Other Sensitivity Assessments Rather than relying on a single point comparison to assess the net benefit of the Susitna project,a sensitivity analysis was c arri ed out to identify the impact of a change in assumpt ions on the results.The analysis was directed at the following variables other than those related to the world price of oil. Variable,Reference Table Discount Rate (%),Table 0.25 Watana Cap.Costs ($x10 6 ),Table Base fuel price ($/MMBtu),Table Coal -Nen ana -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 Escal ation to 2051 Sensitivity Val ues 2,5 2917,4316 1.38,2.06 1.49,2.23 1.98,2.96 Escalation to 2020 only 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 rel ated fuel price escal ation rates.As stated in Section 4.8 under certain forecasts the with Susitna plan is marginal or unattractive when compared to the withoutSusitna 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 val ues 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 Governor1s 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: -fuel supply and price analysis -electrical demand forecasts -generation and conservation alternatives eval uation -development of.electric energy themes or "futures"available to the Rail belt -systems integration/evaluation of electric energy plans. Note that whi le 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 suc 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 incl uded in the system and the number of generating units or the total generating capacity required.The forecast used from this study in the Susitna feasibil ity 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 publ ic acceptance.Alternatives appearing to be best suited for future appl ication 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 el ectri c energy themes or pl ans, 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 criteri a used to eval uate and compare the pl ans 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 technologies for developing energy plans. D-4-32 ,~ -- - .Selecting generating alternatives for the Railbelt 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 Railbe1t.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 ike1y 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 ona1 study.Further di scuss i on of the selection 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 consi derat ions: -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- f1 ected in est imated busbar power costs; -pub 1ic accept ance,both as refl ected in the fr amework of e1ec- 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 lncluslon In the Railbelt electrlc power plans.For each nonhydro technologYt a prototypical plant was defined to facilitate further development of the needed lnformatlon.For the hydro technologies t promising sites were selected for further study.These prototypical plants and sites constitute the generatlng alternatives selected for consideration in the Railbelt electric energy plans.In the following paragraphs,each of the 13 preferred technologies is briefly described t along with some of the principal reasons for its selection.Also described are the prototypical plants and hydro si tes se 1ected 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'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 t the existing Nenana coal fields would need to supply an increased ton- n age at hi gher pr ices. The extremely low sulfur content of Railbelt coal and the availability of commercially tested oxides of sulfur (Sax)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 t possible ambient air- quality effects of residual sax,oxides of nitrogen (NO x )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 facil ities 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 pl ant of simil ar capaclty 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 NO x ,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 pl ants should be somewhat less susceptible to inflation fuel cost than conventional steam-electr;'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 load-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 ic of these un its al so 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. 0-4-35 (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-cycl e pl ants 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- 1ems. A nominal 200 MW prototypical plant was selected for fur- ther study.The pl ant is located in the Bel uga 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 cell s 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 escal ation of natural gas prices compared to combustion turbines.Construction lead time should be compar ab 1e to those of combust i on turbi nes.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 ellerging technology with commercial availability scheduled for the late 1980's~it was not chosen as a major block in the Railbelt generation future.No prototypical pl ant was sel ected for further study. 0-4-36 .-(vi)Natural-Gas -Fuel-Cell -Combined-Cycle These plants would consist of a fuel conditioner that con- verts natural gas to hydrogen and carbon dioxide,molten carbonate fuel cells that produce dc 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 dc 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 si go ificant envi ronmental impact.Operat ion- 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. (vii)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 MIrl to 15 MW.Several small-scale hydro sites have been identified in the Railbelt and two currently undeveloped sites (All 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 escalat ion 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 rel atively 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 pub 1ic interest in these systems,their renewab 1e 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 sel ected 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 ~\ - r II""" -. f to wind energy systems.Surplus wind-generated electricity could be readily Il s tored ll 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 1ected for further study.The prototype cons i sted of a wind farm located in the Isabell Pass area and was com- prised of ten 2.5 MW rated capacity,Boeing MOO-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 Rail belt ,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 facil ities currently operating in the Rail belt.However,these machines operate in a fue l-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 logy profi 1es .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 thi s anal ys is these machi nes were gi ven parity with firm generating alternatives for cost of power comparisons.Because the potential contribution of this alternative is relatively minor even under the rather 1 i beral assumptions of thi s anal ys is,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)Ti dal Power Tidal power pl ants typically consi st of a "tidal barrage" extending across a bay or inl et that has substanti al tidal fluctuations.The barrage contains sluice gates to admit water behind the barrage on the incoming tide and turbine-generator un its to generate power on the outgoi ng 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 batteri es)can be used to regul ate the power output of the ti d al fac il ity. 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 substanti al interest in the resource,as evidenced by the first-phase assessment of Cook Inlet tidal power development (Acres 1981a). Estimated production costs of an unretimed tidal power facil ity 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 establ ished 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 rel ative to other power-producing options because only a fraction of the Ii raw"energy production could be used.An additional alternative would be to construct a retiming facility, probably a pumped storage pl ant.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 pl ans. 0-4-40 ..... (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 rel atively low energy density fuel. Supplemental firing by fossil fuel may be required to compensate for seasonal vari ation 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 - - - -1 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 thi s 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 pl ants 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 (j1t4M: 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 accompanyi ng rate of infl at i on woul d be about 7 percent.In vi ew 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 "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 outl ined within Al aska 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 legisl ation states that the purpose of the project is to generate,transmit and distribute electric power in a manner which wi 11 : (1) (2 ) (3) Minimize market area electrical power costs; Minimize adverse environmental and social impacts while enhancing environmental values to the extent possible;and Safeguard both 1ife and property. Section 44.83.36 Project Financing states that lithe 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 cing Plan 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 ll 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's estimated annual debt capacity for the period. The revenue bonds are expected to be secured by proj ect power sal es 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 ll 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 -I - The actual interest rates at which the project will be financed in the 1990s and the rel ated rate of infl ation 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 pl an 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 infl ation 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 Util ity 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 Ofhce of the Governor,State of Al asRa. ·December 1981b.Susitna Hydroelectric Project Development ------~Selection Report.Prepared for the Alaska Power Authorlty. ·March 1982a.Susitna Hydroelectric Project Feasibility Report -----T(7 Volumes).Prepared for the Alaska Power Authorlty. ·April 1982b.Susitna Hydroelectric Project Reference Report, -----~Economic,Marketing and FlnanClal Evaluatlon.Prepared for the Alaska Power Authorlty. -·April 1982c. -----~Studies.Prepare Pl anning In ,... Alaska Agreements of wa~es and Benefits for Construction Trades. effect January 198 . 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 --TTVo·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 Electr1c Energy Plans. Volume IV:Candidate Electric Energy Technologies for Future Application ln the Ra11belt Reg10n 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 for the Ra1 Ibelt~ Volume XII:Coal-fired Steam-electric Power Plant Alternatives for the Railbelt Reg10n of Alaska. Volume XIII:Natural Gas-Fired Combined-Cycle Power Plant Alternatives for the Ral !belt Reglon of Alaska. Volume XVI:Wind Energy Alternative for the Railbelt Region of Alaska. Volume XVII:Coal-Gasification Combined-Cycle Power Plant Alternatives for tHe Ral Ibelt Reglon of Alaska.Prepared for the Offlce 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.Chakach~nna Hydroelectric Project Interim Report.Prepared for the Alaska Power Authorlty. Canadi an Resourcecon Limited.May 1980.Industri al Thermal Coal,Use in Canada,1980 to 2010. Caterpi 11 ar Tractor Co .October 1981. Handbook.Peoria,Illinois. Caterpillar Performance. 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 Authorl Ey. ~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). Phung,Doan L.April 1978.A Method for Estimating Escalation and Interest During Constructlon.Irstltute for Energy AnaJysls,Oak Rldge Assoclated Onlversltles. 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 CZosts In NEPA Analyses fo~the'EJectrlc Otl Ilty Industry.O.S.Nuclear Regulatory Commlsslon,Washlngton,O.C. Roberts,William S.July 1976.Regionalized Feasibility Study of Cold Weather Earthwork.Cold Reglons Research and Englneerlng laboratory,Speclal Report 76-2. SRI International.October 1981.Personal communication. r-Segal,J.December 1980.Slower Growth for the 1980 1 s.Petroleum Economi st. 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 ~Information Administration.Washlngton,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 P"'"January 1982 Dollars $ X 10 6 Catagory Watana Devl I Canyon Total Production Pl ant $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,o percent inflation,3 percent interest) Escal at ion ~AFDC 485 180 665 TOTAL PRO~IECT COST $4,081 $1,734 $5,815 SUSITNA COST OF POWER (Table 0.10,100%Debt Finance) ,....,Escal at ion 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) Escal at ion 2,560 3,200 5,760 AFDC 314 1,610 1,924 TOTAL PROJECT COST $6,470 $6,364 $12,834 Line NUTber rEscription TABLE 0.2:ESTIMl\TE SLfvMtlRy -WATANA Arount (x 1(1))Total~)(x HF Ranarks PRau:TIll'l PLANT 3lJ LCIld &LCIld Rights .II ••••••••••••••••fI •••••III •••••III ••••••••II ••fI 0 110 e ••l!I •II> 331 Powerplant Struc~ures &hnprovements .•....•.•••...•••••.•..•....•••••• 332 Reservo i r,Dans &WaterwajlS .~"III ••••••~••••••••••••III •••••••••••••••••III III 333 Waterwheels,Turbines &Generators •.•..•.....•....••••.•.•••.•.•.••••. 334 Jlccessory El ectrica1 Equi prent . 335 Miscellaneous Powerplant Equipment (Mechanical).•••••••.•.•••••••.••.• ~Roa::ts &Rai 1roa::ls III ••••••••••••••••••••110 •••••••• Sliltota1 .....III III •••••••••••••••••••••••••••••III •••••••••••••III ••••••••••e U:>r1t i ngef\CY e III •II III III ••••••III ••••• TOTPJ..~OOl...CTlOO PLANT ••••••••e III ••III ,.•••••••••••••••,.••••••••III ••• J $51 74 1,547 66 21 14 214-1,987 D5 $2,293 91eet 1 of 5 l I 1 J -"J 1 1 1 1 -;1 1 1 TABLE D.2 (Cont1d) LineNurber l:escription Arount (x 1(0)Total~ (x 1<J-')Ranarks TOTJIl BRt:lGIT FffiWJlRD TRANSMISSlOO PUWT $2,293 350 352 353 354 356 359 Larx:1 &LCIld Ri ghts •••••••••••••••••••••••••••••••••••••••••••••••••••• Slbstation &Switching Station Stnctures &fullrovarents •••••••••••••• Slbstation &SNitching Station Equiprent . Stee-l TO'Aers &Fixtures . Clverheoo Condoctors &l:evices . Roa:Js &Tra;1s •••••••••••••••••••••••••••••••••,.,•••••••••••••••••••••• $8 12 131 131 100 13 WrIt i ngerlCY •••,.,••,.,. SLbtotal ..................................,.,,.,,.,.395 61 TOT~l'R,OJ\J~ISSIOO PUWT ••••••••,.,..,.,•••••••••••••••••••••••••••••••••••456 $2,749 Sheet 2 of 5 TABLE 0.2 (Gont'd) TranslXlrtatioo EquiP'JlE!f1t .""II"""•••""••••It ••".II •••••".."••11I ••1& rescription Too 1s Stlop &Garage Equi P'JlE!f1t •II III "••"'"••" ""•••"II III ••" • " " •&•••• LciJoratory Equiprent ..III III ••••" " •ell "••••••"III II "II "0 Tota66(x 1 )Ranarks $2,749 Inc 1LKled lJ'lder 330 Included under 331 Inc 1LKled ltlder 399 II Ii II II II II II II Ii Ii II II Ii II Amunt (x UP) 5 $ •••••••••••••••••••••••••••••••••&••••"•••••(10 •• Office FUYlliture/Equiprent ,..8 III "••••••"."."••"••It""II""..a III TOT~~Cl....G-ff FffiWAAD •.II n .."" •a II II II II &II II ••II •II II II ••••II •II •II •II ......."..eo GO e 0 III III III .... GENERAL PLANT Larld &LCIlCf Rights III II II (10 .. Stroctures &Irrproverents .0 III 110 •110 III •••""It 0 110 ".." " • " " • "•• PO\'oer-~rated EquiP'JlE!f1t Carmunications Equiprent Mi see 11 aneous Equi prent Other Tangible Property Stores Equiprent 11II It 110.110 ••"0 ••"It.III III II ••" •110 1(1 •••••""tI oil (10 139 300 391 392 393 394 395 396 397 398 399 Line Nurber TOTJlJ...GENERAL PLAAT IJ ••••••••••••III $5 $2,754 Sheet 3 of 5 1 ':11 --,j 1 1 J )1 1 "1 1 1 1 -1 J 1 1 1 TABLE 0.2 (Cont'd) Line NUlber Il:!scription ~W)Total~)(x lao Ranarks rom..BROLGlT FffiWAAO INDIRECT COSTS $2,754 61 62 63 64 65 66 68 69 Temporary Construction Facilities Constroction EquiJ]TB1t .""""""""""""""""""""""""""""""""""""""""""""""" Carp &CaTmi SSaY"y """"""""""""""""""""""""....""""""""""""""""..""""""""".. Lmr Ex~se """""""""""""""""..""""""........"".""..""""""""""""""""""""""" .5LJJ)E!ri nta1det1<:e """""""""""""""""..""""......""""......""......"""""""""""""""""" InS~ar1Ce "..""".."""""ill " " " " " " " " " " " " " " " " ".,"" " " " " " "...."..".." " "...." " " " " " " " " " " " Mitigatioo """".""""""""""""""""""""""""""""""""""""""""""""""""""""""" Fees """""""""""""""""""""""""""""""""""""""""ill " " " " " " " " " " " " " " " " " " " " "••" rtlte:Costs lllder accounts 61,62,64,G5,66,ct1d 69 are inclLKI~in the appropnate dlrect costs listed ibove. Slbtotal Cont i ngalC:Y """"...""""""ill " " " " " " " " " " " " " " " "••••••••••••••••••••••••••••••• TOTJIJ..INDIRECT COSTS $ 373 29 402 40 $442 5ee rt>te See rt>te 5ee rt>te 5ee rt>te See ttlte roTJlL CONSTROCTIOO COSTS $3,196 Sheet 4 of 5 TABLE 0.2 (Gont'd) Line NUl'tJer 71 72 75 76 77 80 -l j ~scription TOTAL CONSTRUCTION COSTS BROUGHT FORWARD •••••••••••••••••••••••••••••• OVERHEAD ~STRUCTI()\J COSTS (PROJECT INDIRECTS) En,gineering/Mninistration ,.It ••••••••••••,.••••110 ••••••e,.••III III o!J ErlviroYlTB'ltal rv1Jrlitoring ••....••..•.•..••.•.••••,.••••.••••..II •••"'.e,.•• Legal Ex(JE!lses It ••••••••••I II Taxes .••••.••••.•••••••lit "•••It •••••••••• Mninistrative &l?eneral Expenses ••••••••••••••••••••••••••••••••••••• Interest ,.II ••••••••••••••••••••••••• Earnings/Expenses l:AJring Gonstroction ••••••••••••••••••••••••••••••••• Total CNertlea:J .•.•.......•.•••..•••It ••••••••••••••'"••••••••••••••••••• TOTJ'J..ffiQJECT COST .••.••••..•.•.•...•.III •••••••••,.•II ••••••••II •••••III •••• Arol11t (x lCP) $336 14 -- Total~ (x 1(0) $3,1~ 400 $3,596 Ranarks Inclooed in 71 I'bt app 1icID 1e Inclooed in 71 I'bt inc 1ooed I'bt inc 1ooed Sheet 5 of 5 1 1 J 1 1 J 1 I 1 )1 ] TJlJ3LE D.3:.ESTIMl\TE St..Mv\llRy -r:IVIL CANYOO, LineNUTber-~scription ) ~W)I~tf~)Ranarks Roa::Js &Rai 1roa:1s . c:or,t;ng€!1Cy "..""".."""""".. MiscelliJ1€Ous Powerplant EquiP1J31t (Mechanical)••••••••••••••••••••••• Powerplant Structures &bnprovements •••••••••••••••••••••••••••••••••• 22 69 646 42 14 11 119 923 142 $ ."" "\" " """" """ Reservoir,Dans &Waterwaj'S "".. WaterW1eels,Turbines &~er~tors "". kcessory Electrical Equ;P1J31t "". PRCXlCTIOO PLANT LiJ1d &LiJ1d Rights Slbtotal :m 331 332 333 334 335 3)) TOTJlJ..ffioo.crlOO PLANT "" "$1t 0i5 Sheet 1 of 5 TABLE 0.3 (Cont'd) LineNurber 350 352 353 354 356 359 D2scription TOTJ\I...MCl.GIT Frn~D III •••III •••••III III •D III III III II •e III III •III Ii II ••II III ••III fI II •III II ..III ~U II II 11\0 II l!I fJ .. lRANSMISSlOO PLANT LCIlCf &La1d Rights III II •••III "••III III ••••••III III ••••11\0 .....II " •~••III •III II't III •••II II III •IiIII II •III ..l) Substation &Switching Station Structures &knprovements .••••.•••...•• Substation &SMritching Station Equipment .••••.••.•.•••••.••••.•.•••••• Stee 1 To~rs &F;xtures III •••••6 •III III III •III ••III III It •III III III III ••III III ••It III "III III III III III III •III e •III III III III 0 OJerheaj Condoctors &ll=v ices .III •••It III ••III III III III •••III ••III III III III III III III III III III I 110 II III III III ••It "III • RoCk:1s &Trails ••••••••••••••8 •••8 "0 ••0 •••••".8 ••• f:>~) $ - 7 21 29 34 T~tf~) $1,(65 Ranarks Included in WatanaEstimate Included in WatanaEstimate SLbtota1 III III III III III III III III III III III III III III III III III iii III 11II III III "III III III III III III III III ..III III III III III III II III III III III iii III III III III "III III III •III III •III e III It II l!I 91 wntinget1Cy III III ••••III IJ III III III III III III III III III III ...III III III ••III III III ••III III III III.III III III III III III III 11I0 ••III III III.III III III 0"III eo III 14 TOTJ\l...1"RAN3v11 SS I()'J PLmT III III III III III III III III III III III III III III III III III III III II III III III III III III III III III III III II III II III III III III III •III II II III III "$105 $1,170 Sheet 2 of 5 J 1 1 )1 1 J J 1 J 1 )1 1 1 1 TABLE 0.3 (Cont1d) Line NUTber 139 :ro 391 392 393 394 395 396 397 398 399 Description TOTJlJ...ma..err Frn~D .. rENERAJ...PlJ\NT Li)Yld &LCIld Rights ill .. Structures &lrrtJroVarBlts ,.,,.. Office Fumiture/Equi,prent . Tr CI1s(X)rtat i 0f1 Equi pre1t .. Stores ECflJi pre1t ,.;. Tools StlcJp &GaY"'~e Equiprent . Lcix>ratory Equi prent .. Po~r Q:Jerated Equiprent Carmunications Equiprent Mi sce11 aneous Equi prent Other TiJlgible Property Arount (x 1(1') $ 5 Tota~(x 1 )Renarks $1,170 Inc 1Lded under :m Inc 1Lde:1 lIlder 331 Inc 1Lded under 399 II II ../I .. .. II II II II /I .. II II roTM..(Jl:N~pLJWT"•••••,.,.............••$ 5 $1,175 Sheet 3 of 5 TABLE 0.3 (Cont'd) Line Nurber 61 62 63 64 65 66 68 69 Lescription TOT~~00ff FffiWAAD .9 lit III III •••e III lit I!l III ""..IJ .. INDIRECT mSTS i Tarpor ary Construct i on Foci 1iti es •.•..••••••••..•.•..•.••..•••.••...•. Construction Equiprent Carp &CcJrrnissaY""y .&6 III •III"•II L~r Ex~se 8 ••••••••••II •!I III . StJ~ri nter1derJC.e 8 "e " •It II lJ ••• Insl...D"artCe 8 III II II)"110 ..II III .. Mitigation "'e 11 .. F~lit ""It II /'bte:Costs lllder occounts 61,62,64, 65,66,trId 69 are included in the appropnate direct costs 1i sted cbove. SLbtota 1j\5 fill 0 ••••G •••e ••••eo • Cc>nt i nget1Cy a ••••••••••D 8 TOTJ.1J...INDIRECT COSl'S .....•••••.••••••.•...•••••••••0 ••••••"••••••••••" Arolilt (x 1(0) $ 184 4 188 18 Tota]~ (x lCP) $1,175 $2()j Ranarks &>e /'bte &>e /'bte See tbte ~tbte See flbte See tbte TOTAL CO'lSlRLCTIO'J mSTS $1,:~n Sheet 4 of 5 Cj !'1 ])1 -1 1 -)1 --1 1 1 ]-J 1 1 I TABLE 0.3 (Cont1d) Line Number Description mTAL..COOSlRLCTIOO COSTS BRarnT FCRWARD . OVERt£AD a:JNSlRLCTIOO COSTS (PROJECT INDIRECTS) 71 Engineering/A::tnini stration .. Envir<ll1TBltal tblitoring Ito .. 72 Legal ExJB1ses .. 75 Tax.es .. 76 Jldninistrative &General Expenses •••••••••••••••••••••••••••••••••••• 77 Interest '.. 00 Earnings/Expenses riJring Constnction •••••••••••••••••••••••••••••••• Iota 1 Clverhea:l Costs -.-.. roTPJ...ffiUJECT ooST .. Aro~Tota~ (x 1 L Ix 1 ) Renarks $1,l31 $167 6 Ire llXled in 71 tt>t Jlppliccble IrellXled in 71 tt>t Inc llXled -NJt Inc llXled k < f 173 $1,554 Sheet 5 of 5 TABLE D.4:MITIGl\TIO'l r.£ASlRES -StJvMllRY (F OJSTS INCffiPffiATEDINC~l£TI(}l COST ESTI~TES WAT~[EVIL ~Y(}lCOSTSINCCRPffiATEDINCOOSTRlDIfJlESTIMl\TES $X1 $X1 Outlet Facilities Main D~at ~v;l CCJ1~14,600 Tunnel pi 11 way at Wa <J1a 47,100 ~' Restor at i on of Borrow Jlrea D 1,600 ND. Restorat;on of Borrow Jlrea F 600 NA Restoration of Canp <J1d Vi 11 age 2,3))1,0Xl Restoration of Construction Sites 4,100 2,0Xl Fencing around Ccmp 400 200 Fencing around Garbage Disposal Jlrea 100 100 MJlti 1eve 1 Intake Structure 18,400 NA F- C~Faci 1ities Associ ated with trYing 10,200 9,CXXltoeep\lbrkers out of Local Carmunit,es 7-""· Restoration of Haul Roads 800 500 SUBTOTAL 85,600 27,400 Contingency 20%17,100 5,500 TOTAL crnSTRlDH}1 102,700 32,~ Engineering 12.5%12,SOJ 4,100 TOTAL ffiOJECT 115,500 37,00J 152,500 1 --]1 1 1 1 ]1 ---1 ----]I )i J TABLE 0.5:~Y (F CPERATH)\J two Ml\INTENANCE msTS WATANA1 ($000 1 5 Omitted)($000 1 5 Onitted) EXpense EXpense LciJor Itens Stbtotal LciJor Itens Stbtotal- 53])9!X)6320 1920 500 2420 nl nl --400 400 540 340 ffi()120 00 ax> 1000 1000 nl 500 400 ax> Po\\er &Transnission Q:leration/ Maintenit1ce Contra:ted Services Pennanent TO\'Klsite Q:lerations Allowance for Envirorrrental Mitigation Contingency Jldditional Allowance fran 2002 to Repla:e Ccmnunity Fa:ilities Total Q:lerating and Maintenance Expenditure Estimate PolEr l:eveloprent iJ'ld Transmission Fa:i1 ities (1)Incrarenta1 WATANA 10,400 I DEVIL CANY(J\J Zf;00J TABLE 0.6:VARIABLES FOR AFOC COMPUTATIONS Anal ys is Effective Interest Rate (x)%Escalation Rate (y)%Construction Perloo (B)yrs.WatanaDevil Canyon Economic 3o 8.57.5 Fi nanci al 10 7 8.57.5 -1 I 1 ]1 1 1 1 1 1 J I -1 J -1 I TABLE 0.7 -SUSITNA HYffi(ILEClRIC ffiOJECT Watana iJld /elil Canj{)ll CUllJlative a1d Jlnnual Cash Flow JANl.lllRy 1982 oo...LJlRS -IN MILLIOOS ANNlJllL CAS,.rFlUJ ----U..MIATIVCCASH F[(l'J (meriT (F YEJlR) YEM WArANA [EVIL CANYOO UMlINED -WATANA [£VILtJlJ'iWOO-----COOINED 1981 82 83 84 85 ffi 87 88 89 !Xl 91 92 93 94 95 % 97 98 99 2Ol) 2001 2002 mTAI... 27.6 12.9 2B.7 48.5 199.5 2B3.9 295.4 369.0 4l3.4 627.6 600.8 429.0 153.2 73.7 35%.2 4.9 47.9 68.6 64.3 64.9 115.3 201.3 291.8 279.7 241.7 156.0 17.6 1554.0 27.6 12.9 2B.7 48.5 199.5 283.9 295.4 369.0 4l3.4 627.6 613.7 476.9 221.8 1l3.0 64.9 115.3 201.3 291.8 279.7 241.7 156.0 17.6 5150.2 27.6 40.4 69.2 117.7 317.2 601.1 8%.5 1265.5 1703.9 2331.5 2940.3 3369.3 3522.5 35%.2 4.9 52.8 121.4 185.7 250.6 365.9 567.2 854.0 11l3.7 ll3O.4 1536.4 1554.0 27.6 40.5 69.2 117.7 317.2 601.1 8%.5 1265.5 1703.9 2331.5 2945.2 3422.1 3643.9 3781.9 l346.8 3962.1 4163.4 4455.2 4734.9 4976.6 5132.6 5150.2 TABLE 0.8:ftNCl-mA(;E FAIRBAN<S INTERTIE PROJECT COST ESTIW\TE Total Line 175.1 miles Total Slbstation Cost Slbtotal R/W kquisition ($40.00/Mile) MDilization -furdJilization 5% Surveying Engineering 6% Construction Ma1agBTErtt 5% Slbtotal Contingencies 25% Tot a1 Sept.1981 \))11 ars Infl ation @ 10%hear - 2 )ears TOTAL COST (Thousands of tb 11 ars ) 56,556 9,449 66,005 6,784 3,DJ 3,100 3,960 3,lXl 86,449 21,612 100,a>1 13),754 ~urce:Canron\Ealth Associates,January 1982 -TABLE 0.9: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: DESCR I PTI ON WATANA DEVIL CANYON $955,723,000 77,712,000 $1,033,435,000 170,688,000 $1,204,123,000 184,177 ,000 $1,388,300,000 115,000,000 Not Included $1,503,300,000 $2,§14,940,OOO 362,681,000 $3,271,621,000 503,979,000 $3,781,600,000 280,000,000 Not Included $4,061,600,000 $2,502,053,000 411,774,000 1,113,000 Hydraulic Production Plant Transmission Plant General Pl ant Total Direct Construction Cost Indirect Construction Cost Subtotal for Contingency Conttngency Total Specific Construction Cost Professional Services Cl i ent Cost s Total Project Cost ,~ ,.... I 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 10 6 Total Project (Rev.4)5,565 x 10 6 Adjustment for Revision 5 -79 x 10 6 Adjustment Total Project $5,486 x 10 6 NOTE:Adjustments were given by EBASCO in meeting in New York on April 14,1982. ~i.l~!~~~~!~:~~1~~~:i2~.~~1~~:~1~~l~~~:~j~J,%:~~~~~;i~~!tjJ£~:i~~!~J~f~~j:l.£:~£~f.£~ij:Ji;Ai:£~::::::::::::::::::::::::1~;i~t~ii::: 19~5 I 'Je 6 19 e1 1~8~19 E9 1~9(19q1 1<;92 1993 1~S4 OSh flO!,)U/lM~R't ===I~/lILllr.~I====n f-1r-r "::iY .,I-,'1 0 e c 0 c c c C 2C;5?2 9 ~7i21'::hl P"IC>IIILlS o.oc a.oc o.co ('1100 C.C C C•CC c.CC ~.CC II 9 •~~!~~:~i46~"FLAT IC~p,)r¥126.12 13~e5,)145.ee 155.24 Ht .1e 11.7.B I<;C.11 2C3.4E 217.1? "?)?IC~-"llL<0.00 {J.1C 0.00 c.co c.ee e.ce e.ec e.ce ,tC.3C 29f."1 -----I~C-~------------------'-\1 J 1 ::V i='JIJ(c.e c.e C.O G.O C.C C• C c.c e.c H".t U,.1 17 1 Lc~S 'll'r:"~T I '.;C (I]S T5 C.O o.c a.c 0.0 c.C c.c c.c C.C 22.t 24 •,---------------------------------------...------..-------------------------------.... i 17 !?.:1'\!\T I ~.I ~p,('-'"c C.O C.O e.o C.O c.C C•c e.c c.c 1H.e f ~1 •~..,1 I,\r ,-IrlT~R"ST E.~rY r n IJ~Fur'ie 5 e.c a.c e.c e.a e.C c.c c.c C.C c.e 4 •t-"'j ~oj l"r,j'IT',REST [IJ 5 HC,~T TUli"J1.51 e.G e.e C.O 0.0 c.e c •C a.c C.C c •C 12 .1C.L,) ~0 I l ,:S S 1"1 T,-R r S T ~'-~l r:t,G TERM (;[8T C.'J e.e o.a 0.(;c.e e•c e.c C.C 1~t.e 7c;~.~---------------- ---------------- -------- ..._-----.--------...._--------------...._------~1 ~:I ~T :":,\'--',r\r \:(5 f P IJ'"lprR S t1 0 n e.c C.0 a.o e.c C.C C.C c.e e.e I:'+..~ -----C~SH 50tlR CE AND USl---- lj 4·1 CASH IrJCC~F.F"C !',nr ~r.5 01'10 c.e Q.iJ c.a e.g c.c c.e a.e e.c ~4.5 .'..4 to.';1/11 C CL't<T~1,~I)Tlr'J o.c c.e C.(1 C.O e•e.e 'J.e e.e c.e e.c 1;J L'lr:c ER~1 ~E;~T O'/\·,H1Chl ,,"S '.C2.G 4 ;"!5.1 ~11 •~706.7 932.1 141~.2 I ~,t.<;1579.2 6 ~"3 I!I 1 1H.~,~'":',!J'1C ~p t -=-eT ';r.t,\.l:C'..l f\~e.e C•e C.O C.O e.e c.e e.c C.C 126.3 1 ~•~---------------------------------------------------------------------------------,4'T~Tll j""U':'(S ;r r:1Jf-:::')-102.0 42~.1 51 1 .1 106.1 "32.7 1413.2 159t.<;151'1.2 1E C.C 2 t:l6 •'3 ';0)LeSS (t,PIT\l LXi'cf\,)ITUP[402.0 4 ?=.1 51 1• J 7C6.1 c;3i.7 141~.<1596.S 151<;.2 f ~~.1 ,rI .7 '.~1 u:S s 'firJRr:~r .\,;C r l~qC s e.e c.c I).I)C.O t.O ,C.e e•C c.e I Z6.3 1 ~•~_~,~a LeSS DE ET R["~Y''':'HS 0.1)C.C J.(1 1J.t-c.e e.e Gee e.c C•e 2 S •3 ~J-'l L(~S P~Y'~::"1 1":I;TAT'e.e G.e O.G a.o C.C C.C C.e e.c e •c C•(----------------------------------------------......._-------------- ----------------II,1 r:,\S H S ljR I)lIJS (G-:F rei T I C.G c.e C.O O.n Cee c.e O.C G.e e.c c •C~4')~HCI'T T r.:9.~~0-9T ~.C C.C ~"'O 0.0 e.c e.e (I.e c.e c.e c.e ;It 4 r:ASH PECCV"P.O (1.G e.c c.r C.O c.e C.C e.e a.c e.e e •c -----;~"lA'ICL SH'"T ----------~2 )r(~sc,,''/[I\:~c C.:,\T.r U':~:s.c c.e ,~.1 C.O C.C C•C r.c C.G 46.(4 S •"371 JTI-'~,~II Cr,X I ~J ~CA~IT~L C.0 e •c C.O 0",0 C•e c.e e •C e.c cc ~~r;2,,~ ",';4 CASII SUR?lIJS P:cT~I'I~J G.a c.e c.n 0.0 C.r.e.c o.c e.c c.e C•C37Jc.u~.C~"lf~L ."\/?,;:t:'J 1 Tll p;-'.f)2 .0 EZ1 • 1 133>3.4 2C45.0 2'17/.1 4391.C SSE7.E 1~n .C EnC.7 Hzt.4 ==::::::======::::;:;-::.;;::::==========-===-=========:;;;;:::;====;:-::=::;::===-====:::-;;c================.;=.::::;= 'L C)1 CI"IT~L r ~n l 'y'-r;4e2.C f??•I 1~J~.4 2e45.0 ,,'171.7 4 3S 1.C 5<;e7.p 151:1.C E~'d.e E~f:;.S =:::;::::-==::::;;:::;;=====::;;;::;;;;;======:.:;;:::====::::;:::::=======::.:::::::=====::::;::;:.::::::::::::=z::====-============:-:::: 4t 1 '~T ~F C'~:'"T 'I:I,T I'!:,e ..c C.C c.r;c.e e.c C•C e.e e.c C•r c ..C'.i,2 'fTAIl!r::~,i p~:1 i\C')C.O C.C e.c a.oJ e.c c.C c.C C.C c.e ~4 ,~ ~):J ))LeT 01)T S T fJ.:_l I ~:c -r;HC ~T T t ~.I~e.o c •c e.o O.C CaO C.C c.r C.C 1 ~.~..~H l.~ :34 'J L ~f U:.JT 5T .,:..:!':(;-L'lr<G Tell i·1 '~C2.C f 27.1 lJ:~~.4 2C45.[;2"1/.7 43"I.C sse 1.f Et7.c tZiC,1 E ~n.s ;~2 AI,NuAl G e r IJ,)A~r.lIJC~N 11 "B2 J 17.2 313.5 352 ..4 455.2 5 t 1 ..5 7 ~:;•1 8}";.1 71b.C ;(C.2·7 c •~ 3'.3 CUI~.0 e r <)',(AWli[)(WrJ f I ~~2 317.2 63C.1 "8 J • 1 IOt.3 1 ';~S"•E 2H~.e 3634.6 4410.1 47IC.<;~7Et.1<;1'7 DEeT SEll Ie l CCV',R 0.00 a.aa o.ee 0.00 c.ee e.ee e.cc c.cc I.eC 1.C3 CONTRIBUTION SCENARIO AND 10%INTEREST NO STATE 7%INFLATION SHEET OF 6 TABLE 0,10 '.j ]1 1 ]1 ~I --)1 ]-~I -1 1 1 **~l~*~*~***~*¢**~*~¢**~*~**~*******;**~*******~**~****~****~**;*****¢~********~~~~**~~~~~t~***~~~*~~*~***~~*~~**~~~~;~¢~;C~~*~~DATAIlK.CI?W'TA~A leN ll~[i9131-NO STAT~FU~cS-I~Fl'TICN 7:-INTEREST 10~-CAPCCST 15.15 ~~24-Jl~-e3 *¢**~?*=*o*(:~*¢**:~*t*:~***~*~¢*;)*~***~**~******o*~~»****¢~**~**t~Qt**.o****~**~~~~*~*~~4~~~~*9~~;~.~~*.~.~~~~~~~~~~~~~~.~~.~~*(~ 1995 1996 1991 1998 1999 2CCC 20CI 2CC2 2CC!2C[4 CAS~Flew SU~~ARY ===I$~ILLIO~I==== 73 E~~~GY GWH 3005 3019 3026 3055 3C57 3Ct4 31C5 4555 .t7C 'lEt ~21 ~~'L P~ICE-~!LLS 118.3R l1C.59 IC3.51 96.15 ~C.45 64.fC 78.tt 85.99 81.t2 74.~E 466 !NFL'TIC~I~)CX 249.~3 266.73 285.40 3c~.!a 32t.75 349.t2 374.IC 4CC.29 42E.31 45E.29 "20 ~~!CC-~llLS 2~5.1~294.Q7 295.43 294.22 295.54 296.41 294.25 344.22 349.5~;43.17 - - - - - I ric ",v --- --- - - - - - - - - --- ·i I:.'H v f!JU r ."<J t • 7 8 q C• 5 I~9',•5 29 S •a 9 C3 .4 9 C8 .3 IH 1 •6 I 5 I:7•8 It ~2.4 1642.3 170 LE~S ~rEMATI~G CJ5TS 25.q 27.7 29.7 11.B 34.C 31:.4 3 Q .G 6C.e t~.1 tG.7---------------------------------------------.------------------------.--------- ~1?CJi",FHI J~!~cr:~-c',',r 'l6~.8 86~.7 aq.a E57.0 eg.4 e71.9 P.74."I 15C6.<;1~f7.3 157~.~Ll,Ace INr~R~~T EA ~cC C~FU~C.4.9 ~.3 _.6 1:.0 6.~I:.g 1.4 7.g 12.4 I ••i '50 L~5S INT~A~5r ON 5HCRT T~RH CEBT 14.2 14.1:15.J 15.5 1~.9 It.5 17.C 17.7 2".9 'C.5 )]1 L~5S INT~P:ST C~LC~G TfRM :EBT 792.4 7~g.Z 785.6 7!1.7 777.4 772.7 761.5 13;1.1 l~ql.S I:F2.f------------------------ ---------------- ----------------------------------------.,~J :J [T =:,Cd.1.\CS F ~:;H 1)P C;7,S ~9 • 2 6 4 •3 (,9 •3 7 5 •9 e2 • 5 e9 • 1 9 7 •5 I C I:•1 I ~e•8 1 72 • 1 -----C\SJi :;::UflC[Arw US[---- ·~l C5~HINcnMF FRn~~rEqs 59.2 (4.3 69.8 75.q eZ.5 E9.1 97.~IC6.1 I~@.P.112.7 ~4~STIT~CO~TRlnUTI~N 0.0·c.c 0.0 0.0 c.c c.C c.c c.e c.c c.c I',)v;r,G rrR'1 CEBT DP,AWOI),,~S 2C6.2 372.6 676.,8 ICHol Ilg~.C 124(.1 lIC7..7 70.5 C.c c.c ~"t::;'J']:';,C,'\P or::eT r~~\Al':'H::a~~'f.O 4.4 4.0 -4.9 ....2 5.1 6.1 l12.S l-S.r:!le.s--------------------------------------------------~---~------------------------- J~)TOTJL s~u,crs OF F~~C~261.4 ~41.2 751.3 11~I.q 1277.8 1335.~12Ct.4 289.5 174.t IE3.7 120 L~SS CAPITAL lX?~~DITU~(!J3.1 loCI.]7C1.6 IC94.0 1225.2 1277.8 1143.C 113.6 tt.2 70.S "~il L [SS UJ 1 CAr AIHl F 1m e S 4 • 0 4 .4 4 •~4 •9 5 • 2 5 • 1 6.I I I 2 .9 I ';•B I C•9260l.cSS Dcel ,\UAyvC!:TS 32.3 35.5 3<).1 43.0 4"1.3 ~2.(57.2 1:2.9 ~2.•"I 1(1.9 11'i LESS P1Y~[NT Tr ~1\T~0.0 o.CQ.O C.O c.c C.C o.c C.C C.C C.C-----------~--------------------------------------------------------------------141 CASH suqrLUSlr.rFICITI c.e 0.0 1).0 0.0 c.O O.C C.c 0.0 c.c c.C ~4~SHeRT Tr-Q~DfET c.n C.C C.O D.O C.O C.O o.c C.C C.C C.C ~44 CASH RFC0vrR~r 0.0 o.c 0.0 C.D C.C C.C c.c C.c C.C C.C•-----~AlA~(f SH~~T----------, ~2~~I:'S[~VF ,\,;C C1NT."urll)5;:.6 '56.3 60.3 64.5 t9.C 73.e 7g.C 123.5 1~2.2 141.4 371 ~THCR WCRKING CAPITAL 92.9 lJ.i ;4.3 Q5.C 95.7 9t.t 'l7.!11:5.9 113.1 174.7 454 C~Sil SURPLUS REHPIED C.C C.C :J.C 0.0 C.C C.C C.C o.e [.C C.C 17U CU~.CAPITIL EXPENDITUPE a65S.~GC56.8 S1b4.4 118~~.4 12C83.6 13361.5 14~C4.5 14tl!.1 146f<.3 147~~.1 =======~~~~=~;=;:==:=====================:=~::=;================================ ~~5 (~rITAL [~PLC'EO 3101.C 52C6.7 991!.q IICI7.2 12242.3 13531.E 14t81.C 149Cl.6 14SE~.5 I~Cll.]=======;=;~;:=============~==============~~=:;~========================= ======== 461 ST.\TE cr,riTflLLJTlJII ~.Cl C.C~.O C.O C.C C.C C.C O.C C.C c.e 4&2 R~TAIN[J [ARNI~Gj 11).6 117.9 241.8 323.7 4Ct.Z 4g~.5 59].4 iSS.!558.4 lC31.1 j5~DEBT OUTSTA~UING-SHCRT TER~145~5 149.S 154.5 159.4 It4.7 17C.4 17t.5 2E9.4 3C5.2 316.2 534 ~[BT GUTSTA~01~G-L~NG T~R~8541.8 8873.~g516.6 la~34.7 11677.4 12865.6 13~II.C 13918.6 1]~25.q 1~124.C 142 AN~GAL OEer JkA~~DC~~S19U2 C2.7 139.1 237.1 347.4 364.2 354.7 294.7 11.6 C.C ~.c ~43 CU~.D~eT JRAWWnOWN t19~2 4969.4 5C09.1 5246.2 5593.7 5951.81:]12.5 66C7.3 6624.9 t62~.q ft24.5 'il')'):on Sr::WlCE cr'l"P.I.C3 1.03 1.04 I.C4 1.C4 I.C5 I.O~l.e3 I.C~l.e5 NO STATE CONTRIBUTION SCENARIO 7%INFLATION 10%INTEREST SHEET 2 OF 6 TABLE D.10 **¢**~*******4*¢*****~*e¢**4*¢**~;**~*~~****~t~*~~~*~*~~~~~~~*~t~¢*~~.*~¢OO**~*~~~~~~~O*~~~*¢*~*~CO¢**~*¢~*~¢*~*~~~¢#~o~~~~~e;~DATAl?K.DIZ WSTINA ION ll~'r IQQ31-NU STATE FU~CS-I~FlATIC~7Z-I~TEREST 10l-CAPCCST S5.15 ~~24-Jl~-83 *~***~***************~**¢¢*~¢~***~****~o*~:~¢¢*.*.***~**~*»**~¢¢~~~~60**~~~*~*t~t~~*~~~~~~~~e¢¢~¢*~$~~¢*~~~*~;;.~,~;~~~o~¢~~*»~¢ 20C7 2cea 2(eS CASh flOW SU~~4RY =~=I$~llll~~I==== 5224 53~4 ~~44 57.11 52.15 ~7.70561.42 ~CC.72 642.17 320.t2 31~.10 3C6.62 21t..(]23f:..1 2r:4.4 22?8 C.C 0.0 t:.C (l.n 12.5 D.4 n I ~"~I(O'H 321 ~AL P>'I[[-~II l~ H"I flH 10'\H:;i~)( ~J")ry IC:-WJLL~ -----INC~H~----------------~1!)~r:V[;HI~· 17 ,)L ':S 5 r;r ~?,~T I'!C C C'~T $ I 7 J r"AT 1 iJ G "C "!/C1'.t.C I'TCfl:;T E,~n!':"D C~FUNeS :,)L L 1 TiTER ST C~,~,"CRT TERIA CEBT 91'l S~I~H:::i\Sf 'J"lnr.;G TER.'1 DE'!T i 4 1 ·i i~T .(:.I~1\II\J G5 f I'J ~r:P f R J ---[SH ~OURC[ANO US[---- =~SH I C~M(FrOM orER~ ~4 Al-U~Tql~UT1GN 14 ~c T R~OE~T ~~A~~C~~S ~~~CAD C~BT DPA~nCLJ'~ ;~)HT ~L s"u-~er~,!f flye ~ I C L So:LIP IT.~l [)to rw ITURE ",L S S I,',!q CAP ,~h D I)1'1 CS ~a l SS DEET REPAY~NTS 3 'j l :;S p ~Y!\[I;r T IJ T 1\T' \~I ~ASH su~r~~S~Ctf:FIC1TI"~),HeRT T~R,.DeE 44~CAS~R~COVER~D 20C5 4 '1C 2 ~J ~•73/,~~.37 ]17.C3 1,)52 ..C 1 ~•c: 1577.5 1 ~• 1 3 I •"1372." 1 G7.6 1 ~7.6c.o cilia 11.~ 1 -;':J •1 7 ,•? 1 1 •1 11201c.o -8:3 c.n ,20C6 SCt4 62.~9524.69 32!'!.42 1663.C 7~.e 15g~.2 1 J •1 32.E 13~1.2 2 C 4.4 ~101 12 .5 123.4 0.0 8:E 0.0 1674.8e5.3 1529.5 16 •.! 341l1C 1348.2 222.8 eS.7 11.4 13 5.7c.a C.3-G413 0.0 168607 9 I .3 I 5 <;•I, 1 .3 "3 .4 131 .3 2',2.1 24201 C.Oc.o 14.2 2~6.3 92.8 14.2 14 9.3 C.O 8·0.0 S.C 16<;~.~ ';7.7 16(2.112.5 3 ~•e132C.4 2t3e5 263.5 C.C (.C 15.2 2 7E.1 ';~.3 15.2164.2 C.C t:E c.o 2C 1 C 51C4 4'6S6B1:77 ~GC .4E 1713.S 1e 4 .5 16C9.31S• E 38 .3 13C3 .~-------- 2E6.~ 286.9 C.C C.C H .4 3n .~ 1 C6.3 1 t •4 He .t C.C E:to.c 20 11 5062 40.02B5.';I 2'i4.<;4 112f.B Ill.S ltlLC 21.2 39.91285.9 312.4 317..4 C.( C.G 17.~ 32~.e 113.1 1~~:; o.c R:6c.c 2GI2 '::t::23 3 t.7'1787.42 28';.72 1744.S I 1'1.7 lU5.2 22.7 41 .7 12tt.C-------- 34C.2 34C.2o.cc.c 1E• 7 3~e.B 121 .7 lE.l218•~ o.c 8:8c.c 2C 13 6 1 4 e 34.C2 ~42.54 2et.U 17t 2.( 12?•I 1634.C 2 ~•3 43.6 1244.2 3H .~ 31C.5 C• (c.e 2C.C 3';C.5 13C.2 2C.C24(.4 c.c E:E e.c 2C14 t 317 31.27 'i C .52 '~I.E6 17 P C.4 137.C 164 .4 2 • ( if •~ 122 •I H3.7 ~r.3.1c.cc.cn.4-----_..- 425.1 1 ~9 •~ 21.4264,4 C• C 8:f C.C 22, 371 45', HO -----'IAL,HJ(L <;lk~T---------,. ~[S~~V~A~C CGMT.FLhD )THE~WC~Kl~G CAPIT~l C~SH SURPL'jS p.rrAJl,::D (U~.(APIT~L lXPLNJITLRl 15 1.3 176.4 C.O 14.130.9 161.9 PBd C.C 14'i ll.~ 11]4l Z Ig0.3 0.0 14<;',8.7 1e~.4 112 .4 0.0 15CH.S 19E.3 184.7 C.C 151';(.B 212.2 187.2 C• C 15297.C 227.1 IB'i.eo.c 1541C.7 243.( 1';2.tc.c 15532.4 2 tC.C 1';5.5c.c 156f2.t 21~412. 1i12eE C 4 C I~BCI.'; 4u~CAPITAL E~Pl~YED ==~=====~====:==~=~====================~========~=======~~~==========~====:=~=:= 15153.5 l~c5<.1 153:2.2 15459.2 1551~.8 156<;t.4 15<21.6 15Sf1.<;lfll".1 If27:.e ==~~~~==================~=====;=============.=========:========================~ It 1 .i :Tf CG(':T ~I '-3 ,~'TI :'l r' 4 2 ~TAINEO C~F~I~~<; ~~~ET OUTSTA~1ING-iHCPT TERP 5 4 ~ET 1UT~T~~'ING-L~NG lCRH ~4?t'JNIJ.1L O"eT "PAI,j'"CC\;N fl932 '4J eu....(eET CPA\/'"Jr"N llq32 ;I~1~rT SfRVICE CCV~P G.O 121".1 32·;.Q 136l1.8 c.O 6024.'1 1.05 c.c 14~3.1 ~~G• 5 110~.5 C.C 6624.9 1.05 G.O 1t4'.9 35~.S 13JS2.8 G.O 66 7 4.9 1.06 G.O lE~109 367.3 13203.5 0.0 6t2~.9 1.06 c.C 21~1.4 1e3.C 1303<;.4 c.c 6624.'1 1.01 C.C 243a.3 399.4 128~e.e C.C 662~.9 1.C7 c.C, 21"(.6 4 If.•9 1261:0.I c.r 6624.'1 1.C e C.C ~C<;O.8 4 ~5.5 12441.6 C~C 6624.9 ] • C8 c.r"4£1.4 4 ~5 •~ 122C1.2 c.c 6624.9 I.C9 c ..c ~~~• 1 7t.<; 113t.e C.C U24.SI.C'; NO ST ATE CONTRIBUTION SCENARIO 7%INFLATION 10%INTEREST SHEET 3 OF 6 TABLE D.10 ~,,,i 1 ]-")~-1 -]-J 1 I J -I ""~I -1 .~ l)***¢*~******~***~~*;)*C*¢**~*¢**~~~O**~~*****O~~~~~*~*~¢¢o~t*¢~***~*~~*~***¢**~¢~~**~~tO~~t***~O~**~6~4*~~¢*O**~~~~~~O~c~~~~~e~8ATAl~K.CI2 ~~T~~A ION LI~L 1993J-~~Sl~T[r-LNCS-I~r-lATIC~l~-I~TE~fST 10~-CAFC(ST $~.15 e~24-JL~-8~**~*O~*~******¢**~**~*~*¢**C*:~,~**~q~*¢*¢~~t**¢~~¢t~~~***¢**~*¢¢~*~~~*~~*¢**~**O~~4**~~~4~~~~**~q~*~~4*O~O~~*~~*~~~¢~~~¢~~4~*¢*~¢ 2e15 2C16 2011 2013 2019 2e2e 2021 TCTAL C~Sh FlC~SU~~ARY ===($~llll~~J==== 73 '~::!l~Y :;'~:i 6449 Ulb b1Ce 6160 01'5 t\ge4 6'184 1448e2~ZI EAl p~ICE-rlll~~1.94 26.61 74.8~2~.38 21.18 2C.3~19.29 C.OO 4 b·~NFL ATIC'.It'J U,9 "4 .6 )1 0)2.1 5 11 C4 .4 'lIte I•71 1 2 6 ~.4 3 Ll 5 2 •<;~1 4 4 1•6 4 C•ee ~~o "ILE-~Ill~21g.14 ?15.~8 214.86 ~16.]1 27~.44 215.e<;219.~1 o.cc -----IN(C~-----------------~1~~EV[~U,llCC.l lE21.1 le4~.b lE61.7 13S3.5 1921.1 195C.6 429~2.6 171 less 'w ""<\l I,C c..;I :;1 46.6 1 ,/;•<;I 'J 1 •9 119 •6 1 S 2 •2 2 C 5 .6 22 C• C 216 ~•5------------------------------------------------ ----------------Si?l~,,?,.T!!,~l~f(~I':L"."_~1!>5~.4 1664.2 1615.7 1688.i l1Cl.~171~.4 1130.~40,,1.1!t ..J C I ,1.:R ".!:A,·."IJ "~r UIII.,2 I •IJ 2 <;•B ~1 •!I 34 •~E ••_'>•C 4 1.I ~16 •1 'j '.,')1I:~S P l H R ,S Tell :;t-!C f',T TE R11 ;:eT 4 1.1 S C•C 52 .4 'j 5 •1 51.9 6 a .9 /;4 •1 <;6 5 •<; \11 l~SS I~T~PE~T ~~lC~G TE~"0 eT 1193.1 1164./;1132.6 le91.4 lC5f.l lC16.1 969.3 318t3.1----------~--------~---------------------------- ----------------';4,~I:T ur "'P,(:'fWl~''Jp;:u 0<;.<;479.4 522.6 56<;.7 621.2 611.~133.9 1914 •• -----C\Sy SUURCf ANO USE---- ~4S :a~H I~~~M~Frrt'~or~r~43'1.<;471.4 'j2~.6 569.1 621.2 617.:139.'1 1914.Z '•.~~,L\T -Cu.'H " I '1'"I 'PJ O.I)C• C ,• 0 0 • 0 C• C C•"e • c C•C 1"3 lCr--G H~f'\0[8T D~t.4Sr:';~5 c.e C.C 0.0 c.O e.c C.C c.c 14311.1~'t~~.,"J P C.1P DrOT DP.A·~:jr:,H\5 2?9 ,~4.5 zt:.?28.1 3C.C 12.1 3~.'t 1:15.2-------- -------- ---------------- -------------~---------- --------;,,';T.JT~l S'JU'l[.·~S Jr Fljt';S 462.1 ~c;.g ~',C.D 5<;1.3 ,~51.2 1C<;.t 113.3 22<;(t.5 'ZU l"SS CAPITAL CXPE~OITUPE 149.0 15S.5 11e.t lE2.~19~.4 2CS.C 223.1 l1C<;I.t HI Lr:~5 '..-JRCAP !It,C FL)';CS n.9 24.5 (f..?Z£.1 3C.0 3 •.1 34.4 05.2,~u C l:,S S DO:UT Ri.:!'AY'1 P;TS 2 ';C•r;j 19 •<;3 J I •<)381 • 1 42 5 •S 46 E .4 51 5.3 5 1 3 <;•1 315 l[3~PAY~=~T Te ~TAT~C.O C.C c.o o.n c.o c.e c.C C.C---------------------------~----~----------------------- --------141 CA5H S~RDl~S(CErICITI C.O C.C o.n 0.0 O.C O.C c.O C.O~41 :,11':"T l[RI~D":nT C.O c.e 0.,1 C.O c.e c.e c.c C.C 444 CA5H RECQVER~D ~.1 C.C C.O D.O C.C e.e c.c 0.0 -----BAl~NCE SH~'l---------- 22:R[S~FVC ANC C0~T.rl~~2~1.6 Jle.5 3~C.3 364.6 3SC.2 411.~446.7 446.1 171 Jf~~~WC~YI~(CA~IT'l ~C2.2 ~C5.e lCG.!214.C ?1?5 223.3 223.5 229.54'A r.\:'H $LJ ~P llJ 5 r,[T A ./[<)r.•c e •Co.0 0 • 0 c •n C•eo.C C• C J70 c~r.CAPITAL rX~E~OITLJR~15~50.9 1611C.4 16.Bl.0 16463.t It65E.<;ItE67.S 11[91.t l1C<;I.6=========================================~===================;:; 4~~C4rlThl r~Dl1YEO 16450.1 16634.1 16131.)17C42.2 11261.t 115CE.E I11t6.2 11166.8 ===~~~~========= =====================:==========;=~=~==~=:=~~=~= OJ 5T11':C,]"T?I<:t;TIUJ G.O C.O r;.(1 c.o c.r;e.c c.c o.c~2 ~ET~IMrc [~PNI~G~43C5.n 4714.4 5306.9 5816.6 64S1.8 7115.3 7914..7~14.' ~,JdT OUT5TA~:JIt.G-SI1C!n TLRI'4'jS.9 ~?4.3 350.6 5Te.7 6Cf.l 64c.e 05.2 t15.2 34 J[8T UUTSTANOING-l\;NG TEAM 11645.9 11326.C lC114.1 10506.9 10161.1 S692.1 9111.4 9111.4 ~2 ~~NJ~L C Bf ~~Aw~~[WN t19~2 0.0 S.D Q.O e.o c.e o.c O.C 6624.9 "3 CUM.IJ eT ~RAW~.C~N 11g32 6624.1 6t24.9 6624.9 66!4.9 6624.9 6624.9 6624.9 6624.9 I')·J~eT 5.,::1.ICE Cr:V'R 1.10 loll 1.11 1.12 1.13 1.14 1.15 c.oo NO ST ATE CONTRIBUTION SCENARIO 7%INFLATION 10%INTEREST SHEET 4 OF 6 TABLE D.10 ANNUAL PROJECT COSTS Mi 11 s/kWh Cost in Nominal $1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Operatin9 Expenses 8 11 12 12 13 13 14 15 15 15 Capital Renewals 0 8 9 10 10 11 12 12 13 9 Debt Service Cost 252 279 274 273 272 270 270 269 266 320 Total 260 298 295 295 295 294 296 296 294 344 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Operatin9 Expenses 17 18 19 19 20 20 21 22 22 23 Capital Renewals 14 15 15 16 17 17 18 19 19 20 Debt Service Cost 318 310 303 293 284 276 268 259 253 247 Total 349 343 337 328 321 313 307 300 295 290 2013 2014 2015 2016 2017 2018 2019 2020 2021 Operating Expenses 24 25 26 27 28 30 31 33 35 Capital Renewals 21 22 23 24 25 27 28 30 32 Debt Service Cost 242 235 230 224 222 219 216 212 212 Total 287 282 279 275 275 276 275 275 279 NO STATE CONTRIBUTION SCENARIO 7%INFLATION 10%INTEREST SHEET 5 OF 6 TABLE 0.10 '1 'I j 'i i 1-···~1 J j 1 J ]1.-,J 1 1 1 ANNUAL PROJECT COSTS Mills/kWh Cost in Real $1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Operating Expenses 4 5 5 5 5 4 4 4 4 4 Capital Renewals 0 4 4 4 4 4 4 4 3 2 Debt Service Cost 116 119 109 102 95 88 82 77 72 80 Total 120 128 118 111 104 96 90 85 79 86 2003 2004 2005 2006 2007 IQQJ!2009 2010 2011 2012 Operat ing Expenses 4 4 4 4 4 3 3 3 3 3 Capita I Renewals 3 3 3 3 3 3 3 3 3 3 Debt Service Cost 75 68 62 56 50 46 42 38 34 31 Total 82 75 69 63 57 52 48 44 40 37 2013 2014 2015 2016 2017 2018 2019 2020 2021 Operating Expenses 3 3 3 3 3 2 2 2 2 Capital Renewals 3 2 2 2 2 2 2 2 2 Debt Service Cost 28 26 24 22 20 19 18 16 15 Total 34 31 29 27 25 23 22 20 19 NO STATE CONTRIBUTION SCENARIO 7%INFLATION 10%INTEREST SHEET 6 OF 6 TABLE 0.10 TABLE 0.11:SUSITNA OOST a::ITh£R First Full Year of Watana &[evil Ccl1}Un -2003 $15 Per Net Kilowatt 1982 $iS 1.2. 3. Total Plant Investment Inc.I.D.C (RL.M70 T 466) I.Fixed Chanres (a)Cost 5f M?r!ey (b)l:a>rec 1 atlOn (llJX 50 yr S.F.) (c)Insurance (d)Taxes Federal Incare Federal Mi see 11 aneous State &Local Percent10.00 .09.10.00 0.00 0.00 0.00 ~ 2116 215.62 II.Fixed Q;lerating Costs (a)(JJeration &Maintenance Including Administrative CIld General Expense (RLl71 divided by 466)9.38 Total Jlllnual Capocity Costs 225.00 flbtes:(1)RL =Reference Line on far left of printout on Tcble 0.10. ,~ TABLE 0.12:FORECAST FINANCIAL PARAMETERS r I - - Project Completion -Year Energy Level -1994-2002 . -2020 Costs in January 1982 Dollars Capital Costs Operating Costs -per annum Provision for CapitalRenewals-per.annum(0.3 percent of Capital Costs) Operating Working Capital Reserve and Contingency Fund Interest Rate Debt Repayment Period Infl ation Rate Devi 1WatanaCanyon Total 1993 2002 2,957 GWh 4.555 II 6,934 II 3,596.2 1,554.0 5,150.2 ~i 11 ion ~i 11 ion ~i 11 ion10.4 4.8 15.20 mi 11 ion m"il 1ion million $10.79 $4.66 $15.45 15 percent of Operating Costs 10 percent of Revenue iOO percent of OperQting Costs00percentofProvlslonforCapitalRenewals 10 percent per annum 35 years 7 percent per annum T.&BLE 0.13:TOTAL c:ENERATING CflPflCITf WITl1IN THE RAILBELT SYSTEM-1982 Jlbbrevi at i ons M..P CEA GVtA FMJS rvEA f-EA SES ,npJld U of A TOTAL Railbelt Utility /lnchorage M.Jnicipal Light &PO\l€r Cepartrrent O1uga:h Electric Associ ation GJldEJ1 Valley Electric Associatioo Fairbanks M.Jnicipal Utility Systen MatiJluska El ectric As soc i ati 01 J-brer Electric Association Seward El ectric Systan Alaska PO\I€r fldninistration Lhiversityof Alaska Installed Capacity! 311.6 463.5 221.6 68.5 0.9 2.6 5.5 3).0 18.6 1l22.8~ ~, (12)Installed c~a:ity as of 1982 at O·F ()ExclLdes Natiooal MEJ1se installed capacity of 101.3 MfJ """" TABLE 0.14 (Sheet 1 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION -Nameplate Generating Prime Fuel Capacity Capacity Heat Rate Pl ant/Unit Mover Type Date (MW)@ O°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/O 1962 14.0 16.3 14,000 Unit #2 SCCT NG/O 1964 14.0 16.3 14,000 Unit #3 SCCT NG/O 1968 18.0 18.0 14,000 Unit #4 SCCT NG/O 1972 28.5 32.0 12,500 Diesel 1(c)0 0 1962 1.1 1.1 10,500 Diesel 2(c)0 0 1962 1.1 1.1 10,500r- 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/O 1982 73.6 90.0 12,500 Chugach Electric Association -.Bel uga 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 Namepl ate Generating Prime Fuel Capacity Capacity Heat Rate Pl anti Un it Mover Type Date (MW)@ O°F (MW)(Btu/kWh),~ Chugach 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 Un it #3 ST NG 1957 3.0 3.0 Unit #4 ST NG 1957 3.0 3.0 Unit #5 5T 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 I~-~-\ Unit #1 0 0 1952 0.3 0.3 15,000 Un it #2 0 0 1964 0.6 0.6 15,000 Unit #3 0 0 1970 0.6 0.6 15,000 F!C'--\ TABLE 0.14 (Sheet 4 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION Namepl ate Generating Prime Fuel Capacity Capacity Heat Rate Pl anti Un it Mover Type Date (MW)@ O°F (MW)(Btu/kWh)"n University of Alaska -Fairbanks Sl ST Coal 1.50 1.50 12,000 S2 ST Coal 1980 1.50 1.50 12,000 S3 ST Coal 10.0 10.0 12,000 01 0 0 2.8 2.8 10,500 02 D 0 2.8 2.8 20,500 Fairbanks I~unicipal Utilities System Chena 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 °1963 5.3 7.0 15,000 rc::"'-, Unit #5 ST Coal 1970 21.0 21.0 13,320 Unit #6 SCCT °1976 23.1 28.8 15,000 Diesel #1 D °1967 2.8 2.8 12,150 T'"'''' Diesel #2 D °1968 2.8 2.8 12,150 Diesel #3 0 °1968 2.8 2.8 12,150 p-= Military Install ations -Fairbanks Eielson AFB Sl,S2 ST °1953 2.50 S3,S4 ST 0 1953 6.25 Fort Greeley 01,02 .?3(i)D °3.0 10,500 ,''''- 04,D5 C,D 0 2.5 10,500 Ft.Wainwright(j) SIC ·F'S3,S4 ST Coal 1953 20 20,000 S5 'ST Coal 1953 2 ,... .~ Legend H o SCCT RCCT ST CCCT NGo Notes TABLE 0.14 (Sheet 5 of 5) EXISTING GENERATING PLANTS IN THE RAILBELT REGION Hydro Diesel -Simple cycle combustion turbine -Regenerstive cycle combustion turbine -Stearn turbine Combined cycle combustion turbine Natural gas Distillate fuel oil I~ (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 O°F 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 "gas turbine operation"and added to "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 stearn heating. Source:Battelle Pacific Northwest Laboratories.Existing Generating Facilities and Planned Addition for the Rallbelt Reglon of Alaska, Volume Vl,September,1982;updated by Harza-Ebasco Susltna JOlnt Venture,1983. TABLE 0.15:SCHEDJlE (F PLANNED llTILITY J1IDITIOOS (1982-19ffi) Avg.Energy Util ity Lnit T)1Je Year (GWl) )'"c7"--', flPA Broclley Lake Hyjro .~.O 1988 347 flPA G"ant Lake Hjdro 7.0 1988 33 mTAL 97.0 r-", .- TABLE 0.16:CPERATING AND ECCX'JQ\1IC PJlR.LIl'I£TERS Fffi SELECTED fi'fLROELECTRIC PLANTS Max.Average (1981 $)Econanic 2 G"oss Installed J1llnual Plant Capital Cost of rea:!Capecity Energy Foctor Cost 1 Energy rb.Site River (ft)(1vW)(GWl)(%)($106)($/lcm KWl) 1 SnaN SnON 690 50 220 50 255 45-2 Bruskasna flEnana 235 l)140 53 239 113, 3 Keetna Talkeetna 3lJ 100 395 45 463 73 4 Cecile Talkeetna 310 50 220 51 564 100,-5 BroW1e fEnana 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 O1akcr:hama3 O1akechatna 945 500 1925 44 1480 l)r-9 Allison All i son Creek 1270 8 33 47 54 125 10 Strandline Lake Beluga 810 20 85 49 126 115 !lIlII!JItl rbtes: (1)Including engineering and Q\IlJE!rts cdninistrative costs but excluding .AfOC.-(2)Including IOC,Insurance,Amrtization,and QJeration and Maintenance Costs. (3)J1ll independent study by Bechtel has proPJsed an installed capecity of 3lJ f1.J, 1500 GWl annually at a cost of $1,405 million (1982 dollars),inclLrling .AfOC. TABLE 0.17:RESULTS Cf ECOl\G1IC JlNAL YSES Cf PL TERNATIVE rENERATIOO SCENJlRIOS Installed CapOClty (fi'W)by Total Systan Tota1 $ystan Category in 2010 Installed Present hbrth Generation Scenario OJP5Run lhennal H}drO Capocity in Cost - Iype ffiscrl pb on Locrl Forecast Id.fib.COal GaS Oil ana (tvW)($1()6) All Thennal fib Renewals ~ilJTl L.ME1 900 001 50 144 1895 8131 Thenna1 Pl us fib Renewals Plus:~ilJTl L7W1 600 576 70 744 19X1 7000 Alternative Chakochffilla (500)L 1993 Hjdro Keetna (100)-1997 fib Renewals Plus:~ilJTl LFL7 700 501 10 894 Lm5 7040 Chakochama (500)-1993 Keetna (100)-1997 mw (50)-2002 fib Renewals Plus:~ilJTl LWP7 500 576 60 822 1958 7~4 Chakochffilla (500)-1993 Keetna (100)-19% Strandl ine (20)t Allison Creek (8)t Snow (50)-1998 fib Renewals Plus:~ilJTl LXF1 700 426 3)822 1978 7041 Chakochffilla (500)-1993 Keetna (100)-1996 Strandline (2O)t Allison Creek (8), mw (50)-2002 fib Renewals Plus:M=dilJTl L403 500 576 3)922 2028 7008 Chakochffilla (500)-1993 Keetna (100)-1996 mw (50),Coche (50)t Allison Creek (8), Talkeetna-2 (50), Strandline (20)-2002 flbtes:- (1)Installed caoacity.~!'1J]::, i~ T.ABLE 0.18:SIJ<MllRY a::1HERMl1l ~ERATING RESClRCE PLJWT p~Sn98~l ~ CaJbined Gas ~1R.J Turbine Diesel Parareter 2OOI-W 70 I-W 10 Mol /-eat Rate (Btu/kWl )i~OCO ~~I§M200 I§oo500EarliestAvailabillty 1M Costs i""'" Fixed W1~1$/~16.83 7.25 2.7 0.55 Variable $/)0.6 1.69 4.8 5.13 i~Mages Pl armed Mages t%)8 7 3.2 1 Forced Mages ( )5.7 8 8 5 Constroction Perioo (yrs)6 2 1 1 Startup Tirre (yrs)6 4 4 1 Lhit Capital u:>st ($/kW)1 Railbelt -1,075 627 856&luga 2 a51 tEn ana 2:107 Lhit Capital u:>st ($/kW)2 Railbelt 2,242 1,107 6:E &>9 &luga -I~'tEnana 2,3)9 NJtes:- fB fts estimated by Battelle/Ebasco without JlfOC. InclL.K:ling IOC at 0 ReCent escalation and 3 percent interest, assuning an S-shape(j expenditure curve. Source:Battelle 1982,Vol.II,IV,XiII,XIII TJlBLE 0.19:(3~u~~E1~DJ~~S)rn BEllrA MEA STATIOO(a)(c) Cons~rlfntion L<bor ~trlf,tion ~S~1WflJjor Equiprent Rent ~~~~Oi~ta~stiJlnsurancepp1esStbcontroc:ts l.Lmprovements to Site $350,(0)$2,100 $$~l,OO)$110,(0)$$1,1>3,100 2.Earthw:>rk illd Pi 1i ng 2,541,(0)3,888,(0)5,7()),OO)16,(0)12,151,(0) 3.Circulating Water Systen 2,511,(0)174,200 2,391,(0)1,235,(0)10,(0),00)16,311,200 4.Concrete 5,733,(0)540,(0)1,(91,00)2,137,(0)9,751,(0) 5.Stsfci~s Steel,Lifting Equip.,1,757,(0)7,155,(0)8,912,(0) 6.Buildings 682,(0)8)),00)1,482,(0) 7.Turbine-C£nerator 1,8)),00)19,500,(0)21,])),00) 8.Stean l?enerator and J.lccessories 15,764,(0)21,00),000 37,564,(0) 9.Air Q-Jality Control Systen 12,400,(0)27,100,(0)39,500,(0) 10.Other M=chanical Equiprent 8,950,(0)8,950,(0) 11.Coal ald Ash Handling 576,(0)1,500,(0)5,000,(0)7,076,(0) 12.Piping 14,435,(0)9,(0),00)23,435,(0) 13.Insul ation illd L~ging 1,500,(0)1,500,(0) 14.Instrurentation 3,(0),00)3,(0),00) 15.Electrical Equiprent 1,(0),00)lJ,OO),OO)31,(0),00) 16.Painting 1,015,(0)1,100,(0)2,115,(0) 17.Off-Site Facilities 3,(0),00)3,(0),00) 18.Waterfront Constroction 600,(0)600,(0) 19.Stbstation 1,275,(0)22,(0)92,(0)2,6ffi,OOO 4,075,(0) 20.Indirect Constroction Cost ~ Jlrchitect/Engineer Services b)44,515,(0)5O,~7,OO)2,562,(0)2,004,(0)9,(0)100,077 ,(0) Stbtotal $l()),354,OO)$55,533,]))$2,562,(0)$12,265,(0)$103,348,(0)$53,100,(0)$333,162,])) Controc:tor's Overhead and Profit 21,(0),00)9,(0),00)3),00),00) Contingencies 47,(0),00) TOTAL PROJECT fiST $410,162,:m (a)ll1e ~9Jecalncost eSlima~e ras devel~ped ~y S•.J.crovfs i(I(j SOOs ~iJ1~•.ft>all~w~~~tE~t for ~d ~~iJ1~rights,client chargesOWlr1nlstra1011,axes,1n eres dur1ng cons roct1011 or tr sm SSlCJ1 cos set s s at100 SWl c y • (b)IncllX1es $~~W:for fonstroctio9 f~6 H1t])),~for en~ineerin~se)vifeff ~$29~548~f~f other11ndil~~costf incllXling constroctioneqU1prents,cons roc 1011 re a u ngs servlC s,norm ua s a sa ar1e ,cra payro re a cos s. (c)Source Battelle 1982,Vol.XII. ,'j 11 'I --l r -1 -1 .-1 1 -}-)] TPBLE D.al:(S~u~~E1~lbCVr~S)rn NEf'LlWA MEA srATH)~(a)(c} ConciJdr'fntion Lct>or Co~'rition E~Ui~t Equiprent Rent ~fW~~~Slbcontrocts rnJglatostnSurillCelesRea1roor l.Irrprovarents to Site $350,(0)$2,100 $$~1,(0)$110,(0)$$1,353,100 2.Earthwork and Piling 2,100,(0)13,CXXl 5,400,(0)16,(0)7,529,CXXl 3.Circulating Water Systan 2,561,CXXl 174,200 2,391,(0)1,235,(0)11,500,(0)17,861,200 4.Concrete 5,982,CXXl 54O,CXXl 1,Cm,CXXl 2,137,(0)10,CXXl,CXXl 5.Stsfci~s Steel,Lifting Equip.,1,757,CXXl 7,155,CXXl 8,912,CXXl 6.Buildings 682,(0)ro.>,OO)1,482,CXXl 7.Turbine-t:enerator 1,ro.>,CXXl 19,500,(0)21,lXl,CXXl 8.Stean t:enerator and Jlccessories 15,662,CXXl 113,CXXl 12,(0)21,81),CXXl 37,612,CXXl 9.Ai r QJa1i ty Control Systan 12,4OO,CXXl 27,100,(0)39,500,CXXl 10.Other fvkhMlical Equiprent 8,950,(0)8,95O,CXXl 11.Coal and Ash Handling 1,937,CXXl 18,CXXl 15O,CXXl 5,785,(00 7,~,CXXl 12.Piping 14,435,(0)9,CXXl,CXXl 23,435,CXXl 13.Insulation and Lagging 441,CXXl 46,(0)11,CXXl 1,049,CXXl 1,547,CXXl 14.Instrl..lTentation 3,CXXl,(0)3,(0),CXXl 15.Electrical Equiprent 12,7al,CXXl 1,150,(0)ro.>,CXXl 18,CXXl,(0)32,670,CXXl 16.Painting 1,142,CXXl 58,(0)25,(0)575,CXXl 1,ro.>,CXXl 17.Off-Site Focilities 4,827,CXXl 3,600,CXXl 3,260,(0)11,687,CXXl 18.Waterfront Constroctim N/A 19.Slbstation -~itchyard 1,623,CXXl 34,(0)143,(0)3,017,(0)4,817,CXXl 20.Indirect Constroction Cost ~Architect/Engineer Services b}-54;943,00J -42;560,00J -2;882,00J -2;6U,00J --.-.-9,00J ..".-.-.103 ;Ol1,cm Slbtotal $135,352,(0)$44,733,lXl $2,882,CXXl $17,141,CXXl $132,748,CXXl $11 ,500,(0)$344,156,lXl Controctorls Overhead and Profit 21,CXXl,CXXl 9,(0),CXXl lJ,CXXl,CXXl Contingencies 47,CXXl,CXXl mTJll ffiOJECT ruST $421,li6,:ro NJA =fibt Jlpp 1iciD le. (a)The Pr<;>,iect costtestimate was develooed bYdS'.J.troves and ~ns Comanv •.ttl allowance hastbeen moctetfor lClld ood IilCll~.rights,client chargeslO\'ll~r S 0011lnlS rat1on},taxes,lnterest urlng constroctim or tfalSl11SS1m costs bejQn::I fE-slbsta 1m <n1 SW1tc YOIU. (b)IncludeSt$qQ.a81~lCXXl for con.str.octioo caro12 $31 J lXl,00J for enqineerinq services..and $301 895.00J far otherljndirecLcosts including constroctionequ1pret1cHJtwlS;constroctlon relater uunamgs m serv1CE:!S,normanual stat I saTar1e:>,afk:rcratt payro I relatOJ costs. (c)~urce Battelle 1982,Vol.XII. TABLE 0.21:BID LINE ITEM ~r0S{CR W\TIRJll Gl\S-fIRED CXMHNED-CYCLE 200-f'1oJ Station c (January 1982 £bllars) Cor~~{'tMMp~for ~pprfMon R~6~i~or Equiprent Rent ~~pq~~OiJ2t~st 1.Jrrvrovarents to Site $95,600 $$109,700 $83,700 $13,00)$lJ2,00) 2.Earthwork and Piling 313,(0)2,666,3Xl 87,3Xl 151,600 3,218,200 3.Circul ating Water Syst81l 2,455,600 484,400 16,100 28,500 4,400,(0)7,]34,600 4.Concrete 3,450,700 348,(0)372,700 226,600 1,496,(0)5,894,(0) 5.Structural Steel Ct1d Life Equiprent ])5,00)1,900,(0)2,205,(0) 6.Buildings 192,200 491,(0)683,200 7.t-e%§ecover~~s~toGas 5,197,200 172,500 250,(0)31,200,(0)l),819,700urmes,er rs 8.Stean Turbines and l£nerator 3,631,900 115,(0)200,(0)8,600,(0)12,546,900 9.Other M=chanical Equiprent 2,588,700 115,(0)65,(0)4,946,200 7,714,900 10.Piping 3,164,500 345,(0)120,(0)4,500,(0)8,129,500 11.Insulation and Logging 126,500 86,:nJ 50,(0)250,(0)512,3X) 12.Instrurentation 379,500 46,(0)10,(0)700,(0)1,135,500 13.Electrical Equiprent 4,586,(0)57,500 15,(0)5,250,(0).9,~,500 14.Painting 632,600 11,500 2,500 500,(0)1,146,600 15.Off-Site Facilities 2,451,400 211,(0)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 948,3X)23,(0)10,(0)4,035,500 5,017,:nJ 18.Construction Canp Expenses 4,292,400 12,362,(0)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,(0)SUBTOTAL 61,167,900 21,357,500 5,540,3Xl Contractor's Overheoo and Profit 15,(0),00) Contingencies 22,224,200 mTJlL PROJECT COST $200,202,200 ~oj~t co~t estimate was d~elooed by S.J.(foves Ct1d Sons Cmnany.ttl allowance has been nme for lirld.Ct1d liJId r.iqhts,client,-,diarges t~er s cllnlmstratlonJ,taXes,1nterest durmg consfructl"oo Of'tran9TI1SS1OO costs l)e50tl1 tne sLDsfatloo cn:1 sWltchyatd. (b)Includes $14,816 1 200 for1erJqineerinq ser.vices <TId $181729 1 900 for other indire:t costsljncludtinq construction equiprent Ct1d tools,constfuctlon related bUl dlngs and servlces,normanua staff-salarles,and cratt payro I rela ell costs. (c)Source Battelle 1982,Vol.XIII. '1 )I 1j I -TABLE D.22:ECONOMIC ANALYSISSUSITNAPROJECT-BASE PLAN 1982 Present Worth of System Costs $x 100 Estimated 1993-2021-2051 2051 3,386 7,316 Pl an Non-Susitna Susitna Components 600 MW Coal-Beluga 400 MW Coal-Nenana 840 MW GT 200 MW CC 1020 IIo1W Watana 600 MW Devil Canyon 490 MW GT 200 MW CC 1993-2020 3,930 3,396 2020 479 316 2,093 5,489 .,~ Net Economic BenefitofSusitnaPlan 1,827 TABLE 0.23:~ORECASTS OF ELECTRIC POWER DEMAND NET AT PLANT Reference -2 Percent r-'--l Case DR!DOR Escal at ion Year Mw GWh MW GWh MW GWh MW GWh 1990 844 4054 850 4085 793 3808 848 4072 2000 1020 4898 1158 5558 950 4567 959 4610 r-··""\ 2010 1306 6280 1599 7681 1206 5799 1168 5628 2020 1672 8039 2208 10615 1528 7364 1422 6868 - TABLE D.24:--CL£CTRI£-ffinffi £EMl\ND SENSITIVITY ,lINALYSIS 1982 Present W:lrth of Systan U:Jsts ret ~efits -$x 106 $x 106 1993-Estimated 1993 Plan 2020 2020 3)21-2051 2051 Reference Case rtln-Sus i tna 393:>479 3136 7316 Susitna 3396 316 2003 5489 1827-au rtln-Susitna 4~624 4330 9286,..Susitna 4004 499 3384 7468 1818 em. NJn-Susitna -2640 334 2392 5032 Susitna 3259 283 1858 5117 -85.2 -2 Percent rtln-Susitna 1941 186 1056 2997 Susitna 3220 263 1711 4931 -1934 r- I TABLE D.25:DISCOUNT RATE SENSITIVITY ANALYSIS 1982 Present Worth of System Costs ($x 10 6 ) Real Net Oi scount Rate 1993-Est imated 1993-Economic Pl an (Percent)2020 2020 2021-2051 2051 Benefit Non-Susitna 2 4,829 457 5,418 10,247 "-:1"""7' 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 fl"''--' Susitna 5 2,925 423 1,048 3,973 70 TABLE 0.26:.·GAPH.AJ:..·mST-SENSITIVITY·,lINALYSIS ,'....1~·Present WJrthof Systen Costs ($x 1(6) ret 1993-Estimate:!1993-~rw~c,.Plan 2010 2010 2011-2)51 2051--Watalta C~tal CoatsCostsup..Percent rt>n-Susitna 3,93)479 3,l36 7,316 Susitna 3,839 347 2,nJ 6,139 1,117 ,....Watana Capital CostsiCostsLess23Percent flbn-Susitna 3,93)479 3,136 7,316 r-Susitna 2,977 2ffi 1,899 4,876 2,440 TABLE D.27:·FUEL PRICE-SENSITIVITY ,LINll.L YSIS 1982 Present WJrth of Systen Costs ($x 1(6) Costs of Costs of f'Et Non-Susitna Susitna EConomic Plan Plan Benefits 7,316 5,489 1,827 ..-,. ,"'"Reference Case Fuel Costs Increase:! 20 Percent Fuel Costs [kreased 20 Percent 8,281 6,474 5,607 5,418 2,674 1,056 TJlBLE 0.28:Sl.J'-WlRY CF SENSITIVITY ftNAl..YSIS IN!:I:XES (f"NET ECQ\OvlIC BENEFITS Index.Values BASE REFERENCE CASE ~$1,827 MIlL:I~) Oil Price Forecastau 1m -2 Percent Oi scount Rates High (5%) I..oiI (2%) WatCl1a Capital Cost +20 Percent -23 Percent Fuel Price +20 Percent -20 Percent Real Fuel Price Escalation l'b Esc a1at i on after 2020 100 100 -5 -leD 4 192 61134 146 58 53 ,'7':.. -1 1-1 .'J 1 "1 ~l --"1 -')'1 I TABLE 0.29:BATTELLE Pl TERNATIVES SlWY FeR RAILBELT CANDIDATEELECTRICENERGYI?ENERATING TECI-Nl.OOIES Resource Principal Sources Fuel Generation Tfiical Availabilit~orBaseforRailbelt..Conversion Technology .Jlpp ication Canrerei a1 er Coal Beluga Field,Cook Inlet Crush Direct Fired Stean-Electric Baselocrl Currently Available F'€nana Field,I-Ealy Gasification·Direct-FiredStean-Electric Baselocrl 1985-1990CarbinedC)(:le Base looo/C)(:1ing 1985-1990Fuel-Cell -Carbined-C)(:le Baselocrl 1ID-1995 Liquefoction Direct Fired Steam-Electric Baselocrl 1985-1990 Carbined C~le Baselocrl!~ling 1985-1990Fuel-Cell tation Baselocrl!:}C 1i ng 1985-1990 Fuel-Cell -Carbined-C)(:le Basel 000 1ID-1995 Natural Gas Cook Inlet rtme Direct-Fired Steam-Electric Baselocrl Currently Available t-brth Slope Carbined C~le Baselocrl!~ling Curren~AvailableFuel-Cell tation Baselocrl!:}Cling 1985-1 . Fuel-Cell -Carbined-C)(:le Baselocrl 1ID-1il5CarbustionTurbineBaselocrl/C)(:ling Current y Available Petroleun Cook Inlet Refine to Di rect-F ired Stean-El ectric Baselocrl Currently Available rtJrth Slope distillate and Carbined C~le Baseload!~ling Curren~Availableresidualfroctionsfuel-Cell tations BaseloocJ!:}C 1i ng 1985-1 Fuel-Cell -Carbined-C)(:le Basel 000 lID-1995 Carbustion Turbine Baselocrl!~ling Currently AvailableDieselElectricBaselooo!:}Cling Currently Available Peat Kenai Peninsual None Direct-Fired Stean-Electric Baselocrl Currently Available Lower Susitna Valley Gasification Direct-Fired Stean-Electric Baselocrl 1ID-2CroCarbinedc)(:1e Baselocrl/C)(:ling 1ID-2Cro Fuel-Cell -Carbined-C)(:le Baselocrl 1ID-2Cro MUnicipal Refuse Jlnchor~Sort &Classify Direct-Fired Stean-Electric Base locrl(a)Currently Available Fairbifl s ~Waste Kenai fug Direct-Fired Stean-Electric Baselocrl(a)Currently Available Jlnchoragef'eniflaFairbanks TABLE D.29 Continued Resource Principal Sources Fuel Eeneration ~f{ical Availabilit~or Base for Railbelt Conversion Technology JW icatioo Carrrerc ia1 er Q:othermal Wrangell Mountains --Hot Or~Rbck-Steam-Electric Basel 000 19!X)..2OO) Chigmit Mountains --Hydrot ermal-Steam-Electric Baseloa:l Currently Available Hydroe 1ectric Kenai Mountains --Qmyent iona1 H}droe1ectric Baselooo/Cycling Currently Available Al aska Range --Sna l-Scale H~roelectric (b)Currently Available ~crohydroelectric Fuel Saver Currently Available Tidal P01t€r Cook Inlet --Tidal Electric Fuel Saver Currently Available Tidal Electric w/Retirre Baseloa:l/Cycling Currently Available Wind Isabell Pass --L~Wind Energy ~tans Fuel Saver 1985-1~ Offshore Sna 1 Wi nd Energy ~tans Fuel Saver 1985-1~ Coastal Solar Throughout Region --Solar Photovoltaic Fuel Saver 1985-1990 So 1ar Thermal Fuel Saver 1995-2cm Lraniun lrrp:>rt Enridment &Light Water Reactors Basel 000 Currently Available Fabrication (a)SupplEJ!B1tal firing (~/coal)\'()uld be required to sUP/Xlrt baseloa:J pperatloo due to c)1;11cal fuel supply. (b)May be baseloa:l/cycllng or fuel saver depending l4JOn reservoir capacity. 1 )1 1 "I ]J 7""" TABLE 0.3:>:MTTELLE PlTERNATIVES STIJDY,Sl.f+\IlRY CF OOST JlND .....·PERFffiMO.NCE CH,IlAACTBHSTICS -CF-SElECTEO ALlERNATIVES CapJity Aver:rPrlnua Capital Varicble Alternative a)~/~j f~fi_l cbility tw;~y f§7~W)H7i/Wr ~llS/khtl)(~)--- Coal Stean-Electric (Beluga)200 1O,CXXl 87 2Ql1)16.70 0.6 Coal Stean-Electric (fIBlana)200 1O,00J 87 2150 16.70 0.6 Coal Gasifier-CaTbined CjCle 2LU 9,~85 14.00 3.5 Natl.Gas Carbustion Turbines 70 13,SOO(b)89 T5J 48 Natl.Gas Carbined CjCle 200 8,200(c)85 1050 7:JJ 1.7 Natl.Gas Fuel Cell Stations 25 9,200 91 gg)42 Natl.Gas Fuel Cell Carb.CjC.200 5,700 83 50 Bradley Lake H}{lroelectric g)94 311-7 31~9 O1aka:hama H}{lroe1ec.(33)rvw)(d)33J 94 1570 l360 4,-O1akochama H)(Iroe1ec.(480 rvw)(e)480 94 1923 2100 4 LPper Susitna (Watana I)600 94 311-59 4669 5 LPper Susitna (Watana II)340 94 168 5 LPper Susitna (l:eJil Canyoo)600 94 33311-2263 5 Snow El ectric 63 94 220 5850 7J~ Keetna H)droelectric 100 94 395 5480 5 Strandline Lake H}{lroelec.20(17)94 85 7240 44 r-BrMle H}{lroe 1ectric 100(00)94 43:>4470 5 All ison H}{lroelectric 8 94 37 4820 44 i ~ant Lake H}{lroelectric 7 2840 44 Iscbell Pass Wind Farm 25 36 8 24~3.70 3.3 Refuse-Derived Fuel Stean Electric (Jlnchor~e)50 14,00J N/A 2980 140 15 Refuse-Derived Fuel Stean Electric (Fairbanks)LU 14,OCO 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,(XX)Btu/khtl was used in cnal,Y.Sis of Railbelt electric energy ilanso 13,OOJBtu/khtl is pro!;lcbly rrore re~sentative of partial loa:!~ratioo charocteristic of ~ing duty. ~c}Prl earl ier estimate of 8500 Btu/khtl was used in t e cnal~is of Rai"lbelt electric en~pl ans. d Configuratioo selected in ~reliminar;l feasibility stLKlr 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 1 '1 I l 1 1 '1 1 1 I l **O*~~****¢**9************~O**¢**~*~**~~*****~~~**~*.*~**~~~**~*~**¢~4*O*****~~4~~~~~~*~~~~*~~~~**O~**~~*O*~OO~*~*~~~**~~~~~¢~¢D~TA12K.D12 hAT ANA (ON LINE }9931~'1.8 6N(S}9821 STATE FV~CS-J~FLATJC~1t-l~lEREST 1C~-CAFCCSl !5.15 8~23-Jl~-~3*.*.**••*~•••~*••*•••~••••o••••*.***••••*.*••****••*o.*••••••••••••0.*••••••••••••_**_•••••**••••_•••••••••••*****.****~**••*•• 1985 1986 l:l B1 1"B~IH9 19<;C 1991 19<;2 is''3 l'1S~ OSI"flO\.;SUI'MAR~ ===It'''JLLIO~I===. 13 F.N~RGY G\m a 0 0 0 0 C C C (i ~3 2 ;~1'i21 REU I'll ICE-I'lLL5 ll~:~'~C.CO O.CO c.oo c.cc c.cc o.CC C.OC JE.C 2 ~€.11461>Il\FLATI0N INDEX 135.59 1't5.C3 155.24 16t.1C 111.13 1%.11 2C3.H ~1/.13 2]2.~1 ;2')I'~IC~-MllLS 0.00 0.00 0.00 0.00 o.oc O.CC O.CC C.oc 12t.32 );5 ..:, -----INC~Mr----------------- )1"'~~\iUlU"c.o O.C c.O 0.0 c.o C• C C.C O.C 313 .0 4 CC • 7 111 Le',S CPH AT ):~G Cr;STS 0.0 o.c c.o 0.0 C.O C.C e.e c.c 22.t 24.,--------------------------------------------------------------------------------11 1 ,W E[\;\TPI G I ,."C';~i:0.0 c.c c.O 0.0 c.e c.e C.C C.C ~~C.4 ~It.5n4Ace[t;TEREST F.A;l "'I:C 01\FUNes c.o 0.0 e.o 0.0 c.c c.e C.C C.C c.c 4.(; ;;:>'.1 L"SS INTEReST CN SHCRT TERH DE'lT 0.0 C.o 0.0 0.0 c.e C.C C.C C.C C.C f.1 3"1 l:SS PIT'::REST C~LiJl\G 1CR~DEaT C.O 0.0 C.O 0.0 C.C o.C O.C t.O 32~.C ~7t.2 _-------------------------------------_...--------------------------------- --------541 '!1oT [AQNI"IGS FR)M 'II'f'R S 0.0 c.O C.O 0.0 e.o c.e C.C 0.0 21.4 -~.c -----CASH S::'URC~A'IO I:SE---- ~4~CASH I tlCD"!":F~,D"i CPFHS C.O c.C c.o 0.0 C.O C.C o.C 0.0 2 1.4 -J •~446 ;TAH CONHlillJTIGN 4C2.C 384.9 4~8.6 572.8 12e.2 17C.E C.C c.C C.C C.C 141 LOI\G T~RH ~E?T D{A~DCWI\S 0.0 0.0 c.O 0.0 c.e 944.6 1252.2 12Cc.l 632.3 17ht243wORCAPD~e DRAWCCWI\5 c.o c.O 0.0 0.0 C.O C.C C.C c.C ft.7 l:.•2---------------------------...._---------------------------------------------------';41 TOTAL SllURC:=S ]F FUNDS 402.0 39te.9 42 A.6 512.8 12E.2 111~.4 1252.2 12CC.l 74C.4 11;.C 320 Li:S5 CAPITAL EXPEJ\DITUPE 402.0 384.<;429.t 512.8 1,8.2 Illf.4 1252.2 12CC.l t~3.1 •Cl.144,3 LESS ~ORCAP A~D FUND,C.O e.c 0.0 0.0 c.g C•C O.c C.C Et •7 6.2260LESSDE3TREPAYMENTSC.O e.c e.c 0.0 c.C.C O.C G.C C.C 1 ~.~~ 3 ')'i LESS PAYMENT TO STHF 0.1)c.c c.o C.c C.C c.c c.e 0.0 c.C C• C---------------------------------------- --------...-------------------------------141 [ASH SURPLUS(CEfICITI c.o e.o 0.0 0.0 c.O C.C c.O C.O C.C -42.b24°SHeRT TERM Dr:eT 0.0 C.O c.o 0.0 e.o c.e C.C c.e c.c 42.8444CASHREcrv~prc 0.0 C.O 0.0 0.0 e.c c.c e.c C.C c.e c.e -----!\AlANCE SH,;~T---------- 22 'i RESEKVE:A,'1~(ONT.FUND C.e c.c c.c C.O c.o c.C C.C 0.0 40.C 1t-i.2 111 OTHEfl wCRKll>;G CAPITAL C.O 0.0 0.0 0.0 c.c c.e O.C 0.0 40.7 43.7'.54 CA~H SIJRoL'JS RUA.PIED 'J.c c.o 0.0 0.0 C.C c.e C.C C.C C.C C.C110':L~.[IPIT,IL [XPft\f1ITURI:'I e 2.C ?P6.9 1115.5 1138.3 25lt.~~6:}.~4ee4.<.tee4.'tB7.'1 r,<J3;.t ==~:;:::::;:=:=='====;::::======-======"====:::::::::::::::::::::::::::=:.::=,::~=~:=:-:.::;:-::;;=:::::=-=::~==::;;;;..-;::;::~~::;:~~';=!:=::= ',,'):)(t,r I ThL ~~r-L",/,'J ~C2.C P6.;1713.5 IBEd 2 H t.5 ?(;?1.~42U4.l tCe4.t tF.24.t 7C?2.:===========:;::=.:~=-:.;;::~z===.;.;=;:::~~.;:::-=.:;::::::;::::;=============;=:=:==;;;::=========== 'i!J 1 ~TH:(c;~'TO I ~I.'T 1:,""4C2.C 7~6.<;1215.5 1 H~.]25 H.5 26€1.1 26e7.3 2 t.r.:7 •~26E7.1 'i.t.'~7.3 If ~)2 ~rrA"!")::'\C,'!I t,(';CIoC C.C c.o 0.0 C.c C.C O.C C.C 21 .4 1 7.( )');)"eT ~llJ T :;T 'r ')I ~I :;-j f'C'(T FiU-'C.O C.O 0.C 0.0 C.C O.C c.e e.c EC.1 1 ~:• 7 ~)4 F ~T I)'JT ST !<!,,)I "('-L r;t.G Tf:R:1 O.C e.o c.n e.o C.C 944.t 21'11:.9 33<;1.C H <.<;.2 qc 1.S 11 2 4 ~I\I;'\L D e T ')"r.~h:{)(rJN 11 'i:12 e.c C.C C.r.e.o C.C 5~1.5 f:5~.~~9".1 2 Ii C.4 77:• 43 r:U~.C ')T ,'P,A\;',C':::,N il '1 'j 2 o.c c.e 1).0 C.C C.C 531 •~1 18".'i 117').1 2e1C.1 !14 ~•"'1'J :1"eT S~~Ie c cc'rr 0.00 I).nc c.ce 0.00 c.ce C.CC C.CC C.CC I.C7 c.<; $1.8 BILLION (1982 7% DOLLARS) INFLATION ST ATE APPROPRIATION AND 10%INTEREST SCENARIO SHEET 1 OF 6 TABLE 0.32 0;~~~*~*~~;~e*~*:~¢'~~*~~*:~~~~~)')**~~C~~:)i)~*~¢**=¢:)~¢~*~*C*~*~¢~¢~~t:)**¢;~**¢¢¢~*~**O*~~OO~~~~~~C*~~¢~¢**¢*~¢**~60*=¢~t.~¢~~~~*Q~¢ ~~TA1~~.CI2 ~tTA~$]S ll~E 19~31-$I.B 1~1 $19821 STATE FC~CS-I~FlAIIC~7%-I~TEPESl lC~-CAF(CST i5.15 e~23-Jl~-2~ *~***~:***~**Q¢*~*~c~~**(:*Q*¢~~*~o¢*~**¢¢**O¢~Qo*9;e*t¢=cO*C¢QC~*4~O~=~*c***~**~~~~~~Ct¢.*~~~~*~~**~~c¢~*~~~9~q~6(.~~O~~(~~~¢~~~ 1995 1991>1~91 IS9S 1~~9 2CCC 20 C1 2CC2 2C C~2((4 71 '.:~~c "V r IIHj21'lr-=~l P)lC.:':-"'ILL"~ "I}"I"F l hi Ie"If,'J ::X C ?'J ~?Ie"-,v ILL S 3CO 5 58.20 L49.2?, 145.C'7 3C 19 loS.31 266.73 174.21 C';h FlC~5Ur~AR~ ===I$~lll1C~I==== ?02~30~=](57 6C.~7 5~.~5 51.50 2G5.~O 3C5.10 326.75 172.57 169.65 16e.2S 3 Ct 4 41.62 ?4<;.62 16lo.1C nc: 43.1~ 374.1C It3.45 45C;~ 54.18 4((.29 21t.ee 4 t7 C4.tt 4 E.3 1 •1.55 41 0 t ~2.17 ~5C:,,2<; '41.~3 -----II!C':~·1 ------ -- - _ -;1:'.-J::'J[~"nJr 11)L'.oS ,;~~n"TI'J(C:STS 7 1p r nATIH ~rc~c',.':»UIT ~oT F.\''1':[;n fUI\C 'J LESS UH R ST C!l ~ljC,"J(~/'CUlT I l ':S SiN T PST 'J I,ll;,~~;1"~'1 J"H '"1 ~:.~T ":i\'1 .\I ~(S r,~.j ...•J [>f''l -----:AS'1 Sf'urlC<:Ar:r:$5"---- /t ~.'l ~H I f j C r"J ~i L:F r r ~1"1 i'U~~ 4 ~TATr CLNr~I'~TI1N i.l'jtJ,Tl R"G[,q In fli~r.C\HS ~~Jr:'r."r .Jc:eT DnA,r~('··Jf\~ It 3 c:;.q 25."-; '01 C•a4.9 13.6]14.8 2t.'O 2f.. O. .,C ~-1: ~2:.9 21.7 4<;3.15.2 15 •'; 31 J 03 114.3 I 14.3 C.O ;12.6]c;.2 ~2:'.C: :-r:;•7 4<j2.e S III ~ 1C.'1311.6 lit.a 116.()c.o 61~.~ 7.? 51(1.2 31.8 4~lo.56.a 4.936".7 117 .0 111.9 C.O 1C61.1 0.2 ~14 'II 4 34.C 48C.4 i.4 -C.l 367.7 11 <;•.9 115.<;c•C 119C.C 6 • 2 5 I C• 1 ~l:.4 474.4 t.~-t."3l:5'115 12 ••1 1Zt:t 124~:~ ~C7 •i 3 n .'i l,tE.l 7.4 -11.5 :!6~"C 12 It •,~ 12~.6 ~'JC I I ()2.7t.~ 5~7.e f:C.G ~27.C 1.S -16."9ES.lo -3'1.2 -36.2C.C 7CD5 16.2 lCE3.3 65.1 ICI,?·2"jJ ~ ~• 2 9S~.1 "3~.1 ~4.7r•C C.CI:'J.E I I ~7 •~ Co q 110 "'i lCf .6 I •2 1 •~ S ,C •J <j9~S ,').c:;c.C ( • C 17.3 '4 l TGT H SIU~crs IlF FU'JO S .'2 'J ~.~c ",1..L ,):l ?'}U L S~ I),l ,S Cr,;>ll.\L OX;>Co;'JITUR': I-.l r:<:AP HdJ 1!r:C: D~er R[~H'~iaS :>AVII""T Te;T.\1;: 24C ..O 2:;?1 7 •~ I ".3 C.O ~r.t...1 "~1 •:31~•,2 H.P. C• C P,OC.{\ 7C 7.1:: 1.2 1 J •r; -J.O 1117.1 lC94.V "• 22C.3 o •C i316.1 1~2~.~ t •2 22.4 (• C 131(.C 1277.E 7.e ;:;4 •i C • C 123:.1 114~.C t.~ 21.Cc.[ 1C3.4 1 13.lo 16.22C;..E C.C <,< 6 .21•r -.? • C 117." 7C.8 11 I!3 n."( •C lid cA:;H SIJH'lUS(:;cf-lCITI ~4}:i~['~l T~~~V~~T 4~~(~SH R:C~V'r C ----',,\L'HCC ~fl'c T---------- ;l;I Slo\l~(""C:':~.T FWT J7 1 THE',·Li·,<1I.e C.11 Al 't -:;~1'.S ~J S ~J ~P IIJ S ~I!:T I;;~) !1~UV •C~rIT~l lxr ~JITUFc -1":.6 15 •..; ('.J -:2 .~ 47.'5 C.J 1172.7 I::E• 7 -?n.4 G.C t"-'"1-.1.1 .... S J.C 1C•3 7~74.1 6f.7 0.0 ,•1 to.1 6 ~• 3 77.1 C "2 'J 1•f; tlt.a L.G'e.G t,4 •5 lG.3 1',1./ 9313.6 i2.3C.C C.C t .C 7 • ( .'C •<; l~'tC .9 ~~•E C.C C • C 1:.t 74.~ 2 t 3 .7 IISH.7 51.2C.C C.C 1 ').C H.?]2,,:.D I~C21.1 -111.2 C.C coe 1;:3.5 1 C7 •~ 2(',01 1~13".~ -e 7 .7 C• C C •C 1 ~.."2 I 1 • 1 12 •C 1~2C .~ -~~..7 (e C r • ( 1'11.4 1 2 ~e ~ C ,'".,• ,Cl _ 1327Z.4 ~==~=~=:~===~======~~~:==:=~~=====~~=====;:=============~=~=================~=== \~~~1?IT't_r-~~LrY~l 727?~7703.1 [;~D~.2 'JoS2.C In~~.8 1?2~1.(n~97.S 1:!~7t:.'3 1~~7~.e l?(Z";llZ =~=~====~====~=======~========~===~==~~=====~=====~~=~==~;=========~==~:~==~~~==1,1 -He '~'T\l '.T ", J2 }T11t~;:':.,'.?It.J "~'J n J T:T~I,It:<IiC'I LRI' 'l4 iJ ~T I)lST,~tl In -L!.~J,lEP,'A 1;4 '\r~UJJIl.L:eT l=.r./l",Jt:i:Cht,11 '?B2 c.I ~l;w.V.OT ,)~,{,,,.,\;[\·,r.'l,J2 'I ':,:'T ~"'\II,c<(1"'1-1' 2·,J7.3 ~4.2 lJ~~eS It J iJ 2 ..e 8"!..7 222~.t 1.0 3 l6 1.31.,< 1 I~:3 47 8.1. 13 'J.7 2~tJ.3 1.25 2,;"7.3 27 4.5 126.? 53<;6." 2.~7 III I 2 U ~.4 I .25 2611.3 "12.3 114.2 6437.1 347.~ 2952.8 1.25 21',9783 ~12 ..2 14 1.C HC 5.3 36 4.~ 3317.0 1.25 •6'7.3 (;."L '1 1 ~E :e P.82C.E 3 ~4 • 1 3671.7 1.,5 21>P.7• 75 P.• 15~.. c:;e'J t. 2'i "• 7 3~tt.~ 1.2~ 2te703 12C.6 231 .4 <)<;31.2 1 7 .6 3ge4.1 C."3 ~'S 711 ..,~II 2 r. ~r.I. c.r 3tjc4.1 C .5 f ;6~7.3 .:j;::II!I , 2 t 7.t q l'~ol C,C ~c;~4 e 1 I •Ci, $1.8 BILLION (1982 DOLLARS) 7%INFLATION STATE APPROPRIATION AND 10%INTEREST SCENARIO SHEET 2 OF 6 TABLE D.32 J I -1 I -]-)----1 1 J 1 I 1 -1 J *)*¢**¢****~6***¢¢Q*4~;)~¢~:O~~O**~¢~O*~~O*$**~¢**~~C*¢*4***C~~~~*~¢*~~¢***¢;O**~~Q~~*~~O~~~~~**~~~*;~*~**~*~O~~~~~~~¢¢(*C~~,~¢(¢ C~TAI2K.DI2 ~AT~N'(C~LIN2 1)931-$1.8 1h($IJ921 ST!T~FL~CS-I~FL'TJC~7~-JhTE~fST lC~-C'FCOST 15.15 e~23-Jl~-9~ *~*~*****~¢~**¢~**~*;~*(;*~*~:~¢**oo~*c¢**o******~~~oo¢**~*~*~¢~*¢¢~~*****~**~o*~~e~*~~~~~~~~~~**~~~oo~~*~~;~~¢*¢~*c¢~*e~~~~t~~*~¢ 20 e~20eb 20 C7 20CQ 2Ce<;2C 1C 2011 2fI?«1 ~"C I 4 C,Sf HC\<Sl:f'rOK~ ~;~l ;~ILLln~I"~=' 73 ':~'l::F.'3 Y G~iH lir;C2 5C~4 5224 S3E4 !!44 57C4 5~U f.023 t1 4 e 017 Zl q r:AL P",ICE-l'lLLj S7.J6 ~3.G4 4(\.2.g 4 " •'11 4C.H 36 .le 33.66 3r.~3 21'.44 u,.C<; i):J I'IFL.1 T IC'1 I/I:~EX ,,'le.37 "24.6<;S'~1 .4;>6CI].72 1..42.71 "e7.77 7B.91 7S1.42 842.54 ~Cl.52 ,'1 ?.,(C --~I!L LS 2"3.71 21".?9 27l.ee 2<.4.3°,~~e.l"252.3€241.,,~242.n ;~C;.t4 (~~"11 -----r;C""':~---------------- ,I ' ...r,IJ j~1.1 U 0:-:11 'Ie.&I /,OQ.1 t/tlh."1423.2 1<31.2 143~.5 1451.~HI:1.g 1473.2 1.t..~~,,5 1'''-~::S,r!~r.:~ATl·'(:'''~T s 74.;1'j.6 .J ')•~'J 1 .3 Q.1 I CI,•~11 1•~11 g.1 Ii ~• 1 1"7.C---------------------------------------.,......__..._------------_..._-------------------- "I':r F.r.~I T .'JG 1 t;<:rOIl °13 U.1 1329.',1330.7 1311.9 1333.5 1334.S 134r.G 1342.2 P4~.1 1 3 ~,...,1 " ,~~1';rR~<;T f.J\'.,~,..::c st ~Ui\;:;5 1',.I 15 • 1 ll.•2 11.3 1 ~•5 1 ~•e 2 1• 2 22.7 2"•~26 • C.1 ~" '1 .))ll:~S 1 tn~R'o S T ~~J :HC~T ToP I'C~eT 17.~32 • 1 3 :.•~16.8 3g.6 42.4 48.€~2.::~7.'C r.:2 • ( ~"1 L~SS l~n'-~"sr 'I/,l ~J f\f';l[RI'IJ!'eT J 9 I •9 ~75.1 '11,1."<;19.4 15C.3 9H .4 <;29.4 <;11.4 ~C 4 • 1 ee'.1:---------------------------_....-------------------------------------_....------------ ,'...;",T :'~,f.1 :\C S Fr-J .'/IJP r 1\5 Jj C.5 33703 344.3 3~J.O 31:2 .1 312.(383.C 3~5.e f,CA.3 422.<; -----Ctl';:1 :i r:Ui~.c;:Aile USr---- :-4 .i ,~\S:j lI;Cj"~rt"(.;~,-;~r:(~~7,3C.5 331.3 ~4 -4 •3,353.C 362.1 372.C ~E3.C 395.0 4C ~.3 '<'?2.G 'f :..~J :Tt~Tr~C[,!:T711UT IH,colla c.o c.')C.O C.C C.C C.C C.C c.e c • C H3 LQt\S T~:PI''][,n 'FA',ICn'"S c.c c.o ~.;}c.,1 C.C c.e O.C c • C C.C c.e J4~"Jil (~r C~eT l~'Av.!:'CI,~NS ~).6 23.5 2 ]• C 29.2 21.e 6~.t 31'.6 45.3 5C.C 7S.e----_...._-------------------------------------------_...._-----_...._.._----------------- "",lylj T ~T nL ~-::IPUS JF F U'I;:-S 3 -3 4• 1 36C.7 )6 7.r.3 g 1•2 3e9.'1 4~1:.1:419.C 440.3 4 ~~•~5C 1.S \?~L I.:S~eAPIT~L ex;'[1,[;I TU P[75.9 H .1 BI:.7 92.8 <;<;.~lCI:.3 11).1 121 • 1 1::C• 2 1")("':.I,.,-'"1 •~ }~6 UH \i':i\CI\P HI.)FU~,:J~53.6 23.5 23.0 20.2 27.B 64.~)6.6 43.~:c.c 7<;.C DleT Rci'AY~~I'JT5 &8.0 74.0 ;J 2 • 3 90.5 S<;.t 1C ~.-'12 e.5 1~2.5 145.r 1 ~C•4 3 ')Ij LfSS r \yMcr:T TO )T HC ColiC C.C c.n O.(l C.c c.c c.c e.c c.c c.e-----------_..._-------------------------------_....---_.._--------------------------- 1 ',J C,ISft Sl.':~rLusICfFICIT)18".7 Hl.4 17 'i.7 169.7 It~:~1 56.2 1"8.8 14 C• e 13 e'~1 2 ~•2!4 oJ SHC';T T~F,I'O::F C.O c.e 0.'1 0.0 e.c o.~e.e .C C.C ·'.4 '.ca~p f.,·-CI]v[n-:c 276.J 10,1 ...1 n.7 169.7 163.2 15t.2 IH.e 140.E 1 ~2 .3 1 2 ~•2 ------!UM,Cf:S W ,-T -- -------- 227.I 243.C2,!~°t :-5[~~~t\tJ~c;/\r.r Ld~:J 15 1.3 I ~1 •9 172'.;:'1P.5.4 ISe.3 2 12 •~2f:C.C ZP.2 17 I ~TIII:'l '.ICf\;t.(t,S C\~IT"L 16'i ..1 1 '1,'.8 I'H.5 21 C.5 ?2~./1 27t:.t 297.~327.3 ~(C.]421 • 1 ·f ~4 r.t\$H SU?PLU:;f.','":"T :l 1 r,~r:r;e.o C.o c ..n C.Q C.C C.C C.C o.c C ..c c.e '171 CU".~~PIT\L i"t:'C 11 SIT L:Rl 132 /,8.1 1342~.2 13~1(,:.1 13CCf.7 131CE.O 13814.3 13~U.C 14C4S.7 HIH.€14319.1 ::==:=========;;;:;::::C~-;:~~=====~=;===========::::;:-;::::=:::;::;==;;:=======:::;=~=====::;==;;==:========",~~::;·:A P I T .\L L"'DU..y,~i)13~Jt').]13173.«;133[;3.6 14CC4.&14131.e 143('<.1:14452.~1461,.<;14nC.l 1~~1~.4 =====:::;:;~:c::;=:==;:;==========::::=;=::;;====:;===::::===::=::=========::======:::.=============== 4,1 iT~E CSI'-T~ll'~I':T I :"',"'~2():J7.1 26 P7.3 2697.1 26~7.3 26El.~2bn.3 26E7.~26e7.~2"€7.~i.621.3 '."2 ':c T,~1 ;')~D ~.'tp",\rJr~c~lCS.7 lCd .t 1234.6 141:3.0 1£>16.9 1832.6 ;>C cc.,,"2321.0 2~G1.C ;:2q.c -~~::J~ET :.J UTST :./;')1 NG -5 Herr T',,~r~321.2 34',.1 3&7.7 3t;5.9 423.7 4 e 8.3 524.~57C.2 62C.~6'1';.3 ~-:.f.'J::eT QUr5T~~)ING-L1"~1;:~"9751.1 9676.~9594.0 QS03.!j 94C3.~<;294.1,<;173.g '1C41.3 EQCC:0:-::<1~~.2L'.'.. 4 ~:...\J!":lJ H.e eT JP A,'/:,[;CU;H~~Z C.O C.C 0.0 C.O C.O c.e s.c c.c r:.C r:.c .3 CU;O •C .'!T Dl A,,:ol'JCht;!In 2 )'iE',.1 .?.;E 4 • 1 398".1 39J4.1 3984.1 3984.1 3"84.1 1<;E/,.1 3ge4.1 3 <;F.',•1 19 U,:2T SI:P.ICE CCV,:R 1 .2'5 1 •o~5 1 .25 1.25 1 .25 1.25 1.2 5 1.25 1 .2<1•~~ $1.8 BILLION (1982 7% DOLLARS) INFLATION ST ATE APPROPRIATION SCENARIO AND 10%INTEREST SHEET 3 OF 6 TABLE D.32 ~~¢*¢·:~*~:~·~~:~¢*~¢~*(::~~:¢*D*~~~·~:~**¢~~*****;)~¢**¢*~*¢~~***~e~~**~~¢¢~~~~~**~****~~~¢**~e*¢*~~***~;~:)(~*¢~~C~~*~O**~C(~~C~~C~~*~~¢ ~~1~!~~a~!ic~~I~~~~1~~cl!~~~t~~~J;il;~.~~~IA~!iAe~1~1~o~~~~i;!=~~~11~~*J5;!~J~=SiJ.I~~;~C1~£~J.!~~I~.S~.,•••~ooo&.ci~~~~~;~~.c. 1]'I"""Y "Ii ,21 i:\L'."ICf-,'llL; l.lJ~HL,HIC'.H,';[)' r l ~)J let -,~J L L :; 2 C I 'j 0449 2 ~• I 3 9".)4 ..tJ 3 212.7'1 ,,0 I 6 oele> p.1710_2.15 223.78 2017 lOIC 2CI9 C~S~fLCh SG~~~R~ ===(1~ILllr~I==== t7C~t760 tE7~ 20.tl 1~.2e 17.e9 IIO~.~C 1181.71 126~.~3 2?7.f.~'27.Q9 2Zt.22 2Cle t.s e 4!t.t31;_2.~4 22~.~t 2C21 6')84 15.t 9 H47.64 227.10:: HUL 14~~C2 C.OCC.('c C.CC 15.9[.t 3271~.1 22C.C 271:5.5 -----INC'~'----------------- ';1 '.'c'lr',Jr In L ~s~Cf:C°~11':(cr;',rs !7 I)P "\T/\t;r,l'"",\C 'H R sf [t,~,.I:S ,"~FU~[;5 ~)L ~S I Ii r R S 1 r:'}:;HCOT T ~RfI.C[e1 71 l:c S I'd P,Sf r:'.J L'~~G lER:1 CEeT ~)f.:j r T r.:..[1 t-.I N(':;F~.J U ')F-[:(~ - - ---(I,SH 5 C'J I,(f t.~J ,,5 I:- --- ~.,r.I..S}4 1\4l.l~t-·,::=f'Ci~':')")E,il.S,',:TI\1"CC'nRl,UT!'l., 1~LUNG T:~RM SEeT D:{~\~~(~1~3 ~/,''II,':RC \0 C ·~I3T ~f'.A',I"'C··lr\jS l°CI.I 14!l.6 IJ54.'>27.r 69 •• l 73111 ~ 433.<; 43g.'l ":.,0 c.o t,~.S 1513.5 I ';(;.9 1 ?s (;.10 Z~.8 1·;•c ~:5.q 4:;t:.5 4:')t ,,5 0.0 ollie 44 •~ 15.26.'; 1(;7 •'J l'"'.0I.9 2 It 5 ~f.~ 475.9 475.9C.Oa.n 4 C• 1 1:;(1 C .4 17'J.1- 13H:~ fI,Z .'3 c15.1 417.3 ~07.3 C.G C.O /15.4 15~~e~ 192.2 I H?C~f •5 87.C HI.£::--------'i2C.e S 2C.ac.r. C.C 4,.7 1571.C 2 C~.!: n~~:2 C;2.( H 5.e 546.t: 546 .tC•C c.cH.E I ?tt.5 41.7 'l5.~ 737.4--------575.C ':7'5.Cc.c O.C 3 1.4 292~8.t_It.7 1e37.1 21353.2 8074.9 E074.9 26n.3 1C 125.t<;SC.C ;41 3~ t ~ ~( 1 .J ILL:/,) I.I.,{, ...}~ 171 .;:!t 17 'J TOT ~L S fJ U ~(E S 'J;:-r L ~I~:S L'~C PIT~L fXPf~~ITU~~ L ,=-t;~~~C I~~.'\h 0 FU f\j I::S L .~J 0 e1 ~~[.P to V II'~r~T S l,_,P y":E,'IT 1'::;TAF ,~r,<;i'S iJr~q L ';S (::r FIe 1 f I';r -:~T T r::~to'C::ET C\SH ~~C 'V "C.'G ----~:AL_\~F\'rf SH"I ~------~--- ~r~5r,,,\/~,~:\J:'C(~·:T ;'Uf\'O 'JTH:~:\Ie:1K I~,G (I.I Hl C J\C :,1 S lJ 90 L I)S R [T I":r, (~~.C\PIT~L ~K~~~lTU~E 1,71 ..It 140,.0 -4G.5 176.~ C.1 I I 3.4 C.O 1 I l .4 2.7.6 '.'t 2 ..1C.O 1';(.b,~..1 5 C I •~ 1 '1.5 4 •~I 4.C C.C IfJ3.Co•c le3.C ) I fl .5 ~~/:..2 C.C HU1.t=:::===;:-::. 5 II.•0 17 C.6,;Col 2l?'; 0.0 ,]l.tt ~.I] qt.<J ~'•.:~e ~~4.0c.n 1~1'l3.2 5 -1 2 • 7 I fZ ./, 4 5.4 234.8 C.C 7~.9 C.O 79.9 3t 4.6 505.5a.o 14fj:}C.f\ ==:::;;:;-=-=: '>7C.5 1 g !It It 4";.1 25 e•3 C.C-------- t7.1 C.C n.1 3SC.2 52'i",1e.c 1<IH.2 5 e ~..~ lC g •C 3E.E 2 P.4 01 C.C 53.5C.C ~3 •~ 4 17 •~ 541.2 C• C 1~3!}~.2=====:;;::: 6C(;.~ 22 ~.7 31.4 ~12.S C.C 3n.~ G.C )~.~ 446.1 5 4 ~•") C.C 15~C~.~ 21E77.~ 156C?.9 9~C.C 3C(4.1 C.C 2214.9O.C 221~.'7 44 t .7 543.3 C • C l~tee.S '",').~Af)I T ,/\L ::t';"'L,.)'(\~L..IjZC7.9 1°412.3 15623.0 l~e51.C I[G9E.G If343.e If59~.~1~5~2.~ ===~~~=========~===========~~========;=======~==========~======= l 'Te [;'\T'I'''TI,'' Z T,\LJ -5 '~1r r:i I;C-:', j n CUfSTH,JINC-:;IiCPT HR~; 4 eT nUTSfAN01~G-Ln~G TEqM ".2 '.!\:,~gl DeeT ;)I:A'.~wl'[~H~11902 ;i·~)CU~~.C~eT ~RArlr,,")=,;':-j fl'182 Sl1 )E~T S~AVICE ([V~R 2 7. J 2. ~.a J. r::.:::. J,8',.1 1 •~'1 2 37.) 3 7S.6 84.1e64.7 C.C 3;.~4 • 1 I .25 2:",7.3 3,,59.1 ~24.~ e1SI.3 iJ.C 398'1.1 1.2~ 21:'17 •3 437701 nO.2 Hlt.S C.O 39!J4.1 1.25 2,>f:7.3 483':.7 91~.'1 765e.2 C.C 3"e4.1 1.25 26F.1.3 t'323.8 ~5e.t 737401 c.e 3984.1 1.25 26t17.1 5%0.C 9'1C.C 7f61.t O.C 3984.1 I.2 ~ 20 n.J ~2t8.C '7'7C.C 7Ctl.t 39 8401 39E4.1 C.Oo 'I 1 $1.8 BILLION (1982 DOLLARS)STATE APPROPRIATION SCENARIO 7%INFLATION AND 10%INTEREST SHEET 4 OF 6 j TABLE 0.32 1 1 1 -1 1 1 -1 1 1 I 1 1 1 1 ANNUAL PROJECT COSTS Mills/kWh Cost in Real $1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Operating Expenses 8 10 10 11 11 12 13 14 14 15 Capital Renewals 0 8 9 10 10 11 1-2 12 13 9 Debt Service Cost 111 132 130 129 129 128 128 127 126 224 Total 119 140 149 150 150 151 153 153 153 248 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Operatin9 Expenses 16 17 18 18 19 20 20 21 22 22 Capital Renewals 14 15 15 16 17 17 18 19 19 20 Debt Service Cost 225 219 214 207 201 195 189 184 179 174 Total 255 251 247 241 237 232 227 224 220 216 2013 ,2014 2015 2016 2017 2018 2019 2020 2021 Operating Expenses 23 24 25 26 27 29 30 32 34 Capital Renewals 21 22 23 24 25 27 28 30 32 Debt Service Cost 171 166 163 159 157 155 153 150 150 Total 215 212 211 209 209 211 211 212 216 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 TABLE D.32 ANNUAL PROJECT COSTS Mills/kWh Cost in Real i 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Operating Expenses 4 4 4 4 4 4 4 4 4 4 Capital Renewals 0 4 4 4 4 4 4 4 3 2 Debt Service Cost 51 57 52 48 45 42 39 36 34 56 Total 55 65 60 56 53 48 47 44 41 62 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Operating Expenses 4 4 4 4 3 3 3 3 3 3 Capital Renewals 3 3 3 3 3 3 3 3 3 3 Debt Service Cost 53 48 44 40 36 32 30 27 24 22 Total 60 55 51 47 42 38 36 33 31 28 2013 2014 2015 2016 2017 2018 2019 2020 2021 Operating Expenses 3 3 3 3 2 2 2 2 2 Capital Renewals 3 2 2 2 2 2 2 2 2 Debt Service Cost 20 18 17 15 14 13 12 11 10 Tota 1 26 23 22 20 18 17 16 15 14 NOTE:FOR ANNUAL ENERGY SOLD,SEE LINE 73 OF SHEET 1-3 OF THIS TABLE ANNUAL ENERGY COST $1.8 BILLION STATE APPROPRIATION SCENARIO 7%INFLATION AND 10%INTEREST SHEET 6 OF 6 TABLE D.32 (S8Vll00 :!O SNOlllIW)MOl:!HSV:)lVnNNV a !oo• oa..o •! r".~1111 ..; ....~ ~ a !..•c.....~ •I! ••• ..•~ ·•I! ..•I! ••I! ..•• .... ~ ••• 11111/I!Illlllllllllllllll'II~ill!IIIIII!llllll;II~llllj~~i[I!II/II~ [~ilj~j~t ~:.:.;:::: II~!lilllllllI11!!1111 j~/~illlllilli :illlll'II!lllllil~IIII\III!!11111111111!1111!llllllllIlllllr , \ r- I ..... ag• ...; .. a 8 0 a 0 0 a aa0ia00....!!2 ........ (S8V1100 :!O SN0I11IW)M01:::l HSV:)31\1IVlnWn:) 200320022001200019991998199719961995199419931992 .-. (J)400 .-. UJa: ~ ...J CUMULATIVE CASH flOW '\g ~15 0 0 I I I I I I """""""""";';'V -300 u. =ilill:llilillllllllllllill:!II~1I 2 00 o (J) Zo ...J ---l ::E....... YEARS DEVIL CANYON DEVELOPMENT CUMULATIVE AND ANNUAL CASH FLOW JANUARY,1982 DOLLARS FIGURE 0.2 !J '1 ,'1""" C') 0-LlJ (S !:lVll00.:fO SNOlll1lf>J)ex: M01:f HSIfQ lVrlNNV :) c;..0 0 0 ..0 ..0 0 0 0 ..,~'"..'"0 ..0 ::~'"..~u..'"..........'""!!"0 I .. 1 0 I 0 I -l '"~.- I .. I .... 0 N I 5 I ..l-N SI ..(J..w.... N J ~..0.. ~a:..a.... ~I-W..(J a:..UJ~~- -:l I-..0 Z en.. ~a:UJ a:-..a..3:<.. ~...J •(J 0 ...J..-...J 0~ex:...I-u..0-......(J :c~0:UJ C\I 4 en CO....~...J <Q').. ~w (Jr-,.....0 ~ex:...J >- Cl <a: 0 =><..>-!:c z =>..Z Z.. ~<<<..Z J,......,I-0<5!- ~en UJ..=>>~en - '"I-..<~ ...J '"=>., ~~•=>., ~(J..., ~ '"; 0 0 ..0 ..0 ......0 ....8 .", .'1"""0 0 ....0 ....0 0 0 ..0 '"0 '"0 ....'"0 n 0 !!2 co..'"co co ••....N N CS!:lVll00 :fO SNOlllIW) M01:f HSVQ 31\IllilnWnQ 9000 t----,.--------r-----,--------r------,--------,. 8000 t----+------+-----+------+------+--------l 202020152011:)2005200019931995 1 000 +------"+----+-------+---+----+-------+------+-----~ 20 00 +----'>.I----+-------+-----'--1----+-------+------+-----~ ALONE --+----rWATANA AND DEVIL CANYON-----i-!.....~ 7000 +-----j--------f------j--------f--- 6000 ~vO~ THERMAL AND ~X'..... J::OTHER HYDRO vl'~.s:GENERATION ICl 5000:>- C a::: wzw 4000 ENERGY DELIVERIES FROM Sl:JSISTNA 3000 YEARS ENERGY DEMAND AND DELIVERIES FROM SUSITNA FIGURE D.4 1 -]-,)-I ]1 ]1 SYSTEM THERMAL COSTS AVOIDED BY DEVELOPING SUSITNA COMPARED WITH BEST THERMAL OPTION IN MILLS PER UNIT OF SUSITNA OUTPUT IN CURRENT DOLLARS _/"'-AVOIDS COST OF 200 II DEVIL CANYON ON STREA-M 1;200~t-..MW COALpFIRED UNIT I 1 .- IN.CREASING THERMAL ~---- FUEL COSTS AVOIDED'------/"-1 / AVOIDS COSTS OF FURTHER I y""'- 200 MW COAL~FIRED UNITS '/~ 2020 .------ 201520102005 / I 2000 / ~/ -~-------/-----7~4= _.-/-- WATANA ON STREAM IN 19 93- 94 o 800 r-..c ~700 ~ "- C/} -J -J 600 ~ '-' C/} UJ 500 0 a: 0- n 400 Z« C/)300 t- C/} 0 0 200 >- CJa: UJ 100Z UJ YEARS SYSTEM THERMAL COSTS AVOIDED BY DEVELOPING SUSITNA FIGURE 0.5 DATA ON DIFFERENT THERMAL GENERATING SOURCES COMPUTER MODELS TO EVALUATE· SITE SELECTION PREVIOUS STUDIES CRITERIA ECONOMICS ENVIRONMENTAL 4 ITERATIONS ENGINEERING LAYOUTS AND COST STUDIES OBJECTIVE ECONOMICS -POWER AND ENERGY YIELDS -SYSTEM WIDE ECONOMICS CRITERIA ECONOMICS CH.K.S a THERMAL LEGEND SNOW (S) BRUSKASNA (B) KEETNA (K) CACHE (CA) BROWNE (6R) TALKEETNA -2 (T-2) HICKS (H) CHAKACHAMNA (C H ) ALLISON CREEK (AC) STRANOLINE LAKE (SL) •CH.K •CH t K.S - CH• K •S.SL.AC •CH.K •S •SL.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 ""'", ",..."O~~I-~~ 1••-,.,- MilES - - 6 G 0 0·6:5 ...2'·tOO"'");00 ..... I.SlDA"-C\.I~L.'3."'."tlS.(~S 2&.SOlO_3~.LA"E..,LO.E~8(LUGA l4.COAL 21..E.....LOWEll 40.TQttICH1T",• 3 •...C_EQ L4KE,Clt•I~.CIolLrL..lT'lIlLl,21.Gf:lISTLE 41.T(...rNA 4..£~...'SOlll C"~'..OHOO 2'.TA_II.42.CAT><f:DlIAl.llI..U1'S ~.:-E5CO,T LAIIE 2 17.LO.EIt C""l.InoA Xl.8l1U51lA"'A 43.JQ....SQM ~.GIt ...T LAIlE II.CACM(".I(A..f1$Ml1A ,,~44._E r "CCLLiM IAl'".G"EE 'ISTOI'o(32.u.l'f:~eELUGA 4'•JUNCTIO ..IS 8.v~E~OlELU[JUA..20.TAuUTNA 2 33.COf'f££46.v.oc_IS,."OWE.C"EE.I I.GIIA",n QOJI'G(301.GUl.UMA It.47.TAZILOlA 10."LvEII LA.(u."ur.....35.IllUr_4 ••Il("A'LA"" 11 •SO ..01110"GULCH 23.SKEU'cltnlC '6.8I1AO!..£T LAKE .,.C",""ACW"'-" '2.TU51\11O£_2 ...'.Wl"T"A '7.",C,,'S "TE 25.1 Al.IlCI<Ul.ITNA 3••LOWE SELECTED AL TERNATJVE HYDROELECTRIC SITES FIGURE D.7 PREVIOUS STUDIES UNIT TYPE SELECTION COAL:100 MW 250 MW 500 MW COMBINED CYCLE I 2~O 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 4 STEP NUMBER IN STANDARD PROCESS (APPENDIX A) FORMULATION OF PLANS INCORPORATING ALL-THERMAL GENERATION FIGURE 0.8 '1 ,3,-------------------------------------- 2020 2020 2010 20102000 YEAR 2000 YEAR EX ISTING &COMMITTED 1990 1990 "'~~1!'II!111i!~'lllllllll!III~!!!I~il11il!~!~I!III!III~!!111!11!'ll~11111!lll!11111!!lllllllI1i!I!I!I!!!I!I!I'I!1IIIil'~!I'!1111!1:111!il!llljlj!j!'!II!I!I!iIII .'. ;:~:~~~rmmi ~:~:~~~~l ~;:;~illjlj·i) ALTERNATIVE GENERATION SCENARIO REFERENCE CASE LOAD FORECAST :,}{{rtt:!illlll!:I~I!'liilli!i!'llillilliillll!illl!11111'111 LEGEND c=J HYDROELECTRIC f::::::::::::l COAL FIRED THERMAL ~GAS FIRED THERMAL ..OIL FIRED THERMAL (NOT SHOWN ON ENERGY DIAGRAM} +------------------------1955 ---------11 1949 O+----_----_-----t-----__I'------+----"---+-----_-----1 1980 - 6 r- J: 3 Cl 0 0 ;:4 •>--Cla: UJz UJ 2 ..-3 ~ 0 2 0 0.--. >- I- a 1"""-«a.1«a- 0 ~1980I "'""8 FIGURE 0.9 BOO~--------~~-- 100 I I ~~~' I I t_7 //I-,- I I 100%DEBT FINANCING MILL RATE COST BEST THERMAL OPTION 7%INFLATION, 7 II'O%I"1ERE81~// 500 I I .~/'"I I 100%DEBT FINANCING I $1.8 BILLION STATE CONTRIBUTION SUSITNA MILL RATE COST SUSITNA MILL RATE COST 400-+-WITH 7%INFLATION,--WITH 1%INFLATION,~ 10%INTEREST 10%INTEREST ......,'{{\\~\~~lll\~;l\l\l;\;ll~l~l~lll~l~)~::-:'.I \ 600 I --+-I 300 ~·······:····:···~';';';:'~·:;.·.·.·.·.·.·.·.f···················..·:·:·:·:·:·:·:·:·;;;;:O:·;·7;·:·:·7:"YJ::=-::--------i---==--=;;:;:::::::j:==:t rlNFlATIONARY FINANpl'N'G''DEFJCIT:~:}}~{:~::;~,-.- -_._ ·;::::!:::;::!:S@billU@@¥7.@:""'''Y --------------- - - - --- - - - 200 .::':.:.:':.:.:.::''',MILL RAT \::-}:::::/.-.I BEST THERMAL OPTION'}:::=::Z·-------0%INFLATlON.3%INTEREST 1 00 ~NEGLIGIS E FINANCING DEFICIT ITH ZERO INFLATION-.....,.-.-_...-.._.. r-->.c ~ -"..... (J) --J ...J ::i: (J) UJo a:a.. oz« (J) ~ (J) oo >- Cla: UJz UJ SUSITNA COST WITH 0%INFLATION ,3h IN TEA EST o I I I I I I 94 2000 2005 2010 2015 2020 YEARS ENERGY COST COMPARISON-Q AND 7%INFLATION FIGURE D.10 l 1 1 '\ - SUSITNA HYDROELECTRIC PROJECT VOLUME 1 EXHIBIT 0,APPENDIX 0-1 FUELS PRICII~G STUDIES - - i""'" I ..... .-. - APPENDIX D-l FUELS PRICING STUDIES Introduction There are thermal altern at i ves to the Sus itn a Hydroel ectric Proj ect fuel ed 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 potent i a1 fuels 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 a ltern at i ves. 1.Natur alGas 1.1 Resources and Reserves Known recoverable reserves of natural gas are located in the Cook Inl et area near Anchorage and on Al aska I 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 bel ieved to exist in the Cook Inl et area and al so in the Gul f of Al aska where no gas has·been found to date.Estimates of potenti al gas resources in these areas have been made by the United States Geological Survey and the Al aska 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 0-1.1.Estimated recoverable reserves from the Cook Inlet fields and the commitment status of those reserves are shown in Fi g ur e1 )0*.1.2.This table has been developed from an earlier study~and,updated and rearranged to refl ect current conditions.Recoverable reserves are froJTJ..)the Alaska Oil &Gas Conservation Commission's latest estimate.~L New (lO,ntracts between Enstar and Shell &Marathon are shown i)in Figure 0-1.2 as well as the five-year extension of the Phill i ps/Marirahon 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 incl uded as uncommitted reserves, since PALNGls 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 0-1.2 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 Earl ier estimates of additional natural gas resources in the Cook(~qlet area ranged from 6.7 trillion cubic feet (TCF)to 29.2 TCF.)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 Al aska presents estimates of undiscovered gas and (%~l 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 0-1.1. The Department also estimated "economically recoverable"resources by assuming a recovery factor of 0.9 and a min imum commerci al deposit size of 200 BCF.These are also presented in Table D-l.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 Est imated recoverab 1e natur algas 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 )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 pipel ine 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 0-1.3).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 prevail ing at the time of the assessment.l For their lowest imate,there is a probabi 1 ity of 95%that the est imated val ue 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 low 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:l ) 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 avail abil ity of Gulf of Al aska gas for electrical generation is at this time highly speculative.First,the gas (if D1-3 any}must be found and developed;second,a pipeline must be constructed to deliver the gas to where electric generation would take pl ace and third,the del ivered 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,1 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 In 1et gas for the past fi ve years is shown in Table 0-1.2.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 sal es are for export to Japan and the manufactured ammoni a/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 mil itary 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 uti 1 ity 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 popul ation 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 - - - (b) The item,Other Sales,shown in Table 0-1.2 is a residual figure according to the Alaska Department of Natural Resources and is the d iff erence between total sal es as pub 1 i shed by the Oi 1 and Gas Commission and the sum of gas obtained from the utilities, Phillips/Marathon,Collier Chemical and other large users. Cook Inlet Future Use The future consumption of Cook Inlet gas depends on the gas needs of the major users and their abil ity 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 regul atory 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 0-1.2).It is highly probable that both entities wi 11 obtain enough of the uncommitted gas in Figure 0-1.2 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 Coll i er are therefore estimated to consume 62 BCF and 55 BCF respectively per year from 1982 through 2010. At present,Enstar has enough gas under contract to serve its retai 1 customers until after the year 2000,but si nce Enstar al so sells gas to the military,Chugach Electric Association,and Anchorage Municipal Light and Power for electric generation,it may have to seek add it ional 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 01-5 to a State of t't~fka estimate which provides for a growth rate of 4.7%per year. Gas used in field operations and the residual,t10ther 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 0-1.3. 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 0-1.2)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 quanti ties calculated for electrical generation incorporate electrical energy use from the Reference Case forecast (see Exhipit B,Section 5.4). If the forecast for the OORMean case were assumed,the Cook Inl et proven reserves would provide for generation for a longer period whil e if the forecast for the SHCA Basecase was assumed,proven reserves would last for a shorter period. The forecast annual and cumul ati ve use of gas for each of the major users,and the total use of gas for the Railbelt,is shown in Table 0-1.3.The remaining proven and undiscovered (mean or expected quanti ty)gas resources are al so shown and as can be seen,proven reserves will be exhausted by about 1998,and expected und i scovered resources by about 2007.The est imated use of Cook Inlet proven reserves and undiscovered resources is graphically illustrated in Figure D-1.4. 01-6 .... ~, .-: The data from Table 0-1.3 indicates that relying on all gas-fired electrical generation to provide the Railbelt1s 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 .~) The uncommitted,proven reserves and any undi scovered resources could be acquired by entities not shown in Table 0-1.3,reducing or eliminating the availability of Cook Inlet gas for electric generation.This possibility is discussed next. (c)Competition For Cook Inlet Gas Known potential purchasers for the uncommitted,recoverab 1e and undiscovered Cook Inlet gas reserves,in addition to those shown in Table 0-1.3,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 proj ect to 760 BCF (see Fig ur e 0 -1.2). The FERC has approved the PALNG proj ect,but with the cond it ion that PALNG obtain 1.6 TCF of r~Zrves for Phase I of the project and 2.6 TCF for Phase ILP)Pacific Gas and Electric Company,one of the PALNG partners,does not pl an 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 IIPlant Held for Future Use ll 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 ei ght states to 1ast fi fteen to twenty years.) When all of these factors are considered,it does not appe ar th at the PALNG project will be implemented prior to 1995.The recoverable reserves originally committed to PALNG can,therefore, probab 1y be acqui red by other purchasers such as Chugach El ectr ic Association and Enstar. The proposed TAGS project would build a natural gas transmission 1i ne from Prudhoe Bay on the North Slope to the Kenai Pen i nsu 1a (near N-ikishka).The gas from the North Slope would b14 Ji quefied and sold to Japan and other Asian countries.t )The proposed project is an alternat i ve method of bri ng i ng North Slope gas to market.If implemented it would el iminate 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 1 iquefaction pl ant 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 1ine from Prudhoe Bay (although shorter transmission and gathering lines 'fJould probably be required).Any estimate of the probabil ity of whether TAGS wi 11 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 current 1y 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 0-1.4 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 01-8 - PJ'8lo: (e) 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. Al aska Natural Gas Transportation System (ANGTS):In this pl an a pipel 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 pipel ine would be constructed from Prudhoe Bay to the Kenai Peninsula where the gas y.lp~)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 pl ant 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 di ameter pi pel ine 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 util ization of ~orth SloP{16)gas and will therefore probably not be lmplemented. North Slope Generation:This proposed plan is an alternative to transporting the gas by some means,for the gas would be util ized in combustion turbines located on the North Slope and the electricity transmitted to the Railbelt !A(17Q..The costs of this pl an are al so bel ieved to be prohibitive.) 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 v ari ous categori es of gas (some categori es wi 11 be dereg ul ated 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 sal e 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 below. (a)Cook Inlet Currently there are four contracts for the sal e/purchase of Cook Inl et gas where the agreements were negot i ated at arms length and the contracts are publ ic documents.These are: (1) (2 ) (3 ) Chugach Electric Assn ./Chevron,ARCa,She,\l)contract for purchase of gas from the Beluga River Field.~8 Enstar/Union,Marathon,ARC0 19yhevron contract for purchase of gas from the Kenai Field.( Enstar/Shel1 20 Pntract for purchase of gas from the Beluga Ri ver Fie 1 d.l ) (4)Enstar/Marathon contract(20Qr purchase of gas from the Kenai and Beaver Creek Fields.\I) The Chug ach contract current pr i ce is about $0.28/MCF and under the terms of the contract is estimated to increase to about $O.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 0-1.2). The Enstar/Union contract current wellhead price is about $O.27/MCF and becomes about $0.64/Mcf when del ivered 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 $O.27/MCF until contracted reserves are taken (estimated to be 1990 by Battelle)or the contract expires which is in 1992.Like 01-10 ~l -f 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 $O.35/MCF beginning in 1986.The base price and the demand charge are to be adj usted annua 11 y based on the pr i ce 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.tLL Estimated Price For New Purchases:If all current and future Railbelt electrical requirements 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 appl ies 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 el ectri c ut il ity requi rements that increase the daily take.Estimated severance taxes of $0.15/MCF and a fixed pipeline charge of $0.30 for pipeline del ivery from Bel uga 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 oi 1 in the year of escal ation versus the price on January 1, 1983.If it were assumed that the generating units were located at the source of gas,the pi pel i ne charge waul d be el iminated giving a Jan.1,1983 price of $2.47/MCF.(See Table 0-1.5). The pri ce in Tab 1e 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 oi 1 to obtain prices for 1993 to 2040 (See Projected Gas Prices Section). Although the pass i b il ity of uncommitted Cook Inlet reserves bei ng 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 oi 1 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.lJ..al to the weighted average pri ce of oi 1 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 t~ (b) Conditioning,liquefaction,and shipping cost estimates were recently developed by the Governor's Economic Committee in their study of a Trans Al aska 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/I'vlCF from the TAGS study are therefore believed to be representative for estimating the wellhead price of Cook Inlet gas where LNG export opportunities ex i st. The estimated,netback,wellhead price of Cook Inlet gas for LNG export is shown in Table 0-1.6.The price would vary depending on the average price of oil del ivered 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 0-1.5)since the utilities would have to outbid potential LNG exporters. North Slope The relevant price of North Slope gas for use in Railbelt electrical generation is the "del ivered price ll ,that is,·the price of gas delivered to generating units located near the electric load centers or if generat i on were to take pl ace on the North Slope,the equivalent price for electricity delivered to the load centers. The del ivered 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 reinj ect as they are present 1y doi ng 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 del iver 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 del ivery,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,"Production and Use of Natural Gas". Al aska Natural Gas Transportation System (ANGTS):The ANGTS project if constructed as currently proposed,would del iver North Slope gas to the lower fortyei ght states by means of a 1arge diameter pipeline traversing central Alaska,and Canada.A portion of the proposed line would be routed near Fairbanks,Alaska.Due to the line's proximity to Fairbanks,it would be feasible to construct a 1 ateral 1 ine from the main ANGTS trunk1 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 Battell e,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'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~60ffice (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's life,the costs would be about $3.87/M~IBtu in 1983 doll ars. In a separate 1983 study,the General Accounting Office (Study II) has also estimated (291J)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 Sattel 1e to determine del ivered 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 $S.10/MMBtu.The cost estimates of Battelle and the GAO are summarized below in 1983 dollars per MMBtu. 01-14 Max imum Transportat ion Maximum Tota 1 Cost Est imate Costs Well head Price Del ivered 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 est imates include severance or state of Al aska property taxes.These taxes are roughly estimated to total somewhere between $0.50 and $1.00/MMBtu. The estimated costs del ivered to Fairbanks are well above the Cook Inl et 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 est imated from information in the TAGS report.Th is information is presented in Table 0-1.7 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 $S.OO/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 $5.85/1V11V18tu 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/MM8tu.*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 bT2 g)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/MM8tu)provides a delivered cost in Fairbanks of $6.00/MM8tu.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 incurrlng 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 al so been estimated 9~%)they are about 80%of the cost of the gas transmission lines.~Based on this,an equivalent lI gas ll 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 lI equ ivalent delivered ll 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 0-1.8.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 do 11 ar s . *Thi s 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 ,- 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 selected is to ti e the pri ce of natural gas to the worl d price of oil since the two fuels can be substituted in many cases and particul arly since the recent Enstar gas purchase contract price is tied to the price of oi 1.The Enstar price was used as the 1983 est imated pri ce of gas for the Cook Inlet area and it is assumed to be representat i ve of future contracts for Cook In 1et uncommitted and undiscovered gas. If North Slope gas is sold as LNG to Japan or Korea,the del ivered 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 0-1.5 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 0-1.9. The future price of North Slope natural gas was calculated by escalating the base 1983 price from Table 0-1.8 with the same world oil price change scenarios used for Cook Inlet gas.The estimated future prices are shown in Table 0-1.10. The natural gas pri ces from Tab 1es 0-1.9 and 0-1.10 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 ceil ing prices which can lawfully be changed for specific categories of gas production;extends federal price controls over the interstate market to incl ude intrastate gas;and deregul ates as of November 1,1979 the price of certain categories of "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 bi 11,appearing as 5.615 in the Senate and ,as H.R.1760 in the House.It would deregulate the price of 01-17 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 proposal s 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 provisions.Second,proposed legislative changes either to accelerate deregul ation 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,1I 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 potenti ally 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 al so addressed. (i)Chevron,ARCO,Shell Contract.Chugach Electnc o-op as a contact wlth hevron,ARCa and Shell for purchase of Beluga field gas,in the Cook Inlet area. Dl-18 ,~' ,- - 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 NGPAls 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 ceil i ng pri ce 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/ft 3 )obviously is lower than the Section 102 price.Therefore,in accordance with Sect i on 105,the contract pri ce must serve as the cei 1i ng 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 pri ces wi 11 on 1y be deregu 1ated if the pri ce 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 $O.64/Mcf.As such~it too is governed by Section 105 of the NGPA.As explained in the di scussi on of the Chugach/Chevron contract under Sect i on 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. (i i i)Enstar /She 11,Enstar /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 Sect ion 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. 01-19 (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 categori es 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 i on 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 Categori es of Natural Gas.The base pri ce 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 (O-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,AReO,Shell contract would undoubtedly be abrogated by the producers if the Administration bill were 01-20 r~-' r~'-' (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 1e 0-1.9). 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 val ue. The Enstar/Shell and Enstar/Marathon contracts signed in Dec. 1982 mayor 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/IV1CF (plus $0.35/MCF beginning in 1986)changes ~'Jith 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 0-1.9 -Reference Case).The estimated maximum price that will be obtainable for Cook In 1et gas if deregul at i on occurs is di scussed in a 1ater 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 woul d deregul ate New Natur al 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 escal ation cl auses in the Enstar/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 Al aska.The greatest potential effect would be on Cook Inlet gas prices where producers would undoubtedly exerci se their market out rights in 1985 for two of the existing contracts and possibly for the remai n ing two.There woul d probab 1y be no effect on the pr i ce for future sales of North Slope gas for the wellhead price of that gas 01-21 is dictated by the cost to del iver 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 associ ated with coal-fired generation.The capital and operating and maintenance expenses for a gas-fired unit can al so 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 gener at ion. The calculation of an indifferent gas fuel price is presented in Figure 0-1.5.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/MM8tu.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 deregul ated 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 r7"'"'-, 1'0"'"'-\ 1.6 References and Notes 1.Battelle Pacific Northwest Laboratories.Rai1be1t Electric Power Alternative Study:Fossil Fuel Availability and Price Forecasts, Volume VII,March 1982. 2.1982 Statistical Report,State of Alaska,Alaska Oil and Gas Conservation Commission,p.24. 3.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."Japan to Keep Phillips Gas Connection",Anchorage Daily News, Tuesday,January 4,1983. 5.Sweeney,et a1.,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.Letter from Mr.Ross G.Schaff,State Geologist,Department of Natural Resources,Division of Geo10gic~and Geophysical Surveys, to Mr.Eric P.You1d,Executive Director,Alaska Power Authority, February 1,1983. 7.Historical and Projected Oil &Gas Consumption,January 1983, State of Alaska,Department of Natural Resources,Division of Mi ner a1s and Energy Man agement,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 Deve10pment,.Division of Energy and Power Development,State of Alaska,p.1-13. 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.,"Future Gas Supplies",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,Ope Cit.p.A.1O 20.See Reference 3. 21.Battelle,Ope 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). 01-24 - - 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 1iterature reviewed incl uded 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 marketi ng of Al askan 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 al so has lesser deposits on the Kenai Peninsul a,in the northwest and in the Matanuska Valley.Al aska deposits,in total,contain some 130 billion tons of resources (Averitt,1973),and 6 billion tons of reserves as shown in Table 0-2.1.The Nenana and Beluga fields are the most economically promising Alaska deposits as they are very large and have favorabl e 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 al so 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 0-2.2.Its subbituminous coal ranges in qual ity from 7400-8200 Btu/lb.It is high in moisture content,low in sulfur content,and very reactive (see Table 0-2.3).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 0-2.4.Bel uga 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. 01-25 2.2 Present and Potential Alaskan Coal Production Currently there is only one significant producing mine in Al aska,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 (Sworts,1983).The FMUS capacity shown in Table 0-2.5 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 it s ex i st i ng equ i pment,has a prod uct i on capac ity of 1.7-2.0 million tons/yr.Much of that capacity would be employed when the Suneel Al aska 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 pl ans 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. Di amond Alaska Coal Co.hol ds leases on 20 thousand acres of 1and (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 facil ities,and power generation facil ities.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). 01-26 .- 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 Al askan 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 pnclng 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/II1MBtu.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/IVlMBtu 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 mine 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. Thi s pricing perspective of the additional two mill ion 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/rJIMBtu 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 pl ace,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 Nen an a Wi 11 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 ..... - -i base coal prices for use in power plant analysis are therefore $1.72-$1.91/MMBtu. (b)Beluga Field The methods for estimating the price of coal from the Bel uga 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 small er 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 thi s fi gure ill ustrates,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.I"1RI forecasts a smaller total coal market in Japan in 1990,some 72.7 million tons (vs.Sherman H. Clark1s 108.1 million tons).MRI estimates that the U.S.share of that Japanese market is 11.1 mill i on tons,as is shown in Table 0-2.6. There are other estimates of the export market in the Pacific Rim countri es.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 mi 11 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 Al askan 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 "dwarf current production"in Alaska by the 1990'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 Suneel Al aska KEPCO contract.Thi s 15-year contract demonstrates that Alaskan coal can compete successfully in the Pac if ic Rim. Because of the strong evidence for an export market~particularly in Japan (MRI~1982)~it is essential to place a market value on the Al askan coal.Various "shadow pricing"or "net back" 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 Cl ark (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 0-2.7. Deductions are taken from this value to reflect the lower quality of Al askan coal,and to reflect the transportation costs from Al aska to Japan.The market val ue of Al askan coal FOB Granite Point is $1.78-$1.94/million Btu,as is shown in Table 0-2.8. Frequently it is argued that the market value FOB mine is substantially lower than the market value FOB Port.In arguing thi s case ~all capital and operating charges associ ated with transporting the coal from mine to tidewater have to be deducted from the $1.78-$1.94/million Btu.However if the market value of coal assumes exports,then it necessari ly assumes that the coal transport facilities are in place.The assumption of such transport facil ities 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 Bel uga coal have al so 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 0-2.9.The DI-30 ~'-, - lower bound values range from $1.16/m"11lion Btu,to $l.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 val ue and the production cost val ue 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 Stu/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 woul d forego revenues based on market val ue,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 Bell1ga 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 plant); (4)an investment including a road or conveying system between the mi ne and a power pl ant located at ti dewater. Because of the low level s 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 Fi n anci ng 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 Al aska 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 a1 Pr ice Esc a1 at ion Agreements between coal suppliers and electric utilities for the sale/purchase of coal are usually long term contracts wl1ich include a base price for the coal and a method of escal ation 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 Dl-32 - ..... r "'" 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 escal ati on rates were est imated for ut i 1 i ty coal in Al aska and in the lower 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 ORI~and these are shown in Table 0-2.12. These rates of escal ation can be compared to the real hi storical 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 rel ationship varies for different types of coal which results in different estimated future price escal ation rates.This rel ationship is shown in Figure 0-2.6 where future real escal ati on 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 SHeA estimated real escalation rates for new contract domestic U.S. coal are shown below by period. Dl-33 Period Real Escalation Rate -%/yr. Western Coal Western Lignite 1980-1990 1990-2000 2000-2010 Average 1980-2010 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. ORIls estimated real escalation rates (Spring 1983)for new contract, domestic,U.S.coal are shown below by period (ORI 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 0-2.1).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 ORI 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 ORr 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 Nenana coal that is consumed at other locations are determined by adding transportation costs which are shown in Table 0-2.13.Composite real escalation rates which include transportation costs are shown below for Usibe11i coal used at Nenana and Willow. Location Usibelli mine-mouth Nenana Wi 11 ow Compos ite Real Escalation Rate-%/yr. 2.6 2.3 2.2 ..... -i ~ I Assuming that an export market for the Bel uga fi el d 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 escal ate the estimated $1.86/MMBtu 1983 base price of Bel uga Fiel d coal at the estimated export market rate of escalation of 1.6%/yr. (Table 0-2.12) The resulting fuel prices for Nenana and Bel uga field coal for the period 1983-2010 are shown in Table 0-2.14.There are no known projections of coal prices past the year 2010. If an export market for Beluga coal does not deve lop,the 1983 base price should be assumed to be based on the production costs for a small 1-3 mi 11 ion ton per year mine.Thi s wou1 d result in higher coal costs,especially in the initial years when consumption in the Beluga steam plant would be in the 1 million ton per year range required by one 200 MW unit. While there has been some correl ation between export coal prices and world oil prices historically,such a correlation is tenuous,at best, with respect to utility coal contracts.Technical correlations must accommodate differences which exist between coal and oil fired units in the areas of capital costs ($/kW),operating costs,and fuel purchasing agreements.Further such corre1 ations 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 0-2.14. Real Coal Price Escalation Rate -%/yr. Oil Price Nen an a Fie 1d Beluga Field Scenario Mine 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 OOR 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 real esca 1ati on rate for the years 1983-2010. Even though there is on ly a tenuous corre 1at i on between oi 1 and coa 1 prices,the oil prices for all of these scenarios is so low (all 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 States 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. 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. ...... i I~ - 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 1982.Railbelt Electric Power Fossil Fuel Availability and Price Pacific Northwest Laboratories, 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.1983.Use of North Slope Gas for Heat and Electricity in the Rai lbelt.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.ale 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. 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/'idequate 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 0-3.2. 1./Battelle Pacific Northwest Laboratories.Railbelt 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. 01-40 Tab 1e D-1.1 PRELIMINARY ESTIMATES OF UNDISCOVERED GAS RESOURCES IN PLACE A~2) ECONOMICALLY RECOVERABLE GAS RESOURCES FOR THE COOK INLET BASIN -I Probability _%(2) 99 95 90 75 50 25 10 5 1 In Place 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 0.22 0.43 0.93 1.76 2.78 4.04 4.90 6.83 r - - ..... ..... (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 I,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. Tab 1e 0-1.2 HISTORICAL AND CURRENT PRODUCTION AND USE OF COOK INLET NATURAL GAS QUANTITY -BCF USE 1978 1979 1980 1981 1982 Injection 114.1 119.8 115.4 100.4 103.1 Field Operations: Vented,Used on lease, shrinkage 23.5 17.5 28.0 20.6 21.3 Sales:~.,~-, LNG 60.9 64.1 55.3 68.8 62.9 Ammonia/Urea 48.9 51.7 47.6 53.7 55.3 ~I Power Generation: Utilities 24.6 28.2 28.7 29.1 30.5 "''''--'1 Military 5.1 5.0 4.8 4.6 4.7 Gas Utilities*13.5 14.0 15.5 16.2 17.7 i'"'''''-- Other Sales 3.3 4.8 5.1 5.7 9.5 Total Sales 156.3 167.8 157.0 178.1 180.6 Total 293.9 305.1 300.4 299.1 305.0 ,~l Source:"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. I 1 J )J ].---)·--1 1 1 ]I I 1 Tible D-1.3 ESTIMIl.Tffi l£E (f OXK INLET NATlRJIL CAS BY l£ER -JIlL IjQlJv[S IN BCF Year Em Enstar Field Oper-Electric Generation Total Total Rena in i ng Reserves Phillips/Marathon Collier Retail at ions &Gas ClJTUlative PrO/en Plus Year U£/Plant Ammonia/Urea Sales Other Sales Mi lit<ry All Ot!"Ers Use Gas Use Proven M2an Undi scovered 19a?62 55 ---rrT 25 5 13.4 203.1 203.1 3337.9 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 ))47.9 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 1994 62 55 Xl.I 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)lB76.3 1999 62 55 35.8 25 5 35.1 217.9·3922.6 1658.4 2CXXl 62 55 37.0 25 5 35.8 219.8 4142.4 14:£.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&1.9 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 2roJ 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 6(0),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 1Based on historical use fran Tible 0-1.2 inl teleptune conversations with Mr.Jim Settle of Phillips Petroleum Co.arrJ Mr.George Ford of Collier Chanical. 2Estimate JrCNided by Mr.Harold Schnidt,VP Enstar Co"Ftil.14,1983.Inc li.KEs sales to Mataruska Valley custarers beginnirg in 1986.ConsurptiOl fran 1991-2010 (Yojected by Harza/Ebasco at avera~9"Mh rates in Enst<r estimates. 3t:stirnate based 01 historic use stu...,in Toole 0-1.2. 4Estirnate based on historic use stu...,in Tible 0-1.2., 5Calculated based 01 t!"E Reference Case load am energy fom:ast;inclusion of ~neration fran Eklutna,Coq:ler Lake arrJ Bra:lley Lake hydro units and I-Ealy coal unit;and assLlTffl average Railbelt !"Eat rates of 15,000 Btu/kW1 fran 1982-1995 \\I1ien includes older,hi91 heat rate mits,am 8,500 Btu/kl-Al fran 1996-2010,\\hich assure;Jredaronately carbined Cjcle mits. 6Proven reserves of 3,541 BCF on Jan 1,1982.See Exhibit D-1.1.. 7IncllJ(les ITCNen revenues of 3,541 RCF plus expected valt.e for mdiscCNere:1 a:onanically n~:CNer~)le reserves frml Figlre 0-1.1. Tab 1e 0-1.4 CURRENT PRODUCTION AND USE OF NORTH SLOPE GAS FOR 1982 Use Quanity -BCF Injection 671.0 Field Operations: Vented,Used on shrinkage 50.2 Sales Power generation (civilian)0.4 Gas utilities (residential)0.5 Other sales Refi neri es 0.5 Trans Alaska Pipeline System 11.9 Misc.0.2 Total 734.7 Source:II Hi stori ca 1 and Proj ected Oil and Gas Consumpt i on Jan.1983",State of Alaska,Dept.of Natural Resources,Division of Minerals and Energy Management,Table 2.7. r Tab 1e 0-1.5 ESTIMATED BASE PRICES FOR NEW PURCHASES OF UNCOMMITTED AND UNDISCOVERED COOK INLET GAS Without LNG Export Opportunities 1983-1986 1986-1997 Wellhead Price $2.32/Mcf $2.32/Mcf- Additional demand charge(l)0.0 0.35 """Severance tax(2)0.15 0.15 Total (unescal ated)(3)$2.47/Mcf $2.82/Mcf ....charge(4)Transmi ss ion 0.30 0.30 Delivered to Anchorage $2.77 /Mcf $3.12/Mcf.... (l)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 1e 0-1.6 ESTIMATED 1983 BASE PRICES FOR NEW PURCHASES OF UNCOMMITTED AND UNDISCOVERED COOK I NLET GAS With LNG Export Opportunities LNG Price -Japan(l)$5.85/MCF $5.00/IV1CF Less:(2)f'"::;""'---" Conditioning 0.34 0.34 ~1 Liquefaction 0.95 0.95 Shipping 0.71 0.71 Subtotal 2.00 2.00 ~I Maximum Price to Producer(3)$3.85/MCF $3.00/MCF (l)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 Cl,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. .... F""Table 0-1.7 ESTIMATED COST OF NORTH SLOPE NATURAL ""'"GAS FOR ELECTRIC GENERATION AT KENAI I ASSUMING IMPLEMENTATION OF THE TRANS ALASKA GAS SYSTEM (TAGS) (1983 Dollars/MMBtu) Total System Phase I System Low High Low High Tari ff Tari ff Tariff Tariff ~Est imated 1983 LNG Pr i ce Per MI'v1 Btu(l)$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 i"""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 r-Pipeline Costs(5)2.04 2.04 2.79 2.82 2.82 3.86 3.86 3.86 I Wellhead Price 1.81 0.96 0.75 (0.10)0.90 0.05 (0.49)(1.34) .... - - .... (l)LNG prices are delivered prices to Japan and are equivalent to S34/bb1 oil for the $5.85/MMBtu price and $29/bbl oil for the $5.00/MMBtu price. (2)Costs in the report are shown in nominal 1988 dollars which were con- verted to 1983 dollars using an inftation rate of 7%/yr. (3)Minimum price TAGS wouJd accept from uti 1ities for purchase of gas at LNG gas conditioning facility. (4)For pipeline from North Slope to Kenai Peninsula. (5)Maximum price that TAGS would be able to pay North Slope producers. Source:Trans Alaska Gas System:Economics of an Alternative for North Slope Natural Gas,Report by the Governor's Economic Committee on North Slope Gas,January,1983.See Exhibits C1 and C2 and pgs 18 and 46 of the Marketing Study Section . Table 0-1.8 ESTIMATED 1983 DELIVERED COST OF NORTH SLOPE NATURAL GAS FOR RAILBELT ELECTRICAL GENERATION (1983 Dollars/MMBtu) Est imated Value Cost Used Delivery Method.$/MMBtu $/MMBtu ANGTS{l)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 (l)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 "ne tback"approach.See Table 0-1.7. 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 "e quivalent"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 "e quivalent"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 J J )'-1 1 J '1 1 1 TeD1e 0-1.9 (~eet 1 of 2) PROJECTED COO<INLET WELLI£lID NATLRtlL GL\S PRICES ,In 1983 [b11 ars Per MvEtu Reference Case Constant O1ange'Cases (OCR IXR IXR DRI ~ennCl1 C1 ark (~ennCl1 C1 ark Year ·M=an)lJ'Io 50%Spring 1983 Base Case NSD Case)+2/yr Ufo/yr.-1.0/yr •-2 -fJ'Ic,f 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 1.&5 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.ai 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.])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 1.l3 1.64 5.]3 6.09 4.27 4.20 2.73 2.10 1.76 ai 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 Teb le 0-1.9 (Sheet 2 of 2) ffiOJECTEO COO<INLET W£LLHEJlD W\TLRJlL GI\S ffiICES In 1983 [b11 ars Per M13tu Refereoce Case ConstCllt O1Cllge Cases (OCR OCR OCR ffiI ShennCll Cl ark (ShermCl1 C1 ark YEJIR ~an)3J%50'10 Spring 1983 Base Case NSO Case)+2/yr ax,/yr •-La/yr.-2JJYo/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 1.: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 l.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.rn 2040 4.25 1.10 1.12 7.89 8.40 8.13 8.40 2.73 1.54 0.87 (l)Estimated 1983 price of Cook Inlet gas from Teble 0-2.5. (2)Jldditional denand charge of $0.35/M13tu applies from 1986 for~d iJ1d is escalated by price of oil change. "1 1 '1,i J J 1 1 1 J '~~~l cl ')1 '. Table 0-1.10 (Sheet 1 of 2) PROJECTED NCRlH SLOPE DELIVERED NAnRJl.L GAS PRICES In 1983 [b11 ars Per MvBtu Reference Case Constant Ch3l]e Cases ([ffi IXR [ffi eRI Sherman Cl ark (Sherman C1 ark YEAR tlean)30%5a'k Spring 1983 Base Case NSD Case)+2/yr (J'kjyr .-l.O/yr.-2JJ'Myr . I98j(1)If.OO 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 2.05 2.46 4.00 1999 2.04 2.44 4.00 20c0 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 1l.29 .8.13 7.54 4.00 2.9)2.10 Tab le 0-1.10 (Sheet 2 of 2) PROJECTED NCRTH SLOPE OELIVERm NATlRf-\l GAS PRICES In 1983 l:b 11 ars Per rvM8tu Reference Case (OCR OCR OCR ORI Sherman Cl ark Sherman Cl ark YEAR M2an)30'10 50).;Spring 1983 Base Case NSO Case +2/yr CfIo/yr.-l.O/yr .-2.CJ'1o/yr • 2016 4.00 2017 4.00 2018 4.00 2019 4.00 2020 4.65 1.49 1.~9.20 12.16 9.20 8.32 4.00 2.76 1.89 2021 12.16 4.00 2022 12.16 4.00 2023 12.16 4.00 2024 12.16 4.00 2025 4.96 1.49 1.83 9.71 9.91 9.19 4.00 2.62 1.71 2026 12.16 4.00 2027 12.16 4.00 2028 12.16 4.00 2029 12.16 4.00 20J)5.29 1.49 1.73 10.26 12.16 10.67 4.00 2.49 1.55 2031 12.16 10.15 4.00 2.49 1.55 2032 12.16 4.00 2033 12.16 4.00 2034 12.16 4.00 2035 5.64 1.49 1.64 10.84 12.16 11.22 11.20 4.00 2.37 1.40 2036 12.16 4.00 2037 12.16 4.00 2038 12.16 4.00 2039 12.16 4.00 2040 6.02 1.49 1.55 11.45 12.16 11.79 12.37 4.00 2.26 1.26 (l)Estimated 1983 price of North Slope gas fran Table 0-1.8. 1 J Table 0-2.1 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 Tot a1 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 44,063.9 472,713.6 100% Source:Demonstrated Reserve Base of Coal in the United States on January 1,1980. Table 0-2.2 RESERVES AND RESOURCES OF THE NENANA FIELD Reserve/Resource Type Quantity (tons x 10 6 ) Reserve Base 457 Resources Measured 862 Indicated 2,700 Inferred 3,377 Total 6,938~/1"--- ~/Totals do not add due to rounding on measured and inferred. Source:Energy Resources Co.,1980. .~ Table 0-2.3 PROXIMATE AND ULTIMATE ANALYSIS OF NENANA FIELD COAL Proximate Analysis Moisure Ash Volatile Matter Fixed Carbon Ultimate Analysis, As Received (wt %) Weight Percent 26.1 6.4 36.3 31.2 -Hydrogen 3.6 Carbon 47.2 Oxygen 15 . 5 Nitrogen 1.05 Sulfur 0.12 Chlorine Moisture 26.1,...Ash 6.4 Higher Heating Value (Stu/lb) 7,950 .- Source:Hazen Laboratory Analyses for Fairbanks Municipal System . Table 0-2.4 ULTIMATE ANALYSIS OF BELUGA COAL Element/ Compound Analyses (wt %) Stanford2./ Bat tel 1 e.!?J Diamond-Shamrock~/Research Institute Waterfall Seam)Al aska Co a 1 Co. F-'''l Car bon 44.7 45.4 Hydrogen 3.8 2. 9 Nitrogen 0.7 0.7 Oxygen 15.8 14.4 r~'~-' Sulfur 0.2 0.18 0.14 Ash 9.9 16.0 7. 9 Moisture 24.9 21.0 28.0 ,r-"l Higher Heating Value (Btu/lb)7200 7536 7800 a/Stanford Research Institute,1974 ~/Swift,Haskins,and Scott,1980 c/Diamond Shamrock Corporation,1983 Table 0-2.5 COAL FIRED GENERATING CAPACITY IN ALASKA Owner He at Location Rate (Btu/kWh) Capac ity (MW) Golden Valley Healy 13,200 25 Electric Assn. University of Fairbanks 12,000 13 Al aska !"""U.S.Air Force Fairbanks 20,000 20 Ft.Wainwright Fairbanks Fairbanks 13,300-29 Municipal Utility 22,000 System -, Tot a1 N/A 13,000- 22,000 87 - ~- Source:Battelle,Vol VI,1982. Table 0-2.6 PROJECTED NATIONAL SHARES OF JAPANE~~COAL MARKET FOR IMP 0RT SIN THE YE AR 1990- Market Share Nat i on Percentage Mi 11 i on Tons Australia 41.8 30.4 Can ad a 11.9 8.7 United States 15 • 3 11.1 China 16.0 11.6 r"-· USSR 5.6 4.1 /-~- South Africa 4.2 3.0 All Others 5.2 3.8 Tot a 1 100.0 72.7 a/Includes steam co al and metallurgical coal. Source:MRI~1982 Table 0-2.7 THE VALUE OF COAL DELIVERED IN JAPAN BY COAL ORIGIN (Jan.1983 Dollars) Nation of Coal Origination Value of Coal (FOB Port) Shipping Cost ($lton) v.a 1 ue 0 f Co a1 ($!ton)($!million Btu) Australia a / South Africa b / Canada c / $45.00 37.50 45.00 10.50 15.30 10.35 $55.50 52.80 55.35 $2.49 2.37 2.48 .- ""'" - a/From Sherman H.Clark and Associates,1983 b/From friamond Shamrock Corp.;1983 c/Assumes 11,160 Btu/lb per Japanese Specification -in Swift,Haskins,and Scott,1980 . Table 0-2.8 THE MARKET VALUE OF COAL FROM THE BELUGA FIELD FOB GRANITE POINT,ALASKA (Jan.1983 Dollars) Value of Coal ($!Million Btu) The Value of Coal in Japan~/ Price Discount Based upon the impact of lower quality on pl ant capital costs (1.6%)~/ Net Value of Coal in Japan Cost to Transport Coal C / Net Value of Coal at Granite Point Low $2.37 $0.04 $2.33 $0.55 $1.78 ~ $2.49 $0.04 $2.45 $0.51 $1.94 )~, a/From Table 0-2.7 b/S ee 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 Tabl e 0-2.4). p"", r -. ..'" Table 0-2.9 PRODUCTION COST ESTIMATES FOR BELUGA COAL IN 1983 DOLLARS Priceaf Range- $/million Btu Coal Location (FOB) Mine Site (tons/yr) Source .-Di amond A1 as k aE..f 10 million ship 1.20-1.70 Bechtel.s:..f 7. 7 million s hip 1.27-1.65,-P 1 ac er Amex E./5 million mine 1.16-1.74 - r ~fAll previous estimates escalated by the implicit price deflation series.~fSource:Styles,1983. %;source:Bechtel Report for H-B-W (Bechtel,1980). -Source:DOE,1980. - Table D-2.10 BELUGA AREA HYPOTHETICAL MINE SUMMARY OF SELECTED DATA Case 1 Case 2 Production Rate Per Year (Tons) Mine Life At Full Production (Years) Average Stripping Ratio (BCY/Ton) 1,000,000 30 5.93 3,000,000 30 5.89 Per so nne 1 (A v er age) Operatlng Maintenance Salaried Tot a 1 Tons Per Man-Shift (Average) Initial Capital Investment Initial Capital Investment Per Life Of Mine Capital Required 81 74 33 188 21.3 $101,041,000 Annual Ton$101.04 $183,027,000 194 176 56 426 28.2 $186,321,000 $62.11 $353,450,000 $0.60 $0.32 9.19 8.52 1.11 1.08 3.05 1.77 ce 1.24 0.65 1.22 0.79 2.96 1.64 0.35 0.35 $19.72 $15.12 6.10 3.97 $25.82 $19.09 $40.85 $28.52 47.99 33.52 56.40 39.70 $2.72 $1.90 3.20 2.23 3.76 2.65 Average Coal Prices (Per MM Btu)(a) At 10%R.O.R. At 15%R.O.R. At 20%R.O.R. 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 Average Total Cost Average Coal Prices (Per Ton) At 10%R.O.R. At 15%R.O.R. At 20%R.O.R. Average Depreciation Total Cash Costs Note: (a)Assumes 7,500 Btu/Lb. Source:Mining Cost Estimates,Beluga Area Hypothetical Mine, Paul Weir Company,June 27,1983. 1""". Table 0-2.11 SOME PROJECTED REAL ESCALATION RATES FOR COAL PRICES Real Escalation Forecastor Co a1 Rate to 2010 -%-- ..... Battelle (1982)~/Beluga 2. 1 Nenana 2.a Acres (1981 )~./Be 1uga 2.6-Nenana 2.3 Acres (1982 )!;:j Be 1uga 2.5 Nenana 2.7 - - .- - - ~/Secrest and Swift,1982. B./0i e"n e r,1 981 . -~jDiener,1982 . Table 0-2.12 COAL PRICE REAL ESCALATION RATES r,', Author ORI Sherman H. C1 ar k Coal Types New Coal Contracts New Coal Contracts and Spot Market Coal Western Coal a/ Western Lignite~/ Coal Exports Long Term Real Escalation Rate -% 2.6 2.9 2.3 1.6 a/HV of 10,000 Btu/lb. tr/HV of 7,500 Btu/lb. Sources:ORr,1983;Clark,1983. r>;-,--- Table 0-2.13 NENANA COAL TRANSPORTATION COSTS FROM HEALY TO GENERATING PLAN LOCATION (1983 $/MMBtu) Plan t Location Ye ar Nenana Willow Matanuska Anchorage Sew ar d 1983 0.32 O.51 0.60 0.70 0.78 1984 0.30 0.48 0.57 0.67 0.74 1985 0.30 0.48 0.57 0.67 0.75 1986 0.32 0.49 0.58 0.67 0.76 1987 0.33 0.50 0.58 0.68 0.77 1988 0.33 0.50 0.59 0.69 0.78 1989 0.34 0.51 0.60 0.70 0.79 1990 0.34 0.52 0.61 O.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 0.75 0.84 1995 0.36 0.55 0.64 0.75 0.85 1996 0.37 0.55 0.65 0.76 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 0.37 0.56 0.66 0.78 0.88 2000 0.38 0.57 0.67 0.78 0.88 2001 0.38 0.57 0.67 0.79 0.89 2002 0.38 0.57 0.68 0.79 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 0.72 0.84 0.95 2010 0.41 0.61 0.72 0.85 0.95 Notes: ,..~Transportation co st equations:(1983) Healy to: Nen an a =$0.23 +0.09 ( 0 i 1 escalation rates) Willow =0.36 +0.15 ( 0 i 1 escalation rates) Matanuska =0.42 +0.18 ( 0 i 1 escalation rates) Anchorage =0.49 +0.21 ( 0 i 1 escalation rat es ) Seward =0.55 +0.23 (0 il escalation rates) Table 0-2.14 ESTIMATED DELIVERED PRICES OF COAL IN ALASKA BY YEAR (In 1983 $/Btu x10 6 ) Nenana Field Coal Delivered ToYear 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 Mine Mouth (2.6%/yr.) 1.40 1.44 1.47 1.51 1.55 1.59 1.63 1.68 1.72 1.76 1.81 1.86 1.91 1.85 2.01 2.06 2.11 2.17 2.22 2.28 2.34 2.AO 2.46 2.53 2.59 2.66 2.73 2.80 Nen an a (2.2%/yr) 1.72 1.74 1.77 1.83 1.88 1.92 1.97 2.02 2.07 2.11 2. 17 2.22 2.27 2.32 2.38 2.43 2.48 2.55 2.60 2.66 2.73 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 2.05 2.09 2.14 2.20 2.24 2.29 2.35 2.40 2.46 2.50 2.56 2.62 2.67 2.74 2.79 2.85 2.92 2.98 3.05 3.12 3.19 3.26 3.34 3.41 Beluga Field Coal With Exports (1.6%/yr) 1.86 1.89 1.92 1.95 1.98 2.01 2.05 2.08 2.11 2.15 2.18 2.21 2.25 2.29 2.32 2.36 2.40 2.44 2.48 2.51 2.55 2.60 2.64 2.68 2.72 2.77 2.81 2.86 - .-. Table 0-3.1 PRICES OF TURBINE AND DIESEL OIL FOR ELECTRICAL GENERATION -1983 $/MMBtu Locat ion Type Fuel Anchorage Fairbanks Diesel oil -No.loy 6.87 7.46 Turbine oil -No.1-2~/6.23 7.02 Tcble 0-3.2 PROJEClED PRICES (F DIESa.IWJ ~~n£FUEL AT ftJ'[trnAtE Fffi VJlRIOJS OIL PRICE SCENARI~-1983--2010 (1983 $/MvBtu) 1m 1m 1m au St-CA Reference ConstCllt Rates of O1ange M=an n 50'10 Spring 1983 Basecase Case +Z'Iolyr.(JjJyr.-l%/yr.-'do/yr. Year Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine Diesel Turbine l~rj!6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 6.87 6.23 1984 5.69 5.16 5.39 4.89 5.70 5.17 5.97 5.41 6.55 5.94 6.55 5.94 7.01 6.35 6.87 6.23 6.00 6.17 6.73 6.11 1985 5.13 4.88 4.98 4.51 5.84 5.3J 6.41 5.81 6.25 5.66 6.25 5.66 7.15 6.48 6.87 6.23 6.73 6.11 6.60 5.98 1986 5.31 4.81 4.82 4.37 5.23 4.74 6.25 5.66 6.25 5.66 7.29 6.61 6.67 6.04 6.47 5.86 1987 5.21 4.72 4.63 4.20 5.10 4.63 6.25 5.66 6.25 5.66 7.44 6.74 6.60 5.98 6.34 5.75 1988 4.57 4.15 5.a>4.59 6.25 5.66 6.25 5.66 7.59 6.88 6.53 5.92 6.21 5.63 1989 4.53 4.10 5.04 4.57 9.50 8.62 6.43 5.83 7.74 7.02 6.47 5.87 6.09 5.52 1990 5.49 4.98 4.25 3.85 4.99 4.52 8.78 7.97 9.50 8.62 6.63 6.01 7.89 7.16 6.87 6.23 6.40 5.81 5.%5.41 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 9.99 7.68 6.97 8.71 7.90 6.87 6.23 6.09 5.52 5.39 4.89 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 2an 6.24 5.52 3.45 3.15 4.15 3.76 12.69 11.51 12.78 11.58 8.91 8.00 9.62 8.72 6.87 6.23 5.79 5.25 4.87 4.42 1/See Exhibit B Section 5.4 for projected rates of change in oil \rices. ""2"/Prices fran TctJle 0-3.1 I 2 1 "J 1 I ]J 1 I ']'.~.~'] Tcble 0-3.2 ]1 l PROJECTED PRICES a=DIESH..AAD TlR~}NE FUEL AT MCI-ffiAG: FeR VJlRIOOS OIL PRICE SCEr-.LllRIO~-1983-2010 (1983 $/M'13tu) lXR OCR lXR au S/-CA Reference CoostcYIt Rates of O1cY1ge tvEan l:JX 50%Spring 1983 Basecase Case +2/yr.UYJyr.-l%/yr.-2Myr. 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(U) 2007 20ll am 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 .- - ..... MoaUAWKIE, McARTHUR R ¢ KALGIN ISLAND ~ "'i: & (,)0 RAGE CHICKALOON/SA Y ........ . .'.:".«,••'\,--.- 0"""~~.... r_'?-S••••• V'.'~WEST FORK ••••.'.'•••It..._.-.. •••••••••••STERLING KENAI •OIL FIELDS WITH GAS •GAS FIELDS COOK INLET GAS FIELDS FIGURE 0-1.1 256 250(2) 220 285 Collier Phillipsl SOCAL Carbon'Marathon ARCO ~Chemical ~Rental Pac ific Alaska Uncommitted LNG Reserves Assoc. (3) 106(4) 404 99(4) 760(9) o 231 11 13 26 120 22 90 259(8) 17 814 12 23 20 1,654 NIA NIA N/A N/Ao NIA 106 106 ltO(7) 250 360 371 377 (5 ) 285 Chugach Electric ~ 27(6) 159 Enstar Recoverable Reser~es{l} 240 742 11 MIA 13 26 MIA 1,109 22 90 17 951 12 MIA 23 MIA MIA MIA 20 3.541Total Ivan River Ka 1dachabun a Kenai Lewis River McArthur Ri ver Nicolai Creek North Cook Inlet North fork M.Middle Ground Sterling StlJ1lP Lake Swanson River Trail Ridge Tyonek West foreland Bea~er Creek Be luga River Birch Hill Cannery Loop falls Creek Notes (1)Alaska 011 And Gas Conser~atlon Commission. (2)Part of gas will be taken from Kenai field. (3)Participant In exploration underway In 1980. (4)Based on DeGolyer and MacHoughten reserve estimate in 1975. (5)Uncertain royalty status. (6)Royalty gas. (1)This figure assumes that Tokyo Gas Co.and Tokyo Electric Co.contracts will be met by gas from the Cook Inlet fIeld.In actuality,a significant portion is supplied by the Kenai field. (8)Estimate of gas available on blowdown. (9)PALNG's latest estimate of their previously committed reserve is 980 Bcf less the 220 lost to Enstar .. This 760 Bcf is 151 greater 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 FIGURE D-1.2 '))1 1 1 J 1 1 )-]I 1 )--]1 J 1 1 1 1 ~SHADING DENOTES ~OFFSHORE AREAS ,~f:, ",O~\-. .,f:,~. O~..-' U COCO,'i' ,~j", ~CO 'O~1\11 ," 16 , \r-\--~1 GUlF OF ALASKA SHELF GUlF OF ALASKA SLOPE 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.FIGURE D-1.3 lDOO PRO'iIlli.W~~~Oill!fj2 fiUllIlJll-_ 10DO I lila 4000 ...o III U) ~aooo a; w II) w fI: aooo 1000 I PROVEN RfIlERlJE! 11186 111110 111116 YEA" ,Hl-l..lP II 1",,,fI"lHOtl LtlO 2000 200~2010 COOK INLET NATURAL GAS RESERVES AND ESTIMA TED CUMULATIVE CONSUMPTION F IGUR E 0-1.4 l ~i }J Coal Generation Cost· Unit Si ze Unit Capital Cost Ava i 1ab i 1 it Y Annual Generation Fuel Cost Heat Rateo&M Cost Real Cost of Capital Economic life 200 MW $2,340/kw 85% 1.5 x 10 9 kwh $1.70/MMBtu 9,750 Btu/kwh $0.0032/kwh 3.5% 35 years Annual CaRital 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)= Annual Fuel Gost:CF=(1.5 x 10 kwh/yr)(9750 Btu/kwh)($1.70/10 6 Btu)= Total Annual Costs Gas Generation Cost $22.6 x 106 $4.8 x 106 $24.9 x 10 6 $52.3 x 10 6 Unit Size (combined cycle) Unit Capital Cost Avai 1abi 1ity Annual Generation Fuel Cost Heat Rateo&M Cost Real Cost of Capital Economic Life 200 MW $650/kw 85% 1.5 x 109 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={1.5 x 10 kwh/yr.)($0.0042/kwh)= Total Annual Costs Without Fuel Gas Fuel Cost $6.8 x 10 6 . $6.3 x 10 6 $13.1 x 10 6 ,.,.. ! -- Cost of Gas Fuel =Total annual coal generation costs less tas costs without fuel =$52.3 x 10 6 -$13.1 x 10 6 (1.5 x 109 kWh)(S,200 BtuIKwh) =$3.19/MMBtu MAXIMUM DEREGULATED COOK INLET GAS PRICES (BASED ON SUBSTITUTABILITY OF COAL-FIRED UNITS) FIGURE 0-1.5 200 150 (I) Z -l 0 0«I- 0 o 0 u.a::o I-100ill (I)::: I-cr.Z 0 0 a..-l~~ ::: '-' 50 --- ~~~ JAPAN ~~~ 30-YR.AVERAGE GROWTH RATE ~~ ---~---.--. SOUTH KOREA-----5.2 'j{,------30 -YR.AVER1GE GROWTH RArE 1980 1985 1990 1995 YEAR 2000 2005 2010 PRESENT AND PROJECTED COAL IMPORTS IN JAPAN AND SOUTH KOREA.1980-2010 SOURCE:SHERMAN CLARK ASSOCIATES 1983 -,, -,, FIGURE 0-2.1 , GWR/YR 250,00) 200,000 150.000 100,00) SO.OlJ) / JAPAN > I-- ~TAIWAN V - KOREA ;...-- 1980 1990 YEAR 2000 - PROJECTED COAL FIRED ELECTRICITY GENERATION IN PACIFIC RIM COUNTRIES.1980-2000 (GWR/YR) FIGURE 0-2.2 120+---------------+--------------+ TOTAL 110t--------------I--------------.-.e.-- 100 90 80 AVERAGE ANNUAL MARKET GROWTH RATE ::11.3%- JAPAN ~7« z 0o(.)-~:j 0 60 ~(IJ Z 0 ~50 40 30 TAIWAN 20 :KOREA 10 1980 1990 2000 YEAR TOTAL COAL NEEDS FOR ELECTRIC POWER GENERATION IN PACIFIC RIM NATIONS,1980-2010 FIGURE 0-2.3 --]1 J 1 -J J ~--J J J J 1 --1 1 3320 MI. 4262 MI. 4839 MI. 4265 MI. 7291 MI. 9095 MI. 9504 MI. '.""'" •••••,It .. "".. "'" ",'"..,'...."'" .~'"" "..''..,.,.. , ~), """..... " ~~~ O .\~", ""'(;.a••••............... C)j~ TO -JAPAN-a FROM-ALASKA VANCOUVER U.S.WEST COAST AUSTRALIA SOUTH AFRICA U.S.GULF COAST U.S.ATLANTIC OIST ANCES FROM COAL PORTS TO JAPAN COAST (PANAMA CANAL) FIGURE 0-2.4 $3.00 $2.00 $1.00 WESTERN COAL ~~ 30 YA AVERAGE:::@ 10,000 BTU/LB, 2.9%/YR -30 YR AVERAGE:::WESTERN lIG NilE j--~ 2.3%/YR (il 7,500 BY BTU/LB I 1 1980 1990 YEAR 2000 2100 FORECAST REAL COAL PRICES FOR WESTERN COAL AND LIGNITE,1980-20 10jNEW CONTRACT AND SPOT MARKET STEAM COAL (1982DOLLLARS) FIGURE 0-2.5 -, -" - - SUSITNA HYOROELECTIC PROJECT VOLUME 1 EXHIBIT 0,APPENDIX 0-1 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)~ulf 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)Coo kIn 1et . b)Nor t h Slope . 1.4 Projected Gas Prices . 1.5 Effect of Gas Price Deregulation ...................•. a)Ex;sti ng Law . b)Proposed Changes to the NGPA .•................... c)Deregulated Cook Inlet Gas Prices . 1.6 References and Notes ..•..•.........•................. Page 01-1 01-1 01-2 01-2 01-3 01-3 01-4 01-4 01-5 01-7 01-8 01-9 01-10 01-10 01-13 01-17 01-17 01-18 01-20 01-21 01-23 2 -eoa 1 •.•••••.•.•••.••••.•e._••••••••••••••••••••••••e.4I •••••••01-25 2.1 Resources and Reserves ..•............•...............01-25 2.2 Present and Potential Alaskan Coal Production 01-26 2.3 Current Alaskan Coal Prices .........•............•...01-27 a)Nenana Field ...•.•...•.....•...•..................01-27 b)Beluga Field ....•.............•.................•.01-29 2.4 Coal Price Escalation .......•.......•................01-32 2.5 References and Bibliography 01-37 3 -Distillate Oil ..........................•.................01-40 3.1 Availability .•...............•.......................01-40 3•2 Pric e ..............•.........•......................•01-40 Appendix 0-1 LIST OF TABLES 0-1.1 Preliminary Estimates of Undiscovered Gas Resources in Place and Economically Recoverable Gas Resources For the Cook Inlet Bas in. 0-1.2 Hi stori cal and Current Producti on and Use of Cook Inl et Natural Gas 0-1.3 Estimated Use of Cook Inlet Natural Gas by User 0-1.4 Current Production and Use of North Slope Gas For 1982 0-1.5 Estimated Base Prices For New Purchases of Uncommitted and Undiscovered Cook Inlet Gas -Without LNG Export Opportunities 0-1.6 Estimated 1983 Base Prices For New Purchases of Uncommitted and Undiscovered Cook Inlet Gas -With LNG Export Opportunities 0-1.7 Estimated Cost of North Slope Natural Gas For Electric Generation at Kenai Assuming Implementation of the Trans Alaska Gas System (TAGS) 0-1.8 Estimated 1983 Delivered Cost of North Slope Natural Gas For Railbelt Electrical Generation 0-1.9 Projected Cook Inlet Wellhead Natural Gas Prices 0-1.10 Projected North Slope Delivered Natural Gas Prices 0-2.1 Demonstrated Reserve Base in Alaska and the U.S.by Type of Coal 0-2.2 Reserves and Resources of the Nenana Field 0-2.3 Proximate and Ultimate Analysis of Nenana Field Coal 0-2.4 0-2.5 0-2.6 0-2.7 0-2.8 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 - Appendix 0-1 LIST OF TABLES 0-2.9 Production Cost Estimates For Beluga Coal in 1983 Dollars 0-2.10 Beluga Area Hypothetical Mine -Summary of Selected Data 0-2.11 Some Projected Real Escalation Rates For Coal Prices 0-2.12 Coal Price Real Escalation Rates 0-2.13 Nenana Coal Transportation Costs From Healy to Generating Pl ant Location 0-2.14 Estimated Delivered Prices of Coal in Alaska by Year. 0-3.1 Prices of diesel and Turbine Fuel For Electrical Generation - 1983 $/MMBtu 0-3.2 Projected Prices of Diesel and Turbine Fuel at Anchorage For Various Oil Price Scenario Appendix 0-1 LIST OF FIGURES pc ...' 0-1.1 0-1.2 0-1.3 0-1.4 0-1.5 0-2.1 0-2.2 0-2.3 0-2.4 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 0-2.5 Forecast Real Coal Prices For \~estern Coal and Lignite, 1980-2010;New Contracts and Spot Market Steam Coal r i \ r l r l t r t r l r I l r I l r l r t